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As filed with the Securities and Exchange Commission on June 2, 2015

Registration No. 333-            

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

WESTMORELAND RESOURCE PARTNERS, LP

(Exact Name of Registrant as Specified in its Charter)

 

 

 

Delaware		1221		77-0695453
(State or Other Jurisdiction of Incorporation or Organization)		(Primary Standard Industrial Classification Code Number)		(I.R.S. Employer Identification Number)

9540 South Maroon Circle, Suite 200

Englewood, Colorado 80112

(855) 922-6463

(Address, Including Zip Code, and Telephone Number, including Area Code, of Registrant’s Principal Executive Offices)

 

 

Jennifer S. Grafton, Esq.

Chief Legal Officer

9540 South Maroon Circle, Suite 200

Englewood, Colorado 80112

(855) 922-6463

(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)

 

 

Copies to:

 

Amy L. Bowler Lucy Schlauch Stark Holland & Hart LLP 6380 S. Fiddlers Green Circle, Suite 500 Greenwood Village, CO 80111 (303) 290-1600		Joshua Davidson Andrew J. Ericksen Baker Botts L.L.P. 910 Louisiana Street Houston, TX 77002 (713) 229-1234

 

 

Approximate date of commencement of proposed sale to the public: As soon as possible after the effective date of this Registration Statement.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.  ¨

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer		¨				Accelerated filer		¨
Non-accelerated filer		¨		(Do not check if a smaller reporting company)		Smaller reporting company		x

 

 

CALCULATION OF REGISTRATION FEE

 

Title of Each Class of Securities to be Registered		Proposed Maximum Aggregate Offering Price(1)(2)		Amount of Registration Fee(1)
Common Units representing Limited Partner Interests		$86,250,000		$10,022.25

 

(1)	Estimated solely for the purpose of computing the registration fee pursuant to Rule 457(o) under the Securities Act of 1933, as amended.

(2)	Includes the aggregate offering price of additional common units that the underwriters have the option to purchase.

 

 

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until this Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to such Section 8(a), may determine.

 

 

 

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The information in this prospectus is not complete and may be changed. The securities may not be sold pursuant to this prospectus until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

 

 

PRELIMINARY PROSPECTUS

SUBJECT TO COMPLETION, DATED JUNE 2, 2015

 

                     Common Units

 

Westmoreland Resource Partners, LP

Common Units Representing Limited Partner Interests

We are offering              common units representing limited partner interests, or common units, in Westmoreland Resource Partners, LP, or the Partnership, as described in this prospectus. Our common units are traded on the New York Stock Exchange, or the NYSE, under the symbol “WMLP.” The last reported sale price of our common units on the NYSE on May 29, 2015 was $10.50 per common unit.

Investing in our common units involves a high degree of risk. You are urged to carefully read this prospectus and all of the information incorporated by reference herein. You should carefully consider the factors described under “Risk Factors” beginning on page 15 of this prospectus before you make an investment in our common units.

 

		Per Common Unit		Total
Price to the public		$		$
Underwriting discounts and commissions		$		$
Proceeds to Westmoreland Resource Partners, LP (before expenses)		$		$

 

 

We have granted the underwriters a 30-day option to purchase up to an additional              common units from us on the same terms and conditions if the underwriters sell more than              common units in this offering.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the common units on or about                     , 2015.

 

 

Book-Running Manager

BMO Capital Markets

 

 

Prospectus dated                     , 2015.

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TABLE OF CONTENTS

 

		Page
PROSPECTUS SUMMARY			1
THE OFFERING			9
SUMMARY HISTORICAL CONSOLIDATED AND UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION			11
RISK FACTORS			15
THE CONTRIBUTION			42
USE OF PROCEEDS			44
CAPITALIZATION			45
HOW WE MAKE CASH DISTRIBUTIONS			46
PRICE RANGE OF OUR COMMON UNITS AND DISTRIBUTIONS			56
UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS			57
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			73
OUR INDUSTRY			91
OUR BUSINESS			94
MANAGEMENT			115
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS			120
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			122
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES			124
DESCRIPTION OF OUR COMMON UNITS			132
THE PARTNERSHIP AGREEMENT			134
MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES			148
INVESTMENT BY EMPLOYEE BENEFIT PLANS			169
UNDERWRITING			171
VALIDITY OF THE SECURITIES			175
EXPERTS			175
WHERE YOU CAN FIND MORE INFORMATION			176
INFORMATION INCORPORATED BY REFERENCE			176
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS			177
INDEX TO FINANCIAL STATEMENTS			F-1
GLOSSARY OF SELECTED TERMS			G-1

 

 

You should rely only on the information contained or incorporated by reference in this prospectus or any free writing prospectus we may authorize to be delivered to you. Neither we nor the underwriters have authorized anyone to provide you with information that is different. If anyone provides you with different or inconsistent information, you should not rely on it. This prospectus is not an offer to sell or a solicitation of an offer to buy our common units in any jurisdiction where such offer or any sale would be unlawful. You should not assume that the information in this prospectus or any free writing prospectus that we may authorize to be delivered to you, including any information incorporated by reference, is accurate as of any date other than the date indicated for such information. Our business, financial condition, results of operations or prospects may have changed since those dates.

 

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COAL RESERVE INFORMATION

The estimates of our proven and probable reserves are derived from estimates calculated by our geologists and mining engineers, which estimates (other than with respect to our Kemmerer reserves) were audited by John T. Boyd Company, an independent mining and geological consulting firm, in 2014. These estimates are based on geologic data, coal ownership information and current and proposed mine plans. Our proven and probable coal reserves are reported as “recoverable coal reserves,” which is the portion of the coal that could be economically and legally extracted or produced at the time of the reserve determination, taking into account mining recovery and preparation plant yield. These estimates are periodically updated to reflect past coal production, new drilling information and other geologic or mining data. Acquisitions or dispositions of coal properties will also change these estimates. Changes in mining methods may increase or decrease the recovery basis for a coal seam, as will changes in preparation plant processes. We refer to coal reserves we lease to others to mine as our “controlled” reserves.

“Reserves” are defined by SEC Industry Guide 7 as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. Industry Guide 7 divides reserves between “proven (measured) reserves” and “probable (indicated) reserves,” which are defined as follows:

 

•

Proven (Measured) Reserves.” Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; and grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established.

 

•

“Probable (Indicated) Reserves.” Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling, and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation.

For a list of definitions of other coal industry terms used throughout this prospectus, please read “Glossary of Selected Terms.”

INDUSTRY AND MARKET DATA

The market and statistical data included in this prospectus regarding the coal industry, including descriptions of trends in the market and our position and the position of our competitors within the industry, is based on a variety of sources, including independent industry publications, government publications and other published independent sources, information obtained from customers, distributors, suppliers and trade and business organizations, commissioned reports and publicly available information, as well as our good faith estimates, which have been derived from management’s knowledge and experience in the industry in which we operate. Although we have not independently verified the accuracy or completeness of the third-party information included in this prospectus, based on management’s knowledge and experience, we believe that these third-party sources are reliable and that the third-party information included in this prospectus or in our estimates is accurate and complete. While we are not aware of any misstatements regarding the market, industry or similar data presented herein, such data involve risks and uncertainties and are subject to change based on various factors, including those discussed under the headings “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” in this prospectus.

 

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CERTAIN TERMS USED IN THIS PROSPECTUS

Unless the context otherwise requires, references in this prospectus to the following terms have the meanings set forth below:

 

•

our “general partner” refers to Westmoreland Resources GP, LLC, a Delaware limited liability company and our general partner;

 

•

“Kemmerer” refers to Westmoreland Kemmerer, LLC (formerly Westmoreland Kemmerer, Inc.), a Delaware limited liability company and a wholly owned subsidiary of WCC that we have agreed to purchase from WCC;

 

•

our “Predecessor” refers to our partnership for accounting periods prior to the Initial Kemmerer Contribution, which is our predecessor for accounting purposes;

 

•

our “Successor” refers to our partnership for accounting periods following the Initial Kemmerer Contribution;

 

•

“WCC” and our “sponsor” refer to Westmoreland Coal Company, a Delaware corporation and the parent of our general partner, and its subsidiaries other than our general partner, us and our subsidiaries;

 

•

“Westmoreland Resource Partners, LP,” “WMLP,” “our partnership,” “we,” “our,” “us” and similar terms, when used in a historical context, refer to our predecessor for accounting purposes as described in the final bullet below. When used in the present tense or future tense, these terms refer to Westmoreland Resource Partners, LP, a Delaware limited partnership, and its subsidiaries; and

 

•

“WRPS” refers to, collectively, our Successor and Kemmerer.

 

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RISK FACTORS

An investment in our common units involves a high degree of risk. Before you invest in our common units, you should carefully consider the risk factors contained or incorporated by reference in this prospectus, together with all of the other information included or incorporated by reference in this prospectus. If any of these risks were to materialize, our business, results of operations, cash flows and financial condition could be materially adversely affected. In that case, our ability to make distributions to our unitholders may be reduced, the trading price of our common units could decline and you could lose all or part of your investment.

Risks Related to the Contribution

The Contribution may not be completed as anticipated, or if completed, may not be beneficial to us.

The Contribution is expected to close in the third quarter of 2015 and is subject to the receipt by us of net proceeds of at least $65 million in this offering, as well as the satisfaction of other customary closing conditions. If these conditions are not satisfied or waived, the Contribution will not be consummated. There is no assurance that the Contribution will close on or before that time, or at all. Accordingly, if you decide to purchase our common units in this offering, you should be willing to do so whether or not we complete the Contribution.

The consummation of the Contribution involves potential risks, including:

 

•

the failure to realize expected profitability, growth or accretion;

 

•

environmental or regulatory compliance matters or liabilities;

 

•

title issues or environmental or regulatory compliance matters or liabilities or accidents;

 

•

construction cost overruns and delays resulting from numerous factors, many of which may be out of our control;

 

•

the temporary diversion of management’s attention from our existing businesses;

 

•

the incurrence of significant charges, such as asset devaluation or restructuring charges;

 

•

the incurrence of unanticipated liabilities and costs for which indemnification is unavailable or inadequate.

If we consummate the Contribution and if these risks or other unanticipated liabilities were to materialize, any desired benefits of the Contribution may not be fully realized, if at all, and our future financial performance and results of operations could be negatively impacted.

The Contribution will add unionized employees to our workforce, and our workforce may become further unionized in the future.

Currently, none of our employees are represented under collective bargaining agreements. However, approximately 236 of Kemmerer’s 297 employees who will join our workforce in connection with the Contribution are union employees represented by United Mine Workers of America (“UMWA”), and additional members of our workforce may become represented by unions in the future. Although we expect that the Kemmerer employees will continue to be employed at the WCC level following the Contribution, the exposure to unionized labor in our workforce nonetheless presents an increased risk of strikes and other labor disputes, and our ability to alter labor costs will be subject to collective bargaining, which could adversely affect stability of production and our results of operations. While the occurrence of labor strikes are generally deemed force majeure events under Kemmerer’s long-term coal supply agreements, which would thereby exempt the mine from its delivery obligations, the loss of revenue from the Kemmerer Mine caused by a labor strike for even a short time could have a material adverse effect on our financial results, cash flows and ability to make distributions to our unitholders.

 

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Congress has proposed legislation to enact a law allowing workers to choose union representation solely by signing election cards, which would eliminate the use of secret ballots to elect union representation. While the impact is uncertain, if the government enacts this proposal into law, which would make it administratively easier to unionize, it may lead to more coal mines becoming unionized. Increased unionization of our mines may advsersely affect our business, financial condition and/or results of operations.

Risks Related to Our Business

Our credit facility contains operating and financial restrictions that restrict our distributions, business and financing activities.

Our credit facility entered into in December 2014 with the lenders party thereto and U.S. Bank National Association, as Administrative and Collateral Agent (the “2014 Financing Agreement”), contains significant restrictions on our ability to incur additional liens or indebtedness, make fundamental changes or dispositions, make changes in the nature of our business, make certain investments, loans or advances, create certain lease obligations, make capital expenditures in excess of a certain amount, enter into transactions with affiliates, issue equity interests, and modify indebtedness, organizational and certain other documents. The 2014 Financing Agreement also contains covenants requiring us to maintain certain financial ratios and limits our ability to pay distributions to our unitholders, allowing such distributions only under specified circumstances. For example, in order to make cash distributions to our unitholders, no event of default must exist or result from such distribution and, on a pro forma basis immediately after giving effect to such distribution, (x) our consolidated total net leverage ratio (as defined in the 2014 Financing Agreement) must be less than or equal to 3.75:1.00 and (y) our fixed charge coverage ratio (as defined in the 2014 Financing Agreement) must be not less than 1.00:1.00, and (2) we must have liquidity of at least $5,000,000 immediately after giving effect to such distribution; provided that we may make cash distributions in an aggregate amount not to exceed $7,500,000 without being required to satisfy these ratios.

The provisions of the 2014 Financing Agreement may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of the 2014 Financing Agreement could result in a default or an event of default that could enable our lenders to declare the outstanding principal of our debt under the 2014 Financing Agreement, together with accrued and unpaid interest, to be immediately due and payable. If the payment of such debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment.

Our ability to comply with the covenants and restrictions contained in the 2014 Financing Agreement may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the covenants or restrictions in the 2014 Financing Agreement, our indebtedness under the 2014 Financing Agreement may become immediately due and payable, and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under the 2014 Financing Agreement are secured by substantially all of our assets and, if we are unable to repay our indebtedness under the 2014 Financing Agreement, the lenders could seek to foreclose on such assets.

 

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Debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.

We have a substantial amount of indebtedness. At March 31, 2015, we had a total outstanding indebtedness of approximately $176.4 million, all of which was under our 2014 Financing Agreement. On a pro forma basis after giving effect to the Contribution, at March 31, 2015, we had a total outstanding indebtedness of approximately $268.7 million, all of which was under our 2014 Financing Agreement. Our level of indebtedness could have significant consequences to us and our unitholders, including the following:

 

•

our ability to obtain additional financing, if necessary, for working capital, capital expenditures (including acquisitions) or other purposes may be impaired or such financing may not be available on favorable terms;

 

•

our ability to meet financial covenants may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

 

•

our need to use a portion of our cash flow to make principal and interest payments will reduce the amount of funds that would otherwise be available for operations, distributions, and future business opportunities;

 

•

our increased vulnerability to competitive pressures or a downturn in our business or the economy generally; and

 

•

our flexibility in responding to changing business and economic conditions.

These factors could have a material adverse effect on our business, financial condition, results of operations or prospects. Increases in our total indebtedness would increase our total interest expense costs. Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing or delaying our business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms, or at all.

Certain provisions in our long-term supply contracts may provide limited protection during adverse economic conditions, may result in economic penalties, and/or may permit customers to terminate such contracts.

Price adjustment, “price re-opener” and other similar provisions in most of our supply contracts may reduce the protection from short-term coal price volatility traditionally provided by such contracts. Price re-opener provisions typically require the parties to agree on a new price. Failure of the parties to agree on a price under a price re-opener provision can lead to termination of the contract. Any adjustment or renegotiations leading to a significantly lower contract price could adversely affect our business, financial condition and/or results of operations.

Coal supply contracts also typically contain force majeure provisions allowing temporary suspension of performance by our customers or us during the duration of specified events beyond the control of the affected party. Force majeure events include, but are not limited to, floods, earthquakes, storms, fire, faults in the coal seam or other geologic conditions, other natural catastrophes, wars, terrorist acts, civil disturbances, strikes, transportation delays including lack of suitable railcars and actions or restraints by local, state or federal agencies or regulatory bodies. Most of our coal supply contracts also contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as Btu, sulfur content, ash content, hardness and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or termination of the contracts. In addition, certain of our supply contracts permit the customer to terminate the contract in the event of changes in regulations affecting our industry that

 

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increase the price of coal beyond a specified limit. Such changes in regulations that could lead to a permissible termination include, among others, governmental actions that make the use of coal economically unfeasible, materially curtail or prohibit or effectively prohibit the buyer’s use of coal or the operation of the plant, or that modify emission or discharge limitations such that the plant as constructed cannot reasonably comply with such governmental regulation. Any events leading to the termination or suspension of one or more contracts could adversely affect our business, financial condition and/or results of operations.

Please read “Business—Long-Term Coal Supply Contracts” for additional information.

We depend on supply contracts with a few customers for a substantial majority of our revenues.

We sell a material portion of our coal under long-term supply contracts. As of March 31, 2015, we had sales commitments for 100% of our estimated coal production (including purchased coal to supplement our production) for the year ending December 31, 2015, 89.3% of which are under long-term contracts. When our current contracts with customers expire, our customers may decide not to extend existing contracts or enter into new contracts. For the year ended December 31, 2014, we derived approximately 99.1% of our total revenues from coal sales to our ten largest customers (including their affiliates), with affiliates of the following top three customers accounting for approximately 87.5% of our coal revenues for that period: American Electric Power Company, Inc. (56.7%); FirstEnergy Corp. (16.5%); and East Kentucky Power Cooperative (14.3%). Approximately 32.2% of these sales were facilitated by coal brokers.

In the absence of long-term contracts, or upon renewal of such contracts, our customers may decide to purchase fewer tons of coal than in the past or on different terms, including different pricing terms. Negotiations to extend existing contracts or enter into new long-term contracts with those and other customers may not be successful. In addition, interruption in the purchases by or operations of our principal customers could adversely affect our business, financial condition and/or results of operations. Unscheduled maintenance outages at our customers’ power plants, unseasonably moderate weather, or increases in the production of alternative clean-energy generation such as wind power or decreases in the price of competing fossil fuels such as natural gas are examples of conditions that might cause our customers to reduce their purchases. We may have difficulty identifying alternative purchasers for our coal if our existing customers suspend or terminate their contracts.

Additionally, certain of our long-term contracts are set to expire in the next several years. Should we be unable to successfully renew any or all of these expiring contracts, the reduction in the sale of our coal would adversely affect our operating results and liquidity and could result in significant impairments to our mines should we be unable to execute new long-term coal supply agreements for the affected mines.

Please read “Business—Customers” and “—Long-Term Coal Supply Contracts” for additional information.

Substantially all of our coal supply agreements are forward sales agreements. If the production costs underlying these agreements increase, our results of operations could be materially adversely affected.

Substantially all of our coal supply agreements are forward sales agreements under which customers agree to pay a specified price for coal to be delivered in future years. The profitability of these agreements depends on our ability to adequately control the costs of the coal production underlying the agreements. These production costs are subject to variability due to a number of factors, including increases in the cost of labor, supplies or other raw materials. To the extent our costs increase but pricing under these coal supply agreements remains fixed, we will be unable to pass increasing costs on to our customers. If we are unable to control our costs, our profitability under our forward sales agreements may be impaired and our results of operations, business and financial condition, and our ability to make distributions to our unitholders, could be materially adversely affected.

 

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We depend upon our ability to collect payments from our customers.

Our ability to receive payment for the coal we sell depends on the continued creditworthiness of our customers. Periods of economic volatility and tight credit markets increase the risk that we may not be paid.

If the creditworthiness of a customer declines, this would increase the risk that we may not be able to collect payment for some or all of the coal we delivered to that customer. If we determine that a customer is not creditworthy, we may not be required to deliver coal under the customer’s coal sales contract. If we are able to withhold shipments, we may decide to sell the customer’s coal on the spot market, which may be at prices lower than the contract price, or we may be unable to sell the coal at all. Also, competition with other coal suppliers could force us to extend credit to customers on terms that could increase the risk of payment default.

In addition, we sell some of our coal to brokers who may resell our coal to end users, including utilities. These coal brokers may have only limited assets, making them less creditworthy than the end users. Under some of these arrangements, we have contractual privity only with the brokers and may not be able to pursue claims against the end users. The bankruptcy or financial deterioration of any of our customers, whether an end user or a broker, could adversely affect our business, financial condition and/or results of operations.

A decline in demand for coal could adversely affect our ability to sell the coal we can produce and a decline in coal prices could render production from our coal reserves uneconomical.

Our results of operations and the value of our coal reserves are significantly dependent upon the prices we receive for our coal, as well as our ability to improve productivity and control costs. The prices we receive for coal and our cost of producing and transporting our coal depend upon many factors, some of which are beyond our control, including:

 

•

the domestic and foreign supply and demand for coal;

 

•

the quantity and quality of coal available from competitors;

 

•

a decline in prices under existing contracts where the pricing is tied to and adjusted periodically based on indices reflecting current market pricing;

 

•

competition for production of electricity from non-coal sources, including the price and availability of alternative fuels, such as solar and wind;

 

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domestic air emission standards for coal-fueled power plants and the ability of coal-fueled power plants to meet these standards by installing scrubbers or other means;

 

•

the efficiency of our mines;

 

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adverse weather, climate or other natural conditions, including natural disasters;

 

•

the level of domestic and foreign taxes;

 

•

domestic and foreign economic conditions, including economic slowdowns;

 

•

legislative, regulatory and judicial developments, environmental regulatory changes or changes in energy policy and energy conservation measures that would adversely affect the coal industry, such as legislation limiting carbon emissions or providing for increased funding and incentives for alternative energy sources;

 

•

the proximity to, capacity of and cost of transportation and port facilities;

 

•

market price fluctuations for sulfur dioxide emission allowances; and

 

•

work stoppages or other labor difficulties.

Any adverse change in these factors could result in a decline in demand and lower prices for our coal. Substantial or extended declines in the price we receive for our coal or increases in the costs of mining or

 

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transporting our coal could have a material adverse effect on our results of operations and our ability to generate the cash flows we require to invest in our operations, satisfy our obligations and pay distributions to our unitholders.

The risk of prolonged recessionary conditions could adversely affect our financial condition and results of operations.

Because we sell substantially all of our coal to electric utilities, our business and results of operations remain closely linked to demand for electricity. According to the EIA, although electricity demand fell in only three years between 1950 and 2007, it declined in four of the five years between 2008 and 2012. The largest drop in electricity demand occurred in 2009, primarily as the result of the steep economic downtown from late 2007 through 2009, which led to a large drop in electricity sales in the industrial section. Other factors, such as efficiency improvements associated with new appliance standards in the building sectors and overall improvement in the efficiency of technologies powered by electricity, have slowed electricity demand growth and may contribute to slower growth in the future. If demand for electricity production decreases further, our financial condition and results of operations could be adversely affected. Furthermore, because we typically seek to enter into long-term arrangements for the sale of a substantial portion of our coal, the average sales price we receive for our coal may lag behind any general economic recovery.

Competition in the North American coal industry may adversely affect our revenues and results of operations.

Many of our competitors in the North American coal industry are major coal producers who have significantly greater financial resources than we do. The intense competition among coal producers may impact our ability to retain or attract customers and may therefore adversely affect our revenues and results of operations. Among other things, competitors could develop new mines that compete with our mines, have higher quality coal than our mines or build or obtain access to rail lines that would adversely affect the competitive position of our mines. Additionally, during the last several years, the U.S. coal industry has experienced increased consolidation, which has contributed to the industry becoming more competitive. Increased competition by coal producers or producers of alternate fuels could decrease the demand for, or pricing of, or both, for our coal, adversely affecting our business, financial condition and/or results of operations.

Any changes in consumption patterns by utilities away from the use of coal, such as changes resulting from low natural gas prices, could affect our ability to sell the coal we produce.

We compete with coal producers in Northern Appalachia and, following the acquisition of the Kemmerer Assets in connection with the Contribution, we expect to compete with other coal producers in the western United States and in other coal producing regions of the United States. The economic stability of the markets in which we compete has a significant effect on the demand for coal and the level of competition in supplying these markets.

The domestic demand for, and prices of, our coal primarily depend on coal consumption patterns of the domestic electric utility industry. Thermal coal accounted for 100% of our coal sales volume for the year ended December 31, 2014. During this period, 74.3% of our thermal coal sales were to electric utilities for use primarily as fuel for domestic electricity generation. In addition to competing with other coal producers, we compete generally with producers of other fuels. The amount of coal consumed by the domestic electric utility industry is affected primarily by the overall demand for electricity, environmental and other governmental regulations, and the price and availability of competing fuels for power plants such as nuclear, natural gas and alternative sources of energy, such as solar and wind. In 2014, the EIA estimates that coal consumption in the electric power sector totaled 865 million tons, or 93% of total U.S. coal consumption, a historic low, due to low natural gas prices. A further decrease in coal consumption by the electric utility industry could adversely affect the demand for, and price of, coal, which could negatively impact our results of operations and liquidity.

 

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Natural gas is a competing fuel source for power generation due to the relatively lower cost of constructing such plants compared to coal-fired plants, and because natural gas is considered a cleaner burning fuel. In addition, some states have adopted or are considering legislation that encourages domestic electric utilities to switch from coal-fired power generation plants to natural gas powered plants. For example, Colorado’s Clean Air Clean Jobs Act (2010) provides for the retirement or replacement of 900 MW of coal-fired generation by 2017. Furthermore, legislation requiring, subsidizing or providing tax benefits for the use of alternative energy sources and fuels, or legislation providing financing or incentives to encourage continuing technological advances in this area, could further enable alternative energy sources to become more competitive with coal. A number of states have enacted mandates that require electricity suppliers to rely on renewable energy sources to generate a certain percentage of their power. Such mandates, combined with other incentives to use renewable energy sources, such as tax credits, could make alternative fuel sources more competitive with coal. Additionally, on June 2, 2014 the EPA proposed new regulations limiting carbon dioxide emissions from existing power generation facilities. Passage of these and other state or federal laws or regulations limiting carbon dioxide emissions could result in fuel switching, from coal to other fuel sources, by purchasers of our coal. Such laws and regulations could also mandate decreases in carbon dioxide emissions from coal-fired power plants, impose taxes on carbon emissions or require certain technology to capture and sequester carbon dioxide from coal-fired power plants. If these or similar measures are ultimately imposed by federal or state governments or pursuant to international treaty, our reserves and operating costs may be materially and adversely affected. Similarly, alternative fuels (non-fossil fuels) could become more attractive than coal in order to reduce carbon emissions, which could result in a reduction in the demand for coal and, therefore, our revenues.

Recently, the supply of natural gas has reached record highs and the price of natural gas has remained at depressed levels for sustained periods due to extraction techniques involving horizontal drilling and hydraulic fracturing that have led to economic access to large quantities of natural gas in the United States, making it an attractive competing fuel. A continuing decline in the price of natural gas, or continuing periods of sustained low natural gas prices, could cause demand for coal to decrease, result in fuel switching and decreased coal consumption by electricity-generating utilities and adversely affect the price of our coal. Sustained low natural gas prices may cause utilities to phase-out or close additional existing coal-fired power plants or reduce construction of any new coal-fired power plants, which could have a material adverse effect on demand and prices received for our coal. According to the EIA, the use of coal as a fuel source, represented as a percentage of total U.S. electricity production, has declined to 38.7% in 2014 from 44.8% in 2010.

PacifiCorp, the owner of the Naughton Power Station located adjacent to the Kemmerer Mine, which is the Kemmerer Mine’s primary customer, has sought regulatory approval to convert Unit 3 at Naughton to 100% natural gas fueling. Completion is expected in 2018. When complete, the conversion of Unit 3 to natural may result in the loss of coal sales from the Kemmerer Mine. Although there are price protections built into the contract that are in effect from 2017 to 2021, and we believe there are sufficient replacement opportunities for tons sold, in the event such protections are insufficient to cover our losses, the conversion of Unit 3 could result in lost sales of up to approximately 1 million tons annually.

Our business requires substantial capital expenditures, and we may not have access to the capital required to maintain full productive capacity at our mines.

Maintaining and expanding mines and infrastructure is capital intensive. Specifically, the exploration, permitting and development of coal reserves, mining costs, the maintenance of machinery and equipment and compliance with applicable laws and regulations require substantial capital expenditures. We must continue to invest capital to maintain or to increase our production. Decisions to increase our production levels could also affect our capital needs. We cannot assure you that we will be able to maintain our production levels or generate sufficient cash flow, or that we will have access to sufficient financing to continue our production, exploration, permitting and development activities at or above our present levels, and we may be required to defer all or a portion of our capital expenditures. As of March 31, 2015, on a pro forma basis, our liquidity consisted of only $6.8 million of cash on hand and $10.0 million of availability under our revolving credit facility. Our results of

 

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operations, business and financial condition, as well as our ability to pay distributions to our unitholders may be materially adversely affected if we cannot make such capital expenditures.

The amount of estimated reserve replacement capital expenditures our general partner is required to deduct from operating surplus each quarter could increase in the future, resulting in a decrease in available cash from operating surplus that could be distributed to our unitholders.

Our partnership agreement requires our general partner to deduct from operating surplus each quarter estimated reserve replacement expenditures as opposed to actual reserve replacement expenditures in order to reduce disparities in operating surplus caused by fluctuating reserve replacement costs. This amount is based on our current estimates of the amounts of expenditures we will be required to make in future years to maintain our depleting reserve base, which we believe to be reasonable. In the future, our estimated reserve replacement expenditures may be more than our actual reserve replacement expenditures, which will reduce the amount of available cash from operating surplus that we would otherwise have available for distribution to unitholders. The amount of estimated reserve replacement expenditures deducted from operating surplus is subject to review and change by the board of directors of our general partner at least once a year, subject to approval by the conflicts committee of the board of directors of our general partner, or the Conflicts Committee.

An inability to acquire replacement coal reserves could adversely affect our ability to produce coal.

Our business, financial condition and results of operations depend substantially on obtaining coal reserves that have geological characteristics that enable them to be mined at competitive costs and to meet the coal quality needed by our customers. Because we deplete our reserves as we mine coal, our future success and growth will depend, in part, upon our ability to acquire additional coal reserves that are economically recoverable. Our current strategy includes increasing our coal reserves through acquisitions of other mineral rights, leases, or producing properties and continuing to use our existing properties. Our ability to expand our operations may be dependent on our ability to obtain sufficient working capital, either through cash flows generated from operations or financing activities, or both. If we fail to acquire or develop additional reserves, our existing reserves will eventually be depleted. Replacement reserves may not be available when required or, if available, may not be capable of being mined at costs comparable to those characteristic of the depleting mines. Exhaustion of reserves at particular mines with certain valuable coal characteristics also may have an adverse effect on our operating results that is disproportionate to the percentage of overall production represented by such mines. Our ability to obtain other reserves could be limited by restrictions under our existing credit facilities or future debt agreements. Our inability to obtain reserves could adversely affect our business, financial condition and/or results of operations.

Because most of the coal in the vicinity of our mines is owned by the U.S. federal government, our future success and growth would be affected if we are unable to acquire or are significantly delayed in the acquisition of additional reserves through the federal competitive leasing process.

The U.S. federal government owns most of the coal in the vicinity of our mines. Accordingly, the federal competitive leasing process, which is administered by the Bureau of Land Management (“BLM”), is our primary means of acquiring additional reserves. In order to win a lease and acquire additional coal, our bid for a coal tract must meet or exceed the fair market value of the coal based on the internal estimates of the BLM, which are not published, and must also exceed any third-party bids. The BLM, however, is not required to grant a lease even if it determines that a bid meets or exceeds the fair market value estimate. Furthermore, since multiple parties are permitted to submit bids for any such federal lease, another bid may be accepted instead of our own. Over time, federal coal leases have become increasingly more competitive and expensive to obtain, and the review process to act on a lease for bid continues to lengthen. We expect this trend to continue. The increasing size of potential

 

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lease by application tracts may make it easier for new mining operators to enter the market on economically viable terms and may, therefore, increase competition for federal coal leases. Increased opposition from non-governmental organizations and other third parties may also lengthen, delay or complicate the leasing process. Any failure or delay in acquiring a coal lease, or the inability to do so on economically viable terms, could cause our production to decline, and may adversely affect our business, cash flows and results of operations, perhaps materially. For example, in November 2014, two non-governmental organizations brought suit against the Secretary of the Interior and the BLM alleging that the BLM’s coal leasing program is in violation of the National Environmental Policy Act (“NEPA”). Although the plaintiffs acknowledge that the BLM has generally complied with the requirements of NEPA with respect to individual coal leases, they assert that that the agency’s failure to update its 1979 analysis of environmental impacts associated with the broader BLM federal coal management program to include the impacts of GHGs constitutes a violation of NEPA. The plaintiffs are seeking a variety of relief, including an injunction that would, if their efforts are successful, prevent the issuance of new coal leases or modifications until the BLM has satisfied the requirements of NEPA.

The leasing process also requires us to acquire rights to mine from certain surface owners overlying the coal before the federal government will agree to lease the coal. Surface rights are becoming increasingly more difficult and costly to acquire. Certain federal regulations provide a specific class of surface owners, also known as qualified surface owners (‘‘QSOs’’), with the ability to prohibit the BLM from leasing its coal. If a QSO owns the land overlying a coal tract, federal laws prohibit us from leasing the coal tract without first securing surface rights to the land, or purchasing the surface rights from the QSO. This right of QSOs allows them to exercise significant influence over negotiations to acquire surface rights and can delay the leasing process or ultimately prevent the acquisition of coal underlying their surface rights. If we are unable to successfully negotiate access rights with QSOs at a price and on terms acceptable to us, we may be unable to acquire federal coal leases on land owned by the QSO. Our profitability could be adversely affected, perhaps materially, if the prices to acquire land owned by QSOs increase.

We may not be able to successfully replace our reserves or grow through future acquisitions or organic growth projects.

From time to time, we may seek to expand our operations by adding new mines and reserves through strategic acquisitions or other organic growth projects, including dropdowns from our general partner, and we intend to continue expanding our operations and coal reserves through these transactions. Our future growth could be limited if we are unable to continue making acquisitions or conducting organic growth projects, or if we are unable to successfully integrate the companies, businesses or properties we acquire or that are contributed to us from our general partner. We may not be successful in consummating any such transactions and the consequences of undertaking these transactions are unknown. If we are unable to make accretive acquisitions from WCC or third parties, whether because, among other reasons, (i) WCC elects not to sell or contribute additional assets to us or to offer acquisition opportunities to us, (ii) we are unable to identify attractive third-party acquisition opportunities, (iii) we are unable to negotiate acceptable purchase contracts with WCC or third parties, (iv) we are unable to obtain financing for these acquisitions on economically acceptable terms, (v) we are outbid by competitors or (vi) we are unable to obtain necessary governmental or third-party consents, then our future growth and ability to increase distributions will be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations on a per unit basis. Our ability to conduct these transactions in the future could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties, the lack of suitable acquisition candidates, and regulatory restrictions on us or our general partner.

Our reserve estimates may prove to be incorrect.

The coal reserve estimates in this prospectus are estimates based on the interpretation of limited sampling and subjective judgments regarding the grade, continuity and existence of mineralization, as well as the application of economic assumptions, including assumptions as to operating costs and future commodity prices.

 

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The sampling, interpretations or assumptions underlying any reserve estimate may be incorrect, and the impact on the amount of reserves ultimately proven to be recoverable may be material. Should the mineralization and/or configuration of a deposit ultimately turn out to be significantly different from that currently envisaged, then the proposed mining plan may have to be altered in a way that could affect the tonnage and grade of the reserves mined and rates of production and, consequently, could adversely affect the profitability of the mining operations. In addition, short term operating factors relating to the reserves, such as the need for orderly development of coal seams or the processing of new or different ores, may cause reserve estimates to be modified or operations to be unprofitable in any particular fiscal period. There can be no assurance that our projects or operations will be, or will continue to be, economically viable, that the indicated amount of minerals will be recovered or that they will be recovered at the prices assumed for purposes of estimating reserves. Additionally, the estimates of our historical proven and probable reserves are derived from estimates calculated by our geologists and mining engineers, which estimates were audited by John T. Boyd Company, an independent mining and geological consulting firm, in 2014. However, the proven and probable reserves of the Kemmerer Mine that will be contributed to us in the Contribution have not been audited by a third party since WCC’s acquisition of Kemmerer in 2012, and our estimates as of March 31, 2015 have not been audited by a third party.

Any inaccuracies in our estimates of our coal reserves could result in decreased profitability from lower than expected revenues or higher than expected costs.

Our future performance depends on, among other things, the accuracy of our estimates of our proven and probable coal reserves. Our reserve estimates are prepared by our engineers and geologists or by third-party engineering firms and are updated periodically. There are numerous factors and assumptions inherent in estimating the quantities and qualities of, and costs to mine, coal reserves, including many factors beyond our control which include the following:

 

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quality of the coal;

 

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geological and mining conditions, which may not be fully identified by available exploration data and/or may differ from our experiences in areas where we currently mine;

 

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the percentage of coal ultimately recoverable;

 

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the assumed effects of regulation, including the issuance of required permits, taxes, including severance and excise taxes and royalties, and other payments to governmental agencies;

 

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economic assumptions, including assumptions as to future commodity prices;

 

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assumptions concerning the timing for the development of the reserves; and

 

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assumptions concerning equipment and productivity, future coal prices, operating costs, including for critical supplies such as fuel, tires and explosives, capital expenditures and development and reclamation costs.

As a result, estimates of the quantities and qualities of economically recoverable coal attributable to any particular group of properties, classifications of reserves based on risk of recovery, estimated cost of production, and estimates of future net cash flows expected from these properties may vary materially due to changes in the above factors and assumptions. Any inaccuracy in our estimates related to our reserves could result in decreased profitability from lower than expected revenues or higher than expected costs.

A defect in title or the loss of a leasehold interest in certain property could limit our ability to mine our coal reserves or result in significant unanticipated costs.

We conduct a significant part of our coal mining operations on properties that we lease. A title defect or the loss of a lease could adversely affect our ability to mine the associated coal reserves. We may not verify title to our leased properties or associated coal reserves until we have committed to developing those properties or coal reserves. We may not commit to develop property or coal reserves until we have obtained necessary permits and completed exploration. As such, the title to property that we intend to lease or coal reserves that we intend to

 

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mine may contain defects prohibiting our ability to conduct mining operations. Similarly, our leasehold interests may be subject to superior property rights of other third parties. In order to conduct our mining operations on properties where these defects exist, we may incur unanticipated costs. In addition, some leases require us to produce a minimum quantity of coal and require us to pay minimum production royalties. Our inability to satisfy those requirements may cause the leasehold interest to terminate.

We are dependent on information technology and our systems and infrastructure face certain risks, including cybersecurity risks and data leakage risks.

We are dependent on information technology systems and infrastructure. Any significant breakdown, invasion, destruction or interruption of these systems by employees, others with authorized access to our systems, or unauthorized persons could negatively impact operations. There is also a risk that we could experience a business interruption, theft of information, or reputational damage as a result of a cyber-attack, such as an infiltration of a data center, or data leakage of confidential information either internally or at our third-party providers. While we have invested in the protection of our data and information technology to reduce these risks and periodically test the security of our information systems network, there can be no assurance that our efforts will prevent breakdowns or breaches in our systems that could adversely affect our business.

Concerns regarding climate change are, in many of the places where we operate, leading to increasing interest in, and in some cases enactment of, laws and regulations governing greenhouse gas emissions, which affect the end-users of coal and could reduce the demand for coal as a fuel source and cause the volume of our sales and/or the prices we receive to decline. These laws and regulations also have imposed, and will continue to impose, costs directly on us.

Greenhouse gas, or GHG, emissions have increasingly become the subject of international, national, state and local attention. Coal-fired power plants can generate large amounts of GHG emissions. Accordingly, legislation or regulation intended to limit GHGs will likely indirectly affect our coal operations by limiting our customers’ demand for our coal or reducing the prices we can obtain, and also may directly affect our own power operations. In the United States, the United States Environmental Protection Agency, or EPA, has issued a determination that emissions of carbon dioxide, methane, nitrous oxide and other GHGs present an endangerment to human health and the environment, which allows the EPA to begin regulating emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA implemented GHG-related reporting and permitting rules. Portions of the EPA’s GHG permitting rules, which were the subject of litigation by some industry groups and states, were recently struck down in part by the U.S. Supreme Court, but the EPA’s authority to impose GHG control technologies on a majority of large emissions sources, including coal-fired electric utilities, remains in place. President Obama in June 2013 announced a Climate Action Plan, which included a Presidential Memorandum directing the EPA to issue standards for GHG emissions from existing, modified and reconstructed fossil-fuel fired power plants. The EPA issued a revised proposal with standards for new fossil fuel-fired plants, including coal-fired plants, in September 2013, which the EPA plans to finalize by mid-summer 2015. The EPA also released its “Clean Power Plan” in June 2014, which includes proposed standards for existing and modified sources. Under the Clean Power Plan as currently proposed, the EPA would set standards for existing sources as stringent state-specific carbon emission rates that, if finalized, would be phased in between 2020 and 2030. The proposed rule would give states the discretion to use a variety of approaches, including cap-and-trade programs, to meet the standard. The EPA estimates that the proposed existing source rule would reduce CO2 emissions from the power sector by 30 percent by 2030, with a focus on emissions from coal-fired generation. The EPA plans to finalize the rule by June 2015, and state plans are due by June 2016, with one- to two-year extensions available. The U.S. Congress has considered, and in the future may again consider, legislation governing GHG emission, including “cap and trade” legislation that would establish a cap on emissions of GHGs covering much of the economy in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. In addition, coal-fired power plants, including new coal-fired power plants or capacity expansions of existing plants, have become subject to opposition by environmental groups seeking to curb the environmental effects of GHG emissions. It is difficult to predict at this time the effect these proposed rules would have on our revenues and profitability.

 

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Our inability to obtain and/or review permits necessary for our operations could prevent us from mining certain coal reserves.

The slowing pace at which permits are assigned or reviewed for new or existing mines in our area of operations has materially impacted production in Appalachia. We incur greater labor costs in securing these permits as a result. Section 402 National Pollutant Discharge Elimination System permits and Section 404 of the Clean Water Act, or CWA, permits are required to discharge wastewater and dredged or fill material into waters of the United States. Our surface coal mining operations typically require such permits to authorize activities such as the creation of sediment ponds and the reconstruction of streams and wetlands impacted by our mining operations. Although the CWA gives the EPA a limited oversight role in the Section 404 permitting program, the EPA has recently asserted its authority more forcefully to question, delay, and prevent issuance of some Section 404 permits for surface coal mining in Appalachia. Currently, significant uncertainty exists regarding the obtaining of permits under the CWA for coal mining operations in Appalachia due to various initiatives launched by the EPA regarding these permits. The slowing pace at which permits are issued or renewed for new and existing mines has materially impacted production in Appalachia, but could also affect other regions in which we operate. An inability to obtain the necessary permits to conduct our mining operations or an inability to comply with the requirements of applicable permits could reduce our production and cash flows, which could adversely affect our business, financial condition and/or results of operations and our cash flow.

Our coal mining operations are subject to external conditions that could disrupt operations and negatively affect our results of operations.

Our coal mining operations are all surface mines. These mines are subject to conditions or events beyond our control that could disrupt operations, affect production, and increase the cost of mining at particular mines for varying lengths of time. These conditions or events include:

 

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unplanned equipment failures;

 

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geological, hydrological or other conditions such as variations in the quality of the coal produced from a particular seam;

 

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variations in the thickness of coal seams and variations in the amounts of rock and other natural materials that overlie the coal that we are mining;

 

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weather conditions;

 

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competition and/or conflicts with other natural gas resource extraction activities and production within our operating areas;

 

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inability to acquire or maintain necessary permits or mining or surface rights;

 

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changes in governmental regulation of the mining industry or the electric utility industry;

 

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accidental mine water flooding;

 

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labor-related interruptions;

 

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transportation delays in barge, rail and truck systems due to weather-related problems, mechanical difficulties, strikes, bottlenecks, and other events;

 

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mining and processing equipment unavailability and failures and unexpected maintenance problems;

 

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potential unionization of our workforce; and

 

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accidents, including fire and explosions from methane.

Major disruptions in operations at any of our mines over a lengthy period could adversely affect the profitability of our mines. Any of these conditions may increase the cost of mining and delay or halt production at particular mines for varying lengths of time, which in turn could adversely affect our business, financial condition and/or results of operations.

 

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Unplanned outages and extensions of scheduled outages due to mechanical failures or other problems occur from time to time at our power plant customers and are an inherent risk of our business. Unplanned outages typically increase our operation and maintenance expenses and may reduce our revenues due to selling fewer tons of coal. We maintain business interruption insurance coverage to lessen the impact of events such as this. However, business interruption insurance may not always provide adequate compensation for lost coal sales, and significant unanticipated outages at our power plant customers which result in lost coal sales could result in significant adverse effects on our operating results.

In general, mining accidents present a risk of various potential liabilities depending on the nature of the accident, the location, the proximity of employees or other persons to the accident scene and a range of other factors. Possible liabilities arising from a mining accident include workers’ compensation claims or civil lawsuits for workplace injuries, claims for personal injury or property damage by people living or working nearby, and fines and penalties including possible criminal enforcement against us and certain of our employees. In addition, a significant accident that results in a mine shutdown could give rise to liabilities for failure to meet the requirements of coal-supply agreements, especially if the counterparties dispute our invocation of the force majeure provisions of those agreements. We maintain insurance coverage to mitigate the risks of certain of these liabilities, but those policies are subject to various exclusions and limitations. We cannot assure you that we will receive coverage under those policies for any personal injury, or property damage that may arise out of such an accident. Moreover, certain potential liabilities, such as fines and penalties, are not insurable risks. Thus, a serious mine accident may result in material liabilities that adversely affect our business, financial condition and/or results of operations.

Our operations are vulnerable to natural disasters, operating difficulties and infrastructure constraints, not all of which are covered by insurance, which could have an impact on our productivity.

Mining and power operations are vulnerable to natural events, including blizzards, earthquakes, drought, floods, fire, storms and the possible effects of climate change. Operating difficulties such as unexpected geological variations could affect the costs and viability of our operations. Our operations also require reliable roads, rail networks, power sources and power transmission facilities, water supplies and IT systems to access and conduct operations. The availability and cost of infrastructure affects our capital expenditures, operating costs, and planned levels of production and sales.

We maintain insurance for some, but not all, of the potential risks and liabilities associated with our business. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, we may not be able to renew our existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. Although we maintain insurance at levels we believe are appropriate and consistent with industry practice, we are not fully insured against all risks. In addition, pollution and environmental risks and consequences of any business interruptions such as equipment failure or labor disputes generally are not fully insurable. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our financial condition, results of operations and cash flows.

Mining in Northern Appalachia and the Illinois Basin is more complex and involves more regulatory constraints than mining in other areas of the United States.

The geological characteristics of Northern Appalachian and Illinois Basin coal reserves, such as depth of overburden and coal seam thickness, make them complex and costly to mine. As mines become depleted, replacement reserves may not be available when required or, if available, may not be capable of being mined at costs comparable to those of the depleting mines. These factors could adversely affect our business, financial condition and/or results of operations.

 

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The assumptions underlying our reclamation and mine closure obligations could be materially inaccurate.

The Federal Surface Mining Control and Reclamation Act of 1977 and counterpart state laws and regulations establish operational, reclamation and closure standards for all aspects of surface mining, as well as most aspects of underground mining. Estimates of our total reclamation and mine closing liabilities are based upon permit requirements and our engineering expertise related to these requirements. While the estimate of our reclamation liability is reviewed regularly by our management, the estimate can change significantly if actual costs vary from assumptions or if governmental regulations change significantly. Such changes could adversely affect our business, financial condition and/or results of operations.

If the assumptions underlying our asset retirement obligations are materially inaccurate, we could be required to expend greater amounts than anticipated.

We are subject to stringent reclamation and closure standards for our mining operations. We calculate the total estimated asset retirement obligations, or ARO, for final reclamation and mine closure according to the guidance provided by accounting principles generally accepted in the United States of America (“U.S. GAAP”) and current industry practice. Estimates of our total ARO are based upon permit requirements and our engineering expertise related to these requirements. If our estimates are incorrect, we could be required in future periods to spend materially different amounts on reclamation and mine-closing activities than we currently estimate.

We estimate that our gross ARO, which is based upon projected mine lives, current mine plans, permit requirements and our experience, was $51.9 million (on a present value basis) at March 31, 2015.

Although we update our estimated costs annually, our recorded obligations may prove to be inadequate due to changes in legislation or standards and the emergence of new restoration techniques. Furthermore, the expected timing of expenditures could change significantly due to changes in commodity costs or prices that might curtail the life of an operation. These recorded obligations could prove insufficient compared to the actual cost of reclamation. Any underestimated or unidentified close down, restoration or environmental rehabilitation costs could have an adverse effect on our reputation as well as our asset values, results of operations and liquidity.

If the cost of obtaining new reclamation bonds and renewing existing reclamation bonds increases or if we are unable to obtain additional bonding capacity, our operating results could be negatively affected.

We are required to provide bonds to secure our obligations to reclaim lands used for mining. We must post a bond before we obtain a permit to mine any new area. These bonds are typically renewable on a yearly basis. Bonding companies are requiring that applicants collateralize increasing portions of their obligations to the bonding company. In 2014, we paid approximately $1.0 million in premiums for reclamation bonds. We anticipate that, as we permit additional areas for our mines, our bonding and collateral requirements could increase. Any cash that we provide to collateralize our obligations to our bonding companies is not available to support our other business activities or to pay distributions to our unitholders. Our results of operations could be negatively affected if the cost of our reclamation bonding premiums and collateral requirements were to increase. Additionally, if we are unable to obtain additional bonding capacity due to cash flow constraints, we will be unable to begin mining operations in newly permitted areas, which would hamper our ability to efficiently meet our current customer contract deliveries, expand operations, and increase revenues.

Transportation impediments may hinder our current operations or future growth.

We depend upon barge, rail and truck systems to deliver coal to our customers. Disruptions in transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, and other events could impair our ability to deliver coal to our customers. As we do not have long-term contracts with transportation providers to ensure consistent service, decreased performance levels over long periods of time

 

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could cause our customers to look to other sources for their coal needs. In addition, increases in transportation costs, including the price of gasoline and diesel fuel, could make coal a less competitive source of energy when compared to alternative fuels or could make coal produced in one region of the United States less competitive than coal produced in other regions of the United States or abroad. Our inability to timely deliver coal due to rising transportation costs could have a material adverse effect on our business, financial condition and/or results of operations.

The unavailability of rail capacity could also hinder our future growth as we seek to sell coal into new markets. The current availability of rail cars is limited and at times unavailable because of repairs or improvements, or because of priority transportation agreements with other customers. If transportation is restricted or is unavailable, we may be unable to sell into new markets and, therefore, the lack of rail capacity could hamper our future growth.

It is possible that one or more states in which our coal is transported by truck may modify their laws to further limit truck weight limits. In recent years, the Commonwealth of Kentucky and the State of West Virginia have increased enforcement of weight limits on coal trucks on their public roads. It is possible that all states in which our coal is transported by truck may modify their laws to limit truck weight limits. Such legislation and enforcement efforts could result in shipment delays and increased costs, which could have an adverse effect on our ability to increase or to maintain production and could adversely affect our revenues.

Decreased availability or increased costs of key equipment and materials could impact our cost of production and decrease our profitability.

We depend on reliable supplies of mining equipment, replacement parts and materials such as explosives, diesel fuel, tires and magnetite. The supplier base providing mining materials and equipment has been relatively consistent in recent years, although there continues to be consolidation, which has resulted in a limited number of suppliers for certain types of equipment and supplies. Any significant reduction in availability or increase in cost of any mining equipment or key supplies could adversely affect our operations and increase our costs, which could adversely affect our operating results and cash flows.

In addition, the prices we pay for these materials are strongly influenced by the global commodities market. Coal mines consume large quantities of commodities such as steel, copper, rubber products, explosives and diesel and other liquid fuels. A rapid or significant increase in the cost of these commodities could increase our mining costs because we have limited ability to negotiate lower prices, and in some cases, do not have a ready substitute.

We enter into forward-purchase contract arrangements for a portion of our anticipated diesel fuel and explosive needs. Additionally, some of our expected diesel fuel requirements are protected, in varying amounts, by diesel fuel escalation provisions contained in coal supply contracts with some of our customers, that allow for a change in the price per coal ton sold. Price changes typically lag the changes in diesel fuel costs by one quarter. While our strategy provides us protection in the event of price increases to our diesel fuel, it may also prevent us from the benefits of price decreases. If prices for diesel fuel decreased significantly below our forward-purchase contracts, we would lose the benefit of any such decrease.

We and our general partner face intense competition to attract and retain employees.

Our general partner is dependent on retaining existing employees and attracting additional qualified employees to meet our current and future needs. We and our general partner face intense competition for qualified employees, and there can be no assurance that we or our general partner will be able to attract and retain such employees or that such competition among potential employers will not result in increasing salaries. We and our general partner rely on employees with unique skill sets to perform our mining operations, including engineers, mechanics and other highly skilled individuals. An inability to retain existing employees or attract additional employees, especially with mining skills and background, could have a material adverse effect on our business, cash flows, financial condition and results of operations.

 

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Extensive government regulations impose significant costs on our mining operations, and future regulations could increase those costs or limit our ability to produce and sell coal.

The coal mining industry is subject to increasingly strict regulation by federal, state and local authorities with respect to matters such as:

 

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limitations on land use;

 

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employee health and safety;

 

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mandated benefits for retired coal miners;

 

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mine permitting and licensing requirements;

 

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reclamation and restoration of mining properties after mining is completed;

 

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air quality standards;

 

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discharges to water;

 

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construction and permitting of facilities required for mining operations, including valley fills and other structures constructed in water bodies and wetlands;

 

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protection of human health, plant life and wildlife;

 

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management of the materials generated by mining operations and discharge of these materials into the environment;

 

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effects of mining on groundwater quality and availability;

 

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use of explosives; and

 

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remediation of contaminated soil, surface and groundwater.

We are required to prepare and present to governmental authorities data concerning the potential effects of any proposed exploration or production of coal on the environment and the public has statutory rights to submit objections to requested permits and approvals. Failure to comply with regulations of the U.S. Mine Safety and Health Administration may result in the assessment of administrative, civil and criminal penalties. Other governmental agencies may impose cleanup and site restoration costs and liens, issue injunctions to limit or cease operations, suspend or revoke permits and take other enforcement measures that could have the effect of limiting production from our operations. We may also incur costs and liabilities resulting from claims for damages to property or injury to persons arising from our operations. If we are pursued for any sanctions, costs and liabilities, our mining operations and, as a result, our results of operations, could be adversely affected.

United States federal and state regulatory agencies have the authority to temporarily or permanently close a mine following significant health and safety incidents, such as a fatality. In the event that these agencies order the closing of any of our mines, our coal sales contracts may permit us to issue force majeure notices which suspend our obligations to deliver coal under these contracts. However, our customers may challenge our issuances of force majeure notices. If these challenges are successful, we may have to purchase coal from third-party sources, if it is available, and potentially at prices higher than our cost to produce coal, to fulfill these obligations, and negotiate settlements with customers, which may include price and quantity reductions, the extension of time for delivery, or contract termination. Additionally, we may be required to incur capital expenditures to re-open any closed mines. These actions could adversely affect our business, financial condition and/or results of operations.

New legislation or regulations and orders may be adopted that may materially adversely affect our mining operations, our cost structure and/or our customers’ ability to use coal. New legislation or administrative regulations (or new judicial interpretations or administrative enforcement of existing laws and regulations), including proposals related to the protection of the environment that would further regulate and tax the coal industry, may also require us and/or our customers to change operations significantly or incur increased costs.

 

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These regulations, if proposed and enacted in the future, could have a material adverse effect on our financial condition and/or results of operations.

Federal legislation could result in higher healthcare costs.

In March 2010, the Patient Protection and Affordable Care Act (the “PPACA”) was enacted, impacting our costs of providing healthcare benefits to our eligible active employees, with both short-term and long-term implications. In the short term, our healthcare costs could increase due to, among other things, an increase in the maximum age for covered dependents to receive benefits, changes to benefits for occupational disease related illnesses, the elimination of lifetime dollar limits per covered individual and restrictions on annual dollar limits per covered individual. In the long term, our healthcare costs could increase for these same reasons, as well as due to an excise tax on “high cost” plans, among other things. Implementation of this legislation is expected to extend through 2018.

Beginning in 2018, the PPACA will impose a 40% excise tax on employers to the extent that the value of their healthcare plan coverage exceeds certain dollar thresholds. We anticipate that certain governmental agencies will provide additional regulations or interpretations concerning the application of this excise tax. We will continue to evaluate the impact of the PPACA, including any new regulations or interpretations, in future periods.

Any increase in cost, as a result of legislation or otherwise, could adversely affect our business, financial condition and/or results of operations.

Mining operations are subject to extensive and costly environmental laws and regulations, and such current and future laws and regulations could materially increase our operating costs or limit our ability to produce and sell coal.

The coal mining industry is subject to numerous and extensive federal, state and local environmental laws and regulations, including laws and regulations pertaining to permitting and licensing requirements, air quality standards, plant and wildlife protection, reclamation and restoration of mining properties, the discharge of materials into the environment, the storage, treatment and disposal of wastes, protection of wetlands, surface subsidence from underground mining, and the effects that mining has on groundwater quality and availability. The costs, liabilities and requirements associated with these laws and regulations are significant, time-consuming and may delay commencement or continuation of our operations.

The possibility exists that new laws or regulations (or new judicial interpretations or enforcement of existing laws and regulations) could materially affect our mining operations and our business, financial condition and/or results of operations, either through direct impacts such as those regulating our existing mining operations, or indirect impacts such as those that discourage or limit our customers’ use of coal. For example, the EPA and the U.S. Army Corps of Engineers have proposed a rule to clarify which waters and wetlands are subject to regulation under the CWA. A change in CWA jurisdiction and permitting requirements could increase or decrease our permitting and compliance costs. Additionally, in June 2013, President Obama issued a Climate Action Plan, which included a focus on methane reductions from coal mines. In January 2015, the Administration issued its methane strategy, but it did not include requirements for coal mines. Although we believe that we are in substantial compliance with existing laws and regulations, we may, in the future, experience violations that would subject us to administrative, civil and criminal penalties and a range of other possible sanctions. As a result, the consequences for any noncompliance may become more significant in the future.

Existing and future laws and regulations regulating the emission of sulfur dioxide and other compounds could affect coal consumers and as a result reduce demand for our coal.

Federal, state and local laws and regulations extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury and other compounds emitted into the air from electric power plants and other

 

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consumers that burn our coal. These laws and regulations can require significant emission control expenditures, and various new and proposed laws and regulations may require further emission reductions and associated emission control expenditures. A certain portion of our coal has a medium to high sulfur content, which results in increased sulfur dioxide emissions when combusted and therefore the use of our coal imposes certain additional costs on customers. For example, in February 2012, the EPA signed a rule to reduce emissions of mercury and toxic air pollutants from new and existing coal- and oil-fired electric utility steam generating units, often referred to as the MATS Rule. This rule was upheld by the U.S. Court of Appeals for the D.C. Circuit in April 2014, but in November 2014, the U.S. Supreme Court accepted certiorari and will hear an industry challenge in 2015. In April 2014, the U.S. Supreme Court upheld the EPA’s Cross-State Air Pollution Rule (“CSAPR”), which would require stringent reductions in emissions of nitrogen oxides and sulfur dioxide from power plants in much of the Eastern United States, including Texas and North Carolina, and in October 2014 the D. C. Circuit granted the EPA’s motion to lift the D.C. Circuit’s stay of the CSAPR, and remanded the case to the D.C. Circuit for further proceedings, which are ongoing. The EPA issued an interim rule in December 2014 that would require the first phase of reductions in 2015 and 2016, with the second phase of reductions beginning in 2017. Accordingly, these laws and regulations may affect demand and prices for our higher sulfur coal. A reduction in demand for our coal could adversely affect our business, financial condition and/or results of operations.

Risks Inherent in an Investment in Us

Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duties.

Fiduciary duties owed to our unitholders by our general partner are prescribed by law and the partnership agreement. The Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”) provides that Delaware limited partnerships may, in their partnership agreements, restrict the fiduciary duties owed by the general partner to limited partners and the partnership. Our partnership agreement contains such provisions. For example, our partnership agreement:

 

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limits the liability and reduces the fiduciary duties of our general partner, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing common units, our unitholders consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law;

 

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permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership;

 

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provides that our general partner shall not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith, meaning our general partner believed that the decision was in the best interests of the partnership;

 

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generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the audit committee of the board of directors of our general partner acting as a conflicts committee, and not involving a vote of our unitholders, must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous to us; and

 

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provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable

 

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judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct.

By purchasing a common unit, a unitholder will become bound by the provisions of our partnership agreement, including the provisions described above.

Our general partner and its affiliates may have conflicts of interest with us, and their limited fiduciary duties to our unitholders may permit them to favor their own interests to the detriment of our unitholders.

Following this offering and the Contribution, WCC will own common units representing an approximately 61% limited partner interest in us on a fully diluted basis and 100% of our general partner, which owns all of our outstanding 35,291 general partner units and incentive distribution rights. Although our general partner has a duty to manage us in a manner that is in the best interests of our partnership and our unitholders, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owners. Furthermore, since certain executive officers and directors of our general partner are executive officers or directors of affiliates of our general partner, conflicts of interest may arise between WCC and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. The risk to our unitholders due to such conflicts may arise because of the following factors, among others:

 

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our general partner is allowed to take into account the interests of parties other than us, such as WCC, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;

 

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neither our partnership agreement nor any other agreement requires owners of our general partner to pursue a business strategy that favors us. Executive officers and directors of our general partner’s owners have a fiduciary duty to make these decisions in the best interest of their owners, which may be contrary to our interests;

 

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our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings and issuances of additional partnership securities and reserves, each of which can affect our financial condition;

 

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our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

 

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our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf;

 

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our general partner intends to limit its liability regarding our contractual and other obligations;

 

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our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of our common units which could cause unitholders to sell units at a time and price that may not be desirable;

 

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our general partner controls the enforcement of obligations owed to us by it and its affiliates; and

 

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our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

In addition, WCC currently holds substantial interests in other companies in the energy and natural resource sectors. Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership interest in us. However, WCC is not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. As a result, WCC could compete with us for acquisition opportunities and for new business or extensions of the existing services provided by us.

 

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Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers, directors and owners. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders.

For more information, please read “—Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duties.”

Our unitholders have limited voting rights, are not entitled to elect our general partner or its directors and have limited ability to remove our general partner without its consent.

Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our unitholders have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is chosen entirely by its members and not by our unitholders. Furthermore, if our unitholders are dissatisfied with the performance of our general partner, they have limited ability to remove our general partner.

Our unitholders are currently unable to remove our general partner without its consent because affiliates of our general partner own sufficient units to be able to prevent removal of our general partner. The vote of the holders of at least 80% of all outstanding common units is required to remove our general partner. Our general partner owns 0.6% of our common units and, following the Contribution and the completion of this offering, WCC will own              common units and              Series A Convertible Units, collectively representing an approximately 61% limited partner interest in us.

The control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest in us to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the members of our general partner to transfer their respective membership interests in our general partner to a third party. The new members of our general partner would then be in a position to replace the board of directors and executive officers of our general partner with their own choices and to control the decisions and actions of the board of directors and executive officers of our general partner.

The incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights.

 

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Our general partner has a limited call right that may require our unitholders to sell their common units at an undesirable time or price.

At any time that our general partner and its affiliates own more than 80.0% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than the then-current market price. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Our unitholders may also incur a tax liability upon a sale of their common units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its limited call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the common units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). We expect that after this offering, and assuming consummation of the Contribution, WCC will own in excess of 80% of our common units on a fully diluted basis after giving effect to the conversion of the Series A Convertible Units, and therefore be able to exercise the limited call right.

We may issue additional units without unitholder approval, which would dilute unitholder interests.

At any time, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Further, our partnership agreement does not prohibit the issuance of equity securities that may effectively rank senior to our common units. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

 

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our unitholders’ proportionate ownership interest in us will decrease;

 

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the amount of cash available for distribution on each unit may decrease;

 

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the relative voting strength of each previously outstanding unit may be diminished; and

 

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the market price of the common units may decline.

Our general partner may, without unitholder approval, elect to cause us to issue common units and general partner units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights.

Our general partner has the right, at any time when it has received distributions on its incentive distribution rights at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units and general partner units. The number of common units to be issued to our general partner will be equal to that number of common units that would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. Our general partner will be issued the number of general partner units necessary to maintain our general partner’s interest in us that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive

 

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distributions on its incentive distribution rights based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units and general partner units to our general partner in connection with resetting the target distribution levels.

The market price of our common units could be impacted by sales of substantial amounts of our common units in the public markets, including sales by our existing unitholders.

A unitholder may sell some or all of our common units that it owns or it may distribute our common units to the holders of its equity interests and those holders may dispose of some or all of these units. The sale or disposition of a substantial number of our common units in the public markets could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. We do not know whether any such sales would be made in the public market or in private placements, nor do we know what impact such potential or actual sales would have on our unit price in the future.

An increase in interest rates may cause the market price of our common units to decline.

Like all equity investments, an investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly-traded limited partnership interests. Reduced demand for our common units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline.

We must pay fees to and reimburse our general partner and its affiliates for services provided, which will reduce our cash available for distributions.

On March 13, 2015, we entered into a new services agreement (the “Services Agreement”) with our general partner to replace our prior services agreement. Under the Services Agreement, our general partner will continue providing administrative, engineering, operating and other services to the Partnership for a fixed annual fee of $500,000 for certain administrative services plus reimbursement at cost for other expenses and expenditures. The term of the Agreement expires on December 31, 2015, and automatically renews for successive one-year periods unless terminated. The reimbursement to our general partner for such expenses will be determined by our general partner in accordance with the terms of our partnership agreement and as provided under the Services Agreement. In determining the costs and expenses allocable to us, our general partner is subject to its fiduciary duty, as modified by our partnership agreement, to the limited partners, which requires it to act in good faith. These expenses include all costs incurred by our general partner and its affiliates in managing and operating us. We are managed and operated by executive officers and directors of our general partner. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce our cash available for distributions.

Our unitholders may have liability to repay distributions.

Under certain circumstances, our unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that, for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Purchasers of units who become limited partners are liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to the purchaser of units at the time it became a limited partner and for unknown obligations if the liabilities could be

 

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determined from our partnership agreement. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

Common units held by unitholders who are not eligible citizens will be subject to redemption.

Our general partner may require each limited partner to furnish information about its nationality, citizenship or related status. If a limited partner fails to furnish information about its nationality, citizenship or other related status within 30 days after a request for the information or our general partner determines after receipt of the information that the limited partner is not an eligible citizen, the limited partner may be treated as a non-citizen assignee. A non-citizen assignee does not have the right to direct the voting of units and may not receive distributions in kind upon our liquidation. Furthermore, we have the right to redeem all of the common units of any holder that is not an eligible citizen or fails to furnish the requested information. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Please read “The Partnership Agreement—Non-Citizen Assignees; Redemption.”

Tax Risks to Common Unitholders

In addition to reading the following risk factors, please read “Material U.S. Federal Income Tax Consequences” for a more complete discussion of the expected material U.S. federal income tax consequences of owning and disposing of common units.

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our being subject to minimal entity-level taxation by individual states. If the Internal Revenue Service, or IRS, were to treat us as a corporation for federal income tax purposes, or we become subject to a material amount of entity-level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to our unitholders.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we will be treated as a corporation, the IRS could disagree with the positions we take or a change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state and local income tax at varying rates. Distributions to a unitholder would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to the unitholder. Because a tax would be imposed upon us as a corporation, our cash available for distribution to a unitholder would be substantially reduced. Therefore, if we were treated as a corporation for federal tax purposes there could be a material reduction in the anticipated cash flow and after-tax return to a unitholder, likely causing a substantial reduction in the value of our common units.

We are subject to extensive tax laws and regulations, with respect to federal, state and foreign income taxes and transactional taxes such as excise, sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Further, changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income,

 

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franchise and other forms of taxation. For example, Pennsylvania may assess a partnership level tax if the partnership is found to have underreported income by more than $1,000,000 in any tax year. Imposition of any such taxes could adversely affect our cash available for distribution to unitholders.

Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Moreover, any such modification could make it more difficult or impossible for us to meet the exception that allows publicly traded partnerships that generate qualifying income to be treated as partnerships (rather than corporations) for federal income tax purposes, affect or cause us to change our business activities, or affect the tax consequences of an investment in our common units. For example, President Obama’s administration budget proposal for fiscal year 2016 (the “Budget Proposal”) recommends that certain publicly traded partnerships, including WMLP, earning income from activities related to fossil fuels be taxed as corporations. From time to time, members of the U.S. Congress have proposed and considered substantive changes to the existing federal income tax laws that would affect the tax treatment of certain publicly traded partnerships. We are unable to predict whether any of these changes, or any other proposals, will ultimately be enacted. Any changes could negatively impact the value of an investment in our common units.

Certain federal income tax preferences currently available with respect to coal exploration and development may be eliminated in future legislation.

Among the changes contained in the Budget Proposal is the elimination of certain key U.S. federal income tax preferences relating to coal exploration and development. The Budget Proposal would: (i) eliminate all current deductions, the 60-month amortization period and the 10-year amortization period for exploration and development costs relating to coal and other hard mineral fossil fuels, (ii) repeal the percentage depletion allowance with respect to coal properties, (iii) repeal capital gains treatment of coal and lignite royalties and (iv) exclude from the definition of domestic production gross receipts all gross receipts derived from the production of coal and other hard mineral fossil fuels. The passage of any legislation effecting changes similar to those in the Budget Proposal in federal income tax laws could eliminate certain tax deductions that are currently available with respect to coal exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our common units.

If tax authorities contest the tax positions we take, the market for our common units could be adversely impacted, and the cost of any contest with a tax authority would reduce our cash available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. Tax authorities may adopt positions that differ from the positions we take, and a tax authority’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with a tax authority, and the outcome of any such contest, may increase a unitholder’s tax liability and result in adjustment to items unrelated to us and could materially and adversely impact the market for our common units and the price at which they trade. The rights of a unitholder owning less than a 1% profits interest in us to participate in the federal income tax audit process are very limited.

 

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In addition, our costs of any contest with any tax authority will be borne indirectly by our unitholders and our general partner because such costs will reduce our cash available for distribution.

Our unitholders may be required to pay taxes on income from us even if the unitholders do not receive any cash distributions from us.

Because a unitholder is treated as a partner to whom we allocate taxable income which could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income is taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes on the unitholder’s share of our taxable income even if it receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the tax liability that results from that income.

Certain actions that we may take, such as issuing additional units, may increase the federal income tax liability of unitholders.

In the event we issue additional units or engage in certain other transactions in the future, the allocable share of nonrecourse liabilities allocated to the unitholders will be recalculated to take into account our issuance of any additional units. Any reduction in a unitholder’s share of our nonrecourse liabilities will be treated as a distribution of cash to that unitholder and will result in a corresponding tax basis reduction in a unitholder’s units. A deemed cash distribution may, under certain circumstances, result in the recognition of taxable gain by a unitholder, to the extent that the deemed cash distribution exceeds such unitholder’s tax basis in its units.

In addition, the federal income tax liability of a unitholder could be increased if we dispose of assets or make a future offering of units and use the proceeds in a manner that does not produce substantial additional deductions, such as to repay indebtedness currently outstanding or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate currently applicable to the our assets.

Tax gain or loss on the disposition of common units could be more or less than expected.

If a unitholder sells its common units, the unitholder will recognize a gain or loss equal to the difference between the amount realized and the unitholder’s tax basis in those common units. Because distributions to a unitholder in excess of the total net taxable income allocated to it for a common unit decrease its tax basis in that common unit, the amount, if any, of such prior excess distributions with respect to the units sold will, in effect, become taxable income to the unitholder if the common unit is sold at a price greater than its tax basis in that common unit, even if the price is less than the original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation and depletion recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sells its common units, the unitholder may incur a tax liability in excess of the amount of cash the unitholder receives from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as individual retirement accounts, or IRAs, other retirement plans and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income, which may be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file federal tax returns and pay tax on their share of our taxable income. If a unitholder is a tax-exempt entity or a non-U.S. person, the unitholder should consult its tax advisor before investing in our common units.

 

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We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. Our tax counsel is unable to opine as to the validity of such filing positions. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to the unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of common units or result in audit adjustments to unitholders’ tax returns.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. Although the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, such regulations are not final and do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Our tax counsel has not rendered an opinion with respect to whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations.

A unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of the loaned common units, the unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Our tax counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to effect a short sale of common units. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and lending their common units.

We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between our general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional common units or engage in certain other transactions, we determine the fair value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, subsequent purchasers of common units may

 

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have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our general partner and certain of the unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated as a partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination, among other things, would result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedule K-1s if relief from the IRS was not granted, as described below) for one calendar year. Our termination could also result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in its taxable income for the year of termination. Under current law, such a termination would not affect our classification as a partnership for federal income tax purposes, but instead, after our termination, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has announced a relief procedure for publicly traded partnerships that terminate in this manner, whereby if a publicly traded partnership that has terminated requests and the IRS grants special relief, among other things, we will only have to provide one Schedule K-1 to unitholders for the year, notwithstanding two partnership tax years resulting from the termination.

Unitholders may be subject to state and local taxes and return filing requirements in states and localities where they do not reside or own properties.

In addition to federal income taxes, unitholders may be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property now or in the future, even if the unitholders do not live in any of those jurisdictions. Unitholders may be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own assets or do business in additional states that impose a personal income tax or an entity level tax. It is each unitholder’s responsibility to file all federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the state, local or non-U.S. tax consequences of an investment in common units.

Some of the states in which we do business or own property may require us to, or we may elect to, withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the state generally, does not relieve the nonresident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us.

 

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THE CONTRIBUTION

On June 1, 2015, we entered into the Contribution Agreement with WCC, pursuant to which, upon satisfaction or waiver of the conditions set forth in the Contribution Agreement, WCC will make the Contribution to us of the Kemmerer Interests. Upon closing the Contribution, we will own 100% of the outstanding equity interests in Kemmerer. We expect the Contribution to significantly expand the size of our production base, diversify the customers we serve and improve the stability of our cash flows by increasing the average remaining term of our long-term supply contracts from 3.2 years to 5.8 years.

The Contribution Consideration will be approximately $230 million, to be paid in a combination of cash, up to $20 million in common units and up to $75 million in Series A Convertible Units. The aggregate number of common units and Series A Convertible Units to be issued as part of the Contribution Consideration will be determined based on the greater of (i) the volume weighted average price of our common units on the NYSE over the ten-business day period ending on the last business day prior to June 1, 2015, multiplied by 90%, and (ii) the public offering price of the common units in this offering. Following the Contribution and the completion of this offering, WCC will own approximately 61% of our common units on a fully diluted basis. We expect to close the Contribution in the third quarter of 2015. The closing of the Contribution is conditioned on, among other things, the receipt by us of at least $65 million in net proceeds from this offering. However, the closing of this offering is not conditioned on the closing of the Contribution.

In connection with our entry into the Contribution Agreement and the issuance of the Series A Convertible Units, we will enter into the Amendment to our partnership agreement. The Amendment will establish the terms of the Series A Convertible Units and any additional Series A PIK Units, and will provide that each Series A Convertible Unit will have the right to share in distributions from us on a pro rata basis with the common units. All or any portion of the Series A Convertible Unit Distribution may, at our election, be paid in Series A PIK Units. To the extent any portion of the Series A Convertible Unit Distribution is paid in Series A PIK Units for any quarter, the distribution to the holders of incentive distribution rights shall be reduced by that portion of the distribution that is attributable to the payment of those Series A PIK Units, as further described in the Amendment. The Series A Convertible Units and the Series A PIK Units will convert into common units at the earlier of the first anniversary of the initial issuance of the Series A Convertible Units pursuant to the Contribution Agreement, the date on which we first make a regular quarterly cash distribution with respect to any quarter to holders of common units in an amount at least equal to $0.22 per common unit or upon a change of control. The Series A Convertible Units will have the same voting rights as if they were outstanding common units and will vote together with the common units as a single class. In addition, the Series A Convertible Units will be entitled to vote as a separate class on any matters that materially adversely affect the rights or preferences of the Series A Convertible Units in relation to other classes of partnership interests or as required by law.

The Kemmerer Mine supplies approximately 2.7 million tons per year to the adjacent 687 MW three unit Naughton Power Station in Wyoming, which is owned and operated by PacifiCorp. Unit 1 was commissioned in 1963 and Units 2 and 3 were added in 1968 and 1971, respectively. The Naughton Power Station is a base load plant that operates at a high capacity factor, with a monthly average capacity factor of approximately 86% over the past three years. Electrostatic precipitators and scrubbers are installed on all three units to control particulate emissions and sulfur-dioxide and are expected to keep the plant compliant with environmental rules. Coal is delivered along a 4,200-foot belt conveyor under a long-term sales agreement that expires in December 2021. Kemmerer also supplies approximately 1.7 million tons a year to various industrial customers through long-term contracts extending to 2026. Certain of the Kemmerer Mine reserves were contributed to WMLP from WCC as part of its acquisition of our general partner.

In 2014, Kemmerer produced 4.4 million tons of coal, supplying the adjacent Naughton Power Station as well as various industrial customers. The Naughton Power Station supplies power to the Mountain West region, which the U.S. Census Bureau has forecasted will grow at a rate of 17.6% between 2010 and 2020, and at a rate of 17.0% between 2020 and 2030. In addition to PacifiCorp, which owns the Naughton Power Station,

 

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Kemmerer’s industrial customers include Tata Chemicals North America Inc. and FMC Corporation, which are sources of steady and predictable demand. When combined with our existing operations, the addition of Kemmerer represents a 78% increase to our overall coal production as of December 31, 2014. Further, Kemmerer has long-term contracts that have a weighted-average remaining life of seven years. Many of these long life contracts also have varying levels of cost protection which help reduce the impact of external market conditions on Kemmerer’s margins and cash flows. Following WCC’s acquisition of Kemmerer in 2012, WCC management significantly enhanced its financial performance, driving strong improvements in productivity, costs and safety.

The following table provides additional information about the Kemmerer Mine as of December 31, 2014:

 

2014 Production		Proven Reserves				Probable Reserves				Total Proven and Probable Reserves				Permitted Reserves				Current Production Capacity				Total Tons Mined Since Inception				Year Current Complex Opened				Estimated Life of Permitted Reserves(1)				Delivery Method
		(thousands of tons)
4,399			85,430	(2)			8,867				94,297	(2)			35,577				7,000				184,266				1950	(3)			2025			Conveyor / Rail / Truck

 

(1)	Approximate year in which permitted reserves would be exhausted, based on current mine plan and production rates.

(2)	Reserve amounts shown include 29,226 of proven reserves currently leased by WKFCH to a subsidiary of WCC.

(3)	The Elkol Underground Mine opened in 1950 and the Sorenson Surface Operations opened in 1963. Tons mined since inception for the Kemmerer Mine are for tons mined from 1950 through 2014.

 

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USE OF PROCEEDS

We expect to receive net proceeds from this offering of approximately $         million (or approximately $         million if the underwriters’ option to purchase additional common units is exercised in full) after deducting underwriting discounts and commissions and estimated offering expenses payable by us.

We intend to use the net proceeds of this offering to pay a portion of the Contribution Consideration and for general partnership purposes. If the Contribution is not consummated, we intend to use the net proceeds from this offering to repay indebtedness outstanding under the 2014 Financing Agreement and for general partnership purposes. We may temporarily invest the net proceeds in short-term marketable securities until they are used for their stated purpose.

Borrowings under the 2014 Financing Agreement currently bear cash interest at a rate of 9.25% per annum and are scheduled to mature on December 31, 2018. The outstanding borrowings under the 2014 Financing Agreement were incurred to fund capital expenditures and to pay outstanding amounts under our prior credit facility, which we refinanced under the 2014 Financing Agreement.

 

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CAPITALIZATION

The following table shows:

 

•

our historical cash and long-term investments and capitalization as of March 31, 2015; and

 

•

our pro forma cash and long-term investments and capitalization as of March 31, 2015, as adjusted to reflect the investment of the net proceeds of this offering and the closing of the Contribution.

As adjusted amounts will vary from amounts set forth below depending on several factors, including differences from our estimate of fees and expenses.

This table is unaudited and should be read together with, and is qualified in its entirety by reference to, the historical and pro forma financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” as well as the financial statements and notes thereto contained in our filings with the Securities and Exchange Commission, or SEC.

 

		As of March 31, 2015
		Historical				Pro Forma As Adjusted
		(in thousands)
Cash		$	1,785			$	6,785
Long-term debt:
Revolving credit facility			—				5,000
Capital leases			33				15,931
Term loan facility			176,327				247,789
			176,360				268,720
Less current portion			(6	)			(3,447	)
Total long-term debt			176,354				265,273
Total net partners’ capital:
Common units—public			8,143				83,143
Common units—sponsor			21,185				9,428
Limited partner Series A Convertible Units			—				(44,090	)
General partner interest			33,409				32,884
Accumulated other comprehensive income			—				40
Total net partners’ capital			62,737				81,405
Total capitalization		$	239,091			$	346,678

 

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HOW WE MAKE CASH DISTRIBUTIONS

Distributions of Available Cash

General. Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute our available cash to unitholders of record on the applicable record date.

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.

There is no guarantee that we will distribute quarterly cash distributions to our unitholders. Our cash distribution policy is subject to certain restrictions and may be changed at any time. The reasons for such uncertainties in our stated cash distribution policy include the following factors:

 

•

Our cash distribution policy will be subject to restrictions on cash distributions under our 2014 Financing Agreement. Specifically, in order to make cash distributions to our unitholders, no event of default must exist or result from such distribution and, on a pro forma basis immediately after giving effect to such distribution, (x) our consolidated total net leverage ratio (as defined in the 2014 Financing Agreement ) must be less than or equal to 3.75:1.00 and (y) our fixed charge coverage ratio (as defined in the 2014 Financing Agreement) must be not less than 1.00:1.00, and (2) we must have liquidity of at least $5,000,000 immediately after giving effect to such distribution; provided that we may make cash distributions in an aggregate amount not to exceed $7,500,000 without being required to satisfy these ratios. Should we be unable to satisfy these restrictions included in our new credit facility or if we are otherwise in default under our new credit facility, we would be prohibited from making cash distributions notwithstanding our cash distribution policy.

 

•

Our general partner will have the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of or increase in those reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy.

 

•

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions contained therein, may be amended. Please read “The Partnership Agreement—Amendment of Our Partnership Agreement.”

 

•

Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.

 

•

Under Section 17-607 of the Delaware Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.

 

•

We may lack sufficient cash to pay distributions to our unitholders due to reduced revenues or increases in our operating costs, SG&A expenses, principal and interest payments on our outstanding debt and working capital requirements.

 

•

If we make distributions out of capital surplus, as opposed to operating surplus, any such distributions would constitute a return of capital and would result in a reduction in the minimum quarterly distribution and the target distribution levels. Please read “How We Make Cash Distributions—Distributions from Capital Surplus.” We do not anticipate that we will make any distributions from capital surplus.

Definition of Available Cash. Available cash generally means, for any quarter, all cash on hand at the end of the quarter:

 

•

less the amount of cash reserves established by our general partner at the date of determination of available cash for the quarter to:

 

•

provide for the proper conduct of our business (including reserves for our future capital expenditures and anticipated future credit needs subsequent to that quarter);

 

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•

comply with applicable law, any of our debt instruments or other agreements; and

 

•

provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters;

 

•

plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.

The purpose and effect of the last bullet point above is to allow our general partner, if it so decides, to use cash from working capital borrowings made after the end of the quarter but on or before the date of determination of available cash for that quarter to pay distributions to unitholders. Under our partnership agreement, working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely to pay distributions to partners and with the intent of the borrower to repay such borrowings within 12 months other than from additional working capital borrowings. If a working capital borrowing, which increases operating surplus, is not repaid during the twelve-month period following the borrowing, it will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowing is in fact repaid, it will not be treated as a further reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

Minimum Quarterly Distribution. Our partnership agreement provides for a minimum quarterly distribution to the holders of our common units of $0.1333 per unit, or $0.5332 per unit on an annualized basis, to the extent we have sufficient cash from our operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. Even if our cash distribution policy as reflected in the partnership agreement is not modified or revoked, the amount of distributions paid under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.

General Partner Interest and Incentive Distribution Rights. As of the date of this prospectus, our general partner is entitled to 0.6% of all quarterly distributions that we make prior to our liquidation. This general partner interest is represented by 35,291 general partner units as of March 31, 2015. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us in order to maintain its current general partner interest. Our general partner’s 0.6% interest in our distributions may be reduced if we issue additional limited partner units in the future and our general partner does not contribute a proportionate amount of capital to us in order to maintain its 0.6% general partner interest. Our general partner does not intend to make such a proportionate contribution to maintain its interest in connection with this offering.

Our general partner also holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 48.0%, of the cash we distribute from operating surplus (as defined below) in excess of $0.1333 per unit per quarter. The maximum distribution of 48.0% does not include any distributions that our general partner may receive on common units, Series A Convertible Units or general partner units that it owns.

Operating Surplus and Capital Surplus

Overview

All cash distributed to unitholders is characterized as either being paid from “operating surplus” or “capital surplus.” We treat distributions of available cash from operating surplus differently than distributions of available cash from capital surplus.

Definition of Operating Surplus. For any period operating surplus generally means:

 

•

$12.5 million (as described below); plus

 

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•

all of our cash receipts after December 31, 2014, the date of the closing of the Initial Kemmerer Contribution, excluding cash from interim capital transactions (as defined below); plus

 

•

working capital borrowings made after the end of a quarter but on or before the date of determination of operating surplus for that quarter; plus

 

•

cash distributions paid on equity issued (including incremental distributions on incentive distribution rights), other than equity issued on the closing date of our initial public offering (“IPO”), to finance all or a portion of expansion capital expenditures in respect of the period from such financing until the earlier to occur of the date the capital asset commences commercial service and the date that it is abandoned or disposed of; plus

 

•

cash distributions paid on equity issued by us (including incremental distributions on incentive distribution rights) to pay the interest on debt incurred, or to pay distributions on equity issued, to finance the expansion capital expenditures referred to above, in each case in respect of the period from such financing until the earlier to occur of the date the capital asset commences commercial service and the date that it is abandoned or disposed of; less

 

•

all of our operating expenditures (as defined below) after the closing of the Initial Kemmerer Contribution; less

 

•

the amount of cash reserves established by our general partner prior to the date of determination of available cash to provide funds for future operating expenditures; less

 

•

all working capital borrowings not repaid within 12 months after having been incurred, or repaid within such 12-month period with the proceeds of additional working capital borrowings; less

 

•

any cash loss realized on disposition of an investment capital expenditure.

As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders. For example, it includes a provision that enables us, if we choose, to distribute as operating surplus up to $12.5 million of cash we receive from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus.

We define interim capital transactions as (i) borrowings, refinancings or refundings of indebtedness other than working capital borrowings, (ii) sales of equity securities, (iii) sales or other dispositions of assets outside the ordinary course of business, (iv) capital contributions received, (v) corporate reorganizations or restructurings and (vi) the termination of interest rate hedge contracts or commodity hedge contracts prior to the termination date specified therein (provided that cash receipts from any such termination will be included in operating surplus in equal quarterly installments over the remaining scheduled life of the contract).

We define operating expenditures as the sum of (i) estimated reserve replacement expenditures and (ii) all of our cash expenditures, including, but not limited to, taxes, employee and director compensation, reimbursements of expenses to our general partner, repayments of working capital borrowings, debt service payments, reclamation expenses, payments made in the ordinary course of business under interest rate hedge contracts and commodity hedge contracts and actual maintenance capital expenditures other than actual reserve replacement expenditures (as discussed in further detail below), provided that operating expenditures will not include:

 

•

repayments of working capital borrowings where such borrowings have previously been deemed to have been repaid (as described above);

 

•

payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness other than working capital borrowings;

 

•

expansion capital expenditures;

 

•

investment capital expenditures;

 

•

payment of transaction expenses (including taxes) relating to interim capital transactions;

 

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•

distributions to partners;

 

•

actual reserve replacement expenditures; or

 

•

non-pro rata repurchases of partnership interests made with the proceeds of an interim capital transaction.

Capital Expenditures. Maintenance capital expenditures are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain, including over the long term, our operating capacity, asset base or operating income. Our partnership agreement divides maintenance capital expenditures into two categories—reserve replacement expenditures and other maintenance capital expenditures. Examples of reserve replacement expenditures include cash expenditures for the purchase of fee interests in coal reserves and cash expenditures for advance royalties with respect to the acquisition of leasehold interests in coal reserves to the extent of replacing reserves. Examples of other maintenance capital expenditures include capital expenditures associated with the repair, refurbishment and replacement of equipment.

Because our reserve replacement expenditures can be irregular, the amount of our actual reserve replacement expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus and cash available for distribution to our unitholders if we subtracted actual reserve replacement expenditures from operating surplus.

Our partnership agreement requires that an estimate of the average quarterly reserve replacement expenditures and the actual amount of other maintenance capital expenditures be subtracted from operating surplus each quarter. The amount of estimated reserve replacement expenditures deducted from operating surplus for those periods is determined by the board of directors of our general partner at least once a year, subject to approval by the Conflicts Committee. The estimate is made annually and whenever an event occurs that is likely to result in a material adjustment to the amount of our reserve replacement expenditures on a long-term basis. For purposes of calculating operating surplus (other than when used to determine whether the subordination period has ended), any adjustment to this estimate is prospective only.

The use of estimated reserve replacement expenditures in calculating operating surplus has the following effects:

 

•

it reduces the risk that reserve replacement expenditures in any one quarter will be large enough to render operating surplus less than the minimum quarterly distribution to be paid on all the units for the quarter and subsequent quarters;

 

•

it increases our ability to distribute as operating surplus cash we receive from non-operating sources; and

 

•

it is more difficult for us to raise our distribution above the minimum quarterly distribution and pay incentive distributions on the incentive distribution rights held by our general partner.

Expansion capital expenditures are cash expenditures incurred for acquisitions or capital improvements and do not include maintenance capital expenditures or investment capital expenditures. Expansion capital expenditures include interest payments (and related fees) on debt incurred to finance the construction, acquisition or development of an improvement to our capital assets and paid in respect of the period beginning on the date that we enter into a binding obligation to commence construction, acquisition or development of the capital improvement and ending on the earlier to occur of the date that such capital improvement commences commercial service and the date that such capital improvement is abandoned or disposed of. Examples of expansion capital expenditures include the acquisition of reserves, equipment or a new mine or the expansion of an existing mine, to the extent such capital expenditures are expected to expand our long-term operating capacity, asset base or operating income.

 

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Investment capital expenditures are those capital expenditures that are neither maintenance capital expenditures nor expansion capital expenditures. Investment capital expenditures largely consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of a capital asset for investment purposes or development of facilities that are in excess of the maintenance of our existing operating capacity or operating income, but which are not expected to expand, for more than the short term, our operating capacity or operating income.

Capital expenditures that are made in part for two or more purposes consisting of maintenance capital purposes, investment capital purposes or expansion capital purposes will be allocated as maintenance capital expenditures, investment capital expenditures or expansion capital expenditures by our general partner.

Liquidation Units

In connection with the amendment and restatement of our partnership agreement in December 2014, all of the then outstanding subordinated units in our partnership were converted into liquidation units, with every 12 then-outstanding subordinated units becoming one liquidation unit.

The conversion of the subordinated units into liquidation units is intended to eliminate the subordinated units while preserving the capital account associated with those units. The capital account associated with those units is being preserved to avoid having the value associated with that capital account being transferred to the other unitholders in a way that would cause the other unitholders to be taxed on the receipt of that value.

Under our partnership agreement, certain allocations will be made to eliminate the capital account associated with the liquidation units over time. Until the capital account balance of the liquidation units is zero, an item of deduction will be allocated to the holders of liquidation units each year up to a maximum of 5% of the capital account balance. In addition, upon certain revaluation events, after making allocations of loss to the general partner and the unitholders in a manner intended to offset in reverse order the allocations of revaluation gains that have previously been allocated, we will first allocate any loss to holders of liquidation units in proportion to the positive balances in their capital accounts until the capital accounts of the liquidation unitholders have been reduced to zero before allocating any remaining loss pro rata among our general partner and our common unitholders and, following the Contribution, Series A Convertible Unit holders.

General Partner Interest and Incentive Distribution Rights

Our partnership agreement provides that our general partner is entitled to 0.6% of all distributions that we make prior to our liquidation with respect to its general partner units. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us in order to maintain its 0.6% general partner interest if we issue additional units. Our general partner’s 0.6% interest, and the percentage of our cash distributions to which it is entitled from such 0.6% interest, will be proportionately reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us in order to maintain its 0.6% general partner interest.

Incentive distribution rights represent the right to receive an increasing percentage (13.0%, 23.0% and 48.0%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement.

The following discussion assumes that our general partner maintains its 0.6% general partner interest and that our general partner continues to own the incentive distribution rights.

 

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If, for any quarter, we have distributed available cash from operating surplus to the unitholders in an amount equal to the minimum quarterly distribution, then we will distribute any additional available cash from operating surplus for that quarter among the holders of our common units and our general partner in the following manner:

 

•

first, 99.4% to all holders of our common units, pro rata, and 0.6% to our general partner, until each unitholder receives a total of $0.1533 per unit for that quarter (the “first target distribution”);

 

•

second, 86.4% to all holders of our common units, pro rata, and 13.6% to our general partner, until each unitholder receives a total of $0.1667 per unit for that quarter (the “second target distribution”);

 

•

third, 76.4% to all holders of our common units, pro rata, and 23.6% to our general partner, until each unitholder receives a total of $0.2000 per unit for that quarter (the “third target distribution”); and

 

•

thereafter, 51.4% to all holders of our common units, pro rata, and 48.6% to our general partner.

However, our partnership agreement provides that our general partner will suspend distributions on its incentive distribution rights for six quarters following the closing of the Initial Kemmerer Contribution, provided that such suspension may be reduced to no less than three quarters if, during the suspension period, additional drop-down asset acquisition transactions aggregating greater than $35 million in value are undertaken by WCC or its affiliates, acting through our general partner, that are reasonably expected to provide accretion to per unit common unitholder distributions. We expect that the Contribution will qualify as such a transaction and will result in the termination of the distribution suspension beginning after the quarter ending September 30, 2015.

Percentage Allocations of Available Cash from Operating Surplus

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of the unitholders and our general partner in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit Target Amount.” The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 0.6% general partner interest, our general partner has contributed any additional capital necessary to maintain its 0.6% general partner interest and our general partner has not transferred its incentive distribution rights.

 

		Total Quarterly Distribution Per Unit Target Amount								Marginal Percentage Interest in Distributions
										Unitholders				General Partner
Minimum Quarterly Distribution			$0.1333								99.4	%			0.6	%
First Target Distribution			above $0.1333			up to $	0.1533				99.4	%			0.6	%
Second Target Distribution			above $0.1533			up to $	0.1667				86.4	%			13.6	%
Third Target Distribution			above $0.1667			up to $	0.2000				76.4	%			23.6	%
Thereafter			above $0.2000								51.4	%			48.6	%

General Partner’s Right to Reset Incentive Distribution Levels

Our general partner, as the holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial cash target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and cash target distribution levels upon which the incentive distribution payments to our general partner would be set. If our general partner transfers all or a portion of our incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. The following discussion assumes that our general partner holds all of the incentive distribution rights at the time that a reset

 

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election is made. The right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions are based may be exercised, without approval of our unitholders or the Conflicts Committee, at any time when we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for each of the prior four consecutive fiscal quarters. If our general partner and its affiliates are not the holders of a majority of the incentive distribution rights at the time an election is made to reset the minimum quarterly distribution amount and the target distribution levels, then the proposed reset shall be subject to the prior written concurrence of the general partner that the conditions described above have been satisfied. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that there will be no incentive distributions paid under the reset target distribution levels until cash distributions per unit following this event increase as described below. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to our general partner.

In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target cash distributions prior to the reset, our general partner will be entitled to receive a number of newly issued common units and general partner units based on a predetermined formula described below that takes into account the “cash parity” value of the average cash distributions related to the incentive distribution rights received by our general partner for the two quarters prior to the reset event as compared to the average cash distributions per common unit during that two-quarter period. Our general partner will be issued the number of general partner units necessary to maintain our general partner’s interest in us immediately prior to the reset election.

The number of common units that our general partner would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to the quotient determined by dividing (i) the average aggregate amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election by (ii) the average of the amount of cash distributed per common unit during each quarter in that two-quarter period.

Following a reset election, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per unit for the two fiscal quarters immediately preceding the reset election (which amount we refer to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to be correspondingly higher such that we would distribute all of our available cash from operating surplus for each quarter thereafter as follows:

 

•

first, 99.4% to all unitholders, pro rata, and 0.6% to our general partner, until each unitholder receives an amount equal to 115.0% of the reset minimum quarterly distribution for that quarter;

 

•

second, 86.4% to all unitholders, pro rata, and 13.6% to our general partner, until each unitholder receives an amount per unit equal to 125.0% of the reset minimum quarterly distribution for the quarter;

 

•

third, 76.4% to all unitholders, pro rata, and 23.6% to our general partner, until each unitholder receives an amount per unit equal to 150.0% of the reset minimum quarterly distribution for the quarter; and

 

•

thereafter, 51.4% to all unitholders, pro rata, and 48.6% to our general partner.

Our general partner will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the prior four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.

 

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Distributions from Capital Surplus

How Distributions from Capital Surplus Are Made. We make distributions of available cash from capital surplus, if any, in the following manner:

 

•

first, 100.0% to our general partner and all unitholders, pro rata, until the minimum quarterly distribution has been reduced to zero; and

 

•

thereafter, 100% shall be distributed as if it were operating surplus.

Effect of a Distribution from Capital Surplus. Our partnership agreement treats a distribution of capital surplus as the repayment of our then market price, which is a return of capital. Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the capital surplus distribution bears to our then market price. Because distributions of capital surplus will reduce the minimum quarterly distribution, after any of these distributions are made, it may be easier for our general partner to receive incentive distributions. However, any distribution of capital surplus before the unrecovered IPO price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution.

Once we distribute capital surplus equal to our then market price, we will reduce the minimum quarterly distribution and the target distribution levels to zero. We will then make all future distributions from operating surplus, with 51.4% being paid to the unitholders, pro rata, and 48.6% to our general partner. The percentage interests shown for our general partner include its 0.6% general partner interest and assume that our general partner has not transferred the incentive distribution rights.

We have not made and do not anticipate making any distributions from capital surplus.

Adjustment to Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:

 

•

the minimum quarterly distribution; and

 

•

the target distribution levels.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution and each target distribution level would each be reduced to 50% of its initial level. We will not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if legislation is enacted or if existing law is modified or interpreted by a governmental authority, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels for each quarter may be reduced by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter and the denominator of which is the sum of available cash for that quarter plus our general partner’s estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.

Distributions of Cash Upon Liquidation

General. If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and our general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

 

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Allocations for Capital Account Purposes

Manner of Adjustments for Gain. The manner of the adjustment for gain is set forth in our partnership agreement. If our liquidation occurs, we will allocate any gain to our partners in the following manner:

 

•

first, to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;

 

•

second, 99.4% to the common unitholders, pro rata, and 0.6% to our general partner, until the capital account for each common unit is equal to the sum of: (1) the unrecovered price per unit for the common units issued to WCC in connection with the Initial Kemmerer Contribution; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs that has not yet been paid for that quarter (the “Unpaid MQD”);

 

•

third, 99.4% to all unitholders, pro rata, and 0.6% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit for each quarter since the closing of the Initial Kemmerer Contribution over the Unpaid MQD; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 99.4% to the unitholders, pro rata, and 0.6% to our general partner, for each quarter since the closing of the Initial Kemmerer Contribution;

 

•

fourth, 86.4% to all unitholders, pro rata, and 13.6% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter since the closing of the Initial Kemmerer Contribution; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 86.4% to the unitholders, pro rata, and 13.6% to our general partner for each quarter since the closing of the Initial Kemmerer Contribution;

 

•

fifth, 76.4% to all unitholders, pro rata, and 23.6% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter since the closing of the Initial Kemmerer Contribution; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 76.4% to the unitholders, pro rata, and 23.6% to our general partner for each quarter since the closing of the Initial Kemmerer Contribution; and

 

•

thereafter, 51.4% to all unitholders, pro rata, and 48.6% to our general partner.

The percentages set forth above are based on the assumption that our general partner has not transferred its incentive distribution rights and that we do not issue additional classes of equity securities.

Manner of Adjustments for Losses. If our liquidation occurs, after making allocations of loss to the general partner and the unitholders in a manner intended to offset in reverse order the allocations of gains that have previously been allocated, we will generally allocate any loss to our general partner and unitholders in the following manner:

 

•

first, 100% to the holders of liquidation units in proportion to the positive balances in their capital accounts until the capital accounts of the liquidation unitholders have been reduced to zero; and

 

•

second, 99.4% to the holders of common units in proportion to the positive balances in their capital accounts and 0.6% to our general partner, until the capital accounts of the common unitholders have been reduced to zero; and

 

•

thereafter, 100.0% to our general partner.

 

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Adjustments to Capital Accounts. Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for tax purposes, unrecognized gain resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units as a result of such gain, our partnership agreement requires that we generally allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the partners’ capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made. By contrast to the allocations of gain, and except as provided above, we generally allocate any unrealized and unrecognized loss resulting from the adjustments to capital accounts upon the issuance of additional units to the unitholders and our general partner, after making allocations of loss to offset in reverse order the allocations of revaluation gain that have previously been allocated, in the same manner as we allocate loss upon liquidation. In the event we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner designed to result, to the extent possible, in our unitholders’ capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made.

 

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PRICE RANGE OF OUR COMMON UNITS AND DISTRIBUTIONS

Our common units are traded on the NYSE under the symbol “WMLP”. As of May 29, 2015, we had 5,711,630 common units outstanding and eight unitholders of record of our common units. On May 29, 2015 the closing price of our common units, as reported on the NYSE, was $10.50. The following table sets forth, for the periods indicated, the high and low sale prices of our common units, as reported on the NYSE, and the distributions paid by us with respect to those periods. On December 31, 2014, we effected a 12-to-1 reverse split of our common and general partnership units. Price data has been adjusted to give effect to the reverse split.

 

2013		High				Low				Distributions
First quarter		$	58.66			$	20.26				—
Second quarter		$	33.12			$	20.16				—
Third quarter		$	27.46			$	18.24				—
Fourth quarter		$	19.10			$	10.37				—
2014		High				Low				Distributions
First quarter		$	14.88			$	10.56				—
Second quarter		$	14.59			$	7.20				—
Third quarter		$	10.56			$	6.91				—
Fourth quarter		$	13.34			$	5.83				—
2015		High				Low				Distributions
First quarter(1)		$	12.74			$	8.42			$	0.20
Second quarter (through May 29, 2015)		$	12.23			$	10.22

 

(1)	We made a one-time special distribution to our public unitholders in January 2015, consisting of 0.2 million in additional post-reverse split common units.

 

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UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

The accompanying unaudited pro forma combined financial statements of Westmoreland Resource Partners, LP include the accounts and operations of the Partnership and its consolidated subsidiaries and are prepared in conformity U.S. GAAP. WCC’s cost of the GP Acquisition has been pushed-down to establish a new accounting basis for us beginning in the last minutes of the year ended December 31, 2014. Accordingly, the accompanying consolidated financial statements are presented for both our Predecessor and our Successor, corresponding to the accounting periods preceding and following the completion of the GP Acquisition. The summary historical consolidated financial information for our Successor as of December 31, 2014 and for the year then ended, and for our Predecessor for the period from January 1, 2014 to December 31, 2014, has been derived from our audited consolidated financial statements included in our 2014 Form 10-K, which is incorporated by reference into this prospectus. The summary historical financial information for Kemmerer as of the year ended December 31, 2014 has been derived from the audited financial statements of Kemmerer included elsewhere in this prospectus.

The columns with the heading “WRPS Pro Forma” present unaudited pro forma condensed combined financial information of WRPS (which consists of our Successor and Kemmerer) that gives effect to the following transactions as if they occurred as of January 1, 2014:

 

•

the issuance by the Partnership of             common units to the public in this offering;

 

•

the issuance by the Partnership of             common units to WCC as part of the Contribution Consideration;

 

•

the issuance by the Partnership of         Series A Convertible units to WCC as part of the Contribution Consideration;

 

•

the payment of estimated underwriting commissions and other offering expenses of $         million;

 

•

the net proceeds of $70.0 million received from deferred draw borrowings under our existing credit facility with interest at a variable rate per annum equal to, at our option, LIBOR (floor of 0.75% plus 8.5%) or the Reference Rate (as defined in the 2014 Financing Agreement). Additionally, the 2014 Financing Agreement also provides for “PIK Interest” at a variable rate per annum between 1.00% and 3.00% based on our Consolidated Total Net Leverage Ratio (as defined in the 2014 Financing Agreement);

 

•

our entry into an additional $15 million revolving credit facility;

 

•

the distribution to WCC of a portion of the net proceeds generated from this offering and borrowings under our credit facility as part of the Contribution Consideration; and

 

•

the retention of the assets and liabilities of Kemmerer, with the exception of the post-retirement medical benefits obligation, the pension obligations and the related deferred income tax assets.

The unaudited pro forma combined financial information of WRPS is presented for illustrative purposes only and may not be indicative of our financial position or results of operations that would have actually occurred had the Contribution and the other transactions listed above been completed at or as of the dates indicated, nor is it indicative of our future operating results or financial position.

The unaudited pro forma balance sheet and the pro forma statements of operations were derived by adjusting the historical combined financial statements of WRPS. The adjustments are based upon currently available information and certain estimates and assumptions; therefore, actual adjustments will differ from the pro forma adjustments. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma combined financial statements.

 

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The Contribution will be accounted for as business combination involving entities or businesses under common control, which is defined as a business combination in which all of the combining entities or businesses ultimately are controlled by the same party or parties both before and after the combination, and that control is not transitory. FASB ASC Topic 805, Business Combinations (the Transactions Between Entities Under Common Control Subsections of ASC Topic 805), provides guidance on accounting for common control transactions. When accounting for a transfer of assets or exchange of shares between entities under common control, the entity that receives the net assets or the equity interests should initially recognize the assets and liabilities transferred at their carrying amounts in the accounts of the transferring entity at the date of transfer. The contributed assets and liabilities of Kemmerer are reflected in the unaudited pro forma condensed combined financial information of WRPS at carrying value of Kemmerer at March 31, 2015.

We derived the information in the following tables from, and that information should be read together with and is qualified in its entirety by reference to, the historical and pro forma combined financial statements and the accompanying notes included elsewhere in this prospectus. The tables should be read together with such financial statements and notes thereto, and also with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The integration of Kemmerer in connection with the Contribution may not achieve the desired results. The unaudited pro forma condensed combined financial information of WRPS does not reflect the cost of any integration activities or expected benefits from the Cotnribution and synergies that may be derived from any integration activities, both of which may have a material effect on the consolidated results of operations in periods following the completion of the Contribution. Once the necessary due diligence has been completed, the final purchase prices have been determined and any purchase price adjustments have been completed, as applicable, actual results may differ materially from the information presented in the unaudited pro forma combined financial information of WRPS.

 

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WESTMORELAND RESOURCE PARTNERS SUCCESSOR

UNAUDITED PRO FORMA COMBINED BALANCE SHEET

March 31, 2015

(in thousands)

 

		Westmoreland Resource Partners, LP (Successor)				Westmoreland Kemmerer, Inc.				Adjustments						WRPS Pro Forma
ASSETS
Current assets:
Cash and cash equivalents		$	1,785			$	—			$	5,000			3		$	9,785
											70,000			2
											75,000			4
											(1,000	)		7
											(4,000	)		5,8
											(2,000	)		5,9
											(135,000	)		5
Accounts receivable:
Trade			23,560				14,827				(1,847	)		10			36,540
Other			116				72				—						188
Total accounts receivable			23,676				14,899				(1,847	)					36,728
Inventories			12,696				10,548				—						23,244
Deferred income taxes			—				856				(856	)		1			—
Prepaid expenses			2,637				1,894				—						4,531
Total current assets			40,794				28,197				5,297						74,288
Property, plant and equipment, at costs:
Land and mineral rights			72,993				21,301				—						94,294
Plant and equipment			133,949				122,544				—						256,493
			206,942				143,845				—						350,787
Less accumulated depreciation, depletion and amortization			(9,801	)			(39,390	)			—						(49,191	)
Net property, plant and equipment			197,141				104,455				—						301,596
Advance coal royalties			11,498				—				—						11,498
Restricted investments and bond collateral			9,534				25,692				—						35,226
Intangible assets, net of accumulated amortization			30,483				—				—						30,483
Deferred income taxes			—				16,075				(16,075	)		1			—
Other non-current assets			6,607				—				1,000			7			7,607
Total assets		$	296,057			$	174,419			$	(9,778	)				$	460,698

 

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WESTMORELAND RESOURCE PARTNERS SUCCESSOR

UNAUDITED PRO FORMA COMBINED BALANCE SHEET

March 31, 2015

(in thousands)

 

		Westmoreland Resource Partners, LP (Successor)				Westmoreland Kemmerer, Inc.				Adjustments								WRPS Pro Forma
LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)
Current liabilities:
Current installments of long-term debt		$	6			$	3,441			$	—							$	3,447
Accounts payable and accrued expenses:
Trade			19,469				12,206				(1,847	)			10				29,828
Deferred revenue			—				4,944				—								4,944
Production taxes			975				18,963				—								19,938
Accrued compensation			401				—				—								401
Postretirement medical benefits			—				436				(436	)			1				—
Asset retirement obligation			9,855				2,674				—								12,529
Other current liabilities			1,434				—				—								1,434
Total current liabilities			32,140				42,664				(2,283	)							72,521
Long-term debt, less current installments			176,354				13,394				70,000				2				265,273
											5,000				3
											525				12
Postretirement medical costs, less current portion			—				61,410				(61,410	)			1				—
Pension obligations			—				17,922				(17,922	)			1				—
Asset retirement obligation, less current portion			22,714				16,673				—								39,387
Warrants			1,952				—				—								1,952
Other liabilities			160				—				—								160
Total liabilities			233,320				152,063				(6,090	)							379,293
Partners capital (deficit):
Net sponsor investment			—				21,304				63,849				1				—
											(85,153	)			5
Limited partner units			29,328				—				75,000				4				92,571
											(11,757	)			5
Limited partner Series A Convertible Units			—				—				(44,090	)			5				(44,090	)
General partner units			33,409				—				(525	)			12				32,884
Accumulated other comprehensive income			—				1,052				(1,012	)			6				40
Noncontrolling interest			—				—				—								—
Total partners’ capital			62,737				22,356				(3,688	)							81,405
Total liabilities and partners’ capital (deficit)		$	296,057			$	174,419			$	(9,778	)						$	460,698

 

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WESTMORELAND RESOURCE PARTNERS SUCCESSOR

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS

(in thousands)

 

		For the Three Months Ended March 31, 2015
		Westmoreland Resource Partners, LP (Successor)				Westmoreland Kemmerer, Inc.				Adjustments								WRPS Pro Forma
Revenues:
Coal revenues		$	61,750			$	41,523			$	—							$	103,273
Royalty revenues			1,870				—				(1,847	)			10				23
Non-coal revenues			3,947				—				—								3,947
Total revenues			67,567				41,523				(1,847	)			10				107,243
Costs and expenses:
Cost of coal revenues (excluding depreciation, depletion and amortization)			54,651				31,022				(1,847	)							83,826
Cost of non-coal revenues			3,155				—				—								3,155
Depreciation, depletion and amortization			10,180				4,709				—								14,889
Selling and administrative			2,548				1,622				—								4,170
Loss on sale/disposal of assets			1,034				23				—								1,057
Restructuring charges			553				—				—								553
Total cost and expenses			72,121				37,376				(1,847	)							107,650
Operating income (loss)			(4,554	)			4,147				—								(407	)
Other (expense) income:
Interest expense			(5,780	)			(153	)			(525	)			12				(8,077	)
											(1,619	)			13
Interest income			—				369				—								369
Loss on debt extinguishment			—				—				—								—
Change in fair value of warrants			29				—				—								29
Other			—				92				—								92
Total other expenses			(5,751	)			308				(2,144	)							(7,587	)
Net income (loss) before income taxes			(10,305	)			4,455				(2,144	)							(7,994	)
Income tax expense			—				(338	)			338				11				—
Net (loss) income			(10,305	)			4,117				(1,806	)							(7,994	)
Less net (loss) income attributable to noncontrolling interest			—				—				—								—
Net (loss) income attributable to WMLP unitholders			(10,305	)			4,117				(1,806	)							(7,994	)
Less net (loss) income allocated to general partner			(63	)			4,117				(4,067	)			11				(13	)
Net income (loss) income allocated to limited partners		$	(10,242	)		$	—			$	2,261							$	(7,981	)
Net loss per limited partner unit-basic and diluted																		$	(0.36	)
Weighted-average limited partner units-basic and diluted																			14,922,187
Net loss per Class A limited partner unit-basic and diluted																		$	(0.36	)
Weighted-average Class A limited partner units-basic and diluted																			7,500,000
Net loss per general partner unit-basic and diluted																		$	(0.36	)
Weighted-average general partner unit-basic and diluted																			35,291

 

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WESTMORELAND RESOURCE PARTNERS SUCCESSOR

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS

(in thousands)

 

		For the Period of December 31, 2014				For the Year Ended December 31, 2014												For the Period January 1, 2014 to December 31, 2014
		Westmoreland Resource Partners, LP (Successor)				Westmoreland Kemmerer, Inc.				Adjustments				WRPS Pro Forma				Oxford Resource Partners LP (Predecessor)
Revenues:
Coal revenues		$	—			$	170,508			$	—			$	170,508			$	295,662
Royalty revenues			—				—				—				—				284
Non-coal revenues			—				—				—				—				26,317
Total revenues			—				170,508				—				170,508				322,263
Costs and expenses:
Cost of coal revenues (excluding depreciation, depletion and amortization)			—				118,691				—				118,691				258,575
Cost of non-coal revenues			—				—				—				—				1,700
Depreciation, depletion and amortization			—				16,912				—				16,912				39,315
Selling and administrative			—				5,335				—				5,335				20,510
Loss on sale/disposal of assets			—				309				—				309				(218	)
Restructuring charges			2,783				—				—				2,783				75
Total cost and expenses			2,783				141,247				—				144,030				319,957
Operating income (loss)			(2,783	)			29,261				—				26,478				2,306
Other (expense) income:
Interest expense			—				(333	)			(2,100	)12			(8,908	)			(27,787	)
											(6,475	)13
Interest income			—				429				—				429				4
Loss on debt extinguishment			(1,623	)			—				—				(1,623	)			500
Change in fair value of warrants			—				—				—				—				822
Other			—				254				—				254				—
Total other (expenses) income			(1,623	)			350				(8,575	)			(9,848	)			(26,461	)
Net income (loss) before income taxes			(4,406	)			29,611				(8,575	)			16,630				(24,155	)
Income tax expense			—				(4,292	)			4,292				—				—
Net (loss) income			(4,406	)			25,319				(4,283	)11			16,630				(24,155	)
Less net (loss) income attributable to noncontrolling interest			—				—				—				—				1,270
Net (loss) income attributable to WMLP unitholders			(4,406	)			25,319				—				16,630				(22,885	)
Less net (loss) income allocated to general partner			(28	)			25,319				(25,264	)			27				(429	)
Net income (loss) income allocated to limited partners		$	(4,378	)		$	—			$	20,981			$	16,603			$	(22,456	)

 

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		For the Period of December 31, 2014		For the Year Ended December 31, 2014								For the Period January 1, 2014 to December 31, 2014
		Westmoreland Resource Partners, LP (Successor)		Westmoreland Kemmerer, Inc.		Adjustments		WRPS Pro Forma				Oxford Resource Partners LP (Predecessor)
Net income (loss) per limited partner unit-basic and diluted								$	0.75			$	(10.92	)
Weighted-average limited partner units-basic and diluted									14,715,644				2,063,983
Net income (loss) per Class A limited partner unit-basic and diluted								$	0.75				—
Weighted-average Class A limited partner units									7,500,000				—
Net income (loss) per general partner unit-basic and diluted								$	0.75			$	(10.92	)
Weighted-average general partner units-basic and diluted									35,291				35,291

 

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Adjusted EBITDA

EBITDA and Adjusted EBITDA are supplemental measures of financial performance that are not required by, or presented in accordance with, U.S. GAAP. EBITDA and Adjusted EBITDA are key metrics used by us to assess our operating performance and we believe that EBITDA and Adjusted EBITDA are useful to an investor in evaluating our operating performance because these measures:

 

•

are used widely by investors to measure a company’s operating performance without regard to items excluded from the calculation of such terms, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors; and

 

•

help investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure and asset base from our operating results.

Neither EBITDA nor Adjusted EBITDA is a measure calculated in accordance with U.S. GAAP. The items excluded from EBITDA and Adjusted EBITDA are significant in assessing our operating results. EBITDA and Adjusted EBITDA have limitations as analytical tools, and should not be considered in isolation from, or as a substitute for, analysis of our results as reported under U.S. GAAP. For example, EBITDA and Adjusted EBITDA:

 

•

do not reflect our cash expenditures, or future requirements for capital and major maintenance expenditures or contractual commitments;

 

•

do not reflect changes in, or cash requirements for, our working capital needs; and

 

•

do not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on certain of our debt obligations.

In addition, although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA and Adjusted EBITDA do not reflect any cash requirements for such replacements. Other companies in our industry and in other industries may calculate EBITDA and Adjusted EBITDA differently from the way that we do, limiting their usefulness as comparative measures. Because of these limitations, EBITDA and Adjusted EBITDA should not be considered as measures of discretionary cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our U.S. GAAP results and using EBITDA and Adjusted EBITDA only as supplemental data.

Distributable Cash Flow

Distributable Cash Flow represents Adjusted EBITDA less cash interest expense (net of interest income), reserve replacement expenditures, maintenance capital expenditures, cash reclamation expenditures, and noncontrolling interest. Cash interest expense represents the portion of our interest expense accrued and paid in cash during the reporting periods presented or that we will pay in cash in future periods as the obligations become due. Other maintenance capital expenditures represent expenditures for coal reserve replacement, expenditures for plant, equipment and mine development. Cash reclamation expenditures represent the reduction to our reclamation and mine closure costs resulting from cash payments. Earnings attributable to the noncontrolling interest are not available for distribution to our unitholders and accordingly are deducted.

Distributable Cash Flow should not be considered as an alternative to net income (loss) attributable to our unitholders, income from operations, cash flows from operating activities or any other measure of performance presented in accordance with U.S. GAAP. Although Distributable Cash Flow is not a measure of performance calculated in accordance with U.S. GAAP, we believe Distributable Cash Flow is useful to investors because this measurement is used by many analysts and others in the industry as a performance measurement tool to evaluate our operating and financial performance, facilitating comparison with the performance of other publicly traded limited partnerships.

The tables below show how we calculated EBITDA, Adjusted EBITDA and Distributable Cash Flow and reconciles Distributable Cash Flow to net loss, the most directly comparable U.S. GAAP financial measure.

 

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WESTMORELAND RESOURCE PARTNERS SUCCESSOR

UNAUDITED PRO FORMA COMBINED RECONCILIATION OF NET LOSS TO

EBITDA, ADJUSTED EBITDA AND DISTRIBUTABLE CASH FLOW

(in thousands)

 

		For the Three Months Ended March 31, 2015
		Westmoreland Resource Partners, LP (Successor)				Westmoreland Kemmerer, Inc.				Adjustments						WRPS Pro Forma
Reconciliation of Net Loss to Adjusted EBITDA
Net loss		$	(10,305	)		$	4,117			$	(1,806	)				$	(7,994	)
Income tax expense			—				338				(338	)					—
Interest expense, net of interest income			5,780				(216	)			2,144						7,708
Depreciation, depletion and amortization			10,180				4,709				—						14,889
Accretion of ARO			804				443				—						1,247
EBITDA			6,459				9,391				—						15,850
Restructuring and impairment charges			553				—				—						553
Change in fair value of warrants			(29	)			—				—						(29	)
Acquisition related costs1			1,400				—				—						1,400
Loss on sale/disposal of assets			1,034				23				—						1,057
Unit-based compensation			21				92				—						113
Other non-recurring costs			115				(92	)			—						23
Adjusted EBITDA			9,553				9,414				—						18,967
Cash interest expense, net of interest income			(4,047	)			216				(1,619	)					(5,450	)
Other maintenance capital expenditures			(1,353	)			(1,113	)			—						(2,466	)
Reclamation and mine closure costs			(958	)			(44	)			—						(1,002	)
Distributable Cash Flow		$	3,195			$	8,473			$	(1,619	)				$	10,049

 

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WESTMORELAND RESOURCE PARTNERS SUCCESSOR

UNAUDITED PRO FORMA COMBINED RECONCILIATION OF NET LOSS TO

DISTRIBUTABLE CASH FLOW

(in thousands)

 

		For the Period of December 31, 2014				For the Year Ended December 31, 2014														For the Period January 1, 2014 to December 31, 2014
		Westmoreland Resource Partners, LP (Successor)				Westmoreland Kemmerer, Inc.				Adjustments						WRPS Pro Forma				Oxford Resource Partners LP (Predecessor)
Reconciliation of Net Loss to Adjusted EBITDA
Net loss		$	(4,406	)		$	25,319			$	(4,283	)				$	16,630			$	(24,155	)
Income tax expense			—				4,292				(4,292	)					—				—
Loss (gain) on extinguishment of debt			1,623				—				—						1,623				(500	)
Interest expense, net of interest income			—				96				8,575						8,671				28,028
Depreciation, depletion and amortization			—				16,912				—						16,912				39,070
Accretion of ARO			—				1,613				—						1,613				2,337
EBITDA			(2,783	)			48,232				—						45,449				44,780
Restructuring and impairment charges			2,783				—				—						2,783				75
Legal settlements			—				—				—						—				(17,548	)
Recapitalization costs			—				—				—						—				5,470
Change in fair value of warrants			—				—				—						—				(822	)
Loss (gain) on sale/disposal of assets			—				309				—						309				(218	)
Unit-based compensation			—				216				—						216				4,559
Adjusted EBITDA			—				48,757				—						48,757				36,296
Noncontrolling interest’s Adjusted EBITDA			—				—				—						—				(324	)
Debt issuance costs			—				—				—						—				(6,993	)
Cash interest expense, net of interest income			—				96				(6,475	)					(6,379	)			(15,952	)
Other maintenance capital expenditures			—				(7,489	)			—						(7,489	)			(14,066	)
Reclamation and mine closure costs			—				(885	)			—						(885	)			(4,999	)
Distributable Cash Flow		$	—			$	40,479			$	(6,475	)				$	34,004			$	(6,038	)

 

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1. Basis of Presentation, the Offering and Other Transactions

The accompanying pro forma combined financial statements include the accounts and operations of the Partnership and its consolidated subsidiaries and are prepared in conformity with U.S. GAAP. WCC’s cost incurred in the GP Acquisition has been pushed-down to establish a new accounting basis for us beginning in the last minutes of the year ended December 31, 2014. Accordingly, the accompanying consolidated financial statements are presented for both our Predecessor and our Successor, corresponding to the accounting periods preceding and following the completion of the GP Acquisition. The Predecessor and Successor periods have been separated by a vertical line on the face of the pro forma combined financial statements to highlight the facts that the financial information for such periods has been prepared under two different historical-cost bases of accounting.

The accompanying combined financial statements and related notes of WRPS presented in the pro forma combined balance sheet for the period ended March 31, 2015 and the pro forma combined statement of operations for the year ended December 31, 2014 and the three months ended March 15, 2015 are unaudited and include the combined results of (1) Oxford Mining; (2) Oxford Mining-Kentucky; (3) WKFCH; (4) Harrison Resources; and (5) Kemmerer, and WCC’s cost incurred in the GP Acquisition has been pushed-down to establish a new accounting basis for us beginning in the last minutes of the year ended December 31, 2014. Accordingly, the accompanying combined financial statement and related notes are presented for two periods, Predecessor and Successor, which relate to the accounting periods preceding and succeeding the completion of the transaction. The Predecessor and Successor periods have been separated by a vertical line on the face of the consolidated financial statements to highlight the facts that the financial information for such periods has been prepared under two different historical-cost bases of accounting.

These pro forma combined financial statements are prepared in connection with the proposed public offering of limited partner common units in the Partnership, which will own the operations defined above. Subsequent to this offering, WCC will direct the business operations of the Partnership through ownership and control of the Partnership’s general partner. The Partnership is not expected to have any employees. WCC and its affiliates’ employees will be responsible for conducting the Partnership’s business and operating its assets.

As a partnership, we are not a taxable entity for federal or state income tax purposes; the tax effect of our acativities pass through to our unitholders. Therefore, no provision or liability for federal or state income taxes is included in our financial statements. Net income (loss) for financial purposes may differ significantly from taxable income (loss) reportable to our unitholders as a result of timing or permanent difference between financial reporting under U.S. GAAP and regulations promulgated by the U.S. Internal Revenue Service.

2. Pro Forma Adjustments and Assumptions

 

1

Reflects the post retirement-medical benefits obligation, the pension obligations and the related deferred income tax assets and liabilities, which were excluded from the Contribution. Post-retirement medical and pension expenses incurred by our general partner after the transaction are covered by the Services Agreement. Under the Services Agreement, our general partner will continue providing administrative, engineering, operating and other services to us. Administrative services include, without limitation, legal, accounting, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit and tax and reimburse the general partner at cost for other expenses and expenditures.

 

2

Reflects the net proceeds of $70.0 million received from deferred draw borrowings under our existing credit facility with interest at a variable rate per annum equal to, at our option, LIBOR (floor of 0.75% plus 8.5%) or the Reference Rate (as defined in the 2014 Financing Agreement). Additionally, the 2014 Financing Agreement also provides for “PIK Interest” at a variable rate per annum between 1.00% and 3.00% based on our Consolidated Total Net Leverage Ratio (as defined in the 2014 Financing Agreement);

 

3	Reflects $5.0 million of borrowings on a new $15.0 million revolving credit facility;

 

4	Reflects the issuance by the Partnership of 7.0 million common units to the public in this offering;

 

5	Reflects the conversion of WCC’s net book investment in Kemmerer of $85.2 million into 2.0 million common units and 7.5 million Series A Convertible Units issued by the Partnership to WCC and the payment of $135.0 million to WCC net of legal, financing and investment banking fees and other costs;

 

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6	Reflects the elimination of the tax effect on the unrealized and realized gains and losses on available-for-sale securities;

 

7	Reflects the payment delayed draw financing fees payable of $1.0 million under our financing agreement, which were capitalized and will be amortized over the remaining life of the financing agreement;

 

8

Reflects investment banking fees and costs of $4.0 million we incurred in the execution of the Contribution. For the purpose of this pro forma we are assuming all incremental costs are directly attributable to the security offering and are accounted for as a charge against gross proceeds reducing Partners Capital;

 

9

Reflects legal and other cost of $2.0 million we incurred in the execution of the transaction For the purpose of this pro forma we are assuming all incremental costs are directly attributable to the security offering and are accounted for as a charge against gross proceeds reducing Partners Capital;

 

10	Reflects the elimination of transactions between the Partnership and Kemmerer for royalties paid by Kemmerer to the Partnership.

 

11

Reflects the elimination of income tax expense. As discussed in “Material U.S. Federal Income Tax Consequences,” the Internal Revenue Code of 1986, as amended (the “Code”), requires that we must derive 90% or more of our income from qualifying sources each year in order to qualify as a publicly traded partnership and failure to achieve the 90% threshold for any year will cause us to be taxed as a C corporation. Qualifying income included income from certain natural resources and biofuel activities such as income and gains derived from the exploration, development, mining or production, processing, refining, transportation (including pipelines transporting gas, oil, or products thereof), or the marketing of any mineral or natural resource (including fertilizer, geothermal energy, and timber), industrial source carbon dioxide, or the transportation or storage of any fuel described in subsection (b), (c), (d), or (e) of section 6426, or any alcohol fuel defined in section 6426(b)(4)(A) or any biodiesel fuel as defined in section 40A(d)(1). We do not expect the tax effects of the Contribution to be different than if we acquired an unaffiliated C corporation in an arm’s length transaction.

 

12	PIK Interest on proceeds of $70.0 million of received from delayed draw borrowing under our existing credit facility at 3.0%.

 

13	Interest on proceeds of $70.0 million received from delayed draw borrowings under our existing credit facility at 9.25%.

3. Pro Forma Net Income Per Unit

Pro forma net income per unit is determined by dividing the pro forma net income that would have been allocated to the common unitholders and Series A Convertible Unitholders, which is 99.8% of the pro forma net income, by the number of common units and Series A Convertible Units expected to be outstanding at the closing of the offering. For purposes of this calculation, the number of common units and Series A Convertible Units assumed to be outstanding was 22,422,187 at March 31, 2015. All units were assumed to have been outstanding since January 1, 2014. Basic and diluted pro forma net income per unit are equivalent as there are no dilutive units at the date of closing of the public offering of the common units of Westmoreland Resource Partners, LP. Pursuant to the partnership agreement, to the extent that the quarterly distributions exceed certain targets, the general partner is entitled to receive certain incentive distributions that will result in more net income proportionately being allocated to the general partner than to the holders of common units and Series A Convertible Units. The pro forma net income per unit calculations assume that no incentive distributions were made to the general partner because no such distribution would have been paid based upon the pro forma available cash from operating surplus for the periods.

 

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		WRPS Pro Forma
		For the Three Months End March 31, 2015				For the Year Ended December 31, 2014
Net Income (loss) allocated to limited partners		$	(5,312	)		$	10,998
Net Income (loss) per limited partner unit-basic and diluted		$	(0.36	)		$	0.75
Weighted-average limited partner unit-basic and diluted			14,922,187				14,715,644
Net Income (loss) allocated to Class A limited partners		$	(2,669	)		$	5,605
Net Income (loss) per Class A limited partner unit-basic and diluted		$	(0.36	)		$	0.75
Weighted-average Class A limited partner units-basic and diluted			7,500,000				7,500,000
Net Income (loss) allocated to general partners		$	(13	)		$	27
Net Income (loss) per general partner unit-basic and diluted		$	(0.36	)		$	0.75
Weighted-average general partner units-basic and diluted			35,291				35,291

 

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WESTMORELAND RESOURCE PARTNERS SUCCESSOR

UNAUDITED PRO FORMA COMBINED BALANCE SHEETS

(in thousands)

 

		WRPS Pro Forma						Oxford Resource Partners, LP (Predecessor)
		March 31, 2015						March 31, 2014
ASSETS
Current assets:
Cash and cash equivalents		$	9,785					$	4,636
Accounts receivable:
Trade			36,540						27,286
Other			188						71
Total accounts receivable			36,728						27,357
Inventories			23,244						15,734
Prepaid expenses			4,531						1,607
Total current assets			74,288						49,334
Property, plant and equipment, at costs:
Land and mineral rights			94,294						110,702
Plant and equipment			256,493						209,737
			350,787						320,439
Less accumulated depreciation, depletion and amortization			(49,191	)					(185,332	)
Net property, plant and equipment			301,596						135,107
Advance coal royalties			11,498						11,543
Restricted investments and bond collateral			35,226						14,644
Intangible assets, net of accumulated amortization			30,483						1,131
Other non-current assets			7,607						6,688
Total assets		$	460,698					$	218,447

See accompanying notes to combined financial statements.

 

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WESTMORELAND RESOURCE PARTNERS SUCCESSOR

UNAUDITED PRO FORMA COMBINED BALANCE SHEETS

(in thousands)

 

		WRPS Pro Forma						Oxford Resource Partners, LP (Predecessor)
		March 31, 2015						March 31, 2014
LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)
Current liabilities:
Current installments of long-term debt		$	3,447					$	9,375
Accounts payable and accrued expenses:
Trade			29,828						24,668
Deferred revenue			4,944						—
Production taxes			19,938						1,167
Accrued compensation			401						3,423
Asset retirement obligation			12,529						7,420
Other current liabilities			1,434						2,543
Total current liabilities			72,521						48,596
Long-term debt, less current installments			265,273						158,263
Deferred revenue			—						3,578
Asset retirement obligation, less current portion			39,387						23,996
Warrants			1,952						5,014
Other liabilities			160						160
Total liabilities			379,293						239,607
Partners capital (deficit):
Limited partner common units			92,571						(23,039	)
Limited partner Series A Convertible Units			(44,090	)					—
General partner units			32,884						(2,709	)
Accumulated other comprehensive income			40						—
Noncontrolling interest			—						4,588
Total partners’ capital (deficit)			81,405						(21,160	)
Total liabilities and partners’ capital (deficit)		$	460,698					$	218,447

See accompanying notes to combined financial statements.

 

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WESTMORELAND RESOURCE PARTNERS SUCCESSOR

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS

(in thousands)

 

		WRPS Pro Forma						Oxford Resource Partners, LP (Predecessor)												WRPS Pro Forma										Oxford Resource Partners, LP (Predecessor)
		Year Ended December 31, 2014						Period January 1, 2014 to December 31, 2014				Year ended December 31,								Three months ended March 31, 2015				Three months ended March 31, 2014						Three months ended March 31, 2014
												2013				2012
Revenues:
Coal revenues		$	170,508					$	295,662			$	336,201			$	364,928			$	103,273			$	43,123					$	76,770
Royalty revenues			—						284				8				1,496				23				—						99
Non-coal revenues			—						26,317				10,558				7,103				3,947				—						1,135
Total revenues			170,508						322,263				346,767				373,527				107,243				43,123						78,004
Costs and expenses:
Cost of coal revenues (excluding depreciation, depletion and amortization)			118,691						258,575				290,427				312,467				83,826				29,080						65,726
Cost of non-coal revenues			—						1,700				1,619				1,195				3,155				—						402
Depreciation, depletion and amortization			16,912						39,315				48,081				51,170				14,889				4,066						11,224
Selling and administrative			5,335						20,510				17,297				15,629				4,170				1,410						3,656
Loss (gain) on sale/disposal of assets			309						(218	)			(6,488	)			(8,021	)			1,057				(3	)					204
Restructuring charges			2,783						75				1,761				15,650				553				—						75
Total cost and expenses			144,030						319,957				352,697				388,090				107,650				34,553						81,287
Operating income (loss)			26,478						2,306				(5,930	)			(14,563	)			(407	)			8,570						(3,283	)
Other (expense) income:
Interest expense			(8,908	)					(27,787	)			(20,246	)			(11,500	)			(8,077	)			(2,185	)					(6,870	)
Interest income			429						4				4				10				369				6						1
Loss on debt extinguishment			(1,623	)					500				(808	)			—				—				—						—
Change in fair value of warrants			—						822				3,280				—				29				—						(415	)
Other			254						—				—				—				92				39						—
Total other (expenses) income			(9,848	)					(26,461	)			(17,770	)			(11,490	)			(7,587	)			(2,140	)					(7,284	)
Net income (loss)			16,630						(24,155	)			(23,700	)			(26,053	)			(7,994	)			6,430						(10,567	)
Less net income (loss) attributable to noncontrolling interest			—						(1,270	)			1,225				755				—				—						(381	)
Net income (loss) attributable to WMLP unitholders			16,630						(22,885	)			(24,925	)			(26,808	)			(7,994	)			6,430						(10,186	)
Less net income (loss) allocated to general partner			27						(429	)			(497	)			(535	)			(13	)			12						(202	)
Net income (loss) allocated to limited partners		$	(16,603	)				$	(22,456	)		$	(24,428	)		$	(26,273	)		$	(7,981	)		$	6,418					$	(9,984	)

See accompanying notes to combined financial statements.

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The historical financial statements included in this prospectus beginning on page F-1 reflect the assets, liabilities and operations, excluding the post-retirement medical benefit liability, the pension obligation and related deferred tax assets and liabilities, to be contributed to us by WCC and various wholly-owned subsidiaries in the Contribution. We refer to these assets, liabilities and operations combined with our pre-existing assets, liabilities and operations as the assets, liabilities and operations, as WRPS. The following discussion analyzes the financial condition and results of operations of WRPS. You should read the following discussion of the financial condition and results of operations for WRPS in conjunction with the historical combined financial statements and notes of WRPS and the pro forma financial statements for WRPS included elsewhere in this prospectus.

As the Contribution will be accounted for as a business combination involving entities or businesses under common control, the financial information presented in this section represents the unaudited pro forma condensed combined financial information of WRPS that gives effect to the following transactions as if they occurred as of January 1, 2014:

 

•

the issuance by the Partnership of             common units to the public in this offering;

 

•

the issuance by the Partnership of             common units to WCC as part of the Contribution Consideration;

 

•

the issuance by the Partnership of              Series A Convertible units to WCC as part of the Contribution Consideration;

 

•

the payment of estimated underwriting commissions and other offering expenses of $         million;

 

•

the net proceeds of $70.0 million received from deferred draw borrowings under our existing credit facility with interest at a variable rate per annum equal to, at our option, LIBOR (floor of 0.75% plus 8.5%) or the Reference Rate (as defined in the 2014 Financing Agreement). Additionally, the 2014 Financing Agreement also provides for “PIK Interest” at a variable rate per annum between 1.00% and 3.00% based on our Consolidated Total Net Leverage Ratio (as defined in the 2014 Financing Agreement);

 

•

our entry into an additional $15 million revolving credit facility;

 

•

the distribution to WCC of a portion of the net proceeds generated from this offering and borrowings under our credit facility as part of the Contribution Consideration; and

 

•

the retention of the assets and liabilities of Kemmerer, with the exception of the post-retirement medical benefits obligation, the pension obligations and the related deferred income tax assets.

Overview

We are a growth-oriented, low-cost producer and marketer of high-value thermal coal to United States utilities and industrial users, and we are the largest producer of surface mined coal in Ohio. We market our coal primarily to large electric utilities with coal-fired, base load scrubbed power plants under coal sales contracts. We focus on acquiring thermal coal reserves that we can efficiently mine with our large-scale equipment. Our reserves and operations are well positioned to serve our primary market areas of the Midwest and northeastern United States and, following the Contribution (as defined below), the Rocky Mountain region. We have a significant transportation cost advantage compared to many other coal producers in our primary market areas that incur higher transportation rates to deliver coal.

As of March 31, 2015, management estimates that we owned or controlled approximately 104.1 million tons of coal reserves, of which we have leased or subleased approximately 53.6 million tons of reserves to others. These estimates are based on an initial evaluation, as well as subsequent acquisitions, dispositions, depletion of reserves, changes in available geological or mining data and other factors.

 

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We enter into long-term supply contracts (one year or greater in duration) with substantially all of our customers. These contracts allow customers to secure a dependable supply for their future needs and provide us with greater predictability of sales volumes and prices. On a pro forma basis after giving effect to the Contribution, for the year ended December 31, 2014, approximately 99.1% of our coal tons sold were sold under long-term supply contracts with an average remaining life of 5.8 years. We sell the remainder of our coal through short-term contracts and on the spot market.

We operate in a single business segment and have four operating subsidiaries, Oxford Mining, WKFCH, Harrison Resources and Oxford Mining Kentucky. Oxford Mining primarily utilizes surface mining techniques to mine domestic coal and prepare it for sale to our customers, or leases our controlled coal reserves to others. WKFCH and Harrison Resources own and hold coal reserves. WKFCH’s coal reserves are leased to a subsidiary of WCC, from which WKFCH earns a per ton coal royalty. Harrison Resources coal reserves are surface mined and marketed by Oxford Mining.

In December 2014, WCC completed its acquisition of our general partner and contributed the WKFCH royalty-bearing coal reserves to us in exchange for common units. In connection with the transaction, we changed our name, restructured our partnership agreement, made a one-time special distribution to our public common unitholders and refinanced our credit facilities. See “Our Business—WCC Transactions.”

Recent Developments

The Contribution

On June 1, 2015, we entered into the Contribution Agreement with WCC, pursuant to which, upon satisfaction or waiver of the conditions set forth in the Contribution Agreement, WCC will make the Contribution to us of the Kemmerer Interests. Upon closing the Contribution, we will own 100% of the outstanding equity interests in Kemmerer. We expect the Contribution to significantly expand the size of our production base, diversify the customers we serve and improve the stability of our cash flows by increasing the average remaining term of our long-term supply contracts from 3.2 years to 5.8 years.

The Contribution Consideration will be approximately $230 million, to be paid in a combination of cash, up to $20 million in common units and up to $75 million in Series A Convertible Units. Following the Contribution and the completion of this offering, WCC will own approximately 61% of our common units on a fully diluted basis. We expect to close the Contribution in the third quarter of 2015. The closing of the Contribution is conditioned on, among other things, the receipt by us of at least $65 million in net proceeds from this offering. However, the closing of this offering is not conditioned on the closing of the Contribution.

In connection with our entry into the Contribution Agreement and the issuance of the Series A Convertible Units, we will enter into the Amendment to our partnership agreement. The Amendment will establish the terms of the Series A Convertible Units and any additional Series A PIK Units, and will provide that each Series A Convertible Unit will have the right to share in distributions from us on a pro rata basis with the common units. All or any portion of the Series A Convertible Unit Distribution may, at our election, be paid in Series A PIK Units. To the extent any portion of the Series A Convertible Unit Distribution is paid in Series A PIK Units for any quarter, the distribution to the holders of incentive distribution rights shall be reduced by that portion of the distribution that is attributable to the payment of those Series A PIK Units, as further described in the Amendment. The Series A Convertible Units and the Series A PIK Units will convert into common units at the earlier of the first anniversary of the initial issuance of the Series A Convertible Units pursuant to the Contribution Agreement, the date on which we first make a regular quarterly cash distribution with respect to any quarter to holders of common units in an amount at least equal to $0.22 per common unit or upon a change of control. The Series A Convertible Units will have the same voting rights as if they were outstanding common units and will vote together with the common units as a single class. In addition, the Series A Convertible Units will be entitled to vote as a separate class on any matters that materially adversely affect the rights or preferences of the Series A Convertible Units in relation to other classes of partnership interests or as required by law.

 

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The Kemmerer Mine supplies approximately 2.7 million tons per year to the adjacent 687 MW three unit Naughton Power Station in Wyoming, which is owned and operated by PacifiCorp. Unit 1 was commissioned in 1963 and Units 2 and 3 were added in 1968 and 1971, respectively. The Naughton Power Station is a base load plant that operates at a high capacity factor, with a monthly average capacity factor of approximately 86% over the past three years. Electrostatic precipitators and scrubbers are installed on all three units to control particulate emissions and sulfur-dioxide and are expected to keep the plant compliant with environmental rules. Coal is delivered along a 4,200-foot belt conveyor under a long-term sales agreement that expires in December 2021. Kemmerer also supplies approximately 1.7 million tons a year to various industrial customers through long-term contracts extending to 2026. Certain of the Kemmerer Mine reserves were contributed to WMLP from WCC as part of its acquisition of our general partner.

In 2014, Kemmerer produced 4.4 million tons of coal, supplying the adjacent Naughton Power Station as well as various industrial customers. The Naughton Power Station supplies power to the Mountain West region, which the U.S. Census Bureau has forecasted will grow at a rate of 17.6% between 2010 and 2020, and at a rate of 17.0% between 2020 and 2030. In addition to PacifiCorp, which owns the Naughton Power Station, Kemmerer’s industrial customers include Tata Chemicals North America Inc. and FMC Corporation, which are sources of steady and predictable demand. When combined with our existing operations, the addition of Kemmerer represents a 78% increase to our overall coal production as of December 31, 2014. Further, Kemmerer has long-term contracts that have a weighted-average remaining life of seven years. Many of these long life contracts also have varying levels of cost protection which help reduce the impact of external market conditions on Kemmerer’s margins and cash flows. Following WCC’s acquisition of Kemmerer in 2012, WCC management significantly enhanced its financial performance, driving strong improvements in productivity, costs and safety.

AEP Agreement

On February 26, 2015, Oxford Mining and AEP Generation Resources Inc. entered into the AEP Agreement. Under the AEP Agreement, Oxford Mining agreed to sell, and AEP agreed to purchase, certain quantities of coal from January 1, 2016 through December 31, 2018 for use at its Conesville, Ohio generating plant: 1.3 million tons during 2016; 1.2 million tons during 2017; and 0.8 million tons during 2018. In addition, pursuant to the AEP Agreement, Oxford Mining has the right of first refusal to supply up to a certain number of additional tons of coal, as needed by AEP: 400,000 tons during 2016; 300,000 tons during 2017; and 200,000 tons during 2018, an increase of 31%, 25%, and 27% over contracted levels, respectively.

Items that Affect Comparability of Our Results

On December 31, 2014, WCC’s cost incurred in the GP Acquisition has been pushed-down to establish a new accounting basis for us. Accordingly, the accompanying consolidated financial statements are presented for two periods, Predecessor and Successor, which relate to the accounting periods preceding and succeeding the completion of the acquisition. The Predecessor and Successor periods have been separated by a vertical line on the face of the consolidated financial statements to highlight the fact that the financial information for such periods has been prepared under two different historical-cost bases of accounting. The following narrative analysis of results of operations includes a brief discussion of the factors that materially affected our operating results in the Predecessor period of January 1 – December 31, 2014 along with a brief discussion of Successor activity for the last minutes of the day on December 31, 2014 through March 31, 2015.

Upon the closing of this offering, WCC will contribute to us the assets, liabilities and operations of Kemmerer reflected in the historical financial statement other than the postretirement medical benefit liability, the pension obligation and related deferred tax assets and liabilities which will not be contributed to us. The historical financial statement of WRPS do not give effect the additional indebtedness we incur at closing of this offering will increase our interest expense for the interest expense reflected in our historical financial statements.

 

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For the three months ended March 31, 2015 and 2014, our consolidated results include items that affect comparability of our results. The expense components of these items were as follows (in thousands):

 

		WRPS Pro Forma										Oxford Resource Partners, LP (Predecessor)
		Three months ended March 31, 2015				Three months ended March 31, 2014						Three months ended March 31, 2014
Restructuring expense		$	553			$	—					$	75
Acquisition related costs1			1,400				—						—
Impact		$	1,953			$	—					$	75

 

1	Includes acquisition and transition costs included in cost of coal revenue related to the sale of inventory written up to fair value.

Restructuring Expense

 

•

Restructuring expense was $0.6 million for the successor three months ended March 31, 2015. The successor three months ended March 31, 2015 included $0.6 million in severances payments related to the closing of the corporate offices in Columbus, Ohio and the elimination of other nonessential roles.

 

•

Restructuring expense was $0.1 million for the predecessor three months ended March 31, 2014. The predecessor three months ended March 31, 2014 included $0.1 million in various inconsequential costs associated with the restructuring related to our Illinois Basin operations.

 

•

There was not restructuring expense for the successor three months ended March 31, 2014.

Acquisition Related Costs

 

•

As part of the acquisition method of accounting in connection with the GP Acquisition, coal inventory was accounted for at its estimated fair value on December 31, 2014, increasing the coal inventory by $1.4 million. During the successor three months ended March 31, 2015 the inventory held at December 31, 2014 was sold and we recognized a $1.4 million non-cash charge to cost of coal revenues related to the acquisition method of accounting adjustment.

 

•

There were no acquisition-related costs for the successor and predecessor three months ended March 31, 2014.

 

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The Three Months Ended March 31, 2015 (Successor) Compared to the Three Months Ended March 31, 2014 (Successor) and Three Months Ended March 31, 2014 (Predecessor) (in thousands)

Summary

 

		WRPS Pro Forma										Oxford Resource Partners, LP (Predecessor)
		Three months ended March 31, 2015				Three months ended March 31, 2014						Three months ended March 31, 2014
Total Revenues		$	107,243			$	43,123					$	78,004
Net loss			(7,994	)			8,574						(10,567	)
Adjusted EBITDA1			18,967				13,095						9,241
Distributable Cash Flow2			10,049				10,099						1,850
Tons sold—millions of equivalent tons			2.3				1.1						1.4

 

1	Adjusted EBITDA, a non-GAAP measure, is defined and reconciled to net loss at the end of this “Results of Operations” section.

2	Distributable cash flow a non-GAAP measure, is defined and reconciled to net loss at the end of this “Results of Operations” section.

Total revenues were $107.2 million for the successor three months ended March 31, 2015 on the sale of 2.3 million tons of coal. The $107.2 million in revenue translated into a $8.0 million net loss and Adjusted EBITDA of $19.0 million for the successor three months ended March 31, 2014. Additionally we generated $10.0 million in distributable cash flow for the successor three months ended March 31, 2015. Average coal sales price per ton was $45.17 per ton sold offset in part by cost per ton sold of $37.47 per ton resulting in a gross profit margin per ton sold of $7.70 per ton for the successor three months ended March 31, 2015.

Total revenues were $43.1 million for the successor three months ended March 31, 2014 on the sale of 1.1 million tons of coal. The $43.1 million in revenue translated into a $8.6 million in net income and Adjusted EBITDA of $13.1 million for the successor three months ended March 31, 2015. Additionally we generated $13.1 million in distributable cash flow for the successor three months ended March 31, 2014. Average coal sales price per ton was $39.11 per ton sold offset in part by cost per ton sold of $26.38 per ton resulting in a gross profit margin per ton sold of $12.74 per ton for the successor three months ended March 31, 2014.

Total revenues were $78.0 million for the predecessor three months ended March 31, 2014 on the sale of 1.4 million tons of coal. The $78.0 million in revenue translated into a $10.6 million in net loss and Adjusted EBITDA of $9.2 million for the predecessor three months ended March 31, 2014. Additionally we generated $1.9 million in distributable cash flow for the predecessor three months ended March 31, 2014. Average coal sales price per ton was $53.36 per ton sold offset in part by cost per ton sold of $45.68 per ton resulting in a gross profit margin per ton sold of $7.68 per ton for the predecessor three months ended March 31, 2014.

 

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Total Revenues

 

		(in thousands)
		WRPS Pro Forma										Oxford Resource Partners, LP (Predecessor)
		Three months ended March 31, 2015				Three months ended March 31, 2014						Three months ended March 31, 2014
Revenues:
Coal revenues		$	103,273			$	43,123					$	76,770
Royalty revenues			23				—						99
Non-coal revenues			3,947				—						1,135
Total revenues		$	107,243			$	43,123					$	78,004

Coal sales revenue was $103.3 million for the successor three months ended March 31, 2015 on the sale of 2.3 million coal tons sold. Of the $103.3 million in coal sales revenue, $61.8 million in coal sales revenue was generated from the sale of 1.2 million coal tons was attributed to our Predecessor and coal sales revenue of $41.5 million was generated from the sale of 1.1 million coal tons was attributed from the contributed Kemmerer mining operations. Coal sales revenue of $61.8 million attributed to our Predecessor decreased $15.0 million, or 19.6%, from $76.8 million for the predecessor three months ended March 31, 2014. The decrease was primarily attributable to a 20.6% reduction in tons sold in the amount of $15.8 million, partially offset by a $0.66 per ton, or an aggregate $0.8 million, increase in the average sale price per ton for the successor three months ended March 31, 2015. Coal sales revenue of $41.5 million attributed to the contributed Kemmerer mining operations decreased $1.6 million from $43.1 million for the successor three months ended March 31, 2014. The $1.6 million decrease is the result of minor change in customer mix resulting in a decrease in average sale price per ton of $2.79 per ton.

For the successor three months ended March 31, 2015, we generated $0.2 million in oil and gas royalty revenues.

Non-coal revenues, primarily from clay and limestone sales, and other miscellaneous revenue was $3.9 million for the successor three months ended March 31, 2015. Other miscellaneous revenue of $3.3 million for the successor three months ended March 31, 2015 was due primarily to generating $2.4 million in coal handling and transportation services revenue performed on behalf of a subsidiary of WCC and $0.7 million in one-time coal handling and transportation services revenue performed on behalf of a customer. Clay and limestone sales was $0.6 million for the successor three months ended March 31, 2015.

Cost of Coal Revenues

 

		(in thousands)
		WRPS Pro Forma										Oxford Resource Partners, LP (Predecessor)
		Three months ended March 31, 2015				Three months ended March 31, 2014						Three months ended March 31, 2014
Cost of coal revenues (excluding depreciation, depletion and amortization)		$	83,826			$	29,080					$	65,726

 

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Cost of coal revenues (excluding DD&A) was $83.8 million for the successor three months ended March 31, 2015. Of the $83.8 million in cost of coal revenues, $54.7 million of cost of coal revenues was attributed to our legacy Ohio mining operations with the remaining $29.1 million of cost of coal revenues attributed to the contributed Kemmerer mining operations for the successor three months ended March 31, 2015.

The $54.7 million of cost of coal revenues, for the successor three months ended March 31, 2015, attributed to our legacy Ohio mining operations represent a decrease of $11.1 million from $65.7 million for the predecessor three months ended March 31, 2014, primarily due to decreased coal sales and production volumes. On a per ton basis, cost of coal revenues increased 4.7% to $47.81 per ton sold for the successor three months ended March 31, 2015 from $45.68 per ton sold for the predecessor three months ended March 31, 2014 primarily due to various factors, the most significant of which are discussed below:

 

•

Equipment repair and maintenance expense per ton sold increased $1.02 per ton to $4.42 per ton for the successor three months ended March 31, 2015 from $3.39 per ton for the predecessor three months ended March 31, 2014. This increase of $1.02 per ton is the result of incurring equipment maintenance during the successor three months ended March 31, 2015 deferred from fiscal 2014, combined with a 20.6% decrease in tons sold for the successor three months ended March 31, 2015 compared with the predecessor three months ended March 31, 2014.

 

•

Transportation expense per ton sold increased $0.76 per ton to $8.44 per ton for the successor three months ended March 31, 2015 from $7.68 per ton for the predecessor three months ended March 31, 2014. The increase of $0.76 per ton was attributed to longer haul routes to meet customer demand.

 

•

Labor and benefit expenses per ton sold increased 8.4% to $9.73 per ton for the successor three months ended March 31, 2015 from $8.98 per ton for the predecessor three months ended March 31, 2014. This increase of $0.75 per ton was attributed to a $0.44 per ton increase in wages and a $0.31 per ton increase in employee benefits. The $0.44 per ton increase in wages is primarily the result of raises implemented in mid-2014 in response to competition in the labor market from the growing oil and gas drilling business in southeastern Ohio. The $0.31 per ton increase in employee benefits is primarily the result of higher health insurance cost per employee.

The cost of coal revenues attributed to the contributed Kemmerer mining operations for the successor three months ended March 31, 2015 remained flat at $29.1 million compared to the successor three months ended March 31, 2014.

Depreciation, Depletion and Amortization

 

		(in thousands)
		WRPS Pro Forma										Oxford Resource Partners, LP (Predecessor)
		Three months ended March 31, 2015				Three months ended March 31, 2014						Three months ended March 31, 2014
Depreciation, depletion and amortization		$	14,889			$	4,066					$	11,224

Depreciation, depletion and amortization expense was $14.9 million for the successor three months ended March 31, 2015. Of the $14.9 million in depreciation, depletion and amortization expense, $10.2 million of depreciation, depletion and amortization expense, was attributed to our legacy Ohio mining operations with the remaining $4.7 million of depreciation, depletion and amortization expense, attributed to the contributed Kemmerer mining operations for the successor three months ended March 31, 2015.

The $10.2 million of depreciation, depletion and amortization expense, for the successor three months ended March 31, 2015, attributed to our legacy Ohio mining operations decreased $1.0 million from $11.2 million for

 

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the predecessor three months ended March 31, 2014. The decrease of $1.0 million was primarily attributable to the decrease in land and mineral rights asset values resulting from the acquisition method of accounting resulting from WCC’s acquisition of 100% of the equity of our general partner on December 31, 2014.

The $4.7 million of depreciation, depletion and amortization expense, for the successor three months ended March 31, 2015 attributed to contributed Kemmerer mining operations increased $0.6 million. The $0.6 million increase was primarily attributable to the amortization of the production of approximately 41 thousand additional tons mined in the three months ended March 31, 2015 compared to the three months ended March 31, 2014.

Selling and Administrative

 

		(in thousands)
		WRPS Pro Forma										Oxford Resource Partners, LP (Predecessor)
		Three months ended March 31, 2015				Three months ended March 31, 2014						Three months ended March 31, 2014
Selling and administrative		$	4,170			$	1,410					$	3,656

Selling and administrative expenses was $4.2 million for the successor three months ended March 31, 2015. Of the $4.2 million in selling and administrative expenses, $2.5 million of selling and administrative expenses was attributed to our legacy Ohio mining operations with the remaining $1.6 million of selling and administrative expenses, attributed to the contributed Kemmerer mining operations for the successor three months ended March 31, 2015.

The $2.5 million of selling and administrative expenses, for the successor three months ended March 31, 2015, attributed to our legacy Ohio mining operations decreased $1.1 million from $3.7 million for the predecessor three months ended March 31, 2014. The decrease of $1.1 million was primarily due to cost savings from the restructuring efforts put in place to streamline operations and eliminate duplicated roles resulting from the acquisition of our general partner by WCC on December 31, 2014.

The $1.6 million of selling and administrative expenses, for the successor three months ended March 31, 2015, attributed to contributed Kemmerer mining operations increased $0.2 million from $1.4 million for the successor three months ended March 31, 2014 resulting from inflation and wage increases.

Loss on sale/disposal of assets

 

		(in thousands)
		WRPS Pro Forma										Oxford Resource Partners, LP (Predecessor)
		Three months ended March 31, 2015				Three months ended March 31, 2014						Three months ended March 31, 2014
Loss (gain) on sale/disposal of assets		$	1,057			$	(3	)				$	204

The loss (gain) on sale/disposal of assets of $1.1 million for the successor three months ended March 31, 2015 and $(3) thousand and $0.2 million for the successor and predecessor three months ended March 31, 2014, respectively, resulted from the disposal of equipment in the normal course of business.

 

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Adjusted EBITDA

EBITDA and Adjusted EBITDA are supplemental measures of financial performance that are not required by, or presented in accordance with, U.S. GAAP. EBITDA and Adjusted EBITDA are key metrics used by us to assess our operating performance and we believe that EBITDA and Adjusted EBITDA are useful to an investor in evaluating our operating performance because these measures:

 

•

are used widely by investors to measure a company’s operating performance without regard to items excluded from the calculation of such terms, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors; and

 

•

help investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure and asset base from our operating results.

Neither EBITDA nor Adjusted EBITDA is a measure calculated in accordance with U.S. GAAP. The items excluded from EBITDA and Adjusted EBITDA are significant in assessing our operating results. EBITDA and Adjusted EBITDA have limitations as analytical tools, and should not be considered in isolation from, or as a substitute for, analysis of our results as reported under U.S. GAAP. For example, EBITDA and Adjusted EBITDA:

 

•

do not reflect our cash expenditures, or future requirements for capital and major maintenance expenditures or contractual commitments;

 

•

do not reflect changes in, or cash requirements for, our working capital needs; and

 

•

do not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on certain of our debt obligations.

In addition, although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA and Adjusted EBITDA do not reflect any cash requirements for such replacements. Other companies in our industry and in other industries may calculate EBITDA and Adjusted EBITDA differently from the way that we do, limiting their usefulness as comparative measures. Because of these limitations, EBITDA and Adjusted EBITDA should not be considered as measures of discretionary cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our U.S. GAAP results and using EBITDA and Adjusted EBITDA only as supplemental data.

Distributable Cash Flow

Distributable Cash Flow represents Adjusted EBITDA less cash interest expense (net of interest income), reserve replacement expenditures, maintenance capital expenditures, cash reclamation expenditures, and noncontrolling interest. Cash interest expense represents the portion of our interest expense accrued and paid in cash during the reporting periods presented or that we will pay in cash in future periods as the obligations become due. Other maintenance capital expenditures represent expenditures for coal reserve replacement, expenditures for plant, equipment and mine development. Cash reclamation expenditures represent the reduction to our reclamation and mine closure costs resulting from cash payments. Earnings attributable to the noncontrolling interest are not available for distribution to our unitholders and accordingly are deducted.

Distributable Cash Flow should not be considered as an alternative to net income (loss) attributable to our unitholders, income from operations, cash flows from operating activities or any other measure of performance presented in accordance with U.S. GAAP. Although Distributable Cash Flow is not a measure of performance calculated in accordance with U.S. GAAP, we believe Distributable Cash Flow is useful to investors because this measurement is used by many analysts and others in the industry as a performance measurement tool to evaluate our operating and financial performance, facilitating comparison with the performance of other publicly traded limited partnerships.

 

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The tables below show how we calculated EBITDA, Adjusted EBITDA and Distributable Cash Flow and reconciles Distributable Cash Flow to net loss, the most directly comparable U.S. GAAP financial measure.

Reconciliation of Net Loss to Distributable Cash Flows:

 

		WRPS Pro Forma										Oxford Resource Partners, LP (Predecessor)
		Three months ended March 31, 2015				Three months ended March 31, 2014						Three months ended March 31, 2014
		(in thousands)
Reconciliation of Net Loss to Adjusted EBITDA
Net loss		$	(7,994	)		$	6,430					$	(10,567	)
Interest expense, net of interest income			7,708				2,179						6,869
Depreciation, depletion and amortization			14,889				4,066						11,224
Accretion of ARO			1,247				403						565
EBITDA			15,850				13,078						8,091
Restructuring and impairment charges			553				—						75
Change in fair value of warrants			(29	)			—						415
Acquisition related costs1			1,400				—						—
Loss (gain) on sale/disposal of assets			1,057				(3	)					204
Unit-based compensation			113				—						456
Other non-recurring costs			23				—						—
Adjusted EBITDA			18,967				13,075						9,241
Noncontrolling interest’s Adjusted EBITDA			—				—						(94	)
Cash interest expense, net of interest income			(5,450	)			(1,654	)					(4,060	)
Other maintenance capital expenditures			(2,466	)			(1,330	)					(2,622	)
Reclamation and mine closure costs			(1,002	)			8						(615	)
Distributable Cash Flow		$	6,320			$	10,099					$	1,850

 

1	Includes acquisition and transition costs included in cost of coal revenue related to the sale of inventory written up to fair value.

Liquidity and Capital Resources

Liquidity

Our business is capital intensive and requires substantial capital expenditures for, among other things, purchasing, maintaining and upgrading equipment used in developing and mining our coal, and acquiring reserves. Our principal liquidity needs are to finance current operations, replace reserves and fund capital expenditures, including costs of acquisitions from time to time, servicing of our debt and paying quarterly cash distributions to our unitholders. Our primary sources of liquidity to meet these needs are cash generated by our operations and the limited remainder of our initial term loan borrowing under the 2014 Financing Agreement.

Our ability to satisfy our working capital requirements, meet debt service obligations, and fund planned capital expenditures substantially depends upon our future operating performance, which may be affected by prevailing economic conditions in the coal industry. To the extent our future operating cash flow or access to financing sources and the costs thereof are materially different than expected, our future liquidity may be adversely affected.

As of March 31, 2015, our pro forma combined available liquidity was $16.8 million, which consisted $6.8 million of cash on hand and $10.0 million of available under our revolving credit facility.

 

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Please read “—Capital Expenditures” for a further discussion of the impact on liquidity.

Debt Obligations

On December 31, 2014, we entered into a new $295 million credit facility under a Financing Agreement (the “2014 Financing Agreement”) with the lenders party thereto and U.S. Bank National Association as Administrative and Collateral Agent to replace our existing $175 million credit facility consisting of (i) a first lien $75 million term loan and $25 million revolving credit facility and (ii) a second lien $75 million term loan. The new credit facility consists of a $175 million term loan, with an option for up to $120 million in additional term loans for acquisitions if requested by us and approved by the issuing lenders. The 2014 Financing Agreement matures in December 2018 and contains customary affirmative covenants and other affirmative covenants (including, without limitation, the requirement to maintain at the end of each fiscal year an aggregate tonnage of coal reserves (excluding coal produced from coal reserves leased or subleased to third parties) equal to or greater than five times the aggregate tons of coal produced during such fiscal year) and customary negative covenants and financial covenants in respect of lease obligations (i.e., (x) operating lease obligations in any fiscal year not to exceed $15,000,000 and (y) coal leases obligations in any fiscal year not to exceed $11,000,000) and capital expenditures (i.e., capital expenditures not to exceed in any fiscal year the sum of (i) $4.00 per ton of coal produced in such year plus (ii) an additional $2.00 per ton of coal produced by any assets acquired during such year (excluding any royalty payments related thereto) plus any applicable carry-over from a prior year). The 2014 Financing Agreement also permits distributions to our unitholders so long as (i) no event of default is continuing or would result therefrom, (ii) our liquidity is at least $5,000,000 immediately after giving effect to any distribution and (iii) if distributions exceed an aggregate of $7,500,000, we maintain (x) a consolidated total net leverage ratio of no greater than 3.75x and (y) a fixed charge coverage ratio of not less than 1.00x. Borrowings under the 2014 Financing Agreement are secured by substantially all of our physical assets. Proceeds of the new credit facility were used to retire our then existing first and second lien credit facilities and to pay fees and expenses related to our new credit facility, with the limited amount of remaining proceeds being available as working capital.

As of March 31, 2015 the pro forma combined outstanding balance on our 2014 Financing Agreement was $246.4 million. This amount represents the principal balance of $245.0 million, plus PIK Interest of $1.4 million. As of March 31, 2015, our 2014 Financing Agreement had a cash interest rate of 9.25%, consisting of the LIBOR floor (0.75%) plus 8.50%.

The 2014 Financing Agreement also provides for “PIK Interest” (paid-in-kind interest as defined in the 2014 Financing Agreement) at a variable rate per annum between 1.00% and 3.00% based on our total net leverage ratio (as defined in the 2014 Financing Agreement). The rate of PIK Interest is recalculated on a quarterly basis with the PIK Interest added quarterly to the then-outstanding principal amount of the term loan under the 2014 Financing Agreement. PIK Interest expense under the 2014 Financing Agreement was $1.9 million for the three months ended March 31, 2015.

 

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Historical Sources and Uses of Cash

The following is a summary of cash provided by or used in each of the indicated types of activities (in thousands):

 

		Westmoreland Resource Partnership (Successor)						Oxford Resource Partners, LP (Predecessor)				Westmoreland Kemmerer, Inc.
		Three months ended March 31, 2015						Three months ended March 31, 2014				Three months ended March 31, 2015				Three months ended March 31, 2014
Net cash provided by (used in):
Operating activities		$	(380	)				$	817			$	19,451			$	18,858
Investing activities			(3,736	)					(1,779	)			(1,465	)			(1,308	)
Financing activities			(20	)					2,509				(18,069	)			(18,414	)

Westmoreland Resource Partners LP

Net cash used in operating activities was $0.4 million for the three months ended March 31, 2015 compared to $0.8 million of net cash provided by operating activities for the three months ended March 31, 2014, a decrease of approximately $1.2 million. We experienced a net loss for the three months ended March 31, 2015 of $10.3 million, a decrease of $0.3 million, compared to a net loss for the three months ended March 31, 2014 of $10.6 million. The decrease in the net loss was attributable in part to a $1.0 million decrease in depreciation, depletion and amortization, a $0.5 million decrease in non-cash interest expense and amortization of deferred financing costs, respectively, partially offset by a $0.8 million increase in loss on sale/disposal of assets and a $0.5 million increase in amortization of intangible assets and liabilities, net and restructuring and impairment charges, respectively. These differences, combined with a minor change in working capital, are the primary drivers of the decrease in net cash used in operating activities. The changes in working capital comprised of an unfavorable changes of $2.1 million in other assets and liabilities resulting from severance payments, in accordance with employment agreements, to three former executives during the three months ended March 31, 2015, and a unfavorable change of $1.2 million in accrued compensation due to timing, partially offset by a favorable change in inventory of $3.2 million.

Net cash used in investing activities was $3.7 million for the three months ended March 31, 2015 compared to $1.8 million for the three months ended March 31, 2014, an increase of approximately $2.0 million. The increase was attributable to an increase of $2.2 million in cash used for capital expenditures and a decrease of $0.3 million in cash provided from proceeds from the sale of assets, offset in part by $0.5 million increase in cash provided from the change in restricted investments and bond collateral.

Net cash used in financing activities was less than $0.1 million for the three months ended March 31, 2015, down $2.5 million from net cash provided by financing activities of $2.5 million for the three months ended March 31, 2014. The $2.5 million decrease in net cash provided by financing activities was primarily attributable to $2.5 million in less net borrowings for the three months ended March 31, 2015 compared to the three months ended March 31, 2014.

Westmoreland Kemmerer, Inc.

Cash flows provided by operating activities increased $0.6 million, primarily attributed to the $2.1 million favorable change in working capital offset in part by a $2.3 million decrease in net income and an unfavorable change in deferred income taxes. The $2.1 million change in working capital is primarily attributable to a $2.7 favorable change in accounts receivable, a $1.4 million unfavorable change in accounts payable and accrued production taxes and a $1.6 million favorable change in deferred revenues offset in part by an unfavorable change in inventory $1.3 million.

 

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Cash flows used in investing activities increased $0.2 million was primarily the result of the decision to more actively manage its yield investment resulting in receiving $1.6 million in proceeds from the sale of investments and an increase of $1.9 million in restricted investments and bond collateral.

Cash flows used in financing activities for the three months ended March 31, 2015 and 2014 represents the pass through of Westmoreland Kemmerer’s net cash flows to Westmoreland Coal Company under its cash management program.

Capital Expenditures

Our mining operations require investments to maintain, expand, and upgrade existing operations and to meet environmental and safety regulations. We have funded and expect to continue funding capital expenditures primarily from cash generated by our operations, the remainder of the initial term loan borrowings under the 2014 Financing Agreement, and proceeds from asset sales. Our capital expenditures, including capital lease payments, are expected to be between $20 million and $22 million for the remainder of 2015.

The following table summarizes our capital expenditures by type for the three months ended March 31, 2015 and 2014.

 

		WRPS Pro Forma										Oxford Resource Partners, LP (Predecessor)
		Three months ended March 31, 2015				Three months ended March 31, 2014						Three months ended March 31, 2014
		(in thousands)
Coal reserves		$	—			$	—					$	3
Mine development			275				—						189
Equipment and components			2,408				1,330						2,430
Total		$	2,683			$	1,330					$	2,622

Contractual Obligations

We have contractual obligations that are required to be settled in cash. The amounts of our contractual obligations as of March 31, 2015 were as follows.

 

		WRPS Pro Forma Payment Due by Period As of March 31, 2015
		Total				Less than 1 Year				1 – 3 Years				4 – 5 Years				More than 5 Years
		(in thousands)
Long-term debt obligations		$	245,000			$	—			$	245,000			$	—			$	—
Future interest obligations—long-term debt(1)			119,287				22,800				96,487				—				—
Capital lease obligation			16,868				2,575				6,982				7,114				197
Fixed-price diesel fuel purchase contracts			48,310				29,102				19,208				—				—
Asset retirement obligations			96,870				10,224				29,995				6,368				50,283
Operating lease obligations			8,274				4,503				3,579				192				—
Total		$	534,609			$	69,204			$	401,251			$	13,674			$	50,480

 

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Critical Accounting Policies and Estimates

Basis of Presentation and Principles of Consolidation

The accompanying consolidated financial statements include the accounts and operations of the Partnership and its consolidated subsidiaries and are prepared in conformity with U.S. GAAP. WCC’s cost of acquiring our GP has been pushed-down to establish a new accounting basis for us beginning in the last minuted of December 31, 2014. Accordingly, the accompanying consolidated financial statements are presented for two period, Predecessor and Successor, which relate to the accounting periods preceding and succeeding the completion of the transaction. The Predecessor and Successor periods have been separated by a vertical line on the face of the consolidated financial statements to highlight the facts that the financial information for such periods has been prepared under two-different historical-cost bases of accounting.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

We have provided a summary of all significant accounting policies in Note 2, Summary of Significant Accounting Policies, to the audited consolidated financial statements presented in Westmoreland Resource Partners LP’s Annual Report on Form 10-K for the year ended December 31, 2014. The most significant policies requiring the use of management estimates and assumptions relate to the collectability of accounts receivable, useful lives of fixed assets, valuation of coal reserves, reserve estimates of coal reserves, evaluations of asset impairment, recoverability of advanced royalties, useful lives of intangible assets, fair value of assets and liabilities under purchase accounting, and estimates of future asset retirement obligations. We believe that these significant policies involve a high degree of judgment and/or complexity.

Purchase and Pushdown Accounting

WCC’s acquisition of our GP was accounted for using the acquisition method under ASC 805, Business Combination. Under the acquisition method, the purchase price was allocated to the underlying tangible and intangible assets acquired and liabilities assumed based on their respective fair values. The allocation of the purchase price is preliminary pending the completion of various analyses and the finalization of estimates. During the measurement period (which is not to exceed one year from the acquisition date), additional assets or liabilities may be recognized if new information is obtained about facts and circumstances that existed as of the acquisition date that, if known, would have resulted in the recognition of those assets or liabilities as of that date. The preliminary allocation may be adjusted after obtaining additional information regarding, among other things, asset valuations, liabilities assumed and revisions of previous estimates. These adjustments may be significant and will be accounted for retrospectively.

Per ASC 805-50-25-4 (effective November 18, 2014), we, as an acquiree of WCC through our GP, have the option to apply pushdown accounting in our consolidated financial statements when an acquirer (WCC) obtained control of us. We have chosen adopt pushdown accounting and will reflect purchase accounting adjustments in our consolidated financial statement.

Allowance for Doubtful Accounts

We establish an allowance for losses on accounts receivable when it is probable that all or part of an outstanding balance will not be collected. Our management regularly reviews the probability that a receivable will be collected and establishes or adjusts the allowance as necessary.

 

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Inventory

Inventories, which include materials and supplies as well as raw coal, are stated at the lower of cost or market. Cost is determined using the average cost method. Coal inventory costs include labor, supplies, equipment, operating overhead and other related costs.

Property, Plant and Equipment

Property, plant and equipment are recorded at cost. Expenditures that extend the useful lives of existing plant and equipment or increase productivity of the assets are capitalized. Maintenance and repair costs that do not extend the useful life or increase productivity of the asset are expensed as incurred. Coal reserves are recorded at cost, or at fair value originally in the case of acquired businesses and application of pushdown accounting.

Coal reserves, mineral rights and mine development costs are depleted based upon estimated recoverable proven and probable reserves. Plant and equipment are depreciated on a straight-line basis over the assets’ estimated useful lives.

We assess the carrying value of our property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability is measured by comparing estimated undiscounted cash flows expected to be generated from such assets to their net book value. If net book value exceeds estimated cash flows, the asset is written down to fair value. When an asset is retired or sold, its cost and related accumulated depreciation and depletion are removed from the accounts. The difference between the net book value of the asset and proceeds on disposition is recorded as a gain or loss. Fully depreciated plant and equipment still in use are not eliminated from the accounts. Amortization of capital leases is included in depreciation, depletion and amortization.

Advanced Coal Royalties

A substantial portion of our reserves are leased. Advanced coal royalties are advance payments made to lessors under terms of lease agreements that are typically recoupable through an offset or credit against royalties payable on future production. We write-off advanced coal royalties when recoverability is no longer probable based on future mining plans.

Intangible Assets

Identifiable intangible assets acquired in a business combination must be recognized and reported separately from goodwill. In August 2007 we recorded intangible assets associated with certain customer relationships at fair value. These balances arose from the purchase accounting for our acquisition of Oxford Mining and its subsidiaries and were amortized over their expected useful lives until December 31, 2014.

In December 2014, in conjunction with the WCC transactions, we have identified a favorable terminal lease at the Bellaire dock resulting from more favorable market prices than contracted prices in lease agreements as measured during a business combination. These intangible assets are amortized on a straight-line basis over the respective periods of the lease agreements.

Asset Retirement Obligations

Our asset retirement obligations, or ARO, primarily consists of estimated costs to reclaim surface land and support facilities at our mines and in accordance with federal and state reclamation laws as established by each mining permit.

 

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We estimate ARO for final reclamation and mine closure based upon detailed engineering calculations of the amount and timing of the future costs for a third party to perform the required work. These estimates are based on projected pit configurations at the end of mining and are escalated for inflation, and then discounted at a credit adjusted risk-free rate. We record mineral rights associated with the initial recorded liability. Mineral rights are amortized based on the units of production method over the estimated recoverable, proven and probable reserves at the related mine, and the ARO is accreted to the projected settlement date. Changes in estimates could occur due to revisions of mine plans, changes in estimated costs, and changes in timing of the performance of reclamation activities.

Warrants

In connection with our refinancing in June 2013, certain of the second lien lenders and lender affiliates received warrants entitling them to purchase common and subordinated units under a freestanding contract. The subordinated warrants were canceled on December 31, 2014. Pursuant to Financial Accounting Standards Board’s Accounting Standards Board’s Codification Topic 470-20, “Debt With Conversion and Other Options” (ASC 470-20), freestanding contracts that are settled in a company’s own stock, including common and subordinated unit warrants, are to be designated as an asset, liability or equity instrument. Both the common and subordinated unit warrants were determined to be liabilities and were recorded at fair value as determined using the Black-Scholes Pricing Model. ASC 470-20 further requires that the warrants’ fair value be remeasured each reporting period, with the change in fair value being reported in the consolidated statements of operations. Fair value determinations prepared using the Black-Scholes Pricing Model require assumptions related to interest rates, unit price, exercise price, term and volatilities.

Revenue Recognition

Revenue from coal sales is recognized at the time title and risk of loss passes to the customer in accordance with the terms of the underlying sales agreements and after any contingent performance obligations have been satisfied. Coal sales prices are subject to premiums and reductions based on variations in coal quality delivered versus specifications in our coal supply contracts, but such adjustments are typically confirmed in a matter of days. Risk of loss typically transfers to the customer at the mine or dock, when the coal is loaded on the rail, barge, or truck.

Royalty revenue relates to coal reserves which we lease to a third party and oil and gas rights.

Non-coal revenue consists primarily of clay and limestone sales, service fees, and other miscellaneous revenue. Clay and limestone sales relate to material we recover during the coal mining process and sell to third parties. Service fees are earned for operating a coal unloading facility, providing river barge loading services, and hauling ash. Periodically, we recognize miscellaneous revenue related to lost coal claims that result from granting third-party right-of-way access through small portions of various mine complexes.

Recent Accounting Pronouncements

In April 2014, the FASB issued ASU 2014-8, Presentation of Financial Statements and Property, Plant and Equipment, which changes the presentation of discontinued operations on the statements of operations and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held for sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. The new guidance is effective for interim and annual periods beginning after December 15, 2014. We adopted ASU 2014-8 effective January 1, 2015.

 

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In August 2014, the FASB issued ASU 2014-17, Pushdown Accounting, which allows entities the option to elect pushdown of purchase accounting each time there is a change-in-control event in which an acquirer obtains control of an acquiree. If an acquiree does not initially elect to apply pushdown accounting upon a change-in-control event, it can subsequently elect to apply pushdown accounting to its most recent change-in-control event in a later reporting period as a change in accounting principle. Once made, the election to apply pushdown accounting is irrevocable. Entities applying pushdown accounting are required to measure the individual assets and liabilities of the acquired entity based on the measurement guidance in ASC 805, including the recognition of goodwill. However, any bargain purchase gain recognized by the acquirer should not be recognized in the acquiree’s income statement, but rather as an adjustment to additional paid-in capital. Acquisition-related debt is recognized by the acquiree only if the acquired entity is required to recognize a liability for debt in accordance with other applicable guidance. See our application of ASU 2014-17 in Note 2 of Westmoreland Resource Partners LP’s Form 10-Q for the period ended March 31, 2015.

In April 2015, the FASB issued ASU 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, which requires that debt issuance costs related to a recognized liability, be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The new guidance should be applied on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. Upon transition, an entity is required to comply with the applicable disclosures for a change in an accounting principle. These disclosures include the nature of and reason for the change in accounting principle, the transition method, a description of the prior-period information that has been retrospectively adjusted, and the effect of the change on the financial statement line items (i.e., debt issuance cost asset and the debt liability). The new guidance is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years, with early adoption permitted for financial statements that have not been previous issued. Management projects the impact to the financial statements resulting in balance sheet reclassification for which the Deferred financing costs, net account is recharacterized as a contra-liability reducing the Long-term debt, less current installments balance for each of the respective periods upon adoption.

In May 2014, the FASB issued ASU 2014-9, Revenue From Contracts With Customers, which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The ASU is based on the principle that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration which the entity expects to be entitled to receive in exchange for those goods or services. The ASU also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to fulfill a contract. Entities have the option of using either a full retrospective or a modified retrospective approach for the adoption of the new standard. In April 2015, the FASB agreed to propose a one-year deferral of the revenue recognition standard’s effective date. The new guidance is now effective for the interim and annual periods beginning after December 15, 2017; early application is permitted, but not before the original effective date (annual reporting periods beginning after December 15, 2016). We are currently assessing the impact that this standard will have on our consolidated financial statements.

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements-Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern, which is intended to define management’s responsibility to evaluate whether there is substantial doubt about an organization’s ability to continue as a going concern and to provide related footnote disclosures. Under U.S. GAAP, financial statements are prepared based on the presumption that the reporting organization will continue to operate as a going concern, except in limited circumstances. Financial reporting under this presumption is commonly referred to as the going concern basis of accounting. The going concern basis of accounting is critical to financial reporting because it establishes the fundamental basis for measuring and classifying assets and

 

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liabilities. Currently, U.S. GAAP lacks guidance about management’s responsibility to evaluate whether there is substantial doubt about the organization’s ability to continue as a going concern or to provide related footnote disclosures. This ASU provides guidance to an organization’s management, with principles and definitions that are intended to reduce diversity in the timing and content of disclosures that are commonly provided by organizations today in the financial statement footnotes. The new guidance is effective for the interim and annual periods beginning after December 15, 2016; early adoption is permitted for annual or interim reporting periods for which the financial statements have not previously been issued.

Off-Balance Sheet Arrangements

In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees and financial instruments with off-balance sheet risk, such as letters of credit and surety, performance, and road bonds. No liabilities related to these arrangements are reflected in our consolidated balance sheet, and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these arrangements.

Federal and state laws require us to secure certain long-term obligations, such as ARO, and contractual performance. Historically, we secured these obligations with surety bonds supported by letters of credit. Subsequent to our 2014 refinancing, we have supported our surety bonds with cash deposits.

As of March 31, 2015, we had $131.0 million of surety bonds outstanding to secure certain reclamation obligations. Additionally, as of March 31, 2015, we had $32.8 million of cash deposits in support of these bonds. Further, as of March 31, 2015, we had $0.5 million of road bonds and $2.9 million of performance bonds outstanding that required no security. We believe these bonds and letters of credit will expire without any claims or payments thereon, and accordingly we do not expect any material adverse effect on our financial condition, results of operations or cash flows therefrom.

 

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OUR INDUSTRY

Introduction

Coal is an abundant and relatively inexpensive natural resource that is used as fuel for electric power generation and is a key input for certain types of steel manufacturing. Coal is categorized as either thermal coal or metallurgical coal. Thermal coal is used by utilities and power producers to generate electricity, and metallurgical coal is used by steel companies to produce metallurgical coke for use in the steel making process. Thermal coal comprises the vast majority of total coal production.

Coal is the most wide-spread fossil fuel in the world, and more than 75 countries have coal deposits. According to the World Energy Council’s (WEC) World Energy Resources 2013 Survey, global reserves of coal totaled 983 billion tons at the end of 2013. This figure implies a reserve-to-production ratio of greater than 100 years at current production levels. According to the EIA, U.S. recoverable coal reserves totaled 257 billion tons at the end of 2013.

Our Industry Segment

We operate within the U.S. coal industry and are a low-cost producer and marketer of high-value thermal coal to U.S. utilities and industrial users, and we are the largest producer of surface mined coal in Ohio. We market our coal primarily to large electric utilities with coal-fired, base load scrubbed power plants under coal sales contracts. We focus on acquiring thermal coal reserves that we can efficiently mine with our large-scale equipment.

Our mines are principally located in Northern Appalachia and the Illinois Basin and, following the Contribution, will include the Kemmerer Mine in southwestern Wyoming. In 2014, coal production from the Appalachian region and the western United States represented approximately 27% and approximately 55% of total U.S. coal production, respectively. According to the EIA, production from the two regions is expected to grow from an estimated 809 million tons in 2014 to 867 million tons by 2025.

The Northern Appalachian region boasts lower production costs relative to the Central Appalachian basin to the south. As a result, it has been expanding production and it continues to attract market share and employees from the Central Appalachian basin which is burdened with a high cost of mining. In 2014, total production from the Northern Appalachian basin was approximately 128 million tons and is expected to increase to 136 million tons by the end of 2020. In 2014, total production from Wyoming and the Rocky Mountain regions was approximately 431 million tons and is expected to increase to approximately 477 million tons by the end of 2020.

Coal Production By Region

(tons in millions)

 

Source: EIA, as of May 2015

 

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The majority of our production directly associated with, and contractually linked to, the respective coal-fueled power generators we supply. We primarily serve the regional electricity markets of Indiana, Kentucky, Michigan, Ohio, Pennsylvania and West Virginia and, following the Contribution, Wyoming. Coal is the primary source of fuel for power generation in these markets, and the majority of the power plants we serve in these regions are base load power generation sources with minimal risk of closure or natural gas switching in the next five years.

Electric Power: Energy Consumption by Source

 

		East North Central				East South Central				Middle Atlantic				South Atlantic				Mountain
Coal			63	%			56	%			22	%			46	%			53	%
Natural Gas			7	%			17	%			30	%			20	%			21	%
Nuclear			25	%			22	%			36	%			28	%			9	%
Renewable			5	%			6	%			9	%			4	%			17	%
Other			1	%			0	%			3	%			2	%			0	%
Total			100	%			100	%			100	%			100	%			100	%

Source: EIA, as of May 2015.

Transportation

Transportation is a significant component of the total cost of coal at a customer’s point of usage. The cost to transport coal from the mine to the customer can be large relative to the value of the coal as an energy source. Coal produced in the United States for domestic consumption is generally sold FOB by the coal producer at the mine or terminal, and the purchaser normally bears the transportation costs from the FOB point. Our reserves and operations are well positioned to serve our primary market areas minimizing transportation routes.

Coal Industry Trends

The EIA estimates the U.S. coal industry produced approximately 987 million tons of coal in 2014, a .02% increase over production in 2013, and consumed approximately 933 million tons of coal in 2014, of which approximately 93% was used for electricity power generation. Coal consumption is expected to grow to more than 1,005 million tons in the U.S. by 2025.

U.S. Coal Consumption

(tons in millions)

 

		2012A				2013A				2014E				2015E				2025E
Electric Power			824				858				865				854				935
Industrial			43				43				44				43				47
Steel Production			21				21				21				21				21
Commercial/Institutional			2				2				2				2				2
Coal-to-Liquids			—				—				—				—				—
Total U.S. Coal Consumption			889				925				933				921				1,005

Source: EIA, as of May 2015.

Coal continues to be the leading fuel source of U.S. electricity power generation, and according to the EIA represented approximately 40% of the fuel used in net electricity generation in the U.S. in 2014. Coal is currently the lowest cost fossil fuel used in electric generating plants as it is less expensive than natural gas or oil. The EIA projects coal prices to be $2.34 per MBTU for 2015, while natural gas is projected to be $4.54 per MBTU, or

 

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approximately twice the price of coal for 2015. The EIA estimates the average fuel prices per million BTU to electricity generators, using coal and competing fossil fuel power generation alternatives, as follows:

Average Fossil Fuel Cost for Electricity Generation

(Dollars per million BTU)

 

Electricity Generation Type		2012A				2013A				2014E				2015E				2025E
Distillate Fuel Oil		$	23.76			$	24.04			$	23.56			$	17.19			$	25.77
Residual Fuel Oil		$	20.52			$	18.89			$	20.32			$	11.87			$	16.34
Natural Gas		$	3.47			$	4.40			$	5.12			$	4.54			$	7.72
Coal		$	2.37			$	2.34			$	2.31			$	2.34			$	3.13

Source: EIA, as of May 2015.

U.S. Scrubber Market

Utilities in the United States are increasingly purchasing coal based on heat content (measured in dollars per million BTUs) rather than on a sulfur content basis as sulfur mitigation systems, or scrubbers, are installed by utilities to comply with increasingly stringent emissions requirements required of the Clean Air Act (“CAA”) and other state and federal air regulations. The Northern Appalachian basin is characterized by high-BTU coal. Coal with higher heat content generally commands higher prices because less coal is needed to generate a given quantity of electric power.

Coal produced in the Northern Appalachian basin competes favorably against other coal basins due to its low delivered cost, high heat content, and access to a vast network of transportation outlets for broad consumption across the eastern United States. The CAA amendments restricted emissions of sulfur dioxide by electric utilities, which caused most utilities to comply with the new regulations by using lower sulfur coal or by purchasing sulfur emission credits. However, as the emission regulations have continued to evolve to include the CSAPR (in effect January 2015), Mercury and Air Toxics Standards (“MATS”) (in effect April 2015) and other recent EPA and state regulations, these compliance strategies have become less effective and, as a result, most utilities in our core market have elected to install scrubbers at their coal-fired base load electric generating facilities to meet air emission requirements.

In its 2015 Annual Energy Review, the EIA estimates that compliance with MATS, coupled with low natural gas prices and competition from renewables, will lead to the projected retirement of 31 gigawatts of coal-fired generating capacity and the conversion of 4 gigawatts of coal-fired generating capacity to natural gas between 2014 and 2016. However, coal consumption is expected to be supported by an increase in output from the remaining coal-fired power plants, with the projected capacity factor for the U.S. coal fleet increasing from 60% in 2013 to 67% in 2016.

 

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OUR BUSINESS

The historical financial statements of Kemmerer included in this prospectus reflect the assets, liabilities and operations, excluding the post-retirement medical benefit liability, the pension obligation and related deferred tax assets and liabilities, to be contributed to us by WCC and various wholly-owned subsidiaries in the Contribution. We refer to these assets, liabilities and operations combined with our pre-existing assets, liabilities and operations as the assets, liabilities and operations, as WRPS. The following discussion analyzes the financial condition and results of operations of WRPS. You should read the following discussion of the financial condition and results of operations for WRPS in conjunction with the historical combined financial statements and notes of WRPS and the pro forma financial statements for WRPS included elsewhere in this prospectus.

Overview

We are a growth-oriented, low-cost producer and marketer of high-value thermal coal to United States utilities and industrial users, and we are the largest producer of surface mined coal in Ohio. We market our coal primarily to large electric utilities with coal-fired, base load scrubbed power plants under coal sales contracts. We focus on acquiring thermal coal reserves that we can efficiently mine with our large-scale equipment. Our reserves and operations are well positioned to serve our primary market areas of the Midwest and northeastern United States and, following the Contribution (as defined below), the Rocky Mountain region. We have a significant transportation cost advantage compared to other coal producers in our primary market areas that incur higher transportation rates to deliver coal.

As of March 31, 2015, management estimates that we owned or controlled approximately 104.1 million tons of coal reserves, of which we have leased or subleased approximately 53.6 million tons of reserves to others. These estimates are based on an initial evaluation, as well as subsequent acquisitions, dispositions, depletion of reserves, changes in available geological or mining data and other factors.

We enter into long-term supply contracts (one year or greater in duration) with substantially all of our customers. These contracts allow customers to secure a dependable supply for their future needs and provide us with greater predictability of sales volumes and prices. For the year ended December 31, 2014, approximately 96.9% of our coal tons sold were sold under long-term supply contracts with an average remaining life of 3.2 years. On a pro forma basis after giving effect to the Contribution, for the year ended December 31, 2014, approximately 99.1% of our coal tons sold were sold under long-term supply contracts with a weighted-average remaining life of 5.8 years. We sell the remainder of our coal through short-term contracts and on the spot market.

We operate in a single business segment and have four operating subsidiaries, Oxford Mining, WKFCH, Harrison Resources and Oxford Mining Kentucky. Oxford Mining primarily utilizes surface mining techniques to mine domestic coal and prepare it for sale to our customers, or leases our controlled coal reserves to others. WKFCH and Harrison Resources own and hold coal reserves. WKFCH’s coal reserves are leased to a subsidiary of WCC, from which WKFCH earns a per ton coal royalty. Harrison Resources coal reserves are surface mined and marketed by Oxford Mining.

In December 2014, WCC completed its acquisition of our general partner and contributed the WKFCH royalty-bearing coal reserves to us in exchange for common units. In connection with the transaction, we changed our name, restructured our partnership agreement, made a one-time special distribution to our public common unitholders and refinanced our credit facilities. See “—WCC Transactions” below.

 

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The following table summarizes our mining complexes, our coal production for the year ended December 31, 2014 and our pro forma coal reserves as of March 31, 2015, after giving effect to the closing of the Contribution:

 

Mining Complex		Pro Forma Production for the Year Ended December 31, 2014				Pro Forma As of March 31, 2015
						Total Proven & Probable Reserves				Proven Reserves				Probable Reserves				Average Heat Value (BTU/lb)				Average Sulfur Content (%)				Primary Transportation Methods
		(tons in thousands)
Surface Mining Operations:
Northern Appalachia (principally Ohio):
Cadiz			3,074				7,283				6,540				743				11,350				2.7	%		Barge, Rail, Truck
Tuscarawas County			1,185				5,716				5,716				—				11,775				4.1	%		Truck
Plainfield			—				3,447				3,447				—				11,703				4.4	%		Truck
Belmont County			403				10,547				9,928				619				11,804				4.3	%		Barge, Truck
New Lexington			685				5,945				5,424				521				11,177				4.1	%		Rail, Truck
Noble County			251				1,310				1,294				16				11,239				4.8	%		Barge, Truck
Illinois Basin (Kentucky):
Muhlenberg County(1)			—				16,296				15,165				1,131				11,314				3.6	%
Rocky Mountain Region (Wyoming):
Kemmerer(2)			4,399				94,297				85,430				8,867				9,818				0.6	%		Conveyor, Rail, Truck
Total Surface Mining Operations			9,997				144,841				132,944				11,897
Coal Reserves Leased to Others:
Kemmerer(3)							29,226				29,226				—				9,818				0.6	%
Tusky							24,331				18,965				5,366				12,900				2.1	%
Total Coal Reserves Leased to Others							53,557				48,191				5,366

 

(1)

In 2013, we idled our Illinois Basin operations. We are seeking to sell the remaining Illinois Basin equipment, consisting of a large-capacity shovel and several smaller pieces of equipment, and would consider offers to purchase the remaining coal reserves and/or facilities related to our Illinois Basin operations.

(2)

Amounts shown are pro forma assuming the closing of the Contribution occurred on January 1, 2014 for production data and March 31, 2015 for reserves data. We intend to close the Contribution concurrently with the closing of the issuance of common units in this offering, but there is no assurance that it will be completed on its terms or at all. Our completion of the Contribution is subject to several conditions including, among other things, the closing of the issuance of common units in this offering. Amounts shown for the Kemmerer Mine (as defined below) include the Kemmerer coal reserves that are currently leased to a subsidiary of WCC.

(3)

In December 2014, pursuant to a contribution agreement, WCC contributed to us 100% of the membership interests in WKFCH. WKFCH holds fee simple interests in 30.4 million tons of coal reserves and related surface lands at the Kemmerer Mine. In connection with the transaction, WKFCH entered into a coal mining lease with respect to these coal reserves with a subsidiary of WCC pursuant to which we will earn a per ton royalty as these coal reserves are mined. Following the Contribution, the coal mining lease for the Kemmerer reserves will become an intercompany obligation that we expect would be eliminated in consolidation.

WCC Transactions

Acquisition of Oxford Resources GP, LLC

On December 31, 2014, pursuant to a Purchase Agreement dated October 16, 2014, WCC acquired, for $33.5 million in cash, 100% of the equity of our general partner from (i) the holders of all of our general

 

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partner’s outstanding Class A Units, AIM Oxford Holdings, LLC (“AIM”) and C&T Coal, Inc. (“C&T”), (ii) the holders of all of our general partner’s outstanding Class B Units, certain present and former executives of our general partner, and (iii) the holders of all of the outstanding warrants for our general partner’s Class B Units, certain affiliates of our former second lien term loan lenders (the “Warrantholders”). At the same time, WCC also acquired, for no additional consideration, (i) 100% of the Partnership’s outstanding subordinated units from AIM and C&T which were then converted to liquidation units, and (ii) 100% of the Partnership’s outstanding warrants for subordinated units from the Warrantholders, which warrants were then canceled by WCC.

Initial Kemmerer Contribution

In December 2014, pursuant to a contribution agreement, WCC contributed to us 100% of the membership interests in WKFCH. WKFCH holds fee simple interests in 30.4 million tons of coal reserves and related surface lands at WCC’s Kemmerer Mine in Lincoln County, Wyoming. Such contribution was made in exchange for 4,512,500 post-reverse split common units, resulting in WCC holding approximately 77% of our outstanding limited partner units (on a fully diluted basis) at March 3, 2015, after taking into account the above-mentioned “25% unit dividend.”

In connection with the transaction, WKFCH entered into a coal mining lease with respect to these coal reserves with a subsidiary of WCC pursuant to which we will earn a per ton royalty as these coal reserves are mined. Through the coal leasing arrangement, the mining of the Kemmerer fee coal reserves are expected to generate $5.8 million in average annual royalties over the next three years, with a minimum royalty payment of $1 million per quarter from the start of 2015 through December 31, 2020 and $0.5 million per quarter thereafter through December 31, 2025. Following the Contribution, the coal mining lease for the Kemmerer reserves will become an intercompany obligation that we expect would be eliminated in consolidation.

Upon acquiring the Kemmerer operations, all royalty revenues recognized by us and royalty expenses recognized by Westmoreland Kemmerer, Inc. under the coal mining lease agreement executed as part of the initial Kemmerer contribution will eliminate in consolidation.

Name Changes

As part of the transactions with WCC, we changed our name from Oxford Resource Partners, LP to Westmoreland Resource Partners, LP. Our general partner also changed its name from Oxford Resources GP, LLC to Westmoreland Resources GP, LLC. Westmoreland Resource Partners, LP is a Delaware limited partnership listed on the New York Stock Exchange (the “NYSE”) under the ticker symbol “WMLP.”

Restructuring of the Partnership

On December 23, 2014 we received unitholder approval for the amendment and restatement of, and effective December 31, 2014 we amended and restated, our limited partnership agreement to, among other things:

 

•

Effect a 12-to-1 reverse split of our common and general partner units;

 

•

Convert all of our outstanding subordinated units to liquidation units (with no distribution or voting rights, other than in connection with a liquidation);

 

•

Waive and eliminate our current cumulative common unit arrearages and also eliminate the concept of common unit arrearages going forward;

 

•

Reset the minimum quarterly distribution to $0.1333 per common unit;

 

•

Reset the incentive distribution rights (the “IDRs”) held by our general partner to provide that the IDRs will be entitled to receive (i) 13% of quarterly distributions over $0.1533 per unit and up to $0.1667 per unit; (ii) 23% of quarterly distributions over $0.1667 per unit and up to $0.2000 per unit; and (iii) 48% of quarterly distributions over $0.2000 per unit; and

 

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•

Suspend the distributions on the IDRs for six quarters, provided that such suspension may be reduced to three quarters if, during the suspension period, additional dropdown transactions aggregating greater than $35.0 million in enterprise value are undertaken by our general partner or affiliates of our general partner that are reasonably expected to provide accretion to per unit common unitholder distributions.

Special Distribution to Public Unitholders

Following the WCC transactions, we made a one-time special distribution to our public unitholders in January 2015. The distribution was made on a pro rata basis, and consisted of a “25% unit dividend” of 0.2 million in additional post-reverse split common units.

Debt Refinancing

In connection with the WCC transactions, we entered into a new credit facility under the 2014 Financing Agreement with the lenders party thereto and U.S. Bank National Association, as Administrative and Collateral Agent, to replace our existing $175 million credit facility. The 2014 Financing Agreement consists of a $175 million term loan, with an option for an additional up to $120 million in term loans for acquisitions if requested by us and approved by the issuing lenders. The 2014 Financing Agreement matures in December 2018 and contains customary financial and other covenants. It also permits distributions to our unitholders under specified circumstances. Borrowings under the 2014 Financing Agreement are secured by substantially all of our physical assets. Borrowings under the 2014 Financing Agreement were used to retire our then existing first and second lien credit facilities and to pay fees and expenses related to the 2014 Financing Agreement, with the limited amount of remaining proceeds being available as working capital.

Competitive Strengths

We believe the following competitive strengths will enable us to execute our business strategies successfully:

 

•

We have an attractive portfolio of long-term coal sales contracts. We believe our long-term coal sales contracts provide us with a reliable and stable revenue base. For the year ended December 31, 2014, approximately 96.9% of our coal tons sold were sold under long-term supply contracts. We currently have long-term coal sales contracts in place for 2015, 2016, 2017 and 2018 that represent approximately 89.3%, 69.3%, 61.3% and 48.0%, respectively, of our 2015 estimated coal sales of 3.5 to 4.0 million tons. These estimates are based on our historical relationship with our customers and management’s knowledge of the customers’ coal requirements and the customers’ other coal supply arrangements. Substantially all of our customers purchase coal for terms of one year or longer, and the customers served by our Kemmerer Mine purchase coal for terms of one year or longer. We also supply coal on a short-term or spot market basis for some of our customers.

 

•

Our sponsor has significant assets and is incentivized to grow our partnership. We believe our ability to grow through acquisitions and organic opportunities is significantly enhanced by our affiliation with WCC, which is one of the largest coal producers in North America (based on 2014 production volume). WCC has an attractive inventory of assets that operate under long-term contracts with high-quality base load power customers and mine-mouth positioning that reduces transportation costs. WCC’s contracts have a weighted-average length of 10 years and a majority provide for customer reimbursement of reclamation expenses. We believe we are an important growth vehicle and a key source of funding for WCC to pursue its business focus on simple surface mining methods, customer proximity and strategically located rail transportation that allow it to be a low cost supplier to its customers. In addition to the Contribution, as well as the contribution by WCC of certain Kemmerer Mine reserves in December 2014 (the “Initial Kemmerer Contribution”), we believe we will have future opportunities to make additional acquisitions with or directly from WCC, although WCC is not obligated to offer us such opportunities and we are not obligated to purchase assets from WCC.

 

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•

We are a low cost producer of coal. We use efficient mining practices that take advantage of economies of scale and reduce our operating costs per ton. According to Wood Mackenzie, our mines achieved first quartile total cash costs in 2014 as compared to other thermal coal mines in the U.S. Appalachian region. Our use of large scale equipment, our good labor relations with our workforce, the expertise of our general partner’s employees and their knowledge of our mining practices, our low level of legacy liabilities and our history of acquiring reserves without large up-front capital investments have positioned us as one of the lowest cash cost thermal coal producers in Northern Appalachia. Our logistics infrastructure and proximity to coal-fired power plants in our primary market areas provide us with operational and marketing flexibility, reduce the cost to deliver coal to our core markets and allow us to realize higher prices net of transportation costs than competitors in our primary market areas without such transportation advantages. We believe that our strategically located operations provide us with a significant transportation cost advantage compared to many of our competitors for deliveries to customers in our existing core markets and, following the Contribution, the market served by Kemmerer.

 

•

Demand for the coal we produce is expected to increase in our primary market area. According to the United States Energy Information Administration, or EIA, production of coal in Northern Appalachia and the western United States is expected to grow from an estimated 809 million tons in 2014 to 867 million tons by 2025. This expected increase is attributable to anticipated increases in demand for high-sulfur coal from scrubbed power plants and from consumers of Central Appalachia coal as production in that region continues to decline.

 

•

The customer power plants we serve are base load power generators with a low risk of retirement. Our primary power plant customers are located within the PJM Interconnection region which relies heavily on coal for base-load power generation, representing 42% of total operating capacity and 47% of total net generation in 2014. These plants have a variety of scrubbers and environmental controls already that enable them to consume the coal we produce.

 

•

Accomplished management team with proven acquisition and integration record. Our management team has successfully acquired, integrated and optimized multiple mines and businesses including the Kemmerer Mine, Sherritt International’s coal operations, WMLP and the BCC Mine. They have an extensive and diverse background with numerous public and private companies. Since acquiring WMLP in December 2014, management has restarted distributions in conjunction with the contribution of Kemmerer reserves and signed a new coal purchase and sale agreement with AEP.

Business Strategies

Our primary business objective is to consistently increase our quarterly cash distributions to our common unitholders over time by generating stable cash flows from profitable coal production, sales and leases from our asset base. We intend to accomplish this objective by executing the following business strategies:

 

•

Generate stable cash flow supported by long-term coal sales contracts. We primarily serve regional electricity markets in the Midwest and northeastern United States and, following the Contribution, the Rocky Mountain region. We intend to continue to focus on marketing coal to large utilities with coal-fired, base load scrubbed power plants in these areas. In 2014, approximately 47% of the total net electricity generated in our primary PJM market area was supplied by coal-fired power plants, compared to approximately 40% for the rest of the United States. We typically enter into long-term coal sales contracts for substantially all of our coal production, which we expect will continue to reduce our exposure to fluctuations in market prices. Our long-term coal sales contracts typically provide for fixed prices, or a schedule of prices that are either fixed or contain market-based adjustments, over the contract term. In addition, many of our long-term coal sales contracts have full or partial cost pass-through or cost adjustment provisions. For the year ended December 31, 2014, approximately 96.9% of our coal tons sold were sold under long-term supply contracts. As of March 31, 2015, we have 2.6 million, 2.3 million, 1.8 million and 0.9 million coal tons committed and priced under long-term

 

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supply contracts for calendar years 2016, 2017, 2018 and 2019, respectively. On a pro forma basis after giving effect to the Contribution, for the year ended December 31, 2014, approximately 99.1% of our coal tons sold were sold under long-term supply contracts.

 

•

Complete strategic and accretive transactions with our sponsor. Following the Contribution, we intend to continue executing our combined drop-down strategy pursuant to which WCC expects to periodically offer certain of its other U.S. and Canadian coal assets to us in future transactions that we expect will increase our distributable cash flow per unit over time. We believe that WCC’s ownership of our general partner, approximately 77% of our common units (on a fully diluted basis) and all of our incentive distribution rights incentivizes WCC to offer us acquisition opportunities, although it is not obligated to do so.

 

•

Opportunistically pursue strategic acquisitions from third parties. We intend to evaluate opportunities to acquire strategic and economically attractive coal reserves and mining operations from third parties in order to extend the life of our coal reserves and grow our distributable cash flow. We intend to prudently and selectively pursue coal reserves that are adjacent to our existing operations, as well as active mining operations that are complementary to our existing operations. Our management team has a proven record of acquiring and integrating acquisitions and we expect that the strong relationship with our sponsor will expand and enhance the various structuring and financing options available to us.

 

•

Continue to maintain a strong safety record. We have a strong safety record and continue to maintain reportable and lost time incident rates significantly below averages in our mining region. For 2014, our reportable and lost time incident rates of 1.14 and 0.50, respectively, were 47% and 68% below the Appalachian Basin average rates of 2.15 and 1.56, respectively. In 2014, our MSHA Significant and Substantial citation rate per 100 inspection hours was approximately 84% lower than the national average. We have won numerous awards for our strong safety record. We believe that our focus on safety, compliance and continuous improvement promotes greater reliability in our operations, which fosters long-term customer relationships and lower operating costs, which support higher margins. We intend to maintain a strong safety record in all of our operations as a fundamental business principle.

Operations

As of March 31, 2015, we operated 12 active surface mines and managed these mines as six mining complexes located in eastern Ohio. These mining facilities include two preparation plants, both of which receive, wash, blend, process and ship coal produced from one or more of our 12 active mines. Our mines are a combination of area, contour, auger and highwall mining methods using truck/shovel and truck/loader equipment along with large production dozers. We also own and operate seven augers which we move among our mining complexes, as necessary, and two highwall miner systems.

Currently, we own or lease most of the equipment utilized in our mining operations and employ preventive maintenance and rebuild programs to ensure that our equipment is well maintained. The mobile equipment utilized at our mining operations is replaced on an on-going basis with new, more efficient units based on equipment age and mechanical condition. We endeavor to replace the oldest units, thereby maintaining productivity, while minimizing capital expenditures.

As of March 31, 2015, we owned and/or controlled 104.1 million tons of proven and probable coal reserves, of which 50.5 million tons were associated with our surface mining operations, 29.2 million tons were leased to a subsidiary of WCC and the remaining 24.4 million tons consisted of underground coal reserves that we have subleased to a third party in exchange for a royalty. Historically, we have been successful at acquiring reserves with low operational, geologic and regulatory risks, located near our existing mining operations or that otherwise had the potential to serve our primary market area. In 2014, we obtained control of 31.9 million tons of proven and probable coal reserves.

 

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Mining Operations

Northern Appalachia

The following map shows the locations of our Northern Appalachia mining operations and coal reserves and related transportation infrastructure as of March 31, 2015.

 

We operate six surface mining complexes in Northern Appalachia, substantially all of which are located in eastern Ohio. For the year ended December 31, 2014, and for the three months ended March 31, 2015, our mining complexes in Northern Appalachia produced an aggregate of 5.6 million and 1.1 tons of thermal coal, respectively. The following table provides summary information regarding our mining complexes in Northern Appalachia for the years indicated.

 

		Transportation Facilities Utilized				Transportation Method(1)		Number of Active Mines at March 31, 2015				Tons Produced for the Year Ended December 31,
Mining Complex		River Terminal		Rail Loadout								2014				2013				2012
												(in millions)
Cadiz		Bellaire		Cadiz		Barge, Rail, Truck			4				3.1				2.6				2.6
Tuscarawas		—		—		Truck			4				1.2				1.2				0.7
Plainfield		—		—		Truck			—				—				—				0.4
Belmont		Bellaire		—		Barge, Truck			2				0.4				1.0				1.0
New Lexington		—		New Lexington		Rail, Truck			2				0.7				0.8				0.9
Noble		Bellaire		—		Barge, Truck			—				0.2				0.2				0.2
Total									12				5.6				5.8				5.8

 

(1)	Barge means transported by truck to our Bellaire river terminal and then transported to the customer by barge. Rail means transported by truck to a rail facility and then transported to the customer by rail. Truck means transported to the customer by truck.

 

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Cadiz Mining Complex

The Cadiz mining complex, located principally in Harrison County, Ohio, also includes reserves located in Jefferson County, Ohio, and currently consists of the Harrison Resources, Daron, Ellis and Sandy Ridge mines. We began mining operations at this mining complex in 2000. Operations at the Cadiz mining complex target the Pittsburgh #8, Redstone #8A and Meigs Creek #9 coal seams. As of March 31, 2015, the Cadiz mining complex included 7.3 million tons of proven and probable coal reserves. Coal produced from the Cadiz mining complex is trucked either to our Bellaire river terminal on the Ohio River and then transported by barge to the customer, trucked directly to our customer, or trucked to our Cadiz rail loadout facility on the Ohio Central Railroad and then transported by rail to the customer, or trucked to our Strasburg preparation plant then transported by truck to the customer after processing is completed. This mining complex uses the area, contour, auger and highwall miner methods of surface mining. The infrastructure at this mining complex includes three coal crushers, three truck scales and the Cadiz rail loadout. This mining complex produced 3.1 million tons of coal for the year ended December 31, 2014 and 0.6 million tons of coal for the three months ended March 31, 2015.

In early October 2014, Oxford Mining entered into a membership interest redemption agreement with Harrison Resources and CONSOL of Ohio LLC (“CONSOL”) under which Harrison Resources redeemed all of CONSOL’s interest in Harrison Resources. Harrison Resources had been a joint venture owned 51% by Oxford Mining and 49% by CONSOL, and as a result of the redemption Oxford Mining owns 100% of Harrison Resources. In connection with the redemption, Harrison Resources acquired 0.9 million tons of coal reserves from a CONSOL affiliate, and also options to purchase an aggregate of 5.6 million additional tons of coal reserves from a CONSOL affiliate. These tons are in addition to the 2.6 million tons of coal reserves already owned by Harrison Resources. Harrison Resources paid total consideration of $3.6 million in these transactions. These transactions were effective as of October 1, 2014.

Tuscarawas Mining Complex

The Tuscarawas mining complex is located in Tuscarawas, Columbiana and Stark Counties, Ohio, and currently consists of the East Canton, Garrett, Hunt and Stillwater mines. We began mining operations at this mining complex in 2003. Operations at this mining complex target the Brookville #4, Lower Kittanning #5, Middle Kittanning #6, Upper Freeport #7 and Mahoning #7A coal seams. As of March 31, 2015, the Tuscarawas mining complex included 5.7 million tons of proven and probable coal reserves. Coal produced from the Tuscarawas mining complex is transported by truck directly to our customers, our Barb Tipple blending and coal crushing facility or our Strasburg preparation plant. Coal trucked to our Barb Tipple blending and coal crushing facility, our Conesville preparation plant, or our Strasburg preparation plant is then transported by truck to the customer after processing is completed. This mining complex uses the area, contour, auger and highwall miner methods of surface mining. The infrastructure at this mining complex includes three coal crushers with truck scales and the Strasburg blending facility and preparation plant. This mining complex produced 1.2 million tons of coal for the year ended December 31, 2014 and 0.2 million tons of coal for the three months ended March 31, 2015.

Plainfield Mining Complex

The Plainfield mining complex is located in Muskingum, Guernsey and Coshocton Counties, Ohio, and is currently inactive. We began mining operations at this mining complex in 1990. Operations at the Plainfield mining complex target the Middle Kittanning #6 coal seam. As of March 31, 2015, the Plainfield mining complex included 3.4 million tons of proven and probable coal reserves. When operating, the majority of the coal produced from the Plainfield mining complex is trucked to our Barb Tipple facility for crushing and blending or directly to the customer. Coal trucked to our Barb Tipple facility is transported by truck to the customer after processing is completed. Some of the coal production from this mining complex is trucked to our Conesville preparation plant and then transported by truck to the customer. This mining complex uses contour and highwall miner methods of surface mining. The infrastructure at this mining complex includes our Barb Tipple blending

 

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and coal crushing facility, Conesville preparation plant and truck scale. This mining complex produced no coal for the year ended December 31, 2014 and three months ended March 31, 2015. We intend to resume mining at the Plainfield mining complex in 2018.

Belmont Mining Complex

The Belmont mining complex is located in Belmont County, Ohio, and currently consists of the Speidel and Wheeling Valley mines. We began mining operations at this mining complex in 1999. Operations at the Belmont mining complex target the Pittsburgh #8 and Meigs Creek #9 coal seams. As of March 31, 2015, the Belmont mining complex included 10.5 million tons of proven and probable coal reserves. Coal produced from this mining complex is primarily transported to our Bellaire river terminal on the Ohio River and then transported by barge to the customer, or by truck to our Barb Tipple facility or our Conesville preparation plant and then transported by truck to the customer. Coal produced from this mining complex is crushed and blended at the Bellaire river terminal before it is loaded onto barges for shipment to our customers on the Ohio River. This mining complex uses area, contour, auger and highwall miner methods of surface mining. This mining complex produced 0.4 million tons of coal for the year ended December 31, 2014 and 0.2 million tons of coal for the three months ended March 31, 2015.

New Lexington Mining Complex

The New Lexington mining complex is located in Perry, Athens and Morgan Counties, Ohio, and currently consists of the Avondale and New Lexington mines. We began mining operations at this mining complex in 1993. Operations at the New Lexington mining complex target the Lower Kittanning #5 and Middle Kittanning #6 coal seams. As of March 31, 2015, the New Lexington mining complex included 5.9 million tons of proven and probable coal reserves. Coal produced from the New Lexington mining complex is delivered via off-highway trucks to our New Lexington rail loadout facility on the Ohio Central Railroad where it is then transported by rail to the customer or to our Barb Tipple. Some of the coal production from this mining complex is trucked to our Conesville preparation plant and then transported by truck to the customer. This mining complex uses the area and auger methods of surface mining. The infrastructure at this mining complex includes a coal crusher and the New Lexington rail loadout. This mining complex produced 0.7 million tons of coal for the year ended December 31, 2014 and 0.2 million tons of coal for the three months ended March 31, 2015.

Noble Mining Complex

The Noble mining complex is located in Noble and Guernsey Counties, Ohio, and currently consists of the King-Crum mine. We began mining operations at this complex in 2006. Operations at the Noble mining complex target the Pittsburgh #8 and Meigs Creek #9 coal seams. As of March 31, 2015, the Noble mining complex included 1.3 million tons of proven and probable coal reserves. Coal produced from this mining complex is trucked to our Bellaire river terminal on the Ohio River or to our Barb Tipple facility. Coal trucked to our Bellaire river terminal is then transported by barge to the customer. Coal trucked to our Barb Tipple blending and coal-crushing facility is transported by truck to the customer after processing is completed. The Noble mining complex uses the area, contour and auger methods of surface mining. This mining complex produced 0.2 million tons of coal for the year ended December 31, 2014 and less than 0.1 million tons of coal for the three months ended March 31, 2015.

 

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Illinois Basin

The following map shows the locations of our Illinois Basin mining operations and coal reserves and related transportation infrastructure as of March 31, 2015.

 

In December 2013, we idled our surface mining complex in the Illinois Basin, located in western Kentucky. The following table provides summary information regarding our mining complex in the Illinois Basin for the years and periods indicated.

 

Mining Complex		Transportation Facilities Utilized						Transportation Method(1)		Number of Active Mines at March 31, 2015				Tons Produced for the Year Ended December 31,
		River     Terminal		Rail Loadout										2014				2013				2012
														(in millions)
Muhlenberg		Island River			—			Barge, Truck			—				—				0.3				2.2

 

(1)	Barge means transported by truck to the Island river terminal and then transported to the customer by barge. Truck means transported to the customer by truck. While we sold the Island river terminal in April 2014, we retain the right to ship tons through that dock.

Muhlenberg Mining Complex

The Muhlenberg mining complex, located in Muhlenberg and McLean Counties in western Kentucky, is currently inactive. We began mining operations at this mining complex in October 2009. Operations at the Muhlenberg mining complex targeted the #5, #6, #9, #10, #11, #12 and #13 coal seams of the Illinois Basin. As of March 31, 2015, the Muhlenberg mining complex included 16.3 million tons of proven and probable coal reserves. Coal produced from this mining complex was usually crushed at the mine site and then trucked to the

 

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Island river terminal on the Green River or directly to the customer. Coal trucked to the Island river terminal was then transported to the customer by barge. While we sold the Island river terminal in April 2014, we retain the right to ship tons through that dock. This mining complex used the area method of surface mining. The infrastructure at this mining complex includes one coal crusher and one truck scales. This mining complex was idled in December 2013 and remained idled throughout year ended December 31, 2014. We are seeking to sell the remaining Illinois Basin equipment, consisting of a large-capacity shovel and several smaller pieces of equipment, and would consider offers for the remaining coal reserves and/or facilities related to the Illinois Basin operations. None of these assets were classified as held for sale as of March 31, 2015.

Preparation Plants and Blending Facilities

Depending on coal quality and customer requirements, some raw coal may be shipped directly from the mine to the customer. However, the quality of some raw coal does not allow direct shipment to the customer without putting the coal through a preparation process that physically separates impurities from the coal. This processing upgrades the quality and heating value of the coal by removing or reducing sulfur and ash-producing materials, but it entails additional expense and results in some loss of coal. Coals of various sulfur and ash contents can be mixed, or “blended,” at a preparation plant or loading facility to meet the specific combustion and environmental needs of customers. Coal blending helps increase profitability by meeting the quality requirements of specific customer contracts, while maximizing revenue through optimal use of coal inventories. Blending is typically done at one of our four blending facilities:

 

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our Barb Tipple blending and coal crushing facility, adjacent to a customer’s power plant near Coshocton, Ohio;

 

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our Strasburg preparation plant near Strasburg, Ohio;

 

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our Conesville preparation plant in Coshocton County, Ohio, also adjacent to a customer’s power plant near Coshocton, Ohio;

 

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our Bellaire river terminal on the Ohio River in Bellaire, Ohio.

Royalty Revenues

Kemmerer Coal Reserves

Through our subsidiary, WKFCH, we are party to a coal mining lease with a subsidiary of WCC pursuant to which we will earn a per ton royalty as coal reserves owned by WKFCH are mined. Through the coal leasing arrangement, the mining of the Kemmerer fee coal reserves is expected to generate $5.8 million in average annual royalties over the next three years, with a minimum royalty payment of $1 million per quarter from the start of 2015 through December 31, 2020 and $0.5 million per quarter thereafter through December 31, 2025. For the three months ended March 31, 2015, we recognized $1.8 million in coal royalty revenue under the lease for the Kemmerer coal reserves. Following the Contribution, the coal mining lease for the Kemmerer reserves will become an intercompany obligation that we expect would be eliminated in consolidation.

Tusky Coal Reserves

We began underground mining at the Tusky mining complex in late 2003 after leasing coal reserves from a third party in exchange for a royalty based on tons sold. In June 2005, we sold the Tusky mining complex, and subleased the associated underground coal reserves to the purchaser in exchange for a royalty. There are eight years remaining on our lease for the underground coal reserves, and the related sublease. The sublessee has the option at any time after December 31, 2022 to elect to have Oxford assign its interest as “Lessee” and “Sublandlord” to the sublessee for defined and predetermined consideration. For the three months ended March 31, 2015, we did not recognize any royalty revenue on the sublease of the Tusky reserves.

 

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Oil and Gas Reserves

In December 2014, June 2013 and April 2012, we completed the sale of certain oil and gas rights on land in eastern Ohio for $0.2 million, $6.1 million and $6.3 million, respectively, plus future royalties. For the three months ended March 31, 2015, we generated less than $0.1 million in royalty revenue from the receipt of oil and gas royalties.

Limestone Revenues

At our Daron, Pickens, and Strasburg mines, we remove limestone so that we can access the underlying coal. We sell this limestone to a third party that crushes the limestone before selling it to local governmental authorities, construction companies and individuals. The third party pays us for this limestone based on a percentage of the revenue it receives from the limestone sales. For the three months ended March 31, 2015, we generated $0.6 million in limestone sales. Limestone at our Pickens mine was fully depleted in 2014.

Other Revenues

For the three months ended March 31, 2015, we generated $3.3 million of other revenues from a variety of other activities in connection with our surface mining operations. This revenue included the following:

 

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coal handling and transportation service revenue of $2.4 million related to in coal handling and transportation services performed on behalf of a subsidiary of WCC;

 

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coal handling and transportation service revenue of $0.7 million related to in coal handling and transportation services performed on behalf of customer;

 

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clay and dirt sales in addition to service fees we earned for hauling and disposing of ash at a third-party landfill for two municipal utilities total $0.2 million.

For more information regarding our relationships and our former sponsors’ relationships with Tunnel Hill Partners, LP, please read “Certain Relationships and Related Transactions” elsewhere in this prospectus.

Customers

Our primary customers are electric utility companies, predominantly operating in our six-state market area, that purchase coal under long-term coal sales contracts. Substantially all of our current customers purchase coal for terms of one year or longer, but we also supply coal on a short-term or spot market basis for some of our customers. For the year ended December 31, 2014, we derived approximately 99.1% of our total coal revenues from sales to our ten largest customers, with affiliates of the following top three customers accounting for approximately 87.5% of our coal revenues for that period: American Electric Power Company, Inc. (56.7%); FirstEnergy Corp. (16.5%); and East Kentucky Power Cooperative (14.3%). Approximately 32.2% of these sales were facilitated by coal brokers.

Long-term Coal Supply Contracts

As is customary in the coal industry, we enter into long-term supply contracts (one year or greater in duration) with substantially all of our customers. These contracts allow customers to secure a dependable supply for their future needs and provide us with greater predictability of sales volumes and prices. For the year ended December 31, 2014, approximately 96.9% of our coal tons sold were sold under long-term supply contracts. We sell the remainder of our coal through short-term contracts and on the spot market.

The terms of our coal supply contracts result from competitive bidding and extensive negotiations with each customer. Consequently, the terms can vary significantly by contract, and can cover such matters as price adjustment features, price reopener terms, coal quality requirements, quantity adjustment mechanisms, permitted sources of supply, future regulatory changes, extension options, force majeure provisions and termination and

 

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assignment provisions. Force majeure provisions typically allow temporary suspension of performance by our customers or us during the duration of specified events beyond the control of the affected party including, but not limited to, floods, earthquakes, storms, fire, faults in the coal seam or other geologic conditions, other natural catastrophes, wars, terrorist acts, civil disturbances, strikes, transportation delays including lack of suitable railcars and actions or restraints by local, state or federal agencies or regulatory bodies. Some long-term contracts provide for a predetermined adjustment to the stipulated base price at specified times or periodic intervals to account for changes due to inflation or deflation in prevailing market prices.

In addition, most contracts contain provisions to adjust the base price due to new statutes, ordinances or regulations that influence our costs of production. Some of our contracts also contain provisions that allow for the recovery of costs impacted by modifications or changes in the interpretations or application of applicable government statutes.

Price reopener provisions are present in several of our long-term contracts. These price reopener provisions may automatically set a new price based on prevailing market price or, in some instances, require the parties to agree on a new price, sometimes within a specified range. In a limited number of contracts, failure of the parties to agree on a price under a price reopener provision can lead to termination of the contract.

Quality and volume are stipulated in the coal supply contracts. In some instances, buyers have the option to change annual or monthly volumes. Most of our coal supply contracts contain provisions that require us to deliver coal with specific characteristics, such as heat content, sulfur, ash, hardness and ash fusion temperature, that fall within certain ranges. Failure to meet these specifications can result in economic penalties, suspension or cancellation of shipments or termination of the contract.

Supplies

In 2014, we spent more than $118.7 million to procure goods and services in support of our operating business activities, excluding capital expenditures. Principal commodities include repair and maintenance parts and services, fuel, explosives, tires and lubricants. Outside suppliers perform a significant portion of our on- and off-site equipment rebuilds and repairs as well as construction and reclamation activities.

Each of our mining operations has developed its own supplier base consistent with local needs. Additionally, we have a centralized sourcing group for major supplier contract negotiation and administration, and for the negotiation and purchase of major capital goods. Our supplier base has been relatively stable for many years; however, there has been some consolidation. We are not dependent on any one supplier in any region. We promote competition between suppliers and seek to develop relationships with suppliers that focus on lowering our costs. We also seek suppliers who identify and concentrate on implementing continuous improvement opportunities within their area of expertise.

Competition

The markets in which we sell our coal are highly competitive. We compete directly with other coal producers and indirectly with producers of other energy products that provide an alternative to coal. While we do not compete with producers of metallurgical coal or lignite, we do have limited competition from producers of Power River Basin coal (sub-bituminous coal) in our target market area for bituminous coal. We compete on the basis of delivered price, coal quality and reliability of supply. Our principal direct competitors are other coal producers, including (listed alphabetically) Alliance Resource Partners, L.P., Alpha Natural Resources, Arch Coal, Inc., CONSOL, Foresight Energy, Hallador Energy Company, Murray Energy Corp., Patriot Coal Corporation, Peabody Energy Corp., Rhino Resource Partners, L.P. and various other smaller, independent producers.

 

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Reclamation

Reclamation expenses are a significant part of any coal mining operation. Prior to commencing mining operations, a company is required to apply for numerous permits in the state where the mining is to occur. Before a state will approve and issue these permits, it requires the mine operator to present a reclamation plan which meets regulatory criteria and to secure a surety bond to guarantee reclamation funding in an amount determined under state law. Bonding companies require posting of collateral, typically in the form of letters of credit or cash collateral, to secure the bonds. As of March 31, 2015, we had $8.0 million in cash deposits supporting $32.1 million in reclamation surety bonds. While bonds are issued against reclamation liability for a particular permit at a particular site, collateral posted is not allocated to a specific bond, but instead is part of a collateral pool supporting all bonds issued by a particular bonding company. Bonds are released in phases as reclamation is completed in a particular area.

Material Effects of Regulation

We are subject to extensive regulation with respect to environmental and other matters by federal, state and local authorities. Federal laws to which we are subject include the Surface Mining Control and Reclamation Act of 1977, or SMCRA, the Clean Air Act, the Clean Water Act, the Safe Drinking Water Act, the Toxic Substances Control Act, the Endangered Species Act, the Migratory Bird Treaty Act, the Comprehensive Environmental Response, Compensation and Liability Act, the Emergency Planning and Community Right to Know Act and the Resource Conservation and Recovery Act. The United States Environmental Protection Agency, or EPA, and/or other authorized federal or state agencies administer and enforce these laws. We are also subject to extensive regulation regarding safety and health matters pursuant to the United States Mine Safety and Health Act of 1977, which is enforced by the U.S. Mine Safety and Health Administration (“MSHA”). Non-compliance with federal, tribal and state laws and regulations could subject us to material administrative, civil or criminal penalties or other liabilities, including suspension or termination of operations. In addition, we may be required to make large and unanticipated capital expenditures to comply with future laws, regulations or orders as well as future interpretations and more rigorous enforcement of existing laws, regulations or orders. Our reclamation obligations under applicable environmental laws will be substantial.

Safety is a core value of WMLP. We use a grass roots approach, encouraging and promoting employee involvement in safety and accepting input from all employees; we feel employee involvement is a pillar of our safety excellence.

During 2014, and for the 3-months ended March 31, 2015, we continued to maintain reportable and lost time incident rates significantly below Appalachian basin averages, as indicated in the table below.

 

		Three Months Ended March 31, 2015								Year Ended December 31, 2014
		Reportable Rate				Lost Time Rate				Reportable Rate				Lost Time Rate
WMLP Mines			—				—				1.14				0.50
National Surface Coal Averages			1.72				1.19				1.71				1.19

Following passage of The Mine Improvement and New Emergency Response Act of 2006, amending the Federal Mine Safety and Health Act of 1977, MSHA significantly increased the oversight, inspection and enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations. There has also been a dramatic increase in the dollar penalties assessed by MSHA for citations issued over the past two years. The states in which we operate have inspection programs for mine safety and health. Collectively, federal and state safety and health regulations in the coal mining industry are perhaps the most comprehensive and pervasive systems for protection of employee health and safety affecting any segment of U.S. industry.

 

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The following provides brief summaries of certain Federal laws and regulations to which we are subject and their effects upon us:

Surface Mining Control and Reclamation Act

SMCRA establishes minimum national operational, reclamation and closure standards for all surface coal mines. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and following completion of coal mining activities. Permits for all coal mining operations must be obtained from the Federal Office of Surface Mining Reclamation and Enforcement, or OSM, or, where state regulatory agencies have adopted federally approved state programs under SMCRA, the appropriate state regulatory authority. States that operate federally approved state programs may impose standards that are more stringent than the requirements of SMCRA and OSM’s regulations and, in many instances, have done so. Permitting under SMCRA has generally become more difficult in recent years, which adversely affects the availability of coal reserves at our coal mines.

In 1999, a federal court in West Virginia ruled that the stream buffer zone rule issued under SMCRA prohibited most excess spoil fills. While the decision was later reversed on jurisdictional grounds, the extent to which the rule applied to fills was left unaddressed. On December 12, 2008, OSM finalized a rulemaking regarding the interpretation of the stream buffer zone provisions of SMCRA which confirmed that excess spoil from mining and refuse from coal preparation could be placed in permitted areas of a mine site that constitute waters of the United States. That rule, however, was subject to a challenge in federal court. In addition, on November 30, 2009, OSM announced that it would re-examine and reinterpret the regulations finalized eleven months earlier. On February 20, 2014, the federal court vacated the 2008 rule. On December 22, 2014, OSM published the final revisions to the stream buffer zone rule in the Federal Register. The revisions reinstate the previous version of the rule, but do not announce a new interpretation of the rule regarding the ability to construct excess spoil fills. The OSM has also been in the process of developing a “stream protection rule,” which could result in changes to mining operations under the SMCRA program. The OSM has projected that it will issue a proposed stream protection rule in 2015. We cannot predict how these regulations will be applied or how they may affect coal production.

It is our policy to comply in all material respects with the requirements of SMCRA and the state and tribal laws and regulations governing mine reclamation.

Bonding Requirements

Federal and state laws require mine operators to assure, usually through the use of surety bonds, payment of certain long-term obligations, including the costs of mine closure and the costs of reclaiming the mined land. Surety providers are requiring smaller percentages of collateral to secure a bond, which will require us to provide less cash to collateralize bonds to allow us to continue mining. These changes in the terms of the bonds have been accompanied, at times, by an increase in the number of companies willing to issue surety bonds. As of March 31, 2015, we have posted an aggregate of $32.1 million in surety bonds for reclamation purposes, secured by approximately $8.0 million of cash collateral.

Clean Air Act and Related Regulation

The federal Clean Air Act (“CAA”) and comparable state laws that regulate air emissions affect coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations include CAA permitting requirements and emission control requirements relating to air pollutants, including particulate matter, which may include controlling fugitive dust. The CAA indirectly affects coal mining operations by extensively regulating the emissions of particulate matter, sulfur dioxide, nitrogen oxides, mercury and other compounds emitted by coal fired power plants. In recent years, Congress has considered legislation that would require

 

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increased reductions in emissions of sulfur dioxide, nitrogen oxide and mercury, as well as GHGs. The air emissions programs, regulatory initiatives and standards that may affect our operations, directly or indirectly, include, but are not limited to, the following:

 

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Greenhouse Gas Emissions Standards. In April 2012, the EPA proposed new limits on GHG emissions from new electric generating units (“EGUs”) under Section 111 of the CAA (“GHG NSPS”). The proposed limits are referred to as “new source performance standards” because they apply only to new or reconstructed sources. The proposal required all new fossil-fuel-fired EGUs to emit no more than 1,000 pounds of CO2 / megawatt hour on an average annual basis, which is based on the CO2 emissions from natural gas combined cycle facilities. The EPA later indicated its intention to issue a new proposal in light of over two million comments on the April 2012 proposal and ongoing developments in the industry. In June 2013, President Obama directed the EPA to issue that new proposal by September 30, 2013, and to finalize it in a timely manner. In September 2013, the EPA revoked its April 2012 proposal and instead proposed new limits, which would require all new coal-fired EGUs to emit no more than 1,100 pounds of CO2 / megawatt hour on an average annual basis, and new natural gas-fired plants to meet a standard of either 1,000 or 1,100 pounds of CO2 / megawatt hour (depending on size). Under the CAA, new source performance standards like the GHG NSPS have binding effect from the date of the proposal. Once NSPSs are finalized, the EPA must issue guidance to states for the issuance of existing source standards. The GHG NSPS as currently proposed may be a major obstacle to the construction and development of any new coal-fired generation capacity because it is unlikely, with a few possible exceptions, that the limits in the proposal can be achieved by a new coal-fired EGU without the use of carbon capture and sequestration technology. EPA has stated that it will finalize the NSPS in the summer of 2015. The finalization of the NSPS is a predicate for issuance of existing source performance standards under Section 111(d) of the CAA. In June of 2014, EPA proposed existing source standards for fossil-fuel fired power plants, which EPA refers to as the Clean Power Plan. EPA’s proposal mandates GHG emission “goals” for each state, beginning in 2020 with reductions through 2030, based on EPA’s assessment of the “best system of emission reduction,” including (1) average heat rate improvements of 6% for coal-fired power plants; (2) the re-dispatch of power based on an assumption that underutilized capacity at natural gas combined cycle facilities can be increased to 70%; (3) the substitution of coal generation with renewable energy; and (4) cumulative annual energy savings rates of 1.5% based on demand-side energy efficiency programs. EPA plans to finalize the rule in the summer of 2015. Once finalized, the states have one year to submit plans to EPA to implement and enforce the state-specific BSER. EPA has stated that if finalized, the Plan would reduce GHG emissions from the power sector by 30 percent from 2005 levels, due primarily to reduced generation at coal-fired power plants. The Clean Power Plan has been the subject of many lawsuits, challenging, among other things, the EPA’s power to promulgate the rule. If the Clean Power Plan is passed as proposed, and withstands legal challenges, it is projected to have an adverse impact on the demand for coal nationally.

 

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Mercury Air Standards. In February 2012, the EPA published national emission standards under Section 112 of the CAA setting limits on hazardous air pollutant emissions from coal- and oil-fired EGUs. The “Mercury Air Toxics Standards,” or “MATS Rule,” is expected to be one of the most costly rules ever issued by the EPA. It has also proven highly controversial, drawing numerous legal challenges in the U.S. Court of Appeals for the D.C. Circuit as well as petitions for administrative reconsideration filed with the EPA. While the MATS Rule will generally require all coal- and oil-fired EGUs to reduce their hazardous air pollutant emissions, it is particularly problematic for any new coal-fired sources. This is because the new-source limits are so low that they cannot be accurately measured and vendors of pollution control equipment have said they cannot provide commercial guarantees that the limits can be achieved. And because such guarantees are a precondition to obtaining financing in the marketplace, the MATS Rule effectively amounts to a ban on the construction of new coal-fired EGUs. In July 2012, however, the EPA agreed to reconsider the new source standards in response to requests by industry. In November 2012, the EPA published proposed new source standards with revised, less stringent, emission limits. In April 2013, the EPA published new source limits under the

 

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MATS Rule, and then in June 2013, the EPA reopened for 60 days the public comment period on certain startup and shutdown provisions included in the November 2012 proposal. In June 2013, certain environmental organizations and industry groups filed appeals of the rule as revised. The D.C. Circuit upheld the standards, but the Supreme Court accepted certiorari and will hear an industry challenge in 2015.

 

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National Ambient Air Quality Standards (“NAAQS”) for Criteria Pollutants. The CAA requires the EPA to set standards, referred to as NAAQS, for six common air pollutants, including nitrogen oxide and sulfur dioxide. Areas that are not in compliance (referred to as non-attainment areas) with these standards must take steps to reduce emissions levels. Meeting these limits may require reductions of nitrogen oxide and sulfur dioxide emissions. Although our operations are not currently located in non-attainment areas, we could be required to incur significant costs to install additional emissions control equipment, or otherwise change our operations and future development if that were to change. On June 22, 2010, the EPA published a final rule that tightens the NAAQS for sulfur dioxide. EPA finalized designations for the sulfur dioxide NAAOS in 2013 for a handful of counties and delayed designations for the remainder of the country. On March 2, 2015, EPA entered into a consent decree which requires areas with certain large sources of sulfur dioxide emissions, such as coal-fired power plants, to be designated by July 2, 2016. EPA also published guidance allowing remaining states to characterize sulfur dioxide levels through modeling and monitoring and establishing deadlines for state recommendations. On February 17, 2012, the EPA published final NAAQS for nitrogen dioxide, following finalized nonattainment designations for nitrogen dioxide in January 2012. On January 15, 2013, the EPA published final NAAQS for particulate matter; the EPA lowered the annual standard for particles less than 2.5 micrometers in diameter but maintained the NAAQS for particles less than 10 micrometers in diameter. In 2008, the EPA finalized the current 8-hour ozone standard. The EPA agreed to reconsider the standard, and in 2010 the EPA proposed to further reduce the standard. Under orders from President Obama, this NAAQS was not finalized. In December 2014, EPA proposed to lower the primary ozone standard to between 65 ppb and 70 ppb from the current standard of 75 ppb, which would result in disproportionate impacts on the western U.S. EPA is obligated by court order to finalize the standards by October of 2015. We do not know whether or to what extent these developments might affect our operations or our customers’ businesses.

 

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Clean Air Interstate Rule and Cross-State Air Pollution Rule. (“CAIR”) and Cross-State Air Pollution Rule (“CSAPR”). The CAIR calls for power plants in 28 states and the District of Columbia to reduce emission levels of sulfur dioxide and nitrogen oxide pursuant to a cap-and-trade program similar to the system now in effect for acid rain. In 2008, the U.S. Court of Appeals for the District of Columbia Circuit found that the CAIR was fatally flawed, but ultimately agreed to allow it to remain in place pending the EPA’s development of a replacement rule because of concerns about potential disruptions. In June 2011, the EPA finalized the CSAPR as a replacement rule to the CAIR, which requires 28 states in the Midwest and eastern seaboard of the United States to reduce power plant emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states. Under the CSAPR, the first phase of the nitrogen oxide and sulfur dioxide emissions reductions would commence in 2012 with further reduction effective in 2014. On December 15, 2011, the EPA finalized a supplemental rule making to require Iowa, Michigan, Missouri, Oklahoma and Wisconsin to make summertime reductions to nitrogen oxide emissions under the CSAPR ozone-season control program. However, on December 30, 2011, the U.S. Court of Appeals for the District of Columbia Circuit stayed the implementation of CSAPR pending resolution of judicial challenges to the rules and ordered the EPA to continue enforcing the CAIR until the pending legal challenges have been resolved. In August 2012, the U.S. Court of Appeals vacated the CSAPR in a 2-to-1 decision and left the CAIR standards in place. In January 2013, the court rejected the EPA’s request for en banc review. In March 2013, the Solicitor General’s office, on behalf of the EPA, and separately certain non-governmental organizations, filed petitions for writs of certiorari with the U.S. Supreme Court seeking review of the U.S. Court of Appeals decision, and the U.S. Supreme Court granted those petitions in June 2013. The Supreme Court reversed the D.C. Circuit and upheld the rule, but remanded the case to the D.C. Circuit for further proceedings, which are ongoing. EPA issued an

 

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interim final rule in December 2014 that would require the first phase of reductions in 2015 and 2016, with the second phase of reductions beginning in 2017.

 

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Other Programs. A number of other air-related programs may affect the demand for coal and, in some instances, coal mining directly. For example, the EPA has initiated a regional haze program designed to protect and improve visibility at and around national parks, national wilderness areas and international parks. The EPA’s new source review program under certain circumstances requires existing coal-fired power plants, when modifications to those plants significantly change emissions, to install the more stringent air emissions control equipment required of new plants, and concerns about potential failures to comply have resulted in a number of high-profile enforcement actions and settlements over the years resulting in some instances in settlements under which operators install expensive new emissions control equipment. A number of pending regulatory changes and court actions are affecting the scope of the EPA’s new source review program, which under certain circumstances requires existing coal-fueled power plants to install the more stringent air emissions control equipment required of new plants. The new source review program is continually revised and such revisions may impact demand for coal nationally, but we are unable to predict the magnitude of the impact. The Acid Rain program under Title IV of the CAA continues to impose limits on overall sulfur dioxide and nitrogen oxide emissions from regulated EGUs. In June 2013, President Obama issued a Climate Action Plan, which included a focus on methane reductions from coal mines. In January 2015, the Administration issued its methane strategy, but it did not include requirements for coal mines. Indeed, in 2014 the D.C. Circuit upheld EPA’s decision not to list coal mines as a category of air pollution sources that endanger public health or welfare under Section 111 of the CAA and establish standards to reduce emissions from coal mines.

Climate Change Legislation and Regulations

Numerous proposals for federal and state legislation have been made relating to greenhouse gas, or GHG, emissions (including carbon dioxide) and such legislation could result in the creation of substantial additional costs in the form of taxes or required acquisition or trading of emission allowances. Many of the federal and state climate change legislative proposals use a “cap and trade” policy structure, in which GHG emissions from a broad cross section of the economy would be subject to an overall cap. Under the proposals, the cap would become more stringent with the passage of time. The proposals establish mechanisms for GHG sources such as power plants to obtain “allowances” or permits to emit GHGs during the course of a year. The sources may use the allowances to cover their own emissions or sell them to other sources that do not hold enough emissions allowances for their own operations. Some states, including California, and a number of states in the northeastern and mid-Atlantic regions of the U.S. that are participants in a program known as the Regional Greenhouse Gas Initiative (often referred to as “RGGI”), which is limited to fossil-fuel-burning power plants, have enacted and are currently operating programs that, in varying ways and degrees, regulate GHGs.

In addition, the EPA has issued a notice of finding and determination that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment, which allows the EPA to begin regulating emissions of GHGs under existing provisions of the CAA. The EPA has begun to implement GHG-related reporting and permitting rules as described above. In June of 2014, the U.S. Supreme Court overturned the EPA’s GHG permitting rules to the extent they required permits based solely on emissions of GHG. Large sources of air pollutants could still be required to install GHG emission reduction technology. Underground coal mines remain subject to the EPA’s GHG Reporting Program, which required mines to submit annual GHG emission estimates to the EPA, but that program has not been extended to surface coal mines.

The impact of GHG-related legislation and regulations, including a “cap and trade” structure, on us will depend on a number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are allowed, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on coal prices. We may not recover all of the costs related to compliance with regulatory requirements imposed on us from our customers due to limitations in our agreements.

 

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Passage of additional state or federal laws or regulations regarding GHG emissions or other actions to limit carbon dioxide emissions could result in fuel switching from coal to other fuel sources by electricity generators and thereby reduce demand for our coal or indirectly the prices we receive in general. In addition, political and regulatory uncertainty over future emissions controls have been cited as major factors in decisions by power companies to postpone new coal-fired power plants. If these or similar measures, such as controls on methane emissions from coal mines, are ultimately imposed by federal or state governments or pursuant to international treaties, our operating costs or our revenues may be materially and adversely affected. In addition, alternative sources of power, including wind, solar, nuclear and natural gas, could become more attractive than coal in order to reduce carbon emissions, which could result in a reduction in the demand for coal and, therefore, our revenues. Similarly, some of our customers, in particular smaller, older power plants, could be at risk of significant reduction in coal burn or closure as a result of imposed carbon costs. The imposition of a carbon tax or similar regulation could, in certain situations, lead to the shutdown of coal-fired power plants, which would materially and adversely affect our coal and power plant revenues.

Clean Water Act

The Clean Water Act, or CWA, and corresponding state and local laws and regulations affect coal mining and power generation operations by restricting the discharge of pollutants, including dredged or fill materials, into waters of the U.S. The CWA provisions and associated state and federal regulations are complex and subject to amendments, legal challenges and changes in implementation. On April 21, 2014, the EPA and the U.S. Army Corps of Engineers jointly released a proposed rule to clarify which waters and wetlands are subject to regulation under the CWA. If the rule continues forward, it should be finalized in 2015. This rule is highly controversial and litigation is likely from various stakeholders. If CWA authority is eventually expanded, it may impact our operations in some areas by way of additional requirements. Finally, recent court decisions, regulatory actions and proposed legislation have created uncertainty over CWA jurisdiction and permitting requirements that could either increase or decrease the cost and time spent on CWA compliance.

Black Lung Benefits Acts

Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981 (collectively “BLBA”), each coal mine operator must secure payment of federal black lung benefits to claimants who are current and former employees to a trust fund for the payment of benefits and medical expenses to eligible claimants. The trust fund is funded by an excise tax on production of up to $0.55 per ton for surface-mined coal, not to exceed 4.4% of the gross sales price. In 2014, we recognized $2.9 million of expense related to this excise tax.

Comprehensive Environmental Response, Compensation and Liability Act

Under the Comprehensive Environmental Response, Compensation, and Liability Act, also known as CERCLA or Superfund, and similar state laws, responsibility for the entire cost of cleanup of a contaminated site, as well as natural resource damages, can be imposed upon current or former site owners or operators, or upon any party who released one or more designated “hazardous substances” at the site, regardless of the lawfulness of the original activities that led to the contamination. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to public health or the environment and to seek to recover from the potentially responsible parties the costs of such action. In the course of our operations, we may have generated and may generate wastes that fall within CERCLA’s definition of hazardous substances. Some products used in coal mining operations generate waste containing hazardous substances. We are currently unaware of any material liability associated with the release or disposal of hazardous substances from our past or present mine sites.

We may also be an owner or operator of facilities at which hazardous substances have been released by previous owners or operators. We may be responsible under CERCLA for all or part of the costs of clean up facilities at which such substances have been released and for natural resource damages. We have not, to our

 

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knowledge, been identified as a potentially responsible party under CERCLA, nor are we aware of any prior owners or operators of our properties that have been so identified with respect to their ownership or operation of those properties. We also must comply with reporting requirements under the Emergency Planning and Community to Know Act and the Toxic Substances Control Act.

Resource Conservation and Recovery Act

We may generate wastes, including “solid” wastes and “hazardous” wastes, that are subject to the federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, although certain mining and mineral beneficiation wastes and certain wastes derived from the combustion of coal currently are exempt from regulation as hazardous wastes under RCRA. The EPA has limited the disposal options for certain wastes that are designated as hazardous wastes under RCRA. Furthermore, it is possible that certain wastes generated by our operations that currently are exempt from regulation as hazardous wastes may in the future be designated as hazardous wastes, and therefore be subject to more rigorous and costly management, disposal and clean-up requirements.

The EPA determined that coal combustion residuals (“CCR”) do not warrant regulation as hazardous wastes under RCRA in May 2000. Most state hazardous waste laws do not regulate CCR as hazardous wastes. The EPA also concluded that beneficial uses of CCR, other than for mine filling, pose no significant risk and no additional national regulations of such beneficial uses are needed. However, the EPA determined that national non-hazardous waste regulations under RCRA are warranted for certain wastes generated from coal combustion, such as coal ash, when the wastes are disposed of in surface impoundments or landfills or used as minefill. EPA Administrator Gina McCarthy signed the final rule relating to the disposal of CCR from electric utilities on December 19, 2014 and submitted it to the Federal Register for publication. The final rule regulates CCR as solid waste under RCRA. The final rule establishes national minimum criteria for existing and new CCR landfills, surface improvements and lateral expansions. The criteria include location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post-closure care and recordkeeping, notification and interest posting requirements. The rule is largely silent on the reuse of coal ash, but the EPA has plans to develop in 2015 a conceptual model for beneficial uses of coal ash. These changes in the management of CCR could increase our and our customers’ operating costs and potentially reduce their ability to purchase coal. In addition, contamination caused by the past disposal of CCR, including coal ash, could lead to citizen suit enforcement against our customers under RCRA or other federal or state laws and potentially reduce the demand for coal.

Endangered Species Act

The federal Endangered Species Act, or ESA, and similar state laws protect species threatened with extinction. Protection of endangered and threatened species may cause us to modify mining plans or develop and implement species-specific protection and enhancement plans to avoid or minimize impacts to endangered species or their habitats. A number of species indigenous to the areas where we operate are protected under the ESA. Based on the species that have been identified and the current application of applicable laws and regulations, we do not believe that there are any species protected under the ESA or state laws that would materially and adversely affect our ability to mine coal from our properties. Should more stringent protective measures be applied to threatened, endangered or other special status species or to their critical habitat, or additional species be identified as threatened or endangered, then we could experience increased operating costs or difficulty in obtaining future mining permits.

Employees

We are managed and operated by the directors and officers of our general partner. Additionally, full-time employees are employed by WCC, the owner of our general partner, and its affiliates who provide executive, general and administrative services to us.

 

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As of December 31, 2014, through our general partner, we employed 602 full-time employees to conduct our operations, including 470 employees involved in active mining operations, 107 employees in other operations, and 25 corporate employees. We believe that we have good relations with these employees, and we continually seek their input with respect to our operations. Since our inception, we have had no history of work stoppages or union organizing campaigns. Historically, our workforce has been union-free. However, approximately 236 employees of Kemmerer who will join our workforce in connection with the Contribution are represented by a union.

As part our ongoing restructuring, 81 full-time employees have been moved and are employed by WCC in support of us and 50 full-time positions have been eliminated, resulting in 471 full-time employees employed by us, through our general partner, at March 31, 2015.

On March 13, 2015, we entered into the Services Agreement with our general partner to replace our prior services agreement. Under the Services Agreement, our general partner will continue providing administrative, engineering, operating and other services to us. Administrative services include, without limitation, legal, accounting, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit and tax. Under the Services Agreement, we will pay the general partner a fixed annual fee of $500,000 for certain administrative services, and reimburse the general partner at cost for other expenses and expenditures. The term of the Services Agreement expires on December 31, 2015, and automatically renews for successive one-year periods unless terminated.

 

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MANAGEMENT

Partnership Management

We are managed and operated by the directors and executive officers of our general partner, Westmoreland Resources GP, LLC. Our general partner was not elected and is not subject to election in the future by our unitholders. Our general partner has a board of directors, and our unitholders are not entitled to elect the directors or participate in our management or operations. Our general partner owes certain fiduciary duties to our unitholders as well as a fiduciary duty to its owners. Our general partner is liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, we intend to incur indebtedness that is nonrecourse to our general partner.

Currently, our general partner’s board of directors has eight directors, four of whom are independent as defined under the independence standards established by the NYSE and the Exchange Act. Our general partner’s board of directors has affirmatively determined that Robert T. Clutterbuck, Keith D. Horton, Kurt D. Kost and Gerald A. Tywoniuk are independent as described in the rules of the NYSE and the Exchange Act.

The NYSE does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating committee.

Directors and Executive Officers

Directors are appointed for a term of one year and hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Officers serve at the discretion of the board of directors of our general partner. The following table shows certain information for the directors and executive officers of our general partner as of May 29, 2015.

 

Name		Age				Position
Keith E. Alessi			60			Chairman of the Board, President and Chief Executive Officer
Kevin A. Paprzycki			44			Chief Financial Officer and Treasurer
Jennifer S. Grafton			38			Chief Legal Officer and Secretary
Joseph E. Micheletti			49			Executive Vice President
Gregory J. Honish			58			Senior Vice President, Operations
Robert T. Clutterbuck			64			Director
Jennifer S. Grafton			38			Director
Keith D. Horton			61			Director
Kurt D. Kost			58			Director
Kevin A. Paprzycki			44			Director
Gerald A. Tywoniuk			53			Director
Charles C. Ungurean			65			Director

Keith E. Alessi has served as Chief Executive Officer and President of our general partner since January 1, 2015. He was elected and has served as a member of the board of directors since January 6, 2015, and was appointed Chairman of the Board of our general partner on January 13, 2015. Mr. Alessi has served in various capacities at WCC since 2007 and currently serves as its Chief Executive Officer. He was an adjunct lecturer at the University of Michigan Ross School of Business from 2001 to 2010 and was an Adjunct Professor at The Washington and Lee University Law School from 1999 to 2007. Mr. Alessi previously served as Chief Executive Officer, Chief Operating Officer or Chief Financial Officer of a number of public and private companies from 1982 to 2000. He currently serves as a member of the board of directors of MWI Veterinary Supply, Inc. Mr. Alessi’s experience at WCC with the coal industry and as Chief Executive Officer of various companies

 

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provide him with the necessary skills to be a member of the board of directors and chairman of both the board of directors and executive committee of our general partner. Mr. Alessi has a M.B.A. from the University of Michigan and a B.S. from Wayne State University and is a certified public accountant.

Kevin A. Paprzycki has served as Chief Financial Officer and Treasurer of our general partner since January 1, 2015. He was elected and has served as a member of the board of directors of our general partner since January 6, 2015. Mr. Paprzycki joined WCC as Controller and Principal Accounting Officer in June 2006 and was named Chief Financial Officer in April 2008. In June 2010, he was also named Treasurer. Prior to WCC, Mr. Paprzycki was Corporate Controller at Applied Films Corporation from 2005 to 2006. Mr. Paprzycki became a certified public accountant in 1994 and a certified financial manager and certified management accountant in 2004. His experience at WCC with the coal industry and as Chief Financial Officer provide him with the necessary skills to be a member of the board of directors and a member of the compensation committee of our general partner. Mr. Paprzycki earned his B.S. in Accountancy from Case Western Reserve University and his M.B.A from the University of Utah.

Jennifer S. Grafton has served as Chief Legal Officer of our general partner since January 1, 2015, and Secretary from January 1 until February 18, 2015. She was elected and has served as a member of the board of directors of our general partner since January 6, 2015. Ms. Grafton joined WCC as Associate General Counsel in December 2008, was named General Counsel and Secretary in February 2011 and was promoted to Senior Vice President, Chief Administrative Officer and Secretary in November 2014. Prior to WCC, Ms. Grafton worked in the corporate group of various Denver-based and national law firms focusing her practice on securities and corporate governance. She is a member of the Colorado bar. Ms. Grafton’s experience at WCC with the coal industry as Associate General Counsel, General Counsel and then Senior Vice President and Chief Administrative Officer provide her with the necessary skills to be a member of the board of directors and a member of the compensation committee of our general partner. Ms. Grafton graduated from the University of Michigan Ross School of Business with her M.B.A. with High Distinction, graduated from the University of Denver Sturm College of Law with her J.D., Order of St. Ives, and received her B.S. from the University of Puget Sound.

Joseph E. Micheletti has served as Executive Vice President of our general partner since February 18, 2015. Mr. Micheletti joined WCC in 2001 and has held a series of positions since that time including President and General Manager of WCC’s Jewett Mine. In June 2011, Mr. Micheletti was named Senior Vice President—Coal Operations at WCC overseeing their domestic mines. Mr. Micheletti has worked in the production, maintenance, processing, and engineering disciplines of the mining industry for 24 years and sits as a Director of the Rocky Mountain Coal Mining Institute.

Gregory J. Honish has served as Senior Vice President, Operations of our general partner since March 2009. Mr. Honish has served in other capacities with us and our predecessor since January 1999, including Vice President, Mining and Business Development from September 2007 to March 2009 and Senior Mining Engineer from January 1999 to September 2007. Mr. Honish has held various positions in engineering, operations and management in the coal industry during his 35-year professional career at mines in Northern Appalachia, Central Appalachia, the Illinois Basin and the Powder River Basin. He is a licensed professional engineer in Ohio and West Virginia and a certified surface mine foreman in Ohio and Wyoming. Mr. Honish received a B.S. in Mining Engineering from the University of Wisconsin.

Robert T. Clutterbuck was elected and has served as a member of the board of directors of our general partner since January 6, 2015. He is the managing partner and portfolio manager at Clutterbuck Capital Management LLC. Prior thereto, Mr. Clutterbuck was Chairman of Key Capital Partners, which provided brokerage, capital markets, insurance, investment banking and asset management expertise to business and private clients nationwide. He was also Chief Executive Officer of McDonald Investments Inc. and was a Senior Executive Vice President of KeyCorp. In addition to serving on the McDonald Investments Board, Mr. Clutterbuck has served on numerous philanthropic boards as well as several advisory boards of financial institutions. His extensive financial experience provide him with the necessary skills to be a member of the board

 

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of directors, chairman of the compensation committee and a member of the audit committee of our general partner. With respect to the audit committee, Mr. Clutterbuck was designated as financially literate in accordance with NYSE listing standards based on his education and experience. He earned a bachelor’s degree from Ohio Wesleyan University and a M.B.A. from the University of Pennsylvania Wharton School of Business.

Keith D. Horton was elected and has served as a member of the board of directors of our general partner since January 6, 2015. On January 1, 2015 he retired from his position as President of PVR Coal, a subsidiary of Regency Gas Partners. From March 2010 until March 2014, Mr. Horton was Executive Vice President and Chief Operating Officer—Coal at PVR Partners, a publicly traded master limited partnership. He has an extensive background in coal operations and management, including a mine engineer position with WCC that was his first position out of college. Mr. Horton’s extensive experience in the coal industry provide him with the necessary skills to be a member of the board of directors, a member of the executive committee and a member of the audit committee of our general partner. With respect to the audit committee, Mr. Horton was designated as financially literate in accordance with NYSE listing standards based on his education and experience. He earned a bachelor’s degree in Engineering of Mines from West Virginia University and completed the University of Virginia Darden School of Business’ Executive Management Program.

Kurt D. Kost was elected and has served as a member of the board of directors of our general partner since January 6, 2015. He has over 34 years’ experience in the mining industry. Mr. Kost’s expertise includes coal operations and engineering; safety and process management related to operational and maintenance improvements; deploying technology in practical field applications; post-merger organization design and implementation; and executive management and leadership. From September of 2013 until May of 2014 he was a Senior Vice President with Norwest Corporation and from 2009 until 2012 was President of Alpha Natural Resources. Mr. Kost’s extensive experience in the coal industry provide him with the necessary skills to be a member of the board of directors and a member of the audit committee of our general partner. With respect to the audit committee, Mr. Kost was designated as financially literate in accordance with NYSE listing standards based on his education and experience. Mr. Kost earned a bachelor’s degree in Mining Engineering from South Dakota School of Mines and Technology and in 2004 completed Harvard Business School’s Advanced Management Program.

Gerald A. Tywoniuk has served as a member of the board of directors of our general partner since January 2009. He also serves as a director and audit committee chairperson of the general partner of American Midstream Partners, LP, as well as a director and audit committee member of the general partner of Landmark Infrastructure Partners LP. In addition to his board of director roles, Mr. Tywoniuk has provided various interim and project Chief Financial Officer services since May 2010. From June 2008 until August 2013, he held various management and finance roles, including Plan Representative, acting Chief Executive Officer, and Chief Financial Officer of Pacific Energy Resources Ltd., an oil production company. Mr. Tywoniuk joined that company in June 2008 to help the management team work through the company’s financially distressed situation. The board of the company elected to file for Chapter 11 protection in March 2009. In December 2009, the company completed the sale of its assets, and by August 2013 the company completed its liquidation. Mr. Tywoniuk previously served as Chief Financial Officer of Pacific Energy Partners, LP, an oil and refined products pipeline and storage partnership from 2002 to 2006, and MarkWest Energy Partners, L.P. and its predecessor, principally a natural gas and liquids midstream services partnership, from 1997 to 2002. He has over 33 years of experience in accounting and finance, including 12 years as the Chief Financial Officer of three public companies and 4 years as Vice President/Controller of a fourth public company. Mr. Tywoniuk’s extensive accounting, financial and executive management experience, as well as his in-depth knowledge of the mining industry generally and our partnership in particular, and his prior experience with publicly traded partnerships, provide him with the necessary skills to be a member of the board of directors and a member and chairman of the audit committee of our general partner. With respect to the Audit Committee, Mr. Tywoniuk was designated as an audit committee financial expert and financially literate in accordance with NYSE listing standards based on his education and experience. He earned a Bachelor of Commerce degree from The University of Alberta, Canada, and is a Canadian chartered accountant.

 

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Charles C. Ungurean has served as a member of the board of directors of our general partner since its formation in 2007. In 1985, he co-founded our predecessor and wholly owned subsidiary, Oxford Mining Company. Mr. Ungurean served as President and Treasurer of our predecessor from 1985 to August 2007 and as President and Chief Executive Officer of our general partner from its formation in 2007 through December 31, 2014. He currently serves on the board of directors of the National Mining Association. In addition, Mr. Ungurean served as Chairman of the Ohio Coal Association from July 2002 to July 2004. His more than 40 years of experience in the coal industry, over 25 of which have been spent running our operations or the operations of our predecessor and wholly owned subsidiary, Oxford Mining Company, provide him with the necessary skills to be a member of the board of directors and a member of the executive committee of our general partner. Mr. Ungurean received a B.A. in General Studies from Ohio University and is a certified surface mine foreman in Ohio.

Corporate Governance

The board of directors of our general partner has adopted corporate governance guidelines to assist it in the exercise of its responsibilities to provide effective governance over our affairs for the benefit of our unitholders. In addition, we have adopted a code of business conduct and ethics, which sets forth legal and ethical standards of conduct for all our officers, directors and employees. The corporate governance guidelines, the code of business conduct and ethics, the charters of our audit, compensation and executive committees and our lead independent director charter are available on our website at www.westmorelandmlp.com and in print without charge to any unitholder who requests any of them. A unitholder may make such a request in writing by mailing such request to Investor Relations, Westmoreland Resource Partners, LP, 9450 South Maroon Circle, Suite 200, Englewood, Colorado 80112, or by emailing such request to Investor Relations at ir@oxfordresources.com. Amendments to, or waivers from, the code of business conduct and ethics will also be available on our website and reported as may be required under SEC rules; however, any technical, administrative or other non-substantive amendments to the code of business conduct and ethics may not be posted. Please note that the preceding Internet address is for information purposes only and is not intended to be a hyperlink. Accordingly, no information found or provided at that Internet address or at our website in general is intended or deemed to be incorporated by reference herein.

Conflicts Committee

Our partnership agreement provides for Conflicts Committee, as circumstances warrant, to review conflicts of interest between us and our general partner or between us and affiliates of our general partner. The Conflicts Committee, consisting solely of independent directors, determines if the resolution of a conflict of interest that has been presented is fair and reasonable to us. The members of the Conflicts Committee may not be executive officers or employees of our general partner or directors, executive officers or employees of its affiliates. In addition, the members of the Conflicts Committee must meet the independence and experience standards established by the NYSE and the Exchange Act. The composition of our Audit Committee qualifies it to be, and our Audit Committee presently serves as, our Conflicts Committee.

Executive Committee

The board of directors of our general partner has established an executive committee (the “Executive Committee”). The Executive Committee handles matters that arise during the intervals between meetings of the board of directors and that, in the opinion of the chairman of the Executive Committee, do not warrant convening a special meeting of the board of directors but should not be postponed until the next scheduled meeting. Keith E. Alessi, Keith D. Horton and Charles C. Ungurean serve as the members of the Executive Committee. Mr. Alessi serves as the chairman of the Executive Committee.

Audit Committee

The board of directors of our general partner has established an audit committee (the “Audit Committee”) that complies with the NYSE requirements and Section 3(a)(58)(A) of the Exchange Act. Our general partner is

 

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generally required to have at least three independent directors serving on its board at all times. Gerald A. Tywoniuk, Robert T. Clutterbuck, Keith D. Horton and Kurt D. Kost are our independent directors and serve as the members of the Audit Committee, and all have the requisite education and experience sufficient to be designated as financially literate under NYSE listing standards. The board has determined that Mr. Tywoniuk, who serves as the chairman of the Audit Committee, has the accounting or related financial management expertise sufficient to qualify as an audit committee financial expert in accordance with Item 401 of Regulation S-K.

The Audit Committee meets on a regularly-scheduled basis and with our independent accountants at least four times each year. The Audit Committee has the authority and responsibility to review our external financial reporting, to review our procedures for internal auditing, to review the adequacy of our internal accounting controls, to consider the qualifications and independence of our independent accountants, to engage and resolve disputes with our independent accountants, including the letter of engagement and statement of fees relating to the scope of the annual audit work and any special audit work that may be recommended or required by the independent accountants, and to engage the services of any other advisors and accountants as the Audit Committee deems advisable. The Audit Committee reviews and discusses the audited financial statements with management, discusses with our independent auditors matters required to be discussed by statement on auditing standards No. 16 (PCAOB Auditing Standard No. 16, Communications With Audit Committees, Related Amendments to PCAOB Standards and Transitional Amendments to AU Section 380), and makes recommendations to the board of directors of our general partner regarding the inclusion of our audited financial statements in this prospectus.

Compensation Committee

The board of directors of our general partner has established a compensation committee (the “Compensation Committee”). The Compensation Committee establishes standards and makes recommendations concerning the compensation of our directors. Robert T. Clutterbuck, Kevin A. Paprzycki and Jennifer S. Grafton serve as the members of the Compensation Committee. Mr. Clutterbuck serves as the chairman of the Compensation Committee.

Meeting of Non-Management Directors and Communications with Directors

At least quarterly during a meeting of the board of directors of our general partner, all of our independent directors meet in an executive session without management participation or participation by non-independent directors.

The board of directors of our general partner welcomes questions or comments about us and our operations. Unitholders or interested parties may contact the board of directors, including any individual director, by contacting the Secretary of our general partner, Samuel Hagreen, at ir@oxfordresources.com, or at the following address: Name of the Director(s), c/o Secretary, Westmoreland Resource Partners, LP, 9450 South Maroon Circle, Suite 200, Englewood, Colorado 80112.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires the board of directors and executive officers of our general partner, and persons who own more than 10 percent of a registered class of our equity securities, to file with the SEC and any exchange or other system on which such securities are traded or quoted initial reports of ownership and reports of changes in ownership of our common units and other equity securities. Officers, directors and greater than 10 percent unitholders are required by the SEC’s regulations to furnish to us and any exchange or other system on which such securities are traded or quoted with copies of all Section 16(a) forms they filed with the SEC. To our knowledge, based solely on a review of the copies of such reports furnished to us and written representations that no other reports were required, we believe that all reporting obligations of the officers, directors and greater than 10 percent unitholders of our general partner under Section 16(a) were satisfied during the year ended December 31, 2014, other than a late Form 3 filing made by WCC.

 

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

The following table sets forth certain information regarding the beneficial ownership of units as of March 3, 2015 (the “Ownership Reference Date”) by:

 

•

each person who is known to us to beneficially own 5% or more of such units to be outstanding;

 

•

our general partner;

 

•

each of the directors and named executive officers of our general partner; and

 

•

all of the directors and executive officers of our general partner as a group

All information with respect to beneficial ownership has been furnished by the respective directors, officers or 5% or more unitholders as the case may be.

Our general partner is owned by WCC.

The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. In computing the number of common units beneficially owned by a person and the percentage ownership of that person, common units subject to options or warrants held by that person that are currently exercisable or exercisable within 60 days of the Ownership Reference Date, if any, are deemed outstanding, but are not deemed outstanding for computing the percentage ownership of any other person. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.

The percentage of units beneficially owned is based on a total of 5,711,636 common units outstanding as of the Ownership Reference Date as well as warrants convertible into 116,557 common units held by the lenders under our 2014 Financing Agreement.

 

Name of Beneficial Owner		Common Units Beneficially Owned				Percentage of Common Units Beneficially Owned
Westmoreland Coal Company(1)			4,512,500				77.43	%
Keith E Alessi(1)			—				—	%
Kevin A. Paprzycki(1)			—				—	%
Jennifer S. Grafton(1)			—				—	%
Robert T. Clutterbuck(2)			32,584				*
Keith D. Horton(3)			—				—	%
Kurt D. Kost(4)			—				—	%
Gerald A. Tywoniuk(1)(5)			9,140				*
Charles C. Ungurean(6)(7)			56,956				*
Gregory J. Honish(6)			14,962				*
Joseph E. Micheletti(1)			—				—	%
All directors and executive officers as a group (consisting of 10 persons)			113,642				2.0	%

An asterisk indicates that the person or entity owns less than one percent.

 

(1)	The address for this person or entity is 9450 South Maroon Circle, Suite 200, Englewood, Colorado 80112.

(2)	The address for this person or entity is 10 Kensington Oval, Rocky River, Ohio 44116.

(3)	The address for this person or entity is 391 Summer Sound Road, Piney Flats, Tennessee 37686.

(4)	The address for this person or entity is 1112 Mountain Vista Drive, Bristol, Tennessee 37620.

 

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(5)	All of these common units are owned by a trust established and trusteed by Mr. Tywoniuk. Mr. Tywoniuk disclaims beneficial ownership of the units held by such trust, except to the extent of any pecuniary interest therein.

(6)	The address for this person or entity is 544 Chestnut Street, Coshocton, Ohio 43812.

(7)

A total of 30,074 of these common units are owned by C&T Coal, Inc. Mr. Ungurean, as a shareholder of C&T Coal, Inc., shares voting and investment power with respect to the common units owned by C&T Coal, Inc. Mr. Ungurean disclaims beneficial ownership of the units, except to the extent of any pecuniary interest therein.

Securities Authorized for Issuance under Equity Compensation Plans

The following table provides information concerning common units that may be issued under our LTIP. Our LTIP allows for awards of options, phantom units, restricted units, unit awards, other unit awards and unit appreciation rights. It currently permits the grant of awards covering an aggregate of 233,840 units. Our LTIP is administered by the Compensation Committee.

The board of directors of our general partner in its discretion may terminate, suspend or discontinue our LTIP at any time with respect to any award that has not yet been granted. The board of directors of our general partner also has the right to alter or amend our LTIP or any part of our LTIP from time to time, including increasing the number of units that may be granted subject to unitholder approval as required by the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of the participant.

The following table summarizes the number of securities that remained available for future issuance under our LTIP as of December 31, 2014, as adjusted for the 12-to-1 reverse split effective December 31, 2014.

 

Plan Category		Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights				Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights				Number of Securities That Remained Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column(a))
		(a)				(b)				(c)
Equity compensation plans approved by security holders(1)			—			$	—				89,070	(2)
Equity compensation plans not approved by security holders			—				—				—
Total			—			$	—				89,070	(2)

 

(1)	Our LTIP was approved by our partners (general and limited) prior to our initial public offering. As of December 31, 2014, our LTIP permitted the grant of awards covering an aggregate of 233,840 units, inclusive of prior award grants, which grants did not require approval by our limited partners.

(2)	There are no phantom units outstanding under our LTIP as of December 31, 2014.

 

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

At March 31, 2015, WCC owned 4,512,500 common units representing an 79.0% limited partner interest in us. WCC also owns all of the equity in and controls our general partner which owns a 0.6% general partner interest in us and all of our incentive distribution rights.

Distributions and Payments to Our General Partner and Its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with our ongoing operations and liquidation. These distributions and payments were determined by and among affiliated entities, and, consequently, are not the result of arm’s-length negotiations.

 

Ongoing Operations Stage
Distributions of available cash to our general partner and its affiliates		We will make cash distributions 99.4% to the unitholders, including WCC as an affiliate of our general partner as the holder of an aggregate of 4,512,500 common units, and 0.6% to our general partner. If distributions exceed the minimum quarterly distribution and the first target distribution level, our general partner will be entitled to increasing percentages of the distributions, up to 48.0% of the distributions above the highest target distribution level. Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner and its affiliate WCC would receive an annual distribution of approximately $18,818 on the 0.6% general partner interest and approximately $2,406,065 on the common units.
Payments to our general partner and its affiliates		Our general partner will not receive a management fee or other compensation for its management of us. Our general partner and its affiliates will be reimbursed for expenses incurred on our behalf. Our partnership agreement provides that our general partner will determine the amount of these expenses.
Withdrawal or removal of our general partner		If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair value of those interests.
Liquidation Stage
Liquidation		Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.

Ownership Interests of Certain Executive Officers and Directors of Our General Partner

WCC owns 100.0% of our general partner. In addition to the 0.64% general partner interest in us, our general partner owns the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 48.0% of the cash we distribute in excess of $0.2000 per quarter. WCC also owns approximately 77% of our outstanding limited partner interests (on a fully diluted basis).

In connection with the Initial Kemmerer Contribution, WKFCH entered into a coal mining lease with respect to the Kemmerer coal reserves with a subsidiary of WCC, pursuant to which we will earn a per ton royalty as the coal reserves are mined. Through the coal leasing arrangement, the mining of the Kemmerer fee coal reserves are expected to generate $5.8 million in average annual royalties over the next three years, with a minimum royalty payment of $1 million per quarter from the start of 2015 through December 31, 2020 and $0.5

 

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million per quarter thereafter through December 31, 2025. For the three months ended March 31, 2015, we recognized $1.8 million in coal royalty revenue under the lease for the Kemmerer coal reserves. Following the Contribution, the coal mining lease for the Kemmerer reserves will become an intercompany obligation that we expect would be eliminated in consolidation.

Services Agreement

On August 24, 2007, we entered into our prior administrative and operational services agreement with Oxford Mining Company, LLC and our general partner. Under that agreement, our general partner provided services to us and was reimbursed for all related costs incurred on our behalf. During 2014, we paid our general partner approximately $59.4 million for services, primarily related to payroll, performed under the prior services agreement.

On March 13, 2015, we entered into the Services Agreement with our general partner to replace our prior services agreement. Under the Services Agreement, our general partner will continue providing administrative, engineering, operating and other services to us. Administrative services include, without limitation, legal, accounting, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit and tax. Under the Services Agreement, we will pay the general partner a fixed annual fee of $500,000 for certain administrative services, and reimburse the general partner at cost for other expenses and expenditures. The term of the Services Agreement expires on December 31, 2015, and automatically renews for successive one-year periods unless terminated.

Procedures for Review, Approval and Ratification of Related Person Transactions

The board of directors of our general partner has adopted a code of business conduct and ethics that provides that the board of directors of our general partner or its authorized committee will periodically review all related person transactions that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. In the event that the board of directors of our general partner or its authorized committee considers ratification of a related person transaction and determines not to so ratify, the code of business conduct and ethics provides that our management will make all reasonable efforts to cancel or annul the transaction.

The code of business conduct and ethics provides that, in determining whether or not to recommend the initial approval or ratification of a related person transaction, the board of directors of our general partner or its authorized committee should consider all of the relevant facts and circumstances available, including (if applicable) but not limited to: (i) whether there is an appropriate business justification for the transaction; (ii) the benefits that accrue to us as a result of the transaction; (iii) the terms available to unrelated third parties entering into similar transactions; (iv) the impact of the transaction on a director’s independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director or an immediately family member of a director is a partner, shareholder, member or executive officer); (v) the availability of other sources for comparable products or services; (vi) whether it is a single transaction or a series of ongoing, related transactions; and (vii) whether entering into the transaction would be consistent with the code of business conduct and ethics.

The code of business conduct and ethics described above was adopted in connection with the closing of our initial public offering. A copy of the code of business conduct and ethics is found at www.westmorelandmlp.com in the Investor Relations/Corporate Governance section. Additionally a unitholder may make such a request in writing by mailing such request to Investor Relations, Westmoreland Resource Partners, LP, 9540 South Maroon Circle, Suite 200, Englewood, CO 80112, or by emailing such request to Investor Relations at ir@oxfordresources.com.

For further details, please read “Our Business,” “Management” and Note 20: Related Party Transactions included in the notes to our consolidated financial statements elsewhere in this prospectus.

 

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including WCC) on the one hand, and our partnership and our limited partners, on the other hand. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any other partner, on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions taken that, without those limitations, might constitute breaches of fiduciary duty.

Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is:

 

•

approved by the Conflicts Committee, although our general partner is not obligated to seek such approval;

 

•

approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

 

•

on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

 

•

fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us

Our general partner may, but is not required to, seek the approval of such resolution from the Conflicts Committee of its board of directors. If our general partner does not seek approval from the Conflicts Committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the Conflicts Committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement provides that someone act in good faith, it requires that person to believe he is acting in the best interests of the partnership.

Conflicts of interest could arise in the situations described below, among others.

Our general partner and its affiliates may have conflicts of interest with us, and their limited fiduciary duties to our unitholders may permit them to favor their own interests to the detriment of our unitholders.

WCC owns common units representing an approximately 77% limited partner interest in us (on a fully diluted basis) as well as 100% of our general partner, which owns all of our outstanding 35,291 general partner units and incentive distribution rights. The executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owners and have no duty to us or our unitholders. Furthermore, since certain executive officers and directors of our general partner are executive officers or

 

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directors of affiliates of our general partner, conflicts of interest may arise between WCC and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. The risk to our unitholders due to such conflicts may arise because of the following factors, among others:

 

•

our general partner is allowed to take into account the interests of parties other than us, such as WCC, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;

 

•

neither our partnership agreement nor any other agreement requires owners of our general partner to pursue a business strategy that favors us. Executive officers and directors of our general partner’s owners have a fiduciary duty to make these decisions in the best interest of their owners, which may be contrary to our interests;

 

•

our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings and issuances of additional partnership securities and reserves, each of which can affect our financial condition;

 

•

our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

 

•

our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf;

 

•

our general partner intends to limit its liability regarding our contractual and other obligations;

 

•

our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of our common units which could cause unitholders to sell units at a time and price that may not be desirable;

 

•

our general partner controls the enforcement of obligations owed to us by it and its affiliates; and

 

•

our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

In addition, WCC currently holds substantial interests in other companies in the energy and natural resource sectors. Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership interest in us. However, WCC is not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. As a result, WCC could potentially compete with us for acquisition opportunities and for new business or extensions of the existing services provided by us.

Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers, directors and owners. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders.

For more information, please read “—Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duties.”

 

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Neither our partnership agreement nor any other agreement requires WCC to pursue a business strategy that favors us or utilizes our assets or dictates what markets to pursue or grow. WCC’s directors have a fiduciary duty to make these decisions in the best interests of the owners of WCC, which may be contrary to our interests.

Because certain of the directors of our general partner are also directors and/or officers of WCC, such directors have fiduciary duties to WCC that may cause them to pursue business strategies that disproportionately benefit WCC or which otherwise are not in our best interests.

We rely on the employees of our general partner and its affiliates.

All of our executive management personnel are employees of our general partner and devote only a portion of their time to our business and affairs. We also utilize a significant number of employees of WCC to operate our business and provide us with general and administrative services for which we reimburse WCC. WCC conducts businesses and activities of its own in which we will have no economic interest. If these separate activities are significantly greater than our activities, there could be material competition for the time and effort of the officers and employees who provide services to WCC and its affiliates.

Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duties.

Fiduciary duties owed to our unitholders by our general partner are prescribed by law and the partnership agreement. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, restrict the fiduciary duties owed by the general partner to limited partners and the partnership. Our partnership agreement contains such provisions. For example, our partnership agreement:

 

•

limits the liability and reduces the fiduciary duties of our general partner, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing common units, our unitholders consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law;

 

•

permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership;

 

•

provides that our general partner shall not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith, meaning our general partner believed that the decision was in the best interests of the partnership;

 

•

generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the audit committee of the board of directors of our general partner acting as a conflicts committee, and not involving a vote of our unitholders, must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous to us; and

 

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•

provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct.

By purchasing a common unit, a unitholder will become bound by the provisions of our partnership agreement, including the provisions described above.

Our unitholders have limited voting rights, are not entitled to elect our general partner or its directors and have limited ability to remove our general partner without its consent.

Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our unitholders have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is chosen entirely by its members and not by our unitholders. Furthermore, if our unitholders are dissatisfied with the performance of our general partner, they have limited ability to remove our general partner.

Our unitholders are unable to remove our general partner without its consent because affiliates of our general partner own sufficient units to be able to prevent removal of our general partner. The vote of the holders of at least 80% of all outstanding common units is required to remove our general partner. Our general partner owns 0.6% of our common units and the owner of our general partner, WCC, owns approximately 77% of our outstanding common units (on a fully diluted basis).

The control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest in us to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the members of our general partner to transfer their respective membership interests in our general partner to a third party. The new members of our general partner would then be in a position to replace the board of directors and executive officers of our general partner with their own choices and to control the decisions and actions of the board of directors and executive officers of our general partner.

The incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights.

Our general partner has a limited call right that may require our unitholders to sell their common units at an undesirable time or price.

At any time that our general partner and its affiliates own more than 80.0% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than the then-current market price. As a result, our unitholders may be required to sell their common units at an

 

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undesirable time or price and may not receive any return on their investment. Our unitholders may also incur a tax liability upon a sale of their common units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its limited call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the common units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Exchange Act. We expect that the additional common units to be issued to our general partner in connection with the Contribution will cause our general partner’s ownership in us to exceed 80.0%.

We may issue additional units without unitholder approval, which would dilute unitholder interests.

At any time, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Further, our partnership agreement does not prohibit the issuance of equity securities that may effectively rank senior to our common units. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

 

•

our unitholders’ proportionate ownership interest in us will decrease;

 

•

the amount of cash available for distribution on each unit may decrease;

 

•

the relative voting strength of each previously outstanding unit may be diminished; and

 

•

the market price of the common units may decline.

Our general partner may, without unitholder approval, elect to cause us to issue common units and general partner units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights.

Our general partner has the right, at any time when it has received distributions on its incentive distribution rights at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units and general partner units. The number of common units to be issued to our general partner will be equal to that number of common units that would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. Our general partner will be issued the number of general partner units necessary to maintain our general partner’s interest in us that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive distributions on its incentive distribution rights based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units and general partner units to our general partner in connection with resetting the target distribution levels.

 

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We must pay fees to and reimburse our general partner and its affiliates for services provided, which will reduce our cash available for distributions.

On March 13, 2015, we entered into the Services Agreement with our general partner. Under the Services Agreement, our general partner will continue providing administrative, engineering, operating and other services to the Partnership for a fixed annual fee of $500,000 for certain administrative services plus reimbursement at cost for other expenses and expenditures. The term of the Agreement expires on December 31, 2015, and automatically renews for successive one-year periods unless terminated. The reimbursement to our general partner for such expenses will be determined by our general partner, in accordance with the terms of our partnership agreement and as provided under the Services Agreement. In determining the costs and expenses allocable to us, our general partner is subject to its fiduciary duty, as modified by our partnership agreement, to the limited partners, which requires it to act in good faith. These expenses include all costs incurred by our general partner and its affiliates in managing and operating us. We are managed and operated by executive officers and directors of our general partner. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce our cash available for distributions.

Fiduciary Duties

Our general partner is accountable to us and our unitholders as a fiduciary. Fiduciary duties owed to unitholders by our general partner are prescribed by law and the partnership agreement. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, modify, restrict or expand the fiduciary duties otherwise owed by a general partner to limited partners and the partnership.

Our partnership agreement contains various provisions modifying and restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these restrictions to allow our general partner or its affiliates to engage in transactions with us that would otherwise be prohibited by state law fiduciary duty standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because our general partner’s board of directors will have fiduciary duties to manage our general partner in a manner beneficial to its owners, as well as to you. Without these modifications, the general partner’s ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards enable the general partner to take into consideration all parties involved in the proposed action, so long as the resolution is fair and reasonable to us. These modifications also enable our general partner to attract and retain experienced and capable directors. These modifications are detrimental to our common unitholders because they restrict the remedies available to unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners:

 

State law fiduciary duty standards		Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present.   The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where

 

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		an effort to cause a general partner to do so is not likely to succeed. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.
Partnership agreement modified standards		Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues about compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These standards reduce the obligations to which our general partner would otherwise be held.
		In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that the general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct.
		Special provisions regarding affiliated transactions. Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a vote of unitholders and that are not approved by the conflicts committee of the board of directors of our general partner must be:
		•    on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or   •    “fair and reasonable” to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us).
		If our general partner does not seek approval from the Conflicts Committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, acted in good faith and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held.

 

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By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in the partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner or assignee to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

We must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct. We must also provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. Please read “The Partnership Agreement—Indemnification”.

 

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DESCRIPTION OF OUR COMMON UNITS

Common Units

The common units represent limited partner interests in Westmoreland Resource Partners, LP. The holders of common units are entitled to participate in partnership distributions and exercise the rights and privileges available to limited partners under our partnership agreement. For a description of the relative rights and privileges of holders of common units and our general partner in and to partnership distributions, please read this section and “How We Make Cash Distributions.” For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read “The Partnership Agreement.” As of May 29, 2015, we had 5,711,630 common units outstanding.

Transfer Agent and Registrar

Duties. American Stock Transfer & Trust Company, LLC serves as registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units except the following that must be paid by unitholders:

 

•

surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

 

•

special charges for services requested by a common unitholder; and

 

•

other similar fees or charges.

There will be no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their equity holders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal. The transfer agent may resign by notice to us or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our books and records. Each transferee:

 

•

represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

 

•

automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; and

 

•

gives the consents and approvals contained in our partnership agreement.

A transferee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any transfers to be recorded on our books and records from time to time as necessary.

We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial owner’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

 

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Common units are securities and are transferable according to the laws governing transfers of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

 

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THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. A copy of this agreement has been filed with the SEC.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

 

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with regard to distributions of available cash, please read “How We Make Cash Distributions”;

 

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with regard to the fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties”;

 

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with regard to the transfer of common units, please read “Description of Our Common Units—Transfer of Common Units”; and

 

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with regard to allocations of taxable income and taxable loss, please read “Material U.S. Federal Income Tax Consequences.”

Organization and Duration

We were organized in August 2007 and have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.

Purpose

Our purpose under the partnership agreement is limited to any business activities that are approved by our general partner and in any event that may lawfully be conducted by a limited partnership organized under Delaware law. Our general partner, however, may not cause us to engage, directly or indirectly, in any business activity that our general partner determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the coal mining and marketing business, our general partner may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. Our general partner is authorized in general to perform all acts it determines to be necessary or appropriate to carry out our purposes and conduct our business. In addition, our general partner will have the power to construe and interpret our partnership agreement and to act upon any such construction or interpretation, and any such construction or interpretation made by our general partner and any action taken or determination made pursuant thereto in good faith will be conclusive and binding on our limited partners.

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.”

Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its percentage interest if we issue additional units. Our general partner’s percentage interest, and the percentage of our cash distributions to which it is entitled, will be proportionately reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its percentage interest.

 

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Voting Rights

The following matters require the limited partner vote specified below. Various matters require the approval of a “unit majority,” which means the approval of a majority of the outstanding common units.

If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors of our general partner.

In voting their common units, our general partner and its affiliates will have no fiduciary duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or in the best interests of us and our limited partners.

 

Issuance of additional units		No approval rights.
Amendment of our partnership agreement		Certain amendments may be made by our general partner without the approval of our limited partners. Other amendments generally require the approval of a unit majority. Please read “—Amendment of Our Partnership Agreement.”
Merger of us or the sale of all or substantially all of our assets		Unit majority in certain circumstances. Please read “—Merger, Consolidation, Conversion, Sale or Other Disposition of Assets.”

 

Dissolution of our partnership		Unit majority. Please read “—Termination and Dissolution.”
Continuation of our partnership upon dissolution		Unit majority. Please read “—Termination and Dissolution.”
Withdrawal of our general partner		Under most circumstances, the approval of a majority of the outstanding common units, voting as a class, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to June 30, 2020 in a manner that would cause a dissolution of our partnership. Please see “—Withdrawal or Removal of Our General Partner.”
Removal of our general partner		Not less than 80.0% of the outstanding units (not including general partner units, incentive distribution rights or liquidation units), voting as a single class, including units held by our general partner and its affiliates, is required for the removal of our general partner. Please read “—Withdrawal or Removal of Our General Partner.”
Transfer of general partner interest		Our general partner may transfer all, but not less than all, of its general partner interests in us without a vote of our unitholders to an affiliate or another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to, such person. The approval of a majority of our

 

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		common units, voting as a class, excluding common units held by our general partner and its affiliates, is required in other circumstances for a transfer of our general partner interests to a third party prior to June 30, 2020. No transfer by our general partner of any part of its general partner interest is permitted unless the transferee agrees to assume the rights and duties of our general partner under our partnership agreement, our partnership receives an opinion of counsel that the proposed transfer would not result in the loss of limited liability to the limited partners under applicable law and the proposed transferee agrees to purchase the partnership, membership or limited liability company interest held by our general partner in the partnership and each of its subsidiaries. Please see “—Transfer of General Partner Interests.”
Transfer of ownership interests in our general partner		No approval rights. Please read “—Transfer of Ownership Interests in Our General Partner.”
Transfer of incentive distribution rights or liquidation units		No approval rights. Please read “—Transfer of Incentive Distribution Rights or Liquidation Units.”
Voting and waivers of incentive distribution rights		For as long as a majority of the incentive distribution rights are held by our general partner and its affiliates, the holders of the incentive distribution rights shall not be entitled to vote their incentive distribution rights on any partnership matter except as otherwise required by law.

Applicable Law; Forum, Venue and Jurisdiction

Our partnership agreement is governed by Delaware law. The partnership agreement requires that any claims, suits, actions or proceedings:

 

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arising out of or relating in any way to the partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of the partnership agreement or the duties, obligations or liabilities among partners or of partners to us, or the rights or powers of, or restrictions on, the partners or us);

 

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brought in a derivative manner on our behalf;

 

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asserting a claim of breach of a duty owed by any director, officer or other employee of us or our general partner, or owed by our general partner, to us or the partners;

 

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asserting a claim arising pursuant to any provision of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”); or

 

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asserting a claim governed by the internal affairs doctrine

shall be exclusively brought in the Court of Chancery of the State of Delaware, regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims.

By purchasing a common unit, each limited partner irrevocably consented to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other court) in connection with any such claims, suits, actions or proceedings.

 

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Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that it otherwise acts in conformity with the provisions of our partnership agreement, its liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital it is obligated to contribute to us for its common units plus its share of any undistributed profits and assets. If it were determined, however, that the right of, or exercise of the right by, the limited partners as a group:

 

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to remove or replace our general partner;

 

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to approve some amendments to our partnership agreement; or

 

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to take other action under our partnership agreement;

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware to the same extent as our general partner. This liability would extend to persons who transact business with us who reasonably believe that a limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for such a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of its assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from our partnership agreement.

Our subsidiaries conduct business in Indiana, Kentucky, Ohio, Pennsylvania, West Virginia and Wyoming. Our subsidiaries may conduct business in other states in the future. Maintenance of our limited liability relating to our interests in our subsidiaries may require compliance with legal requirements in the jurisdictions in which our subsidiaries conduct business, including qualifying our subsidiaries to do business there.

Limitations on the liability of limited partners for the obligations of a limited partnership have not been clearly established in many jurisdictions. If, by virtue of our interests in our subsidiaries or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as the general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

 

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Issuance of Additional Interests

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests and options, rights, warrants, restricted units, tracking and phantom interests, appreciation rights and other economic interests relating to our partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of our limited partners.

It is possible that we will fund acquisitions through the issuance of additional common units or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership interests may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, as determined by our general partner, may have rights to distributions or special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity securities which would effectively rank senior to the common units.

Upon issuance of additional partnership interests (other than the issuance of partnership interests issued in connection with a reset of the incentive distribution target levels relating to our general partner’s incentive distribution rights or the issuance of partnership interests upon conversion of outstanding partnership interests), our general partner will be entitled, but not required, to make additional capital contributions to the extent necessary to maintain its percentage interest in us. Our general partner’s percentage interest in us will be reduced if we issue additional units in the future (other than the issuance of partnership interests issued in connection with a reset of the incentive distribution target levels relating to our general partner’s incentive distribution rights or the issuance of partnership interests upon conversion of outstanding partnership interests) and our general partner does not contribute a proportionate amount of capital to us to maintain its percentage interest in us. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units or other partnership interests whenever, and on the same terms that, we issue those interests to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of our general partner and its affiliates, including such interest represented by common units, that existed immediately prior to each issuance. The holders of common units do not have preemptive rights to acquire additional common units or other partnership interests.

Amendment of Our Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or our limited partners, including any duty to act in good faith or in the best interests of us or our limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner must seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments

No amendment may be made that would:

(1) enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or

(2) enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which may be given or withheld at its option.

 

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The provision of our partnership agreement preventing the amendments having the effects described in clauses (1) and (2) above can be amended upon the approval of the holders of at least 90.0% of the outstanding units voting together as a single class (including units owned by our general partner and its affiliates). As of March 31, 2015, our general partner owned 0.6% of our common units and WCC, the owner of our general partner, owned approximately 77% of our outstanding common units (on a fully diluted basis).

No Unitholder Approval

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect or that is:

 

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a change in our name, the location of our principal place of our business, our registered agent or our registered office;

 

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the admission, substitution, withdrawal, or removal of partners in accordance with our partnership agreement;

 

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a change that our general partner determines to be necessary or appropriate for us to qualify or to continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that none of we, our operating companies, or any of our other subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for U.S. federal income tax purposes;

 

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a change in our fiscal year or taxable period and related changes;

 

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an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or the directors, officers, agents, or trustees of our general partner from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or plan asset regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;

 

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subject to the provisions of the partnership agreement, an amendment that our general partner determines to be necessary or appropriate for the authorization or issuance of additional partnership interests, including options, rights, warrants, appreciation rights, tracking and phantom interests or other economic interests in our partnership relating to partnership interests, including any amendment that our general partner determines is necessary or appropriate in connection with:

 

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the adjustments of the minimum quarterly distribution, first target distribution, second target distribution and third target distribution in connection with the reset of our general partner’s incentive distribution rights as described under “Cash Distribution Policy Before and After the Effectiveness of the Amended and Restated Partnership Agreement and Related Transactions—Cash Distribution Policy After the Effectiveness of the Amended and Restated Partnership Agreement and Related Transactions—General Partner’s Right to Reset Incentive Distribution Levels”;

 

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the implementation of the provisions relating to our general partner’s right to reset its incentive distribution rights; or

 

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any modification of the incentive distribution rights made in connection with the issuance of additional partnership interests or rights to acquire partnership interests, provided that any such modifications and related issuance of partnership interests have received approval by a majority of the members of the Conflicts Committee.

 

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any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

 

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an amendment effected, necessitated, or contemplated by a merger agreement that has been approved under the terms of the partnership agreement;

 

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any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership, or other entity, as otherwise permitted by the partnership agreement;

 

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conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or

 

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any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our general partner may make amendments to the partnership agreement without the approval of any limited partner if our general partner determines that those amendments:

 

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do not adversely affect in any material respect our limited partners considered as a whole or any particular class of partnership interests as compared to other classes of partnership interests;

 

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are necessary or appropriate to satisfy any requirements, conditions or guidelines of any federal or state agency or judicial authority or contained in any statute, directive, order, ruling, or regulation;

 

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are necessary or appropriate to facilitate the trading of units or to comply with any rule, regulation, guideline, or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;

 

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are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

 

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are required to effect the intent expressed in the registration statement for our initial public offering or the intent of the provisions of the partnership agreement or are otherwise contemplated by the partnership agreement.

Opinion of Counsel and Limited Partner Approval

For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes in connection with any of the amendments. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90.0% of the outstanding units voting as a single class unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interest of us or our limited partners.

In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our and our subsidiaries’ assets in a single transaction or a series of related transactions, including

 

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by way of merger, consolidation, or other combination, or sale of ownership interests of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our and our subsidiaries’ assets without that approval. Our general partner may also sell all or substantially all of our and our subsidiaries’ assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to our partnership agreement, each of our units will be a substantially identical unit of our partnership following the transaction, and our partnership interests to be issued do not exceed 20% of our outstanding partnership interests immediately prior to the transaction.

If the conditions specified in the partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey some or all of our assets to, a newly formed entity if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters, and the governing instruments of the new entity provide our limited partners and our general partner with the same rights and obligations as contained in the partnership agreement. The unitholders are not entitled to dissenters’ rights of appraisal under the partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets, or any other similar transaction or event.

Termination and Dissolution

We will continue as a limited partnership until terminated under the partnership agreement. We will dissolve upon:

 

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the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;

 

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there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

 

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the entry of a decree of judicial dissolution of our partnership; or

 

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the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with the partnership agreement or withdrawal or removal following approval and admission of a successor.

Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in the partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

 

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the action would not result in the loss of limited liability of any limited partner; and

 

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none of our partnership, our operating companies or any of our other subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.

Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are continued as a limited partnership, the liquidator authorized to wind up our affairs, acting with all of the powers of our general partner that are necessary or appropriate, will liquidate our assets and apply the proceeds of the liquidation as described in “How We Make Cash Distributions—Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

 

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Withdrawal or Removal of Our General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to June 30, 2020 without giving 90 days’ written notice to the limited partners of its intention to withdraw and obtaining the approval of the holders of at least a majority of the outstanding common units, voting as a class, excluding common units held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after June 30, 2020, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice to our unitholders, and that withdrawal will not constitute a violation of our partnership agreement. In addition, the partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest, incentive distributions rights and liquidation units in us without the approval of the unitholders. Please see “—Transfer of General Partner Interest” and “—Transfer of Incentive Distribution Rights.”

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up, and liquidated, unless within a specified period of time after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please see “—Termination and Dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 80% of the outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units. The ownership of more than 20% of the outstanding common units by our general partner and its affiliates would give them the practical ability to prevent our general partner’s removal.

The partnership agreement also provides that, if our general partner is removed as our general partner under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal, our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at that time.

In the event of removal of a general partner under circumstances where cause exists or withdrawal of a general partner where that withdrawal violates the partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution rights for their fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest and its incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

 

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In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Interest

Except for the transfer by our general partner of all, but not less than all, of its general partner interests to:

 

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an affiliate of our general partner (other than an individual); or

 

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another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity;

our general partner may not transfer all or any part of its general partner interests to another person prior to June 30, 2020 without the approval of the holders of at least a majority of the outstanding common units, voting as a class, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of the partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters.

On or after June 30, 2020, our general partner and its affiliates may at any time transfer all or any of their general partnership interests to one or more persons, without unitholder approval.

Transfer of Ownership Interests in Our General Partner

At any time, the owners of our general partner may sell or transfer all or part of their ownership interests in our general partner to an affiliate or third party without the approval of our unitholders.

Transfer of Incentive Distribution Rights and Liquidation Units

Our general partner, or any other holder of our incentive distribution rights, may transfer all or part of its incentive distribution rights without approval of our unitholders. Any holder of liquidation units may transfer all or part of its liquidation units without approval of our unitholders.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove our general partner or otherwise change our management. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20.0% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group that acquires the units with the prior approval of the board of directors of our general partner.

Our partnership agreement also provides that, if our general partner is removed as our general partner under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal, our general partner will have the right to convert its general partner interests and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at that time.

Prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market.

 

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Limited Call Right

If at any time our general partner and its affiliates own more than 80.0% of the outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the remaining limited partner interests of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10 but not more than 60 days’ notice. The purchase price in the event of this purchase is the greater of:

 

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the highest cash price paid by either our general partner or any of its affiliates for any partnership securities of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those partnership securities; and

 

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the current market price as of the date three days before the date the notice is mailed.

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have its limited partner interests purchased at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of its common units in the market. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Common Units.”

Meetings; Voting

Except as described below regarding a person or group owning 20.0% or more of any class of units then outstanding, unitholders who are record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20.0% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority, by percentage interest, of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

Each record holder of a unit has a vote according to its percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “—Issuance of Additional Interests.” However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20.0% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum, or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and its nominee provides otherwise.

Any notice, demand, request, report, or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

 

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Voting Rights of Incentive Distribution Rights

If a majority of the incentive distribution rights are held by our general partner and its affiliates, the holders of the incentive distribution rights will have no right to vote in respect of such rights on any matter, unless otherwise required by law, and the holders of the incentive distribution rights shall be deemed to have approved any matter approved by our general partner.

If less than a majority of the incentive distribution rights are held by our general partner and its affiliates, the incentive distribution rights will be entitled to vote on all matters submitted to a vote of unitholders, other than amendments and other matters that our general partner determines do not adversely affect the holders of the incentive distribution rights in any material respect. On any matter in which the holders of incentive distribution rights are entitled to vote, such holders will vote together with the common units, as a single class, and such incentive distribution rights shall be treated in all respects as common units when sending notices of a meeting of our limited partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under our partnership agreement. The relative voting power of the holders of the incentive distribution rights and the common units will be set in the same proportion as cumulative cash distributions, if any, in respect of the incentive distribution rights for the four consecutive quarters prior to the record date for the vote bears to the cumulative cash distributions in respect of the common units for such four quarters.

Status as Limited Partner

By transfer of common units in accordance with our partnership agreement, each transferee of common units will be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Except as described above under “—Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.

Non-Citizen Assignees; Redemption

If we are or become subject to federal, state, or local laws or regulations that, in the determination of our general partner, create a substantial risk of cancellation or forfeiture of any property in which we have an interest because of the nationality, citizenship or other related status of any limited partner, our general partner may require each limited partner to furnish information about its nationality, citizenship or related status. If a limited partner fails to furnish information about its nationality, citizenship or other related status within 30 days after a request for the information or our general partner determines after receipt of the information that the limited partner is not an eligible citizen, the limited partner may be treated as a non-citizen assignee. A non-citizen assignee does not have the right to direct the voting of its units and may not receive distributions in kind upon our liquidation.

Furthermore, we have the right to redeem all of the common units of any holder that our general partner concludes is not an eligible citizen or fails to furnish the information requested by our general partner. The redemption price in the event of such redemption for each unit held by such unitholder will be the lesser of (i) the current market price for each such unit and (ii) the price paid for each such unit by the unitholder. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Any such promissory note will bear interest at the rate of 5% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date.

Indemnification

Under our partnership agreement, we will indemnify the following persons in most circumstances, to the fullest extent permitted by law, from and against all losses, claims, damages, or similar events:

(1) our general partner;

(2) any departing general partner;

 

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(3) any person who is or was an affiliate of our general partner or any departing general partner;

(4) any person who is or was an officer, director, member, partner, fiduciary or trustee of any entity described in clause (1), (2) or (3) above or any of its subsidiaries;

(5) any person who is or was serving as a director, officer, member, partner, fiduciary or trustee of another person at the request of our general partner or any departing general partner or any of their affiliates; and

(6) any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or loan funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement. To the extent that the indemnification provisions of our partnership agreement purport to include indemnification for liabilities arising under the Securities Act of 1933, as amended, or the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and is therefore unenforceable.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to us.

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and financial reporting purposes, we use the calendar year.

We will furnish or make available (by posting on our website or other reasonable means) to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to its interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at its own expense, have furnished to it:

 

•

a current list of the name and last known address of each partner;

 

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a copy of our tax returns;

 

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information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each became a partner;

 

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copies of our partnership agreement, the certificate of limited partnership of the partnership, related amendments, and powers of attorney under which they have been executed;

 

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information regarding the status of our business and financial condition; and

 

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any other information regarding our affairs as our general partner determines is just and reasonable.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or that we are required by law or by agreements with third parties to keep confidential.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units or other partnership interests proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts.

 

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MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

This section is a summary of the material U.S. federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States with respect to the acquisition, ownership and disposition of our common units issued pursuant to this prospectus and, unless otherwise noted in the following discussion, is the opinion of Holland & Hart LLP, tax counsel to our general partner and us, only insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Code”), existing and proposed Treasury regulations promulgated under the Code (the “Treasury Regulations”) and current administrative rulings and court decisions, all of which are subject to change, possibly retroactively. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Westmoreland Resource Partners, LP and our operating subsidiaries.

The following discussion does not comment on all U.S. federal income tax matters affecting us or our unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, entities treated as partnerships for U.S. federal income tax purposes, trusts, nonresident aliens, U.S. expatriates and former citizens or long-term residents of the United States or other unitholders subject to specialized tax treatment, such as banks, insurance companies and other financial institutions, tax-exempt institutions, non-U.S. persons (including, without limitation, controlled foreign corporations, passive foreign investment companies and non-U.S. persons eligible for the benefits of an applicable income tax treaty with the United States), former U.S. citizens and residents, IRAs, employee benefit plans, persons who hold or receive our common units pursuant to the exercise of any employee option or otherwise as compensation, partnerships, real estate investment trusts (REITs) or mutual funds, dealers in securities or currencies, traders in securities, U.S. persons whose “functional currency” is not the U.S. dollar, persons holding their units as part of a “straddle,” “hedge,” “conversion transaction” or other risk reduction transaction, and persons deemed to sell their units under the constructive sale provisions of the Code. In addition, the discussion only comments to a limited extent on state, and does not comment on local or non-U.S., tax consequences. Accordingly, we encourage each prospective unitholder to consult its own tax advisor in analyzing the federal, state, local and non-U.S. tax consequences particular to it of the ownership or disposition of common units.

No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions of tax counsel. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

All statements as to matters of U.S. federal income tax law and legal conclusions with respect thereto, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of tax counsel and are based on the accuracy of the representations made by us.

For the reasons described below, tax counsel has not rendered an opinion with respect to the following specific federal income tax issues: (i) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “-Tax Consequences of Unit Ownership-Treatment of Short Sales”); (ii) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “-Disposition of Common Units-Allocations Between Transferors and Transferees”); (iii) whether assignees of common units who are entitled to execute and deliver transfer

 

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applications, but who fail to execute and deliver transfer applications, will be treated as our partners for tax purposes (please read “—Limited Partner Status”); and (iv) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “—Tax Consequences of Unit Ownership-Section 754 Election” and “—Uniformity of Units”).

Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account its share of items of income, gain, loss and deduction of the partnership in computing its federal income tax liability, regardless of whether cash distributions are made to it by the partnership. Distributions by a partnership to a partner are generally not taxable to the partner unless the amount of cash distributed to it is in excess of the partner’s adjusted basis in its partnership interest. Section 7704 of the Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the mining, production, transportation, storage and marketing of coal and certain other natural resources. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 5% of our gross income for our current taxable year will not be qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, tax counsel is of the opinion that at least 90% of our gross income for our current taxable year constitutes qualifying income. The portion of our income that is qualifying income may change from time to time.

A publicly traded partnership may not rely upon the Qualifying Income Exception if it is registered under the Investment Company Act of 1940, as amended, or the 1940 Act. If we are required to register under the 1940 Act, we will be taxed as a corporation even if we meet the Qualifying Income Exception. Based on an opinion of counsel regarding the 1940 Act and the factual representations made by us and our general partner, tax counsel is of the opinion that we may rely on the Qualifying Income Exception.

No ruling has been or will be sought from the IRS regarding, and the IRS has made no determination as to, our status or the status of our operating subsidiaries for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Code. Instead, we will rely on the opinion of tax counsel on such matters. It is the opinion of tax counsel that, based upon the Code, Treasury Regulations, published revenue rulings and court decisions and the representations described below that:

 

•

We are classified as a partnership for federal income tax purposes; and

 

•

Each of our operating subsidiaries is disregarded as an entity separate from us for federal income tax purposes.

In rendering its opinion, tax counsel has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which tax counsel has relied include:

 

•

Neither we nor our operating subsidiaries have elected or will elect to be treated as a corporation;

 

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For each taxable year, more than 90% of our gross income has been and will be income of the type that tax counsel has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Code; and

 

•

Each hedging transaction that we treat as resulting in qualifying income has been and will be appropriately identified as a hedging transaction pursuant to applicable Treasury Regulations, and has been and will be associated with coal that is held or to be held by us in activities that tax counsel has opined or will opine result in qualifying income.

 

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We believe that these representations have been true in the past and expect that these representations will continue to be true in the future.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as, at that time, we do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

If we were taxed as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as taxable dividend income, to the extent of our current and accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in its common units, or taxable capital gain, after the unitholder’s tax basis in its common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The discussion below is based on tax counsel’s opinion that we will be classified as a partnership for federal income tax purposes.

Limited Partner Status

Unitholders of Westmoreland Resource Partners, LP who have become limited partners of Westmoreland Resource Partners, LP will be treated as partners of the partnership for federal income tax purposes. A unitholder becomes a limited partner when the transfer or issuance of units to such person, or the admission of such person as a limited partner, is reflected in our books and records. Assignees who have executed and delivered transfer applications, and assignees who are awaiting admission as limited partners, will also be treated as partners of the partnership for federal income tax purposes. Where units are held in street name or by a nominee, the person in whose name the units are registered with us will be treated as the holder of such units. As there is no direct authority addressing assignees of units who are entitled to execute and deliver transfer applications and thereby become entitled to direct the exercise of attendant rights, but who fail to execute and deliver transfer applications, tax counsel’s opinion does not extend to these persons. Furthermore, a purchaser or other transferee of units who does not execute and deliver a transfer application may not receive some federal income tax information or reports furnished to record holders of units unless the units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application for those units.

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose its status as a partner with respect to those units for federal income tax purposes. Please read “—Tax Consequences of Unit Ownership-Treatment of Short Sales.”

Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their tax advisors with respect to their tax consequences of holding common units in Westmoreland Resource Partners, LP.

The references to “unitholders” in the discussion that follows are to holders of our common units who are treated as partners in Westmoreland Resource Partners, LP for federal income tax purposes.

 

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Tax Consequences of Unit Ownership

Flow-Through of Taxable Income

Subject to the discussion below under “—Entity-Level Collections,” we will not pay any federal income tax. Instead, each unitholder will be required to report on its income tax return its share of our income, gains, losses and deductions without regard to whether we make cash distributions to such unitholder. Consequently, we may allocate income to a unitholder even if it has not received a cash distribution. Each unitholder will be required to include in income its allocable share of our income, gains, losses and deductions for our taxable year or years ending with or within its taxable year. Absent a termination of our partnership for federal tax purposes, our taxable year ends on December 31.

Treatment of Distributions

Distributions made by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds the unitholder’s tax basis in its common units immediately before the distribution. Cash distributions made by us to a unitholder in an amount in excess of the unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under “—Disposition of Common Units.” Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution by us of cash to that unitholder. To the extent our distributions cause a unitholder’s “at-risk” amount to be less than zero at the end of any taxable year, the unitholder must recapture any losses deducted in previous years. Please read “—Limitations on Deductibility of Losses.”

A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease its share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. This deemed distribution may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of its tax basis in its common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture, depletion recapture and/or substantially appreciated “inventory items,” each as defined in the Code, and collectively, “Section 751 Assets.” To that extent, the unitholder will be treated as having been distributed its proportionate share of the Section 751 Assets and then having exchanged those assets with us in return for the non-pro rata portion of the actual (or deemed, with respect to certain debt) distribution made to the unitholder. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (i) the non-pro rata portion of that distribution over (ii) the unitholder’s tax basis (generally zero) for the share of Section 751 Assets deemed relinquished in the exchange.

Basis of Common Units

A unitholder’s initial tax basis for its common units will generally equal the amount the unitholder paid for the common units plus its share of our nonrecourse liabilities. That basis will be increased by its share of our income and by any increases in its share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in its share of our nonrecourse liabilities and by its share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner under Section 752 of the Code, but will have a share, generally based on its share of profits, of our nonrecourse liabilities. The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Please read “—Disposition of Common Units-Recognition of Gain or Loss.”

 

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Ratio of Taxable Income to Distributions

We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending December 31, 201    , will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than     % of the cash distributed with respect to that period. These estimates are based upon many assumptions regarding our business operations, including assumptions as to our revenues, capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we have adopted and will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct, and our counsel has not opined on the accuracy of these estimates.

The actual ratio of taxable income to distributions could be higher or lower than expected, and any differences could be material and could affect the value of the common units. For example, the ratio of taxable income to cash distributions to a purchaser of common units in this offering would be higher, and perhaps substantially higher, than our estimate with respect to the period described above if:

 

•

we distribute less cash than we have assumed in making this projection;

 

•

we make a future offering of common units and use the proceeds of the offering in a manner that does not produce additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering; or

 

•

legislation is passed that limits or repeals certain federal income tax preferences currently available with respect to coal exploration and development.

Limitations on Deductibility of Losses

The deduction by a unitholder of its share of our losses will be limited to the tax basis in its units and, in the case of an individual unitholder, estate, trust, or corporate unitholder (if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations) to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than its tax basis. A common unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause its at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction to the extent that its at-risk amount is subsequently increased, provided such losses do not exceed such common unitholder’s tax basis in its common units. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at-risk limitation in excess of that gain would no longer be utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of its units, excluding any portion of that basis attributable to its share of our nonrecourse liabilities, reduced by (i) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any amount of money it borrows to acquire or hold its units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at-risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in its share of our nonrecourse liabilities.

In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally trade or business activities in which

 

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the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or a unitholder’s investments in other publicly traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when the unitholder disposes of its entire investment in us in a fully taxable transaction with an unrelated party. The passive loss limitations are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.

A unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

Limitations on Interest Deductions

The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

 

•

interest on indebtedness properly allocable to property held for investment;

 

•

our interest expense attributed to income that is treated as portfolio income under the passive loss rules; and

 

•

the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or (if applicable) qualified dividend income. The IRS has indicated that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of income that is treated as portfolio income under the passive loss rules will be treated as investment income.

Entity-Level Collections

If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder, general partner, or former unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of a particular unitholder in which event the unitholder would be required to file a claim with the appropriate authority in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction

In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. At any time that incentive distributions are made to our general partner, gross income will be allocated to our general partner to the extent

 

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of these distributions. If we have a net loss, that loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts, second, to our general partner.

Specified items of our income, gain, loss and deduction will be allocated to account for (i) any difference between the tax basis and fair market value of our assets at the time of an offering and (ii) any difference between the tax basis and fair market value of any property contributed to us by the general partner and its affiliates that exists at the time of such contribution, together referred to in this discussion as the “Contributed Property.” The effect of these allocations, referred to as Section 704(c) Allocations, to a unitholder purchasing common units from us in an offering will be essentially the same as if the tax bases of our assets were equal to their fair market values at the time of the offering. In the event we issue additional common units or engage in certain other transactions in the future, “reverse Section 704(c) Allocations,” similar to the Section 704(c) Allocations described above, will be made to the general partner and all of our unitholders immediately prior to such issuance or other transactions to account for the difference between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of such issuance or future transaction. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Code to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity,” will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has “substantial economic effect.” In any other case, a partner’s share of an item will be determined on the basis of its interest in us, which will be determined by taking into account all the facts and circumstances, including:

 

•

its relative contributions to us;

 

•

the interests of all the partners in profits and losses;

 

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the interest of all the partners in cash flow; and

 

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the rights of all the partners to distributions of capital upon liquidation.

Tax counsel is of the opinion that allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction, except as to the issues described in “—Section 754 Election” and “—Disposition of Common Units-Allocations Between Transferors and Transferees” on which tax counsel is not opining.

Treatment of Short Sales

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:

 

•

any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

 

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any cash distributions received by the unitholder as to those units would be fully taxable; and

 

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all of these distributions would appear to be ordinary income.

 

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Because there is no direct or indirect controlling authority on the issue relating to partnership interests, tax counsel has not rendered an opinion regarding the tax treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their units. The IRS has previously announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read “—Disposition of Common Units-Recognition of Gain or Loss.”

Alternative Minimum Tax

Each unitholder will be required to take into account its distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. For 2015, the minimum tax rate for non-corporate taxpayers is 26% on the first $185,400 of alternative minimum taxable income (or, in the case of a married individual taxpayer filing a separate return, the first $92,700 of alternative minimum taxable income) in excess of the exemption amount and 28% on any additional alternative minimum taxable income, which thresholds change annually. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

Tax Rates

Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 39.6% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than twelve months) of individuals is 20%. However, these rates are subject to change by new legislation at any time.

A 3.8% Medicare tax is imposed upon certain net investment income earned by individuals, estates and trusts. For these purposes, net investment income generally includes a unitholder’s allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder’s net investment income or (ii) the amount by which the unitholder’s modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if the unitholder is married and filing separately) or $200,000 (in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Section 754 Election

We have made, and following any termination of our partnership for federal tax purpose, expect to make, the election permitted by Section 754 of the Code. That election is irrevocable without the consent of the IRS unless there is a constructive termination of the partnership. Please read “—Disposition of Common Units-Constructive Termination.” The election will generally permit us to adjust a common unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Code to reflect its purchase price. This election does not apply with respect to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, the unitholder’s inside basis in our assets will be considered to have two components: (i) its share of our tax basis in our assets (“common basis”) and (ii) its Section 743(b) adjustment to that basis.

We have adopted the remedial allocation method as to all our properties. Where the remedial allocation method is adopted, the Treasury Regulations under Section 743 of the Code require a portion of the Section 743(b) adjustment that is attributable to recovery property that is subject to depreciation under Section 168 of the Code and whose book basis is in excess of its tax basis to be depreciated over the remaining cost recovery period for the property’s unamortized Book-Tax Disparity. Under Treasury Regulation

 

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Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these and any other Treasury Regulations. Please read “—Uniformity of Units.”

We depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as non-amortizable to the extent attributable to property which is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “—Uniformity of Units.” A unitholder’s tax basis for its common units is reduced by its share of our deductions (whether or not such deductions were claimed on an individual’s income tax return) so that any position we take that understates deductions will overstate the common unitholder’s basis in its common units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “—Disposition of Common Units-Recognition of Gain or Loss.” Tax counsel has not rendered an opinion as to whether our method for depreciating Section 743 adjustments is sustainable for property subject to depreciation under Section 167 of the Code or if we use an aggregate approach as described above, as there is no direct or indirect controlling authority addressing the validity of these positions. Moreover, the IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the units. If such a challenge were sustained, the gain from the sale of units might be increased without the benefit of additional deductions.

A Section 754 election is advantageous if the transferee’s tax basis in its units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation deductions and its share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in its units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally, a built-in loss or a basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than the purchaser would have been allocated had the election not been revoked.

 

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Tax Treatment of Operations

Accounting Method and Taxable Year

We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income its share of our income, gain, loss and deduction for our taxable year ending within or with its taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of its units following the close of our taxable year but before the close of its taxable year must include its share of our income, gain, loss and deduction in income for its taxable year, with the result that the unitholder will be required to include in income for its taxable year its share of more than twelve months of our income, gain, loss and deduction. Please read “—Disposition of Common Units-Allocations Between Transferors and Transferees.”

Initial Tax Basis, Depreciation and Amortization

The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to an offering of new units will be borne by our unitholders holding interests in us prior to any such offering. Please read “—Tax Consequences of Unit Ownership-Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, we may elect to use the depreciation and cost recovery methods, including bonus depreciation to the extent available, that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. Please read “—Uniformity of Units.” Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Code.

The IRS may challenge the useful lives assigned to our assets or seek to characterize intangible assets as nonamortizable goodwill. If any such challenge or characterization is successful, the deductions allocated to a unitholder in respect of our assets could be reduced, and its share of taxable income received from us could be increased accordingly. Any such increase could be material.

If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of its interest in us. Please read “—Tax Consequences of Unit Ownership-Allocation of Income, Gain, Loss and Deduction” and “—Disposition of Common Units-Recognition of Gain or Loss.”

The costs we incur in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or determinations of basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

 

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Coal Income

Section 631 of the Code provides special rules by which gains or losses on the sale of coal may be treated, in whole or in part, as gains or losses from the sale of property used in a trade or business under Section 1231 of the Code. Specifically, Section 631(c) provides that if the owner of coal held for more than one year disposes of that coal under a contract by virtue of which the owner retains an economic interest in the coal, the gain or loss realized will be treated under Section 1231 of the Code as gain or loss from property used in a trade or business. Net Section 1231 gains will be treated as capital gains and net Section 1231 losses will be treated as ordinary losses. Please read “—Sales of Coal Reserves.” In computing such gain or loss, the amount realized is reduced by the adjusted depletion basis in the coal, determined as described in “—Coal Depletion.” For purposes of Section 631(c), the coal generally is deemed to be disposed of on the day on which the coal is mined. Further, Treasury Regulations promulgated under Section 631 provide that advance royalty payments may also be treated as proceeds from sales of coal to which Section 631 applies and, therefore, such payment may be treated as capital gain under Section 1231. However, if the right to mine the related coal expires or terminates under the contract that provides for the payment of advance royalty payments or such right is abandoned before the coal has been mined, pursuant to the Treasury Regulations, we may file an amended return that reflects the payments attributable to unmined coal as ordinary income and not as received from the sale of coal under Section 631.

Our royalties from coal leases generally will be treated as proceeds from sales of coal to which Section 631 applies. Accordingly, the difference between the royalties paid to us by the lessees and the adjusted depletion basis in the extracted coal generally will be treated as gain from the sale of property used in a trade or business, which may be treated as capital gain under Section 1231. Please read “—Sales of Coal Reserves.” Our royalties that do not qualify under Section 631(c) generally will be taxable as ordinary income in the year of sale.

Coal Depletion

In general, we are entitled to depletion deductions with respect to coal mined from the underlying mineral property. We generally are entitled to the greater of cost depletion limited to the basis of the property or percentage depletion. The percentage depletion rate for coal is 10%. If Section 631(c) applies to the disposition of the coal, however, we are not eligible for percentage depletion. Please see “—Coal Income.”

Depletion deductions we claim generally will reduce the tax basis of the underlying mineral property. Percentage depletion deductions can, however, exceed the total tax basis of the mineral property. The excess of our percentage depletion deductions over the adjusted tax basis of the property at the end of the taxable year is subject to tax preference treatment in computing the alternative minimum tax. Please read “—Tax Consequences of Unit Ownership—Alternative Minimum Tax.” Upon the disposition of the mineral property, a portion of the gain, if any, equal to the lesser of the deductions for depletion which reduce the adjusted tax basis of the mineral property plus deductible development and mining exploration expenses (discussed below), or the amount of gain recognized upon the disposition, will be treated as ordinary income to us. In addition, a corporate unitholder’s allocable share of the amount allowable as a percentage depletion deduction for any property will be reduced by 20% of the excess, if any, of that partner’s allocable share of the amount of the percentage depletion deductions for the taxable year over the adjusted tax basis of the mineral property as of the close of the taxable year.

Mining Exploration and Development Expenditures

We will elect to currently deduct mining exploration expenditures that we pay or incur to determine the existence, location, extent or quality of coal deposits prior to the time the existence of coal in commercially marketable quantities has been disclosed.

Amounts we deduct for mine exploration expenditures must be recaptured and included in our taxable income at the time a mine reaches the production stage, unless we elect to reduce future depletion deductions by the amount of the recapture. A mine reaches the producing stage when the major part of the coal production is obtained from working mines other than those opened for the purpose of development or the principal activity of the mine is the production of developed coal rather than the development of additional coal for mining. This

 

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recapture is accomplished through the disallowance of both cost and percentage depletion deductions on the particular mine reaching the producing stage. This disallowance of depletion deductions continues until the amount of adjusted exploration expenditures with respect to the mine have been fully recaptured. This recapture is not applied to the full amount of the previously deducted exploration expenditures. Instead, these expenditures are reduced by the amount of percentage depletion, if any, that was lost as a result of deducting these exploration expenditures.

We generally elect to defer mine development expenses, consisting of expenditures incurred in making coal available for extraction, after the exploration process has disclosed the existence of coal in commercially marketable quantities, and deduct them on a ratable basis as the coal benefited by the expenses is sold.

Mine exploration and development expenditures are subject to recapture as ordinary income to the extent of any gain upon a sale or other disposition of our property or of your common units. See “—Disposition of Common Units.” Corporate unitholders are subject to an additional rule that requires them to capitalize a portion of their otherwise deductible mine exploration and development expenditures. Corporate unitholders, other than some S corporations, are required to reduce their otherwise deductible exploration expenditures by 30%. These capitalized mine exploration and development expenditures must be amortized over a 60-month period, beginning in the month paid or incurred, using a straight-line method and may not be treated as part of the basis of the property for purposes of computing depletion.

When computing the alternative minimum tax, mine exploration and development expenditures are capitalized and deducted over a ten year period. Unitholders may avoid this alternative minimum tax adjustment of their mine exploration and development expenditures by electing to capitalize all or part of the expenditures and deducting them over ten years for regular income tax purposes. You may select the specific amount of these expenditures for which you wish to make this election.

Sales of Coal Reserves

If any coal reserves are sold or otherwise disposed of in a taxable transaction, we will recognize gain or loss measured by the difference between the amount realized (including the amount of any indebtedness assumed by the purchaser upon such disposition or to which such property is subject) and the adjusted tax basis of the property sold. Generally, the character of any gain or loss recognized upon that disposition will depend upon whether our coal reserves or the mined coal sold are held by us:

 

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for sale to customers in the ordinary course of business (i.e., if we are a “dealer” with respect to that property);

 

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for use in a trade or business within the meaning of Section 1231 of the Code; or

 

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as a capital asset within the meaning of Section 1221 of the Code.

In determining dealer status with respect to coal reserves and other types of real estate, the courts have identified a number of factors for distinguishing between a particular property held for sale in the ordinary course of business and one held for investment. Any determination must be based on all the facts and circumstances surrounding the particular property and sale in question.

We intend to hold our coal reserves for use in a trade or business and for long-term capital appreciation. Although our general partner may consider strategic sales of coal reserves consistent with achieving long-term capital appreciation, our general partner does not anticipate frequent sales of coal reserves or significant marketing, improvement or subdivision activity in connection with any strategic sales. Thus, the general partner does not believe that we will be viewed as a dealer. In light of the factual nature of this question, however, there is no assurance that our purposes for holding our properties will not change and that our future activities will not cause us to be a “dealer” in coal reserves.

 

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If we are not a dealer with respect to our coal reserves and we have held the disposed property for more than a one-year period primarily for use in our trade or business, the character of any gain or loss realized from a disposition of the property will be determined under Section 1231 of the Code. If we have not held the property for more than one year at the time of the sale, gain or loss from the sale will be taxable as ordinary income.

A unitholder’s distributive share of any Section 1231 gain or loss generated by us will be aggregated with any other gains and losses realized by that unitholder from the disposition of property used in the trade or business, as defined in Section 1231(b) of the Code, and from the involuntary conversion of such properties and of capital assets held in connection with a trade or business or a transaction entered into for profit for the requisite holding period. If a net gain results, all such gains and losses will be long-term capital gains and losses; if a net loss results, all such gains and losses will be ordinary income and losses. Net Section 1231 gains will be treated as ordinary income to the extent of prior net Section 1231 losses of the taxpayer or predecessor taxpayer for the five most recent prior taxable years to the extent such losses have not previously been offset against Section 1231 gains. Losses are deemed recaptured in the chronological order in which they arose.

If we are not a dealer with respect to our coal reserves and that property is not used in a trade or business, the property will be a “capital asset” within the meaning of Section 1221 of the Code. Gain or loss recognized from the disposition of that property will be taxable as capital gain or loss, and the character of such capital gain or loss as long-term or short-term will be based upon our holding period of such property at the time of its sale. The requisite holding period for long-term capital gain treatment is more than one year.

Upon a disposition of coal reserves, a portion of the gain, if any, equal to the lesser of (1) the depletion deductions that reduced the tax basis of the disposed mineral property plus deductible development and mining exploration expenses or (2) the amount of gain recognized on the disposition, will be treated as ordinary income to us.

Deduction for U.S. Production Activities

Subject to the limitations on the deductibility of losses discussed above and the limitation discussed below, each unitholder will be entitled to a deduction, herein referred to as the Section 199 deduction, equal to a specified percentage of our qualified production activities income that is allocated to such unitholder. The percentage is currently 9% for qualified production activities income.

Qualified production activities income is generally equal to gross receipts from domestic production activities reduced by cost of goods sold allocable to those receipts, other expenses directly associated with those receipts, and a share of other deductions, expenses and losses that are not directly allocable to those receipts or another class of income. The products produced must be manufactured, produced, grown or extracted in whole or in significant part by the taxpayer in the United States.

For a partnership, the Section 199 deduction is determined at the partner level. To determine its Section 199 deduction, each unitholder will aggregate its share of the qualified production activities income allocated to it from us with the unitholder’s qualified production activities income from other sources. Each unitholder must take into account its distributive share of the expenses allocated to it from our qualified production activities regardless of whether we otherwise have taxable income. However, our expenses that otherwise would be taken into account for purposes of computing the Section 199 deduction are only taken into account if and to the extent the unitholder’s share of losses and deductions from all of our activities is not disallowed by the basis rules, the at-risk rules or the passive activity loss rules. Please read “—Tax Consequences of Unit Ownership—Limitations on Deductibility of Losses.”

The amount of a unitholder’s Section 199 deduction for each year is limited to 50% of the IRS Form W-2 wages actually or deemed paid by the unitholder during the calendar year that are deducted in arriving at qualified production activities income. Each unitholder is treated as having been allocated IRS Form W-2 wages from us equal to the unitholder’s allocable share of our wages that are deducted in arriving at qualified

 

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production activities income for that taxable year. It is not anticipated that we or our subsidiaries will pay material wages that will be allocated to our unitholders, and thus a unitholder’s ability to claim the Section 199 deduction may be limited.

This discussion of the Section 199 deduction does not purport to be a complete analysis of the complex legislation and Treasury authority relating to the calculation of domestic production gross receipts, qualified production activities income, or IRS Form W-2 wages, or how such items are allocated by us to common unitholders. Further, because the Section 199 deduction is required to be computed separately by each common unitholder, no assurance can be given, and counsel is unable to express any opinion, as to the availability or extent of the Section 199 deduction to the common unitholders. Moreover, the availability of Section 199 deductions may be reduced or eliminated if recently proposed (or similar) tax legislation is enacted. For a discussion of such legislative proposals, please read “Recent Legislative Developments” below. Each prospective common unitholder is encouraged to consult its tax advisor to determine whether the Section 199 deduction would be available to it.

Disposition of Common Units

Recognition of Gain or Loss

A unitholder will be required to recognize gain or loss on a sale of units equal to the difference between the unitholder’s amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by it plus its share of our nonrecourse liabilities attributable to the units sold. Because the amount realized includes all or a portion of a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

A unitholder’s tax basis in the unitholder’s units is adjusted by distributions, as well as by virtue of allocations of income, gains, losses, deductions and liabilities. Please read “—Tax Consequences of Unit Ownership-Basis of Common Units.” Prior distributions from us in excess of cumulative net taxable income for a unit that decreased a unitholder’s tax basis in that unit, in effect, will become taxable income if the unit is sold at a price greater than the unitholder’s tax basis in that unit, even if the price received is less than its original cost. If any of our allocations are subsequently disputed by the IRS, unitholders who sold units prior to the resolution of such dispute may be required to increase or decrease the amount of gain or loss reported on such sale. Please read “—Disposition of Units-Allocations Between Transferors and Transferees” and “—Tax Consequences of Unit Ownership-Section 754 Election.”

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held for more than twelve months will generally be taxed at the U.S. federal income tax rate applicable to long-term capital gains. However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to assets giving rise to depreciation or depletion recapture or other “unrealized receivables” or to “inventory items” we own. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Capital losses may offset capital gains and no more than $3,000 of ordinary income each year, in the case of individuals, and may only be used to offset capital gains in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest

 

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sold equals an amount that bears the same relation to the partner’s tax basis in its entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling discussed above, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, the unitholder may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult its tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Code can affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

 

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a short sale;

 

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an offsetting notional principal contract; or

 

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a futures or forward contract;

in each case, with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees

In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will generally be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations as there is no direct or indirect controlling authority on this issue. The Department of the Treasury and the IRS have issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. The proposed regulations do not specifically authorize the use of the proration method we have adopted. Existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations; however, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Accordingly, tax counsel has not rendered an opinion on the validity of this method of allocating income and deductions between transferor and transferee unitholders because the issue has not been finally resolved by the IRS or the courts. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our

 

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taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferor and transferee unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who disposes of common units prior to the record date set for a cash distribution for any quarter will be allocated items of our income, gain, loss and deductions attributable to the month of sale but will not be entitled to receive that cash distribution.

Notification Requirements

A unitholder who sells any units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale), unless a broker or nominee will satisfy such requirement. A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a sale of units, in some cases, may lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker who will satisfy such requirements.

Constructive Termination

We will be considered to have terminated our tax partnership for federal income tax purposes if there are sales or exchanges which, in the aggregate, constitute 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of measuring whether the 50% threshold is reached, multiple sales of the same interest are counted only once. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in its taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in us filing two tax returns (and unitholders could receive two Schedules K-1 if the relief discussed below is not available) for one fiscal year and the cost of the preparation of these returns will be borne by all unitholders. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination. The IRS has announced a publicly traded partnership technical termination relief procedure whereby if a publicly traded partnership that has technically terminated requests publicly traded partnership technical termination relief and the IRS grants such relief, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.

Uniformity of Units

Because we cannot match transferors and transferees of common units and for other reasons, we must maintain uniformity of the economic and tax characteristics of the common units to a purchaser of these common units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity could result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to apply to a material portion of our assets. Any non-uniformity could have a negative impact on the value of the common units. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.”

Our partnership agreement permits our general partner to take positions in filing our tax returns that preserve the uniformity of our common units even under circumstances like those described above. These positions may include reducing for some unitholders the depreciation, amortization or loss deductions to which

 

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they would otherwise be entitled or reporting a slower amortization of Section 743(b) adjustments for some unitholders than that to which they would otherwise be entitled. Tax counsel is unable to opine as to validity of such filing positions. A unitholder’s basis in common units is reduced by its share of our deductions (whether or not such deductions were claimed on an individual income tax return) so that any position that we take that understates deductions will overstate the unitholder’s basis in its common units, and may cause the unitholder to understate gain or overstate loss on any sale of such common units. Please read “—Disposition of Units—Recognition of Gain or Loss” and “—Tax Consequences of Unit Ownership—Section 754 Election.” The IRS may challenge one or more of any positions we take to preserve the uniformity of common units. If such a challenge were sustained, the uniformity of common units might be affected, and, under some circumstances, the gain from the sale of common units might be increased without the benefit of additional deductions.

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, non-U.S. corporations and other non-U.S. persons raises issues unique to those investors and, as described below to a limited extent, may have substantially adverse tax consequences to them. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units. Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income less certain allowable deductions allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to it.

A regulated investment company or “mutual fund” is required to derive 90% or more of its gross income from certain permitted sources. The American Jobs Creation Act of 2004 generally treats net income from the ownership of publicly traded partnerships as derived from such permitted sources. We anticipate that all of our net income will be treated as derived from such permitted sources.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, we will withhold tax at the highest applicable effective tax rate, from cash distributions made to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or W-8BEN-E, or applicable substitute form, in order to obtain credit for these withholding taxes. We will also withhold tax on U.S. source income recognized by foreign unitholders that is not effectively connected with our U.S. trade or business, unless foreign unitholders qualify for certain treaty benefits or an exception provided in the Code. Certain exceptions may require foreign unitholders to provide certain information to us and to the IRS. A change in applicable law may require us to change these procedures. In addition, because a non-U.S. corporation that owns units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our earnings and profits, as adjusted for changes in the non-U.S. corporation’s “U.S. net equity,” that is effectively connected with the conduct of a U.S. trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the non-U.S. corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Code.

A non-U.S. unitholder who sells or otherwise disposes of a common unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the non-U.S. unitholder. Under a ruling published by the IRS, interpreting the scope of “effectively connected income,” a non-U.S. unitholder would be considered to be engaged in a trade or business in the United States by virtue of the U.S. activities of the partnership, and part or all of that unitholder’s gain would be effectively connected with that unitholder’s indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a non-U.S. unitholder generally will be subject to U.S. federal

 

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income tax upon the sale or disposition of a common unit if (i) the unitholder owned (directly or constructively applying certain attribution rules) more than 5% of our common units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the common units or the five-year period ending on the date of disposition. Currently, we believe that more than 50% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future. Therefore, non-U.S. unitholders may be subject to U.S. federal income tax on gain from the sale or disposition of their units.

Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes its share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor tax counsel can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of its return.

Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. Our partnership agreement names Westmoreland Resources GP, LLC as our Tax Matters Partner.

The Tax Matters Partner has made and will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on its federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

 

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Additional Withholding Requirements

Under the Foreign Account Tax Compliance Act, the relevant withholding agent may be required to withhold 30% of any interest, dividends and other fixed or determinable annual or periodical gains, profits and income from sources within the United States (“FDAP Income”) or gross proceeds from the sale of any property of a type which can produce interest or dividends from sources within the United States paid to (i) a foreign financial institution (for which purposes includes foreign broker-dealers, clearing organizations, investment companies, hedge funds and certain other investment entities) unless such foreign financial institution agrees to verify, report and disclose its U.S. accountholders and meets certain other specified requirements or (ii) a non-financial foreign entity that is a beneficial owner of the payment unless such entity certifies that it does not have any substantial U.S. owners or provides the name, address and taxpayer identification number of each substantial U.S. owner and such entity meets certain other specified requirements or otherwise qualifies for an exemption from this withholding. These rules generally will apply to payments of FDAP Income which are made after June 30, 2014, and to payments of relevant gross proceeds which are made after December 31, 2016. Thus, to the extent we have FDAP Income or gross proceeds after these dates that are not treated as effectively connected with a U.S. trade or business (please read “—Tax-Exempt Organizations and Other Investors”), unitholders who are foreign financial institutions or certain other non-U.S. entities may be subject to withholding on distributions they receive from us, or their distributive share of our income, pursuant to the rules described above. Non-U.S. and U.S. unitholders are encouraged to consult their own tax advisors regarding the possible implications of this legislation on their investment in our units.

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

 

•

the name, address and taxpayer identification number of the beneficial owner and the nominee;

 

•

whether the beneficial owner is:

 

•

a person that is not a U.S. person;

 

•

a non-U.S. government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

 

•

a tax-exempt entity;

 

•

the amount and description of units held, acquired or transferred for the beneficial owner; and

 

•

specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from dispositions.

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1.5 million per calendar year, is imposed by the Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

 

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For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

 

•

for which there is, or was, “substantial authority;” or

 

•

as to which there is a reasonable basis and the pertinent facts of that position are adequately disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must adequately disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which we do not believe includes us, or any of our investments, plans or arrangements.

A substantial valuation misstatement exists if (a) the value of any property, or the adjusted basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or adjusted basis, (b) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Code Section 482 is 200% or more (or 50% or less) of the amount determined under Section 482 to be the correct amount of such price, or (c) the net Code Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10% of the taxpayer’s gross receipts. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 200% or more than the correct valuation or certain other thresholds are met, the penalty imposed increases to 40%. We do not anticipate making any valuation misstatements.

In addition, the 20% accuracy-related penalty also applies to any portion of an underpayment of tax that is attributable to transactions lacking economic substance. To the extent that such transactions are not adequately disclosed, the penalty imposed is increased to 40%. Additionally, there is no reasonable cause defense to the imposition of this penalty to such transactions. We do not anticipate undertaking any transactions that lack economic substance.

Reportable Transactions

If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single year, or $4 million in any combination of six successive tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read “-Information Returns and Audit Procedures.”

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following additional consequences:

 

•

accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “-Accuracy-Related Penalties;”

 

•

for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and

 

•

in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any “reportable transactions.”

 

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Recent Legislative Developments

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Please read “-Partnership Status.” We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us and may be applied retroactively. Any such changes could negatively impact the value of an investment in our units.

The White House recently released the Budget Proposal. Among the changes recommended in the Budget Proposal is the elimination of certain key U.S. federal income tax preferences relating to coal exploration and development. The Budget Proposal would (i) eliminate current deductions and 60-month amortization for exploration and development costs relating to coal and other hard mineral fossil fuels; (ii) repeal the percentage depletion allowance with respect to coal properties; (iii) repeal capital gains treatment of coal and lignite royalties; and (iv) exclude from the definition of domestic production gross receipts all gross receipts derived from the sale, exchange, or other disposition of coal, other hard mineral fossil fuels, or primary products thereof. The passage of any legislation as a result of the Budget Proposal or any other similar changes in U.S. federal income tax laws could eliminate certain tax deductions that are currently available to us, and any such change could increase the taxable income allocation to our unitholders and negatively impact the value of an investment in our units.

State, Local and Non-U.S. Tax Considerations

In addition to federal income taxes, you likely will be subject to other taxes, such as state and local income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we conduct business or own property or in which you are a resident. We currently conduct business or own property in several states, each of which impose personal income taxes on individuals. Most of these states also impose an income or other entity-level tax on corporations and other entities. Moreover, we may also do business or own property in other states in the future that impose income or similar taxes on individuals, corporations and other entities. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on its investment in us. A unitholder may be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we conduct business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “-Tax Consequences of Unit Ownership-Entity-Level Collections.” Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states and localities, of its investment in us. Accordingly, each prospective unitholder is urged to consult its own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and non-U.S., as well as U.S. federal tax returns, that may be required of it. Tax counsel has not rendered an opinion on the state, local or non-U.S. tax consequences of an investment in us.

 

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INVESTMENT BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of the Employee Retirement Income Security Act of 1974 (“ERISA”) and the restrictions imposed by Section 4975 of the Internal Revenue Code and provisions under any federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of the Internal Revenue Code or ERISA (collectively, “Similar Laws”). For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or individual retirement accounts (known as IRAs) or annuities established or maintained by an employer or employee organization, and entities whose underlying assets are considered to include “plan assets” of such plans, accounts and arrangements. Among other things, consideration should be given to:

 

•

whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;

 

•

whether, in making the investment, the plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws;

 

•

whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read “Material Federal Income Tax Consequences—Tax-Exempt Organizations and Other Investors”; and

 

•

whether making such an investment will comply with the delegation of control and prohibited transaction provisions of ERISA, the Internal Revenue Code and any other applicable Similar Laws

The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans, and IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving “plan assets” with parties that, with respect to the plan, are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code unless an exemption is available. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Internal Revenue Code. In addition, the fiduciary of the ERISA plan that engaged in such a non-exempt prohibited transaction may be subject to penalties and liabilities under ERISA and the Internal Revenue Code.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our general partner would also be a fiduciary of such plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code. For this purpose, the Department of Labor regulations and Section 3(42) of ERISA provide guidance with respect to whether, in certain circumstances, the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets.” Under these rules, an entity’s assets would not be considered to be “plan assets” if, among other things:

(a) the equity interests acquired by the employee benefit plan are publicly offered securities—i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, are freely transferable and are registered under certain provisions of the federal securities laws;

(b) the entity is an “operating company,”—i.e., it is primarily engaged in the production or sale of a product or service, other than the investment of capital, either directly or through a majority-owned subsidiary or subsidiaries; or

 

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(c) there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest, disregarding any such interests held by our general partner, its affiliates and some other persons, is held generally by the employee benefit plans referred to above that are subject to ERISA and IRAs and other similar vehicles that are subject to Section 4975 of the Internal Revenue Code.

Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in clauses (a) and (b) above.

In light of the serious penalties imposed on persons who engage in prohibited transactions or other violations, plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA, the Internal Revenue Code and other Similar Laws.

 

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UNDERWRITING

BMO Capital Markets Corp. is acting as the representative of the underwriters in this offering. Under the terms of an underwriting agreement, a form of which is filed as an exhibit to the registration statement relating to this prospectus, each of the underwriters named below has severally agreed to purchase from us the respective number of common units opposite its name below.

 

Underwriters		Number of Common Units
BMO Capital Markets Corp.
Total

The underwriting agreement provides that the underwriters’ obligation to purchase the common units depends on the satisfaction of the conditions contained in the underwriting agreement including:

 

•

the obligation to purchase all of the common units offered hereby if any of the common units are purchased;

 

•

the representations and warranties made by us to the underwriters are true;

 

•

there has been no material change in the condition of us or in the financial markets; and

 

•

we deliver customary closing documents to the underwriters.

Commissions and Expenses

The following table summarizes the underwriting discounts we will pay to the underwriters in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us for the common units.

 

		No Exercise				Full Exercise
Per common unit		$				$
Total		$				$

The representative of the underwriters has advised us that the underwriters propose to offer the common units directly to the public at the public offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $         per common unit. The underwriters may allow, and the selected dealers may re-allow, a discount from the concession not in excess of $         per common unit to other dealers. After the offering, the representative may change the offering price and other selling terms.

The expenses of the offering that are payable by us are estimated to be approximately $             million (exclusive of underwriting discounts).

Option to Purchase Additional Common Units

We have granted the underwriters an option exercisable for 30 days after the date of this prospectus to purchase, from time to time, in whole or in part, up to an aggregate of             additional common units at the public offering price less underwriting discounts. This option may be exercised if the underwriters sell more than             common units in connection with this offering. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional common units based on the underwriter’s proportionate share of the underwriting commitment in the offering as indicated in the table at the beginning of this “Underwriting” section.

 

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Lock-Up Agreements

We, our subsidiaries, our general partner and its affiliates, including the directors and executive officers of the general partner, have agreed, without the prior written consent of the representative, not to, directly or indirectly, offer, pledge, announce the intention to sell, sell, contract to sell, sell an option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase, or otherwise transfer or dispose of any common units or any securities that may be converted into or exchanged for any common units, enter into any swap or other agreement that transfers, in whole or in part, any of the economic consequences of ownership of the common units, file or cause to be filed a registration statement with respect to the registration of any common units or securities convertible, exercisable or exchangeable into common units or any other of our securities or publicly disclose the intention to do any of the foregoing for a period of 90 days from the date of this prospectus other than permitted transfers provided, however, that the foregoing will not apply to the offer for sale, sale or other issuance of common units or other securities to WCC or any of its subsidiaries provided that any such recipient of common units or other securities enters into a similar lock-up agreement with the underwriters.

The 90-day restricted period described in the preceding paragraph will be extended if:

 

•

during the last 17 days of the 90-day restricted period we issue an earnings release or announce material news or a material event; or

 

•

prior to the expiration of the 90-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 90-day period,

in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or material event.

The representative, in its sole discretion, may release the common units subject to these restrictions in whole or part at any time with or without notice. When determining whether or not to release common units from these restrictions, the primary factors that the representative will consider include the requesting unitholder’s reasons for requesting the release, the number of common units for which the release is being requested and the prevailing economic and equity market conditions at the time of the request.

Indemnification

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, and to contribute to payments that the underwriters may be required to make for these liabilities.

Stabilization, Short Positions and Penalty Bids

The representative may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales, and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the common units, in accordance with Regulation M under the Exchange Act:

 

•

Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

 

•

A short position involves a sale by the underwriters of common units in excess of the number of common units the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of common units involved in the sales made by the underwriters in excess of the number of common units they are obligated to purchase is not greater than the number of common units that they may purchase by exercising their option to purchase additional common units. In a naked short position, the number of common units involved is greater than the number of common

 

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units in their option to purchase additional common units. The underwriters may close out any short position by either exercising their option to purchase additional common units and/or purchasing common units in the open market. In determining the source of common units to close out the short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through their option to purchase additional common units. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering.

 

•

Syndicate covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions.

 

•

Penalty bids permit the representative to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common units or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NYSE or otherwise and, if commenced, may be discontinued at any time.

Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. In addition, neither we nor any of the underwriters make representation that the representative will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

Electronic Distribution

A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of common units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representative on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter’s web site and any information contained in any other web site maintained by an underwriter is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter in its capacity as underwriter and should not be relied upon by investors.

Stamp Taxes

If you purchase common units offered in this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.

Relationships/FINRA Rules

The underwriters and their respective affiliates have, from time to time, performed, and may in the future perform, various financial advisory, commercial banking and investment banking services for us and our affiliates, for which they received or will receive customary fees and expense reimbursement. Additionally, affiliates of BMO Capital Markets Corp. are providing advisory services to WCC in connection with the Contribution and will receive customary fees in connection with such services.

 

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In addition, in the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers, and such investment and securities activities may involve securities and instruments of ours or our affiliates. The underwriters and their affiliates may also make investment recommendations and/or publish or express independent research views in respect of such securities or financial instruments and may hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

Because the Financial Industry Regulatory Authority, or FINRA, views our common units as interests in a direct participation program, this offering is being made in compliance with Rule 2310 of the FINRA Rules. Investor suitability with respect to the common units will be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

 

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VALIDITY OF THE SECURITIES

The validity of the common units offered by this prospectus will be passed upon for us by Holland & Hart LLP, Denver, Colorado. Holland & Hart LLP will also render an opinion on the material federal income tax consequences regarding the common units. Certain legal matters in connection with our common units offered hereby will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.

EXPERTS

The financial statements of Westmoreland Resource Partners, LP included and incorporated by reference in this prospectus and elsewhere in the registration statement have been so included or incorporated by reference in reliance upon the report of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.

The financial statements of Westmoreland Kemmerer, Inc. as of December 31, 2014 and 2013 and for the years then ended, and for the eleven months ended December 31, 2012, appearing in this prospectus and Registration Statement have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The information incorporated by reference in this prospectus relating to the estimates of our proven and probable reserves associated with our surface mining operations in Ohio is derived from our internal estimates, which estimates were audited by John T. Boyd Company, an independent mining and geological consulting firm. The information included in this prospectus relating to the estimates of our coal reserves located in Northern Appalachia and the Illinois Basin is derived from reserve reports prepared by John T. Boyd Company. This information is included in this prospectus upon the authority of said firm as an expert.

 

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WHERE YOU CAN FIND MORE INFORMATION

We have filed a registration statement with the SEC under the Securities Act that registers the securities offered by this prospectus. The registration statement, including the attached exhibits, contains additional relevant information about us. The rules and regulations of the SEC allow us to omit some information included in the registration statement from this prospectus. For further information with respect to our Partnership and our common units to be sold in this offering, reference is made to the registration statement, including the exhibits and schedules to the registration statement. Statements contained in this prospectus as to the contents of any contract or other document referred to in this prospectus are not necessarily complete and, where that contract is an exhibit to the registration statement, each statement is qualified in all respects by reference to the exhibit to which the reference relates.

In addition, we file annual, quarterly and other reports and other information with the SEC. You may read and copy any document we file, including the registration statement and the exhibits and schedules thereto, at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-732-0330 for further information on the operation of the SEC’s public reference room. Our SEC filings are available on the SEC’s website at http://www.sec.gov. We also make available free of charge on our website at http://www.westmorelandmlp.com all materials that we file electronically with the SEC, including our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, Section 16 reports and amendments to these reports as soon as reasonably practicable after such materials are electronically filed with, or furnished to, the SEC.

INFORMATION INCORPORATED BY REFERENCE

The SEC allows us to “incorporate by reference” the information we have filed with the SEC. This means that we can disclose important information to you without actually including the specific information in this prospectus by referring you to other documents filed separately with the SEC. These other documents contain important information about us, our financial condition and our results of operations. The information incorporated by reference is an important part of this prospectus, and any information contained in this prospectus or in any document incorporated by reference in this prospectus will be deemed to be modified or superseded to the extent that a statement contained in this prospectus or any free writing prospectus provided to you in connection with this offering modifies or supersedes the original statement. Any statement so modified or superseded will not be deemed, except as so modified or superseded, to be a part of this prospectus.

We incorporate by reference in this prospectus and in the registration statement of which this prospectus forms a part the documents listed below, excluding any information in those documents that is deemed by the rules of the SEC to be “furnished” and not “filed”:

 

•

our Annual Report on Form 10-K for the year ended December 31, 2014, filed with the SEC on March 6, 2015;

 

•

out Quarterly Report on Form 10-Q for the quarter ended March 31, 2015, filed with the SEC on April 28, 2015; and

 

•

our Current Reports on Form 8-K filed with the SEC on January 7, 2015, January 12, 2015, January 16, 2015, February 24, 2015, March 4, 2015 and March 16, 2015.

 

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You may obtain any of the documents incorporated by reference in this prospectus from the SEC through the SEC’s website at the address provided above. You also may request a copy of any document incorporated by reference in this prospectus (including exhibits to those documents specifically incorporated by reference in this prospectus), at no cost, by visiting our internet website at http://www.westmorelandmlp.com, or by writing or calling us at the following address:

Westmoreland Resource Partners, LP

9540 South Maroon Circle, Suite 200

Englewood, Colorado 80112

(855) 922-6463

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Some of the information included in this prospectus and the documents we incorporate by reference contain “forward-looking statements.” Forward-looking statements can be identified by words such as “anticipates,” “intends,” “plans,” “seeks,” “believes,” “estimates,” “expects,” “may,” “plan,” “predict,” “project,” “should,” “could,” “will” and similar references to future periods. Examples of forward-looking statements include, but are not limited to, statements we make throughout this prospectus regarding recent significant transactions and their anticipated effects on us, and statements we make regarding factors that may cause our results of operation in future periods to differ from our expectations.

Forward-looking statements are based on our current expectations and assumptions regarding our business, the economy and other future conditions. Because forward-looking statements relate to the future, they are subject to inherent uncertainties, risks and changes in circumstances that are difficult to predict. Our actual results may differ materially from those contemplated by the forward-looking statements. We therefore caution you against relying on any of these forward-looking statements. They are statements neither of historical fact nor guarantees or assurances of future performance. Important factors that could cause actual results to differ materially from those in the forward-looking statements include political, economic, business, competitive, market, weather and regulatory conditions and the following:

 

•

Our substantial level of indebtedness and our ability to adhere to financial covenants related to our borrowing arrangements;

 

•

Inaccuracies in our estimates of our coal reserves;

 

•

The effect of consummating financing, acquisition and/or disposition transactions;

 

•

Our potential inability to expand or continue current coal operations due to limitations in obtaining bonding capacity for new mining permits, and/or increases in our mining costs as a result of increased bonding expenses;

 

•

The effect of prolonged maintenance or unplanned outages at our operations or those of our major power generating customers;

 

•

The inability to control costs;

 

•

Competition within our industry and with producers of competing energy sources;

 

•

Our relationships with, and other conditions affecting, our customers;

 

•

The availability and costs of key supplies or commodities, such as diesel fuel, steel, explosives and tires;

 

•

Potential title defects or loss of leasehold interests in our properties, which could result in unanticipated costs or an inability to mine the properties;

 

•

The inability to renew our mineral leases or material changes in lease royalties;

 

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•

The effect of legal and administrative proceedings, settlements, investigations and claims, including any related to citations and orders issued by regulatory authorities, and the availability of related insurance coverage;

 

•

Existing and future legislation and regulation affecting both our coal mining operations and our customers’ coal usage, governmental policies and taxes, including those aimed at reducing emissions of elements such as mercury, sulfur dioxides, nitrogen oxides, particulate matter or greenhouse gases;

 

•

The effect of Environmental Protection Agency’s inquiries and regulations on the operations of the power plants to which we provide coal;

 

•

Our ability to pay our quarterly distributions which substantially depends upon our future operating performance (which may be affected by prevailing economic conditions in the coal industry), debt covenants, and financial, business and other factors, some of which are beyond our control;

 

•

Adequacy and sufficiency of our internal controls;

 

•

Our potential need to recognize additional impairment and/or restructuring expenses associated with our operations, as well as any changes to previously identified impairment or restructuring expense estimates, including additional impairment and restructuring expenses associated with our Illinois Basin operations; and Other factors that are described in “Risk Factors” in this prospectus and under the heading “Risk Factors” found in our reports filed with the SEC, including our Annual Reports on Form 10-K and our Quarterly Reports on Form 10-Q.

Unless otherwise specified, the forward-looking statements in this prospectus speak as of the date of this prospectus. Factors or events that could cause our actual results to differ may emerge from time to time, and it is not possible for us to predict all of them. We undertake no obligation to publicly update any forward-looking statements, whether because of new information, future developments or otherwise, except as may be required by law.

Reserve engineering is a process of estimating underground accumulations of coal that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by our reserve engineers. In addition, the results of mining, testing and production activities may justify revision of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development of reserves. Accordingly, reserve estimates may differ from the quantities of coal that are ultimately recovered.

 

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INDEX TO FINANCIAL STATEMENTS

 

Westmoreland Resource Partners, LP Unaudited Pro Forma Combined Financial Statements			F-2
Westmoreland Kemmerer, Inc. (A Wholly Owned Subsidiary of Westmoreland Coal Company) As of and for the three months ended March 31, 2015 and 2014 (Unaudited)
Balance Sheets			F-19
Statements of Operations			F-20
Statements of Comprehensive Income			F-21
Statements of Shareholder’s Equity			F-22
Statements of Cash Flows			F-23
Notes to Financial Statements			F-24
Westmoreland Kemmerer, Inc. (A Wholly Owned Subsidiary of Westmoreland Coal Company) As of and for the years ended December 31, 2014 and 2013 and Eleven Months Ended December 31, 2012
Report of Independent Registered Public Accounting Firm			F-31
Balance Sheets			F-32
Statements of Operations			F-33
Statements of Comprehensive Income			F-34
Statements of Shareholder’s Equity			F-35
Statements of Cash Flows			F-36
Notes to Financial Statements			F-37

 

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UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

The accompanying unaudited pro forma combined financial statements of Westmoreland Resource Partners, LP include the accounts and operations of the Partnership and its consolidated subsidiaries and are prepared in conformity with accounting principles generally accepted in the United States of America (“US GAAP”). WCC’s cost of acquiring our general partner (the “GP Acquisition”) has been pushed-down to establish a new accounting basis for us beginning in the last minutes of the year ended December 31, 2014. Accordingly, the accompanying consolidated financial statements are presented for both our Predecessor and our Successor, corresponding to the accounting periods preceding and following the completion of the GP Acquisition. The summary historical consolidated financial information for our Successor as of December 31, 2014 and for the year then ended, and for our Predecessor for the period from January 1, 2014 to December 31, 2014, has been derived from our audited consolidated financial statements included in our 2014 Form 10-K, which is incorporated by reference into this prospectus. The summary historical financial information for Kemmerer as of the year ended December 31, 2014 has been derived from the audited financial statements of Kemmerer included elsewhere in this prospectus.

The columns with the heading “WRPS Pro Forma” present unaudited pro forma condensed combined financial information of WRPS (which consists of our Successor and Kemmerer) that gives effect to the following transactions as if they occurred as of January 1, 2014:

 

•

the issuance by the Partnership of             common units to the public in this offering;

 

•

the issuance by the Partnership of             common units to WCC as part of the Contribution Consideration;

 

•

the issuance by the Partnership of              Series A Convertible units to WCC as part of the Contribution Consideration;

 

•

the payment of estimated underwriting commissions and other offering expenses of $         million;

 

•

the net proceeds of $70.0 million received from deferred draw borrowings under our existing credit facility with interest at a variable rate per annum equal to, at our option, LIBOR (floor of 0.75% plus 8.5%) or the Reference Rate (as defined in the 2014 Financing Agreement). Additionally, the 2014 Financing Agreement also provides for “PIK Interest” at a variable rate per annum between 1.00% and 3.00% based on our Consolidated Total Net Leverage Ratio (as defined in the 2014 Financing Agreement);

 

•

our entry into an additional $15 million revolving credit facility;

 

•

the distribution to WCC of a portion of the net proceeds generated from this offering and borrowings under our credit facility as part of the Contribution Consideration; and

 

•

the retention of the assets and liabilities of Kemmerer, with the exception of the post-retirement medical benefits obligation, the pension obligations and the related deferred income tax assets.

The unaudited pro forma combined financial information of WRPS is presented for illustrative purposes only and may not be indicative of our financial position or results of operations that would have actually occurred had the Contribution and the other transactions listed above been completed at or as of the dates indicated, nor is it indicative of our future operating results or financial position.

The unaudited pro forma balance sheet and the pro forma statements of operations were derived by adjusting the historical combined financial statements of WRPS. The adjustments are based upon currently available information and certain estimates and assumptions; therefore, actual adjustments will differ from the pro forma adjustments. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma combined financial statements.

 

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The Contribution will be accounted for as business combination involving entities or businesses under common control, which is defined as a business combination in which all of the combining entities or businesses ultimately are controlled by the same party or parties both before and after the combination, and that control is not transitory. FASB ASC Topic 805, Business Combinations (the Transactions Between Entities Under Common Control Subsections of ASC Topic 805), provides guidance on accounting for common control transactions. When accounting for a transfer of assets or exchange of shares between entities under common control, the entity that receives the net assets or the equity interests should initially recognize the assets and liabilities transferred at their carrying amounts in the accounts of the transferring entity at the date of transfer. The contributed assets and liabilities of Kemmerer are reflected in the unaudited pro forma condensed combined financial information of WRPS at carrying value of Kemmerer at March 31, 2015.

We derived the information in the following tables from, and that information should be read together with and is qualified in its entirety by reference to, the historical and pro forma combined financial statements and the accompanying notes included elsewhere in this prospectus. The tables should be read together with such financial statements and notes thereto, and also with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The integration of Kemmerer in connection with the Contribution may not achieve the desired results. The unaudited pro forma condensed combined financial information of WRPS does not reflect the cost of any integration activities or expected benefits from the Contribution and synergies that may be derived from any integration activities, both of which may have a material effect on the consolidated results of operations in periods following the completion of the Contribution. Once the necessary due diligence has been completed, the final purchase prices have been determined and any purchase price adjustments have been completed, as applicable, actual results may differ materially from the information presented in the unaudited pro forma combined financial information of WRPS.

 

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WESTMORELAND RESOURCE PARTNERS SUCCESSOR

UNAUDITED PRO FORMA COMBINED BALANCE SHEET

March 31, 2015

(in thousands)

 

		Westmoreland Resource Partners, LP (Successor)				Westmoreland Kemmerer, Inc.				Adjustments						WRPS Pro Forma
ASSETS
Current assets:
Cash and cash equivalents		$	1,785			$	—				5,000			3		$	9,785
											70,000			2
											75,000			4
											(1,000	)		7
											(4,000	)		5,8
											(2,000	)		5,9
											(135,000	)		5
Accounts receivable:
Trade			23,560				14,827				(1,847	)		10			36,540
Other			116				72				—						188
Total accounts receivable			23,676				14,899				(1,847	)					36,728
Inventories			12,696				10,548				—						23,244
Deferred income taxes			—				856				(856	)		1			—
Prepaid expenses			2,637				1,894				—						4,531
Total current assets			40,794				28,197				5,297						74,288
Property, plant and equipment, at costs:
Land and mineral rights			72,993				21,301				—						94,294
Plant and equipment			133,949				122,544				—						256,493
			206,942				143,845				—						350,787
Less accumulated depreciation, depletion and amortization			(9,801	)			(39,390	)			—						(49,191	)
Net property, plant and equipment			197,141				104,455				—						301,596
Advance coal royalties			11,498				—				—						11,498
Restricted investments and bond collateral			9,534				25,692				—						35,226
Intangible assets, net of accumulated amortization			30,483				—				—						30,483
Deferred income taxes			—				16,075				(16,075	)		1			—
Other non-current assets			6,607				—				1,000			7			7,607
Total assets		$	296,057			$	174,419			$	(9,778	)				$	460,696

 

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WESTMORELAND RESOURCE PARTNERS SUCCESSOR

UNAUDITED PRO FORMA COMBINED BALANCE SHEET

March 31, 2015

(in thousands)

 

		Westmoreland Resource Partners, LP (Successor)				Westmoreland Kemmerer, Inc.				Adjustments								WRPS Pro Forma
LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)
Current liabilities:
Current installments of long-term debt		$	6			$	3,441			$	—							$	3,447
Accounts payable and accrued expenses:
Trade			19,469				12,206				(1,847	)			10				29,828
Deferred revenue			—				4,944				—								4,944
Production taxes			975				18,963				—								19,938
Accrued compensation			401				—				—								401
Postretirement medical benefits			—				436				(436	)			1				—
Asset retirement obligation			9,855				2,674				—								12,529
Other current liabilities			1,434				—				—								1,434
Total current liabilities			32,140				42,664				(2,283	)							72,521
Long-term debt, less current installments			176,354				13,394				70,000				2				265,273
											5,000				3
											525				12
Postretirement medical costs, less current portion			—				61,410				(61,410	)			1				—
Pension obligations			—				17,922				(17,922	)			1				—
Asset retirement obligation, less current portion			22,714				16,673				—								39,387
Warrants			1,952				—				—								1,952
Other liabilities			160				—				—								160
Total liabilities			233,320				152,063				(6,090	)							379,293
Partners capital (deficit):
Net sponsor investment			—				21,304				63,849				1				—
											(85,153	)			5
Limited partner units			29,328				—				75,000				4				92,571
											(11,757	)			5
Limited partner Series A Convertible Units			—				—				(44,090	)			5				(44,090	)
General partner units			33,409				—				(525	)			12				32,884
Accumulated other comprehensive income			—				1,052				(1,012	)			6				40
Noncontrolling interest			—				—				—								—
Total partners’ capital			62,737				22,356				(3,688	)							81,405
Total liabilities and partners’ capital (deficit)		$	296,057			$	174,419			$	(9,778	)						$	460,698

 

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WESTMORELAND RESOURCE PARTNERS SUCCESSOR

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS

(in thousands)

 

		For the Three Months Ended March 31, 2015
		Westmoreland Resource Partners, LP (Successor)				Westmoreland Kemmerer, Inc.				Adjustments				WRPS Pro Forma
Revenues:
Coal revenues		$	61,750			$	41,523			$	—			$	103,273
Royalty revenues			1,870				—				(1,847	)10			23
Non-coal revenues			3,947				—				—				3,947
Total Revenues			67,567				41,523				(1,847	)10			107,243
Costs and expenses:
Cost of coal revenues (excluding depreciation, depletion and amortization)			54,651				31,022				(1,847	)			83,826
Cost of non-coal revenues			3,155				—				—				3,155
Depreciation, depletion and amortization			10,180				4,709				—				14,889
Selling and administrative			2,548				1,622				—				4,170
Loss on sale/disposal of assets			1,034				23				—				1,057
Restructuring charges			553				—				—				553
Total cost and expenses			72,121				37,376				(1,847	)			107,650
Operating income (loss)			(4,554	)			4,147				—				(407	)
Other (expense) income:
Interest expense			(5,780	)			(153	)			(525	)12			(8,077	)
											(1,619	)13
Interest income			—				369				—				369
Loss on debt extinguishment			—				—				—				—
Change in fair value of warrants			29				—				—				29
Other			—				92				—				92
Total other expenses			(5,751	)			308				(2,144	)			(7,587	)
Net income (loss) before income taxes			(10,305	)			4,455				(2,144	)			(7,994	)
Income tax expense			—				(338	)			338	11			—
Net (loss) income			(10,305	)			4,117				338				(7,994	)
Less net (loss) income attributable to noncontrolling interest			—				—				—				—
Net (loss) income attributable to WMLP unitholders			(10,305	)			4,117				(1,806	)			(7,994	)
Less net (loss) income allocated to general partner			(63	)			4,117				(4,067	)11			(13	)
Net income (loss) income allocated to limited partners		$	(10,242	)		$	—			$	2,261			$	(7,981	)
Net loss per limited partner unit-basic and diluted														$	(0.36	)
Weighted-average limited partner units-basic and diluted															14,922,187
Net loss per Class A limited partner unit-basic and diluted														$	(0.36	)
Weighted-average Class A limited partner units-basic and diluted															7,500,000
Net loss per general partner unit-basic and diluted														$	(0.36	)
Weighted-average general partner unit-basic and diluted															35,291

 

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WESTMORELAND RESOURCE PARTNERS SUCCESSOR

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS

(in thousands)

 

		For the Period of December 31, 2014				For the Year Ended December 31, 2014														For the Period January 1, 2014 to December 31, 2014
		Westmoreland Resource Partners, LP (Successor)				Westmoreland Kemmerer, Inc.				Adjustments				WRPS Pro Forma						Oxford Resource Partners LP (Predecessor)
Revenues:
Coal revenues		$	—			$	170,508			$	—			$	170,508					$	295,662
Royalty revenues			—				—				—				—						284
Non-coal revenues			—				—				—				—						26,317
Total Revenues			—				170,508				—				170,508						322,263
Costs and expenses:
Cost of coal revenues (excluding depreciation, depletion and amortization)			—				118,691				—				118,691						258,575
Cost of non-coal revenues			—				—				—				—						1,700
Depreciation, depletion and amortization			—				16,912				—				16,912						39,315
Selling and administrative			—				5,335				—				5,335						20,510
Loss on sale/disposal of assets			—				309				—				309						(218	)
Restructuring charges			2,783				—				—				2,783						75
Total cost and expenses			2,783				141,247				—				144,030						319,957
Operating income (loss)			(2,783	)			29,261				—				26,478						2,306
Other (expense) income:
Interest expense			—				(333	)			(2,100	)12			(8,908	)					(27,787	)
											(6,475	)13
Interest income			—				429				—				429						4
Loss on debt extinguishment			(1,623	)			—				—				(1,623	)					500
Change in fair value of warrants			—				—				—				—						822
Other			—				254				—				254						—
Total other (expenses) income			(1,623	)			350				(8,575	)			(9,848	)					(26,461	)
Net income (loss) before income taxes			(4,406	)			29,611				(8,575	)			16,630						(24,155	)
Income tax expense			—				(4,292	)			4,292				—						—
Net (loss) income			(4,406	)			25,319				4,292	11			16,630						(24,155	)
Less net (loss) income attributable to noncontrolling interest			—				—				(4,283	)			—						1,270
Net (loss) income attributable to WMLP unitholders			(4,406	)			25,319				(4,283	)			16,630						(22,885	)
Less net (loss) income allocated to general partner			(28	)			25,319				(25,264	)			27						(429	)
Net income (loss) income allocated to limited partners		$	(4,378	)		$	—			$	20,981			$	16,603					$	(22,456	)

 

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		For the Period of December 31, 2014		For the Year Ended December 31, 2014										For the Period January 1, 2014 to December 31, 2014
		Westmoreland Resource Partners, LP (Successor)		Westmoreland Kemmerer, Inc.		Adjustments		WRPS Pro Forma						Oxford Resource Partners LP (Predecessor)
Net income (loss) per limited partner unit-basic and diluted								$	0.75					$	(10.92	)
Weighted-average limited partner units- basic and diluted									14,715,644						2,063,983
Net income (loss) per Class A limited partner unit-basic and diluted								$	0.75						—
Weighted-average Class A limited partner units									7,500,000						—
Net income (loss) per general partner unit-basic and diluted								$	0.75					$	(10.92	)
Weighted-average general partner units-basic and diluted									35,291						35,291

 

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Adjusted EBITDA

EBITDA and Adjusted EBITDA are supplemental measures of financial performance that are not required by, or presented in accordance with, GAAP. EBITDA and Adjusted EBITDA are key metrics used by us to assess our operating performance and we believe that EBITDA and Adjusted EBITDA are useful to an investor in evaluating our operating performance because these measures:

 

•

are used widely by investors to measure a company’s operating performance without regard to items excluded from the calculation of such terms, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors; and

 

•

help investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure and asset base from our operating results.

Neither EBITDA nor Adjusted EBITDA is a measure calculated in accordance with GAAP. The items excluded from EBITDA and Adjusted EBITDA are significant in assessing our operating results. EBITDA and Adjusted EBITDA have limitations as analytical tools, and should not be considered in isolation from, or as a substitute for, analysis of our results as reported under GAAP. For example, EBITDA and Adjusted EBITDA:

 

•

do not reflect our cash expenditures, or future requirements for capital and major maintenance expenditures or contractual commitments;

 

•

do not reflect changes in, or cash requirements for, our working capital needs; and

 

•

do not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on certain of our debt obligations.

In addition, although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA and Adjusted EBITDA do not reflect any cash requirements for such replacements. Other companies in our industry and in other industries may calculate EBITDA and Adjusted EBITDA differently from the way that we do, limiting their usefulness as comparative measures. Because of these limitations, EBITDA and Adjusted EBITDA should not be considered as measures of discretionary cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our GAAP results and using EBITDA and Adjusted EBITDA only as supplemental data.

Distributable Cash Flow

Distributable Cash Flow represents Adjusted EBITDA less cash interest expense (net of interest income), reserve replacement expenditures, maintenance capital expenditures, cash reclamation expenditures, and noncontrolling interest. Cash interest expense represents the portion of our interest expense accrued and paid in cash during the reporting periods presented or that we will pay in cash in future periods as the obligations become due. Other maintenance capital expenditures represent expenditures for coal reserve replacement, expenditures for plant, equipment and mine development. Cash reclamation expenditures represent the reduction to our reclamation and mine closure costs resulting from cash payments. Earnings attributable to the noncontrolling interest are not available for distribution to our unitholders and accordingly are deducted.

Distributable Cash Flow should not be considered as an alternative to net income (loss) attributable to our unitholders, income from operations, cash flows from operating activities or any other measure of performance presented in accordance with GAAP. Although Distributable Cash Flow is not a measure of performance calculated in accordance with GAAP, we believe Distributable Cash Flow is useful to investors because this measurement is used by many analysts and others in the industry as a performance measurement tool to evaluate our operating and financial performance, facilitating comparison with the performance of other publicly traded limited partnerships.

 

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The tables below show how we calculated EBITDA, Adjusted EBITDA and Distributable Cash Flow and reconciles Distributable Cash Flow to net loss, the most directly comparable GAAP financial measure.

WESTMORELAND RESOURCE PARTNERS SUCCESSOR

UNAUDITED PRO FORMA COMBINED RECONCILIATION OF NET LOSS TO

EBITDA, ADJUSTED EBITDA AND DISTRIBUTABLE CASH FLOW

(in thousands)

 

		For the Three Months Ended March 31, 2015
		Westmoreland Resource Partners, LP (Successor)				Westmoreland Kemmerer, Inc.				Adjustments				WRPS Pro Forma
Reconciliation of Net Loss to Adjusted EBITDA
Net loss		$	(10,305	)		$	4,117			$	(1,806	)		$	(7,994	)
Income tax expense			—				338				(338	)			—
Interest expense, net of interest income			5,780				(216	)			2,144				7,708
Depreciation, depletion and amortization			10,180				4,709				—				14,889
Accretion of ARO			804				443				—				1,247
EBITDA			6,459				9,391				—				15,850
Restructuring and impairment charges			553				—				—				553
Change in fair value of warrants			(29	)			—				—				(29	)
Acquisition related costs1			1,400				—				—				1,400
Loss on sale/disposal of assets			1,034				23				—				1,057
Unit-based compensation			21				92				—				113
Other non-recurring costs			115				(92	)			—				23
Adjusted EBITDA			9,553				9,414				—				18,967
Cash interest expense, net of interest income			(4,047	)			216				1,619				(5,450	)
Other maintenance capital expenditures			(1,353	)			(1,113	)			—				(2,466	)
Reclamation and mine closure costs			(958	)			(44	)			—				(1,002	)
Distributable Cash Flow		$	3,195			$	8,473			$	(1,619	)		$	10,049

 

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WESTMORELAND RESOURCE PARTNERS SUCCESSOR

UNAUDITED PRO FORMA COMBINED RECONCILIATION OF NET LOSS TO

DISTRIBUTABLE CASH FLOW

(in thousands)

 

		For the Period of December 31, 2014				For the Year Ended December 31, 2014												For the Period January 1, 2014 to December 31, 2014
		Westmoreland Resource Partners, LP (Successor)				Westmoreland Kemmerer, Inc.				Adjustments				WRPS Pro Forma				Oxford Resource Partners LP (Predecessor)
Reconciliation of Net Loss to Adjusted EBITDA
Net loss		$	(4,406	)		$	25,319			$	(4,283	)		$	16,630			$	(24,155	)
Income tax expense			—				4,292				(4,292	)			—				—
Loss (gain) on extinguishment of debt			1,623				—				—				1,623				(500	)
Interest expense, net of interest income			—				96				8,575				8,671				28,028
Depreciation, depletion and amortization			—				16,912				—				16,912				39,070
Accretion of ARO			—				1,613				—				1,613				2,337
EBITDA			(2,783	)			48,232				—				45,449				44,780
Restructuring and impairment charges			2,783				—				—				2,783				75
Legal settlements			—				—				—				—				(17,548	)
Recapitalization costs			—				—				—				—				5,470
Change in fair value of warrants			—				—				—				—				(822	)
Loss (gain) on sale/disposal of assets			—				309				—				309				(218	)
Unit-based compensation			—				216				—				216				4,559
Adjusted EBITDA			—				48,757				—				48,757				36,296
Noncontrolling interest’s Adjusted EBITDA			—				—				—				—				(324	)
Debt issuance costs			—				—				—				—				(6,993	)
Cash interest expense, net of interest income			—				96				(6,475	)			6,379				(15,952	)
Other maintenance capital expenditures			—				(7,489	)			—				(7,489	)			(14,066	)
Reclamation and mine closure costs			—				(885	)			—				(885	)			(4,999	)
Distributable Cash Flow		$	—			$	40,479			$	(6,475	)		$	34,004			$	(6,038	)

 

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1. Basis of Presentation, the Offering and Other Transactions

The accompanying pro forma combined financial statements include the accounts and operations of the Partnership and its consolidated subsidiaries and are prepared in conformity with accounting principles generally accepted in the United States of America (“US GAAP”). WCC’s cost of acquiring our general partner has been pushed-down to establish a new accounting basis for us beginning in the last minutes of the year ended December 31, 2014. Accordingly, the accompanying pro forma combined financial statements are presented for two periods, Predecessor and Successor, which relate to the accounting periods preceding and succeeding the completion of the transaction. The Predecessor and Successor periods have been separated by a vertical line on the face of the pro forma combined financial statements to highlight the facts that the financial information for such periods has been prepared under two different historical-cost bases of accounting.

The accompanying combined financial statement and related notes of WRPS presented in the pro forma combined balance sheet for the period ended March 31, 2015 and the pro forma combined statement of operations for the year ended December 31, 2014 and the three months ended March 15, 2015 are unaudited and include the combined results of (1) Oxford Mining; (2) Oxford Mining-Kentucky; (3) WKFCH; (4) Harrison Resources; and (5) Kemmerer, and WCC’s cost of acquiring our general partner has been pushed-down to establish a new accounting basis for us beginning in the last minutes of the year ended December 31, 2014. Accordingly, the accompanying combined financial statement and related notes are presented for two periods, Predecessor and Successor, which relate to the accounting periods preceding and succeeding the completion of the transaction. The Predecessor and Successor periods have been separated by a vertical line on the face of the consolidated financial statements to highlight the facts that the financial information for such periods has been prepared under two different historical-cost bases of accounting.

These pro forma combined financial statements are prepared in connection with the proposed public offering of limited partner common units in the Partnership, which will own the operations defined above. Subsequent to this offering, WCC will direct the business operations of the Partnership through ownership and control of the Partnership’s general partner. The Partnership is not expected to have any employees. WCC and its affiliates’ employees will be responsible for conducting the Partnership’s business and operating its assets.

The pro forma combined financial statements include the accounts of WRPS and have been prepared in accordance with accounting principles generally accepted in the United States. All significant intercompany balances and transactions within WRPS have been eliminated. The combined financial statements of WRPS have been prepared from the separate records maintained by WCC and may not necessarily be indicative of the conditions that would have existed or the results of operations if WRPS had been operated as an unaffiliated entity. In the opinion of management, all adjustments have been reflected that are necessary for a fair presentation of the pro forma combined financial statements.

The interim pro forma combined balance sheet as of March 31, 2015 and the pro forma combined statements of operations for the three months ended March 31, 2015 are unaudited. WCC’s cost of acquiring our general partner has been pushed-down to establish a new accounting basis for us beginning in the last minutes of the year ended December 31, 2014. Accordingly, the accompanying pro forma combined financial statements are presented for two periods, Predecessor and Successor, which relate to the accounting periods preceding and succeeding the completion of the transaction. The Predecessor and Successor periods have been separated by a vertical line on the face of the condensed consolidated financial statements to highlight the facts that the financial information for such periods has been prepared under two different historical-cost bases of accounting. These unaudited interim pro forma combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States. In the opinion of management, the unaudited interim pro forma combined financial statements have been prepared on the same basis as the audited combined financial statements and include all adjustments necessary to present fairly the financial position and results of operations for the respective interim periods. Interim combined financial results are not necessarily indicative of the results to be expected for an annual period.

 

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The historical financial information is derived from the historical combined financial statements of WRPS. The pro forma adjustments have been prepared as if the transactions to be effected at the closing of this offering had taken place on March 31, 2015, in the case of the pro forma balance sheet, or as of January 1, 2014, in the case of the pro forma statement of operations for the year ended December 31, 2014 and for the three months ended March 31, 2015.

The pro forma financial statements reflect the following transactions:

 

•

the issuance by the Partnership of             common units to the public in this offering;

 

•

the issuance by the Partnership of             common units to WCC as part of the Contribution Consideration;

 

•

the issuance by the Partnership of              Series A Convertible units to WCC as part of the Contribution Consideration;

 

•

the payment of estimated underwriting commissions and other offering expenses of $             million;

 

•

the net proceeds of $70.0 million received from deferred draw borrowings under our existing credit facility with interest at a variable rate per annum equal to, at our option, LIBOR (floor of 0.75% plus 8.5%) or the Reference Rate (as defined in the 2014 Financing Agreement). Additionally, the 2014 Financing Agreement also provides for “PIK Interest” at a variable rate per annum between 1.00% and 3.00% based on our Consolidated Total Net Leverage Ratio (as defined in the 2014 Financing Agreement);

 

•

our entry into an additional $15 million revolving credit facility;

 

•

the distribution to WCC of a portion of the net proceeds generated from this offering and borrowings under our credit facility as part of the Contribution Consideration; and

 

•

the retention of the assets and liabilities of Kemmerer, with the exception of the post-retirement medical benefits obligations pension obligations and the related deferred income tax assets.

As a partnership, we are not a taxable entity for federal or state income tax purposes; the tax effect of our activities pass through to our unitholders. Therefore, no provision or liability for federal or state income taxes is included in our financial statements. Net income (loss) for financial purposes may differ significantly from taxable income (loss) reportable to our unitholders as a result of timing or permanent difference between financial reporting under U.S. GAAP and regulations promulgated by the U.S. Internal Revenue Service.

2. Pro Forma Adjustments and Assumptions

 

1

Reflects the post retirement-medical benefits obligations pension obligations and the related deferred income tax assets and liabilities, which were excluded from the Contribution. Post-retirement medical and pension expenses incurred by our general partner after the transaction are covered by the Service Agreement. Under the Services Agreement, our general partner will continue providing administrative, engineering, operating and other services to us. Administrative services include, without limitation, legal, accounting, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit and tax and reimburse the general partner at cost for other expenses and expenditures.

 

2

Reflects the net proceeds of $70.0 million received from deferred draw borrowings under our existing credit facility with interest at a variable rate per annum equal to, at our option, LIBOR (floor of 0.75% plus 8.5%) or the Reference Rate (as defined in the 2014 Financing Agreement). Additionally, the 2014 Financing Agreement also provides for “PIK Interest” at a variable rate per annum between 1.00% and 3.00% based on our Consolidated Total Net Leverage Ratio (as defined in the 2014 Financing Agreement);

 

3	Reflects $5.0 million of borrowings on a new $15.0 million revolving credit facility;

 

4	Reflects the issuance by the Partnership of 7.0 million common units to the public in this offering;

 

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5	Reflects the conversion of the net WCC investment in Kemmerer of $85.2 million into 2.0 million common units and 7.5 million Series A Convertible Units issued by the Partnership to WCC and the payment of $138.0 million to WCC net of legal, financing and investment banking fees and other costs;

 

6	Reflects the elimination of the tax effect on the unrealized and realized gains and losses on available-for-sale securities;

 

7	Reflects the payment delayed draw financing fees payable of $1.0 million under our financing agreement, which were capitalized and will be amortized over the remaining life of the financing agreement;

 

8

Reflects investment banking fees and costs of $4.0 million we incurred in the execution of the Contribution. For the purpose of this pro forma we are assuming all incremental costs are directly attributable to the security offering and are accounted for as a charge against gross proceeds reducing Partners Capital;

 

9

Reflects legal and other cost of $2.0 million we incurred in the execution of the transaction For the purpose of this pro forma we are assuming all incremental costs are directly attributable to the security offering and are accounted for as a charge against gross proceeds reducing Partners Capital;

 

10	Reflects the elimination of transactions between the Partnership and Kemmerer for royalties paid by Kemmerer to the Partnership.

 

11

Reflects the elimination of income tax expense. As discussed in “Material U.S. Federal Income Tax Consequences,” the Internal Revenue Code of 1986, as amended (the “Code”), requires that we must derive 90% or more of our income from qualifying sources each year in order to qualify as a publicly traded partnership and failure to achieve the 90% threshold for any year will cause us to be taxed as a C corporation. Qualifying income included income from certain natural resources and biofuel activities such as income and gains derived from the exploration, development, mining or production, processing, refining, transportation (including pipelines transporting gas, oil, or products thereof), or the marketing of any mineral or natural resource (including fertilizer, geothermal energy, and timber), industrial source carbon dioxide, or the transportation or storage of any fuel described in subsection (b), (c), (d), or (e) of section 6426, or any alcohol fuel defined in section 6426(b)(4)(A) or any biodiesel fuel as defined in section 40A(d)(1). We do not expect the tax effects of the Contribution to be different than if we acquired an unaffiliated C corporation in an arm’s length transaction.

 

12	PIK Interest on proceeds of $70.0 million of received from delayed draw borrowing under our existing credit facility at 3.0%.

 

13	Interest on proceeds of $70.0 million received from delayed draw borrowings under our existing credit facility at 9.25%.

3. Pro Forma Net Income Per Unit

Pro forma net income per unit is determined by dividing the pro forma net income that would have been allocated to the common unitholders and Series A Convertible Unitholders, which is 99.8% of the pro forma net income, by the number of common units and Series A Convertible Units expected to be outstanding at the closing of the offering. For purposes of this calculation, the number of common units and Series A Convertible Units assumed to be outstanding was 22,422,187 at March 31, 2015. All units were assumed to have been outstanding since January 1, 2014. Basic and diluted pro forma net income per unit are equivalent as there are no dilutive units at the date of closing of the public offering of the common units of Westmoreland Resource Partners, LP. Pursuant to the partnership agreement, to the extent that the quarterly distributions exceed certain targets, the general partner is entitled to receive certain incentive distributions that will result in more net income proportionately being allocated to the general partner than to the holders of common units and Series A Convertible Units. The pro forma net income per unit calculations assume that no incentive distributions were made to the general partner because no such distribution would have been paid based upon the pro forma available cash from operating surplus for the periods.

 

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		WRPS Pro Forma
		For the Three Months End March 31, 2015				For the Year Ended December 31, 2014
Net income (loss) allocated to limited partners		$	(5,307	)		$	10,998
Net income (loss) per limited partner unit-basic and diluted		$	(0.36	)		$	0.75
Weighted-average limited partner unit-basic and diluted			14,922,187				14,715,644
Net income (loss) allocated to Class A limited partners		$	(2,666	)		$	5,605
Net income (loss) per Class A limited partner unit-basic and diluted		$	(0.36	)		$	0.75
Weighted-average Class A limited partner units-basic and diluted			7,500,000				7,500,000
Net income (loss) allocated to general partners		$	(13	)		$	27
Net income (loss) per general partner unit-basic and diluted		$	(0.36	)		$	0.75
Weighted-average general partner units-basic and diluted			35,291				35,291

 

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WESTMORELAND RESOURCE PARTNERS SUCCESSOR

UNAUDITED PRO FORMA COMBINED BALANCE SHEETS

(in thousands)

 

		WRPS Pro Forma				Oxford Resource Partners, LP (Predecessor)
		March 31, 2015				March 31, 2014
ASSETS
Current assets:
Cash and cash equivalents		$	9,785			$	4,636
Accounts receivable:
Trade			36,540				27,286
Other			188				71
Total accounts receivable			36,728				27,357
Inventories			23,244				15,734
Prepaid expenses			4,531				1,607
Total current assets			74,288				49,334
Property, plant and equipment, at costs:
Land and mineral rights			94,294				110,702
Plant and equipment			256,493				209,737
			350,787				320,439
Less accumulated depreciation, depletion and amortization			(49,191	)			(185,332	)
Net property, plant and equipment			301,596				135,107
Advance coal royalties			11,498				11,543
Restricted investments and bond collateral			35,226				14,644
Intangible assets, net of accumulated amortization			30,483				1,131
Other non-current assets			7,607				6,688
Total assets		$	460,698			$	218,447

 

See accompanying notes to combined financial statements.

 

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WESTMORELAND RESOURCE PARTNERS SUCCESSOR

UNAUDITED PRO FORMA COMBINED BALANCE SHEETS

(in thousands)

 

		WRPS Pro Forma				Oxford Resource Partners, LP (Predecessor)
		March 31, 2015				March 31, 2014
LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)
Current liabilities:
Current installments of long-term debt		$	3,447			$	9,375
Accounts payable and accrued expenses:
Trade			29,828				24,668
Deferred revenue			4,944				—
Production taxes			19,938				1,167
Accrued compensation			401				3,423
Asset retirement obligation			12,529				7,420
Other current liabilities			1,434				2,543
Total current liabilities			72,521				48,596
Long-term debt, less current installments			265,273				158,263
Deferred revenue			—				3,578
Asset retirement obligation, less current portion			39,387				23,996
Warrants			1,952				5,014
Other liabilities			160				160
Total liabilities			379,293				239,607
Partners capital (deficit):
Limited partner common units			92,571				(23,039	)
Limited partner Series A Convertible Units			(44,090	)			—
General partner units			32,884				(2,709	)
Accumulated other comprehensive income			40				—
Noncontrolling interest			—				4,588
Total partners’ capital (deficit)			81,405				(21,160	)
Total liabilities and partners’ capital (deficit)		$	460,698			$	218,447

See accompanying notes to combined financial statements.

 

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WESTMORELAND RESOURCE PARTNERS SUCCESSOR

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS

(in thousands)

 

		Successor						Oxford Resource Partners, LP (Predeccessor)												WRPS Pro Forma										Oxford Resource Partners, LP (Predecessor)
		Year Ended December 31, 2014						Period January 1, 2014 to December 31, 2014				Year ended December 31,								Three months ended March 31, 2015				Three months ended March 31, 2014						Three months ended March 31, 2014
												2013				2012
Revenues:
Coal revenues		$	170,508					$	295,662			$	336,201			$	364,928			$	103,273			$	43,123					$	76,770
Royalty revenues			—						284				8				1,496				23				—						99
Non-coal revenues			—						26,317				10,558				7,103				3,947				—						1,135
Total Revenues			170,508						322,263				346,767				373,527				107,243				43,123						78,004
Costs and expenses:
Cost of coal revenues (excluding depreciation, depletion and amortization)			118,691						258,575				290,427				312,467				83,826				29,080						65,726
Cost of non-coal revenues			—						1,700				1,619				1,195				3,155				—						402
Depreciation, depletion and amortization			16,912						39,315				48,081				51,170				14,889				4,066						11,224
Selling and administrative			5,335						20,510				17,297				15,629				4,170				1,410						3,656
Loss (gain) on sale/disposal of assets			309						(218	)			(6,488	)			(8,021	)			1,057				(3	)					204
Restructuring charges			2,783						75				1,761				15,650				553				—						75
Total cost and expenses			144,030						319,957				352,697				388,090				107,650				34,553						81,287
Operating income (loss)			26,478						2,306				(5,930	)			(14,563	)			(407	)			8,570						(3,283	)
Other (expense) income:
Interest expense			(8,908	)					(27,787	)			(20,246	)			(11,500	)			(8,077	)			(41	)					(6,870	)
Interest income			429						4				4				10				369				6						1
Loss on debt extinguishment			(1,623	)					500				(808	)			—				—				—						—
Change in fair value of warrants			—						822				3,280				—				29				—						(415	)
Other			254						—				—				—				92				39						—
Total other (expenses) income			(9,848	)					(26,461	)			(17,770	)			(11,490	)			(7,587	)			4						(7,284	)
Net income (loss)			16,630						(24,155	)			(23,700	)			(26,053	)			(7,994	)			8,574						(10,567	)
Less net income (loss) attributable to noncontrolling interest			—						(1,270	)			1,225				755				—				—						(381	)
Net income (loss) attributable to WMLP unitholders			16,630						(22,885	)			(24,925	)			(26,808	)			(7,994	)			8,574						(10,186	)
Less net income (loss) allocated to general partner			27						(429	)			(497	)			(535	)			(13	)			16						(202	)
Net income (loss) allocated to limited partners		$	16,603					$	(22,456	)		$	(24,428	)		$	(26,273	)		$	(7,981	)		$	8,558					$	(9,984	)

See accompanying notes to combined financial statements.

 

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Table of Contents

WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

Balance Sheets

 

		March 31, 2015				December 31, 2014
		(in thousands)
Assets
Current assets:
Cash and cash equivalents		$	—			$	83
Accounts receivable
Trade			14,827				17,572
Other			72				99
			14,899				17,671
Inventories			10,548				10,472
Deferred income taxes			856				903
Prepaid expenses			1,894				2,356
Total current assets			28,197				31,485
Property, plant and equipment, at cost:
Land and mineral rights			21,301				21,301
Plant and equipment			122,544				115,855
			143,845				137,156
Less accumulated depreciation, depletion and amortization			39,390				34,773
Net property, plant and equipment			104,455				102,383
Restricted investments and bond collateral			25,692				25,282
Deferred income taxes			16,075				15,477
Total assets		$	174,419			$	174,627
Liabilities and Shareholder’s Equity
Current liabilities:
Current installments of long-term debt		$	3,441			$	2,310
Accounts payable			11,065				10,607
Book overdrafts			474				—
Deferred revenue			4,944				2,513
Payable to related party			667				450
Accrued production taxes			18,963				17,157
Postretirement medical benefits			436				436
Asset retirement obligations			2,674				2,658
Total current liabilities			42,664				36,131
Long-term debt, less current installments			13,394				9,321
Postretirement medical costs, less current portion			61,410				60,245
Pension obligations			17,922				17,762
Asset retirement obligations, less current portion			16,673				16,202
Total liabilities			152,063				139,661
Shareholder’s equity:
Common stock of $.01 par value. Authorized, issued and outstanding 100 shares at March 31, 2015 and December 31, 2014			—				—
Additional paid-in capital			50,573				50,481
Advances from (to) Parent			(34,272	)			(16,527	)
Accumulated other comprehensive income			1,052				1,012
Retained earnings			5,003				—
Total Westmoreland Kemmerer, Inc. shareholder’s equity			22,356				34,966
Total liabilities and shareholder’s equity		$	174,419			$	174,627

See accompanying Notes to Financial Statements.

 

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Table of Contents

WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

Statements of Operations

 

		Three Months Ended March 31, 2015				Three Months Ended March 31, 2014
		(In thousands)
Revenues		$	41,523			$	43,123
Costs and expenses:
Cost of sales			31,022				29,080
Depreciation, depletion, and amortization			4,709				4,066
Selling and administrative			1,622				1,410
Loss (gain) on sales of assets			23				(3	)
			37,376				34,553
Operating income			4,147				8,570
Other income (expense):
Interest expense			(153	)			(41	)
Interest income			369				6
Other			92				39
			308				4
Income before income taxes			4,455				8,574
Income tax expense			338				2,187
Net income		$	4,117			$	6,387

See accompanying Notes to Financial Statements.

 

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Table of Contents

WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

Statements of Comprehensive Income

 

		Three Months Ended March 31, 2015				Three Months Ended March 31, 2014
		(In thousands)
Net income		$	4,117			$	6,387
Other comprehensive income (loss):
Adjustments to and amortization of accumulated actuarial gains or losses, pension			—				(119	)
Unrealized and realized gains and losses on available-for-sale securities			40				—
			40				(119	)
Comprehensive income attributable to Westmoreland Kemmerer, Inc.		$	4,157			$	6,268

See accompanying Notes to Financial Statements.

 

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WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

Statements of Shareholder’s Equity

Three Months Ended March 31, 2015

 

		Additional paid-in capital				Advance from (to) Parent				Accumulated Other Comprehensive Income (Loss)				Retained Earnings				Total Shareholder’s Equity
		(In thousands)
Balance at December 31, 2014		$	50,481			$	(16,527	)		$	1,012			$	—			$	34,966
Westmoreland Coal Company common stock issued as compensation			92				—				—				—				92
Transactions with Parent/affiliates			—				(17,745	)			—				886				(16,859	)
Other comprehensive income			—				—				40				—				40
Net income			—				—				—				4,117				4,117
Balance at March 31, 2015		$	50,573			$	(34,272	)		$	1,052			$	5,003			$	22,356

See accompanying Notes to Financial Statements.

 

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Table of Contents

WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

Statements of Cash Flows

 

		Three Months ended March 31, 2015				Three Months ended March 31, 2014
		(In thousands)
Cash flows from operating activities:
Net income		$	4,117			$	6,387
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization			4,709				4,066
Accretion of asset retirement obligation and receivable			443				403
Share-based compensation			92				—
Loss on retirement and sales of assets			23				(3	)
Gain on sales of investment securities			(15	)			—
Change in:
Accounts receivable			2,772				77
Inventories			(76	)			1,257
Accounts payable and accrued production taxes			2,571				3,945
Payable to related parties			217				(114	)
Deferred revenues			2,431				844
Asset retirement obligation			44				(6	)
Accrual for postretirement medical benefits			1,165				1,054
Pension obligations			160				(6	)
Other assets and liabilities			798				954
Net cash provided by operating activities			19,451				18,858
Cash flows from investing activities:
Additions to property, plant and equipment			(1,113	)			(1,330	)
Decrease (increase) in restricted investments and bond collateral			(1,923	)			22
Proceeds from the sale of investments			1,568				—
Proceeds from sales of assets			3				—
Net cash used in investing activities			(1,465	)			(1,308	)
Cash flows from financing activities:
Book overdrafts			474				(1	)
Repayments of long-term debt			(798	)			(413	)
Transactions with Parent/affiliates			(17,745	)			—
Distributions			—				(18,000	)
Net cash used in financing activities			(18,069	)			(18,414	)
Net decrease in cash and cash equivalents			(83	)			(864	)
Cash and cash equivalents, beginning of period			83				7,942
Cash and cash equivalents, end of period		$	—			$	7,078
Supplemental disclosures of cash flow information:
Noncash transactions:
Capital leases		$	5,065			$	12,936

See accompanying Notes to Financial Statements.

 

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Table of Contents

WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

NOTES TO FINANCIAL STATEMENTS

 

1.	Summary of Significant Accounting Policies

Basis of Operations

Westmoreland Kemmerer, Inc., or WKI, or the Company, a wholly owned subsidiary of Westmoreland Coal Company, or WCC, or the Parent, owns a surface coal mining operation located in southwestern Wyoming. On January 31, 2012, WCC acquired the Kemmerer Mine. Coal produced from the Kemmerer Mine is sold to electric utilities and various industrial customers based in the north central region of the United States. Westmoreland Coal Company owns and operates the Company. On December 31, 2014, WCC completed the acquisition of Westmoreland Resources GP, LLC (formerly Oxford Resources GP, LLC) (the “GP”), the general partner of Westmoreland Resource Partners, LP (formerly Oxford Resource Partners, LP) (“WMLP”) and, concurrent with the GP acquisition, all of the royalty- bearing coal reserves owned by WKI were contributed to WCC. The basis of the royalty-bearing coal reserves transferred to WCC was the book value of $33.2 million. Also on December 31, 2014, WCC then contributed these royalty-bearing coal reserves to WMLP.

The Company’s financial statements reflect substantially all of its costs of doing business. Common expenses incurred by the Parent on behalf of the Company are charged to the Company based on proportional cost allocations. The Company believes the allocations used are reasonable; however, these financial statements may not necessarily be representative of a stand-alone company.

The Company’s financial statements have been prepared in accordance with United States generally accepted accounting principles and require use of management’s estimates. The financial information contained in these financial statements is unaudited, but reflects all adjustments, which are, in the opinion of management, necessary for a fair presentation of the financial information for the periods shown. Such adjustments are of a normal recurring nature. The results of operations for the three months ended March 31, 2015 are not necessarily indicative of results to be expected for the year ending December 31, 2015.

These quarterly financial statements should be read in conjunction with the Company’s audited financial statements and notes for the year ended December 31, 2014 (the “2014 Audited Financials”). The accounting principles followed by the Company are set forth in the 2014 Audited Financials. Most of the descriptions of the accounting principles and other footnote disclosures previously made have been omitted in this report so long as the interim information presented is not misleading or inconsistent.

WCC Liquidity

The Company anticipates that its cash from operations, cash on hand and available WCC borrowing capacity will be sufficient to meet its investing, financing, and working capital requirements for the foreseeable future.

Under WCC’s revolving credit agreement, the maximum available borrowing amount is $50 million, to which the maximum principal amount available for borrowings under the credit agreement can be increased to $100 million under certain circumstances. The revolver may support an equal amount of letters of credit, which would reduce the balance available under the revolver. At March 31, 2015, availability on the revolver was $27.2 million with $22.8 million supporting letters of credit.

Debt Obligations

As of March 31, 2015, the Company is among the guarantors for the following major debt arrangements of the Parent: (1) $350.0 million in aggregate principal amount of 8.75% senior secured notes at the parent level

 

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WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

NOTES TO FINANCIAL STATEMENTS (Continued)

 

(the “8.75% Notes”); (2) a secured term loan facility at the Parent level in the aggregate principal amount of $423.9 million (the “WCC Term Loan Facility”). The 8.75% Notes and the WCC Term Loan Facility are each guaranteed by the Company, Westmoreland Energy LLC, Westmoreland Mining LLC and Westmoreland Resources, Inc. and their respective subsidiaries (other than Absaloka Coal, LLC, Westmoreland Risk Management, Inc. and certain other immaterial subsidiaries).

Fair Value

The Company is required to disclose the fair value of financial instruments. The carrying amounts of cash equivalents, accounts receivable and accounts payable reflected on the balance sheet approximates the fair value of these instruments due to the short duration to maturities.

Fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value and is defined as:

 

•

Level 1, defined as observable inputs such as quoted prices in active markets for identical assets. Level 1 assets include available-for-sale equity securities generally valued based on independent third-party market prices.

 

•

Level 2, defined as observable inputs other than Level 1 prices. These include quoted prices for similar assets or liabilities in an active market, quoted prices for identical assets and liabilities in markets that are not active, or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.

 

•

Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.

The Company’s non-recurring fair value measurements include asset retirement obligations. The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to reclamation liabilities using level 3 inputs. The significant inputs used to calculate such liabilities includes estimates of costs to be incurred, the Company’s credit adjusted discount rate, inflation rates and estimated dates of reclamation. The asset retirement liability is accreted to its present value each period.

See Note 3 for further disclosures related to the Company’s fair value estimates.

Accounting Pronouncements Adopted

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers, issued as a new Topic, Accounting Standards Codification (ASC) Topic 606. The new revenue recognition standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle of the guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This ASU is effective beginning in fiscal 2017 and can be adopted by the Company either retrospectively or as a cumulative-effect adjustment as of the date of adoption. The Company is currently evaluating the effect that adopting this new accounting guidance will have on its consolidated results of operations, cash flows and financial position.

In August 2014, the FASB issued ASU 2014-15 Presentation of Financial Statements—Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. The

 

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WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

NOTES TO FINANCIAL STATEMENTS (Continued)

 

new standard provides guidance around management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. The new standard is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. Early adoption is permitted. The adoption of this standard is not expected to have a material impact on the Company’s financial statements.

 

2.	Inventories

Inventories consisted of the following (in thousands):

 

		March 31, 2015				December 31, 2014
Coal		$	226			$	275
Materials and supplies			10,694				10,569
Reserve for obsolete inventory			(372	)			(372	)
Total		$	10,548			$	10,472

 

3.	Restricted Investments and Bond Collateral

The Company’s restricted investments and bond collateral consisted of the following (in thousands):

 

		March 31, 2015				December 31, 2014
Reclamation bond collateral		$	25,692			$	25,282

The Company’s carrying value and estimated fair value of its restricted investments and bond collateral at March 31, 2015 were as follows (in thousands):

 

		Carrying Value				Fair Value				Fair Value Hierarchy
Cash and cash equivalents		$	194			$	194				Level 1
Available-for-sale securities			25,498				25,498				Level 1
		$	25,692			$	25,692

These accounts include available-for-sale securities. Available-for-sale securities are reported at fair value with unrealized gains and losses excluded from earnings and reported in Accumulated other comprehensive income (loss).

Available-for-Sale Restricted Investments and Bond Collateral

The cost basis, gross unrealized holding gains and losses and fair value of available-for-sale securities at March 31, 2015 are as follows:

 

Cost basis		$	25,564
Gross unrealized holding gains			326
Gross unrealized holding losses			(392	)
Fair value		$	25,498

 

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Table of Contents

WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

NOTES TO FINANCIAL STATEMENTS (Continued)

 

Maturities of available-for sale securities are as follows at March 31, 2015:

 

		Cost Basis				Fair Value
		(In thousands)
Due in five years or less		$	7,195			$	7,005
Due after five years to ten years			11,545				11,541
Due in more than ten years			6,824				6,952
		$	25,564			$	25,498

 

4.	Long-Term Debt

The amounts outstanding under the Company’s long-term debt consisted of the following at March 31, 2015:

 

		Total Debt Outstanding
		(In thousands)
Capital lease obligations		$	15,898
Other debt			937
			16,835
Less current portion			(3,441	)
Total debt outstanding, less current portion		$	13,394

The following table presents aggregate contractual debt maturities of all long-term debt:

 

		As of March 31, 2015
		(In thousands)
2015		$	2,569
2016			3,519
2017			3,436
2018			3,534
2019			3,580
Thereafter			197
Total debt		$	16,835

The Company engages in leasing transactions for equipment utilized in its mining operations. At March 31, 2015, the capital leases outstanding had a weighted average interest rate of 3.75% and mature at various dates beginning in 2016 through 2020. During the three months ended March 31, 2015, the Company acquired $5.1 million of equipment under capital leases.

 

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WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

NOTES TO FINANCIAL STATEMENTS (Continued)

 

5.	Postretirement Medical Benefits

The Company provides postretirement medical benefits pursuant to collective bargaining agreements. These benefits are provided through self-insured programs.

The components of net periodic postretirement medical benefit cost are as follows:

 

		Three Months Ended March 31,
		2015				2014
		(In thousands)
Components of net periodic benefit cost:
Service cost		$	816			$	650
Interest cost			642				626
Amortization of deferred items			—				(119	)
Total net periodic benefit cost		$	1,458			$	1,157

These costs are included in the accompanying statements of operations in Cost of sales and Selling and administrative expenses.

 

6.

Pension

Defined Benefit Pension Plans

The Company provides a defined benefit pension plan to qualified full-time employees pursuant to a collective bargaining agreement. Benefits are generally based on years of service and a specific dollar amount per year of service as specified in the plan agreement.

The components of net periodic benefit cost are as follows:

 

		Three Months Ended March 31,
		2015				2014
		(In thousands)
Components of net periodic benefit cost:
Service cost		$	379			$	280
Interest cost			626				430
Expected return on plan assets			(844	)			(596	)
Total net periodic pension cost		$	161			$	114

These costs are included in the accompanying statements of operations in Cost of sales and Selling and administrative expenses.

 

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WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

NOTES TO FINANCIAL STATEMENTS (Continued)

 

7.	Asset Retirement Obligations

Changes in the Company’s asset retirement obligations were as follows:

 

		Three Months Ended March 31,
		2015				2014
		(In thousands)
Asset retirement obligations, beginning of year (including current portion)		$	18,860			$	17,174
Accretion			443				403
Liabilities settled			44				(8	)
Asset retirement obligations, end of period			19,347				17,569
Less current portion			(2,674	)			(2,011	)
Asset retirement obligations, less current portion		$	16,673			$	15,558

As permittee, the Company is responsible for the total amount.

 

8.	Contingencies

The company is subject to litigation in the ordinary course of business. No material litigation exists.

 

9.	Accumulated Other Comprehensive Income (Loss)

Changes in Accumulated Other Comprehensive Income (Loss)

The following table reflects the changes in accumulated other comprehensive income (loss) by component:

 

		Pension				Postretirement Medical Benefits				Available for Sale Securities				Accumulated Other Comprehensive Income (Loss)
		(In thousands)
Balance at December 31, 2014		$	(1,599	)		$	2,718			$	(107	)		$	1,012
Other comprehensive income (loss) before reclassifications			—				—				25				25
Amounts reclassified from accumulated other comprehensive income (loss)			—				—				15				15
Balance at March 31, 2015		$	(1,599	)		$	2,718			$	(67	)		$	1,052

The following table reflects the reclassifications out of accumulated other comprehensive income (loss) for the three months ended March 31, 2015 (in thousands):

 

Details about accumulated other comprehensive income (loss) components		Amount reclassified from accumulated other comprehensive income (loss)				Affected line item in the statement where net income (loss) is presented
Realized gains and losses on available-for-sale securities		$	15				Other income

 

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WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

NOTES TO FINANCIAL STATEMENTS (Continued)

 

10.	Related Party Transactions

The Company was allocated audit and tax fees and information technology costs incurred by its Parent. For the three months ended March 31, 2015 and 2014, these fees were $0.3 million, and $0.2 million, respectively, which are included in Selling and administrative expenses.

Advances to Parent of $17.7 million for the three months ended March 31, 2015 represent the net movement of cash from the Company’s bank accounts to bank accounts held by WCC.

Additionally, in December 2014, the Company entered into an agreement to mine certain coal reserves contributed to WMLP in connection with WCC’s acquisition of the GP. Under this lease, the Company pays a per ton royalty as these coal reserves are mined. For the three months ended March 31, 2015, the Company recognized $1.8 million of royalties in Cost of sales, which was included in Accounts payable at March 31, 2015.

 

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Report of Independent Registered Public Accounting Firm

The Board of Directors of Westmoreland Kemmerer, Inc.

We have audited the accompanying balance sheets of Westmoreland Kemmerer, Inc. (the Company) (a wholly owned subsidiary of Westmoreland Coal Company) as of December 31, 2014 and 2013, and the related statements of operations, comprehensive income, shareholder’s equity, and cash flows for the years ended December 31, 2014 and 2013 and the eleven-month period ended December 31, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above presents fairly, in all material respects, the financial position of Westmoreland Kemmerer, Inc. at December 31, 2014, and 2013, and the results of its operations and its cash flows for each of the years ended December 31, 2014 and 2013 and the eleven-month period ended December 31, 2012 in conformity with U.S. generally accepted accounting principles.

/s/ ERNST & YOUNG LLP

Denver, Colorado

May 18, 2015

 

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WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

Balance Sheets

 

		December 31, 2014				December 31, 2013
		(in thousands)
Assets
Current assets:
Cash and cash equivalents		$	83			$	7,942
Accounts receivable
Trade			17,572				16,906
Other			99				83
			17,671				16,989
Inventories			10,472				10,753
Deferred income taxes			903				870
Prepaid expenses			2,356				916
Total current assets			31,485				37,470
Property, plant and equipment, at cost:
Land and mineral rights			21,301				63,386
Plant and equipment			115,855				99,372
			137,156				162,758
Less accumulated depreciation, depletion and amortization			34,773				31,053
Net property, plant and equipment			102,383				131,705
Restricted investments and bond collateral			25,282				24,966
Deferred income taxes			15,477				—
Total assets		$	174,627			$	194,141
Liabilities and Shareholder’s Equity
Current liabilities:
Current installments of long-term debt		$	2,310			$	213
Accounts payable			10,607				6,794
Deferred revenue			2,513				3,969
Payable to related party			450				927
Accrued production taxes			17,157				16,211
Postretirement medical benefits			436				329
Asset retirement obligations			2,658				1,998
Total current liabilities			36,131				30,441
Long-term debt, less current installments			9,321				438
Deferred tax liabilities			—				6,220
Postretirement medical costs, less current portion			60,245				49,418
Pension obligations			17,762				9,381
Asset retirement obligations, less current portion			16,202				15,176
Total liabilities			139,661				111,074
Shareholder’s equity:
Common stock of $.01 par value. Authorized, issued and outstanding 100 shares at December 31, 2014 and 2013			—				—
Additional paid-in capital			50,481				65,576
Advances from (to) Parent			(16,527	)			—
Accumulated other comprehensive income			1,012				17,491
Retained earnings			—				—
Total Westmoreland Kemmerer, Inc. shareholder’s equity			34,966				83,067
Total liabilities and shareholder’s equity		$	174,627			$	194,141

See accompanying Notes to Financial Statements.

 

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WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

Statements of Operations

 

		Year Ended December 31, 2014				Year Ended December 31, 2013				Eleven Months Ended December 31, 2012
		(In thousands)
Revenues		$	170,508			$	172,467			$	151,606
Costs and expenses:
Cost of sales			118,691				120,088				104,971
Depreciation, depletion, and amortization			16,912				17,742				13,287
Selling and administrative			5,335				5,675				5,351
Loss on sales of assets			309				236				242
			141,247				143,741				123,851
Operating income			29,261				28,726				27,755
Other income (expense):
Interest expense			(333	)			(11	)			—
Interest income			429				380				4
Other			254				108				189
			350				477				193
Income before income taxes			29,611				29,203				27,948
Income tax expense			4,292				8,461				8,916
Net income		$	25,319			$	20,742			$	19,032

See accompanying Notes to Financial Statements.

 

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WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

Statements of Comprehensive Income

 

		Year Ended December 31, 2014				Year Ended December 31, 2013				Eleven Months Ended December 31, 2012
		(In thousands)
Net income		$	25,319			$	20,742			$	19,032
Other comprehensive income (loss):
Adjustments to and amortization of accumulated actuarial gains or losses, pension			(9,119	)			10,554				(3,034	)
Adjustments to and amortization of accumulated actuarial gains or losses, postretirement medical benefits			(7,253	)			11,940				(1,969	)
Unrealized and realized gains and losses on available-for-sale securities			(107	)			—				—
			(16,479	)			22,494				(5,003	)
Comprehensive income attributable to Westmoreland Kemmerer, Inc.		$	8,840			$	43,236			$	14,029

See accompanying Notes to Financial Statements.

 

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WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

Statements of Shareholder’s Equity

Eleven Months Ended December 31, 2012 and Years Ended December 31, 2013 and 2014

 

		Additional paid-in capital				Advance from (to) Parent				Accumulated Other Comprehensive Income (Loss)				Retained Earnings				Total Shareholder’s Equity
		(In thousands)
Balance at January 31, 2012		$	76,523			$	—			$	—			$	—			$	76,523
Westmoreland Coal Company common stock issued as compensation			254				—				—				—				254
Transactions with Parent/affiliates			—				—				—				8,916				8,916
Distributions			—				—				—				(19,173	)			(19,173	)
Other comprehensive loss			—				—				(5,003	)			—				(5,003	)
Net income			—				—				—				19,032				19,032
Balance at December 31, 2012			76,777				—				(5,003	)			8,775				80,549
Westmoreland Coal Company common stock issued as compensation			671				—				—				—				671
Transactions with Parent/affiliates			—				—				—				3,111				3,111
Distributions			(11,872	)			—				—				(32,628	)			(44,500	)
Other comprehensive income			—				—				22,494				—				22,494
Net income			—				—				—				20,742				20,742
Balance at December 31, 2013			65,576				—				17,491				—				83,067
Westmoreland Coal Company common stock issued as compensation			216				—				—				—				216
Transactions with Parent/affiliates			—				(16,527	)			—				26,022				9,495
Property distributions			—				—				—				(33,152	)			(33,152	)
Cash distributions			(15,311	)			—				—				(18,189	)			(33,500	)
Other comprehensive loss			—				—				(16,479	)			—				(16,479	)
Net income			—				—				—				25,319				25,319
Balance at December 31, 2014		$	50,481			$	(16,527	)		$	1,012			$	—			$	34,966

See accompanying Notes to Financial Statements.

 

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WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

Statements of Cash Flows

 

		Year Ended December 31, 2014				Year Ended December 31, 2013				Eleven Months Ended December 31, 2012
		(In thousands)
Cash flows from operating activities:
Net income		$	25,319			$	20,742			$	19,032
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion and amortization			16,912				17,742				13,287
Accretion of asset retirement obligation and receivable			1,613				1,670				1,670
Share-based compensation			216				671				254
Loss on sales of assets			309				236				242
Loss on sales of investment securities			4				—				—
Change in:
Accounts receivable			(682	)			(3,296	)			(13,693	)
Inventories			281				608				(1,978	)
Accounts payable and accrued production taxes			5,145				1,459				19,334
Payable to related parties			(477	)			(126	)			1,053
Deferred revenues			(1,456	)			972				772
Asset retirement obligation			(862	)			(1,945	)			(1,136	)
Accrual for postretirement medical benefits			3,681				5,619				4,858
Pension obligations			(738	)			589				709
Other assets and liabilities			2,847				5,520				(1,086	)
Net cash provided by operating activities			52,112				50,461				43,318
Cash flows from investing activities:
Additions to property, plant and equipment			(7,489	)			(6,019	)			(3,562	)
Increase in restricted investments and bond collateral			(5,525	)			(264	)			(24,702	)
Proceeds from the sale of investments			5,098				—				—
Proceeds from sales of assets			63				227				221
Net cash used in investing activities			(7,853	)			(6,056	)			(28,043	)
Cash flows from financing activities:
Repayments of long-term debt			(2,091	)			(92	)			—
Transactions with Parent/affiliates			(16,527	)			3,111				8,916
Distributions			(33,500	)			(44,500	)			(19,173	)
Net cash used in financing activities			(52,118	)			(41,481	)			(10,257	)
Net increase (decrease) in cash and cash equivalents			(7,859	)			2,924				5,018
Cash and cash equivalents, beginning of year			7,942				5,018				—
Cash and cash equivalents, end of year		$	83			$	7,942			$	5,018
Supplemental disclosures of cash flow information:
Cash paid for interest		$	333			$	11			$	—
Noncash transactions:
Accrued purchases of property and equipment			307				693				—
Capital leases			13,071				743				—

See accompanying Notes to Financial Statements.

 

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WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

NOTES TO FINANCIAL STATEMENTS

 

1.	Summary of Significant Accounting Policies

Nature of Operations

Westmoreland Kemmerer, Inc., or WKI, or the Company, a wholly owned subsidiary of Westmoreland Coal Company, or WCC, or the Parent, owns a surface coal mining operation located in southwestern Wyoming. On January 31, 2012, WCC acquired the Kemmerer Mine. Coal produced from the Kemmerer Mine is sold to electric utilities and various industrial customers based in the north central region of the United States. Westmoreland Coal Company owns and operates the Company. On December 31, 2014, WCC completed the acquisition of Westmoreland Resources GP, LLC (the “GP”), the general partner of Westmoreland Resource Partners, LP (“WMLP”) and, concurrent with the GP acquisition, all of the royalty- bearing coal reserves owned by WKI were contributed to WCC. The basis of the royalty-bearing coal reserves transferred to WCC was the book value of $33.2 million. Also on December 31, 2014, WCC then contributed these royalty-bearing coal reserves to WMLP.

The Company’s financial statements reflect substantially all of its costs of doing business. Common expenses incurred by the Parent on behalf of the Company are charged to the Company based on proportional cost allocations. The Company believes the allocations used are reasonable; however, these financial statements may not necessarily be representative of a stand-alone company.

WCC Liquidity

The Company anticipates that its cash from operations, cash on hand and available WCC borrowing capacity will be sufficient to meet its investing, financing, and working capital requirements for the foreseeable future.

Under WCC’s revolving credit agreement, the maximum available borrowing amount is $50 million, to which the maximum principal amount available for borrowings under the credit agreement can be increased to $100 million under certain circumstances. The revolver may support an equal amount of letters of credit, which would reduce the balance available under the revolver. At December 31, 2014, availability on the revolver was $16.9 million with an outstanding balance of $9.6 million and $23.5 million supporting letters of credit.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash and Cash Equivalents

Cash and cash equivalents are stated at cost, which approximate fair value. Cash equivalents consist of highly liquid investments with original maturities of three months or less.

Accounts Receivable

Accounts receivable are recorded at the invoiced amount and do not bear interest. The Company evaluates the need for an allowance for doubtful accounts based on a review of collectability. The Company has determined that no allowance is necessary for accounts receivable as of December 31, 2014.

 

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WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

NOTES TO FINANCIAL STATEMENTS (Continued)

 

Inventories

Inventories, which include materials and supplies as well as raw coal, are stated at the lower of cost or market. Cost is determined using the average cost method. Coal inventory costs include labor, supplies, equipment, depreciation, depletion, amortization, operating overhead and other related costs.

Exploration and Mine Development

Exploration expenditures are charged to Cost of sales as incurred, including costs related to drilling and study costs incurred to convert or upgrade mineral resources to reserves.

At existing surface operations, additional pits may be added to increase production capacity in order to meet customer requirements. These expansions may require significant capital to purchase additional equipment, relocate equipment, build or improve existing haul roads and create the initial pre-production box cut to remove overburden for new pits at existing operations. If these pits operate in a separate and distinct area of the mine, the costs associated with initially uncovering coal for production are capitalized and amortized over the life of the developed pit consistent with coal industry practices. Once production has begun, mining costs are then expensed as incurred.

Where new pits are routinely developed as part of a contiguous mining sequence, the Company expenses such costs as incurred. The development of a contiguous pit typically reflects the planned progression of an existing pit, thus maintaining production levels from the same mining area utilizing the same employee group and equipment.

Property, Plant, and Equipment

Property, plant and equipment are recorded at cost. Expenditures that extend the useful lives of existing plant and equipment or increase productivity of the assets are capitalized. Maintenance and repair costs that do not extend the useful life or increase productivity of the asset are expensed as incurred. Coal reserves are recorded at cost, or at fair value in the case of acquired businesses.

Coal reserves, mineral rights and mine development costs are depleted based upon estimated recoverable proven and probable reserves. Plant and equipment are depreciated on a straight-line basis over the assets’ estimated useful lives as follows:

 

		Years
Buildings and improvements			15 to 30
Machinery and equipment			3 to 30

The Company assesses the carrying value of its property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability is measured by comparing estimated undiscounted cash flows expected to be generated from such assets to their net book value. If net book value exceeds estimated cash flows, the asset is written down to fair value. When an asset is retired or sold, its cost and related accumulated depreciation and depletion are removed from the accounts. The difference between the net book value of the asset and proceeds on disposition is recorded as a gain or loss. Fully depreciated plant and equipment still in use is not eliminated from the accounts. Amortization of capital leases is included in Depreciation, depletion and amortization.

 

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WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

NOTES TO FINANCIAL STATEMENTS (Continued)

 

Restricted Investments and Bond Collateral

The Company has requirements to maintain restricted cash and investments for bonding requirements. Amounts held are recorded as Restricted investments and bond collateral. Funds in the restricted investment and bond collateral accounts are not available to meet the Company’s operating cash needs.

Fair Value

The Company is required to disclose the fair value of financial instruments. The carrying amounts of cash equivalents, accounts receivable and accounts payable reflected on the balance sheet approximates the fair value of these instruments due to the short duration to maturities.

Fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value and is defined as:

 

•

Level 1, defined as observable inputs such as quoted prices in active markets for identical assets. Level 1 assets include available-for-sale equity securities generally valued based on independent third-party market prices.

 

•

Level 2, defined as observable inputs other than Level 1 prices. These include quoted prices for similar assets or liabilities in an active market, quoted prices for identical assets and liabilities in markets that are not active, or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.

 

•

Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.

The Company’s non-recurring fair value measurements include asset retirement obligations. The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to reclamation liabilities using level 3 inputs. The significant inputs used to calculate such liabilities includes estimates of costs to be incurred, the Company’s credit adjusted discount rate, inflation rates and estimated dates of reclamation. The asset retirement liability is accreted to its present value each period.

See Notes 3, 6, and 7 for further disclosures related to the Company’s fair value estimates.

Financial Instruments

The Company evaluates all of its financial instruments to determine if such instruments are derivatives, derivatives that qualify for the normal purchase normal sale exception, or instruments, which contain features that qualify them as embedded derivatives. Except for derivatives that qualify for the normal purchase normal sale exception, all financial instruments are recognized in the balance sheet at fair value. Changes in fair value are recognized in earnings if they are not eligible for hedge accounting or Accumulated other comprehensive income (loss) if they qualify for cash flow hedge accounting.

Postretirement Health Care Benefits

The Company accrues the cost to provide the benefits over the employees’ period of active service for postretirement benefits other than pensions. These costs are determined on an actuarial basis. The Company’s balance sheet reflects the unfunded status of postretirement benefit obligations.

 

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WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

NOTES TO FINANCIAL STATEMENTS (Continued)

 

Pension Plan

The Company accrues the cost to provide the benefits over the employees’ period of active service for the non-contributory defined benefit pension plan it sponsors. These costs are determined on an actuarial basis. The Company’s balance sheet reflects the unfunded status of the defined benefit pension plan.

Deferred Revenue

Deferred revenues represent a multi-tiered pricing structure on a certain coal sales contract.

Income Taxes

The Company files consolidated federal and state tax returns with its Parent. As the Company itself is not a taxable entity, the Parent’s tax expense for its income tax return group included on the Parent’s consolidated income tax return is allocated among the members of that group. This allocation is calculated as if each member were a separate taxpayer. This allocation is reflected by the Company in Income tax expense with the offset in Shareholder’s equity. There is no formal tax sharing agreement with the Parent.

The Company accounts for deferred income taxes using the asset and liability method. Deferred tax liabilities and assets are recognized for the expected future tax consequences of events that have been reflected in the Company’s financial statements based on the difference between the financial statement carrying amounts and tax bases of assets and liabilities, as well as net operating loss and tax credit carryforwards, using enacted tax rates in effect in the years in which the differences are expected to reverse. The Company establishes a valuation allowance against its net deferred tax assets to the extent the Company believes that it is more likely than not (greater than 50%) that a deferred tax asset will not be realized.

Accounting guidance prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. Under this guidance, a company can recognize the benefit of an income tax position only if it is more likely than not (greater than 50%) that the tax position will be sustained upon tax examination, based solely on the technical merits of the tax position. Guidance is also provided on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company includes interest and penalties related to income tax matters in income tax expense.

Asset Retirement Obligations

The Company’s asset retirement obligation, or ARO, liabilities primarily consist of estimated costs related to reclaiming surface land and support facilities at its mines in accordance with federal and state reclamation laws as established by each mining permit.

The Company estimates its ARO liabilities for final reclamation and mine closure based upon detailed engineering calculations of the amount and timing of the estimated future costs for a third party to perform the required work. Cost estimates are escalated for inflation, and then discounted at the credit-adjusted risk-free rate. The Company records mineral rights associated with the initial recorded liability. Mineral rights are amortized based on the units-of-production method over the estimated recoverable, proven and probable reserves at the related mine, and the ARO liability is accreted to the projected settlement date. Changes in estimates could occur due to revisions of mine plans, changes in estimated costs, and changes in the timing of the performance of reclamation activities.

 

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WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

NOTES TO FINANCIAL STATEMENTS (Continued)

 

Coal Revenues

The Company recognizes coal sales revenue at the time title passes to the customer in accordance with the terms of the underlying sales agreements and after any contingent performance obligations have been satisfied. Coal sales revenue is recognized based on the pricing contained in the coal contracts in place at the time that title passes and any retroactive pricing adjustments to those contracts are recognized as revised agreements are reached with the customers and any performance obligations included in the agreements are satisfied.

Share-Based Compensation

Share-based compensation expense is generally measured at the grant date and recognized as expense over the vesting period of the entire award. This expense relates to WCC common stock attributable to the Company’s employees. These costs are recorded in Cost of sales and Selling and administrative expenses.

Accounting Pronouncements Adopted

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers, issued as a new Topic, Accounting Standards Codification (ASC) Topic 606. The new revenue recognition standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle of the guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This ASU is effective beginning in fiscal 2017 and can be adopted by the Company either retrospectively or as a cumulative-effect adjustment as of the date of adoption. The Company is currently evaluating the effect that adopting this new accounting guidance will have on its results of operations, cash flows and financial position.

In August 2014, the FASB issued ASU 2014-15 Presentation of Financial Statements—Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. The new standard provides guidance around management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. The new standard is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. Early adoption is permitted. The adoption of this standard is not expected to have a material impact on the Company’s financial statements.

 

2.	Inventories

Inventories consisted of the following (in thousands):

 

		December 31,
		2014				2013
Coal		$	275			$	156
Materials and supplies			10,569				10,995
Reserve for obsolete inventory			(372	)			(398	)
Total		$	10,472			$	10,753

 

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WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

NOTES TO FINANCIAL STATEMENTS (Continued)

 

3.	Restricted Investments and Bond Collateral

The Company’s restricted investments and bond collateral consisted of the following (in thousands):

 

		December 31,
		2014				2013
Reclamation bond collateral		$	25,282			$	24,966

During the year ended December 31, 2014, the Company decided to more actively manage its investment yields. This decision resulted in the sale of $5.1 million carrying value of securities and realized gains of less than $0.1 million during the year ended December 31, 2014 that were previously designated as held-to-maturity. The Company transferred the remainder of its securities classified as held-to-maturity to available-for-sale securities. The carrying value of held-to-maturity securities held as Restricted investments and bond collateral transferred to available-for-sale during the year ended December 31, 2014 was $25.3 million. As a result of the transfer, the Company recorded $0.3 million of unrealized holding gains in Accumulated other comprehensive income (loss) during the year ended December 31, 2014.

The Company’s carrying value and estimated fair value of its restricted investments and bond collateral at December 31, 2014 are as follows (in thousands):

 

		Carrying Value				Fair Value				Fair Value Hierarchy
Cash and cash equivalents		$	259			$	259				Level 1
Available-for-sale securities			25,023				25,023				Level 1
		$	25,282			$	25,282

These accounts include available-for-sale securities. Available-for-sale securities are reported at fair value with unrealized gains and losses excluded from earnings and reported in Accumulated other comprehensive income (loss).

Held-to-Maturity and Available-for-Sale Restricted Investments and Bond Collateral

The amortized cost, gross unrealized holding gains and losses and fair value of held-to-maturity securities are as follows:

 

		December 31,
		2014				2013
		(In thousands)
Amortized cost		$	—			$	24,527
Gross unrealized holding gains			—				81
Gross unrealized holding losses			—				(410	)
Fair value		$	—			$	24,198

 

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WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

NOTES TO FINANCIAL STATEMENTS (Continued)

 

The cost basis, gross unrealized holding gains and losses and fair value of available-for-sale securities are as follows:

 

		December 31,
		2014				2013
		(In thousands)
Cost basis		$	25,286			$	—
Gross unrealized holding gains			212				—
Gross unrealized holding losses			(475	)			—
Fair value		$	25,023			$	—

Maturities of available-for sale securities are as follows at December 31, 2014:

 

		Cost Basis				Fair Value
		(In thousands)
Due in five years or less		$	8,672			$	8,437
Due after five years to ten years			10,040				10,001
Due in more than ten years			6,574				6,585
		$	25,286			$	25,023

 

4.	Long-Term Debt

The amounts outstanding under the Company’s long-term debt consisted of the following at December 31, 2014:

 

		Total Debt Outstanding
		(In thousands)
Capital lease obligations		$	11,631
Less current portion			(2,310	)
Total debt outstanding, less current portion		$	9,321

The following table presents aggregate contractual debt maturities of all long-term debt:

 

		As of December 31, 2014
		(In thousands)
2015		$	2,310
2016			2,356
2017			2,212
2018			2,246
2019			2,308
Thereafter			199
Total debt		$	11,631

The Company engages in leasing transactions for equipment utilized in its mining operations. At December 31, 2014, the capital leases outstanding had a weighted average interest rate of 3.14% and mature at various dates beginning in 2016 through 2020. During the year ended December 31, 2014, the Company acquired $13.1 million of equipment under capital leases.

 

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WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

NOTES TO FINANCIAL STATEMENTS (Continued)

 

5.	Postretirement Medical Benefits

The Company provides postretirement medical benefits pursuant to collective bargaining agreements. These benefits are provided through self-insured programs.

The following table sets forth the actuarial present value of postretirement medical benefit obligations and amounts recognized in the Company’s financial statements:

 

		Year Ended December 31, 2014				Year Ended December 31, 2013
		(In thousands)
Change in benefit obligations:
Net benefit obligation at beginning of period		$	49,748			$	56,068
Service cost			2,600				3,659
Interest cost			2,504				2,325
Actuarial loss (gain)			6,776				(11,941	)
Gross benefits and expenses paid			(947	)			(363	)
Net benefit obligation at end of year			60,681				49,748
Change in plan assets:
Employer contributions			947				363
Gross benefits and expenses paid			(947	)			(363	)
Fair value of plan assets at end of year			—				—
Unfunded status at end of year		$	(60,681	)		$	(49,748	)
Amounts recognized in the balance sheet consist of:
Current liabilities		$	(436	)		$	(329	)
Noncurrent liabilities			(60,245	)			(49,418	)
Accumulated other comprehensive loss			(2,717	)			(9,971	)
Net amount recognized		$	(63,398	)		$	(59,718	)
Amounts recognized in accumulated other comprehensive loss consists of:
Net actuarial loss (gain)		$	(2,717	)		$	(11,941	)

Actuarial gains and losses are amortized over the average future service of the plan’s participants. The Company will not have any amounts amortized from accumulated other comprehensive loss into net periodic benefit cost in 2015.

The components of net periodic postretirement medical benefit cost are as follows:

 

		Year Ended December 31, 2014				Year Ended December 31, 2013				Eleven Months Ended December 31, 2012
		(In thousands)
Components of net periodic benefit cost:
Service cost		$	2,600			$	3,659			$	2,834
Interest cost			2,504				2,325				2,029
Amortization of:
Actuarial gain			(477	)			—				—
Total net periodic benefit cost		$	4,627			$	5,984			$	4,863

 

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WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

NOTES TO FINANCIAL STATEMENTS (Continued)

 

These costs are included in the accompanying statement of operations in Cost of sales and Selling and administrative expenses.

Assumptions

The weighted-average assumptions used to determine the benefit obligations as of the end of each year were as follows:

 

		December 31, 2014		December 31, 2013
Discount rate		4.25%		5.05%
Measurement date		December 31, 2014		December 31, 2013

The discount rate is adjusted annually based on an Aa corporate bond index adjusted for the difference in the duration of the bond index and the duration of the benefit obligations. This rate is calculated using a yield curve, which is developed using the average yield for bonds in the tenth to ninetieth percentiles, which excludes bonds with outlier yields.

The weighted-average assumptions used to determine net periodic benefit cost were as follows:

 

		Year Ended December 31, 2014		Year Ended December 31, 2013
Discount rate		5.05%		4.15%
Measurement date		December 31, 2013		January 31, 2012

The following presents information about the assumed health care trend rate:

 

		December 31, 2014				December 31, 2013
Health care cost trend rate assumed for next year			6.50	%			6.75	%
Rate to which the cost trend is assumed to decline (ultimate trend rate)			5.00	%			5.00	%
Year that the trend rate reaches the ultimate trend rate			2021				2021

The effect of a one percent change on the health care cost trend rate used to calculate periodic postretirement medical benefit costs and the related benefit obligation are summarized in the table below:

 

		Postretirement Medical Benefits
		1% Increase				1% Decrease
		(In thousands)
Effect on service and interest cost components		$	1,003			$	(892	)
Effect on postretirement medical benefit obligation		$	25,705			$	(21,647	)

 

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WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

NOTES TO FINANCIAL STATEMENTS (Continued)

 

Cash Flows

The following benefit payments and Medicare D subsidy (which the Company receives as a benefit partially offsetting its prescription drug costs for retirees and their dependents) are expected by the Company:

 

		Postretirement Medical Benefits				Medicare D Subsidy				Net Postretirement Medical Benefits
		(In thousands)
2015		$	440			$	(4	)		$	436
2016			608				(9	)			599
2017			802				(20	)			782
2018			1,084				(32	)			1,052
2019			1,353				(42	)			1,311
Years 2020 – 2024			10,101				(585	)			9,516

 

6.

Pension

Defined Benefit Pension Plans

The Company provides a defined benefit pension plan to qualified full-time employees pursuant to a collective bargaining agreement. Benefits are generally based on years of service and a specific dollar amount per year of service as specified in the plan agreement. The Company’s funding policy is to contribute annually the minimum amount prescribed, as specified by applicable regulations.

 

		Year Ended December 31, 2014				Year Ended December 31, 2013
		(In thousands)
Change in benefit obligation:
Net benefit obligation at the beginning of period		$	55,916			$	62,465
Service cost			1,262				1,451
Interest cost			2,477				2,223
Actuarial loss			9,744				(7,309	)
Benefits paid			(3,104	)			(2,914	)
Net benefit obligation at end of year			66,295				55,916
Change in plan assets:
Fair value of plan assets at the beginning of period			46,535				43,119
Actual return on plan assets			4,176				6,330
Employer contributions			926				—
Benefits paid			(3,104	)			(2,914	)
Fair value of plan assets at end of year			48,533				46,535
Underfunded status at end of year		$	(17,762	)		$	(9,381	)
Amounts recognized in the accompanying balance sheet consist of:
Noncurrent liability		$	(17,762	)		$	(9,381	)
Accumulated other comprehensive loss (income)			1,599				(7,520	)
Net amount recognized at end of year		$	(16,163	)		$	(16,901	)
Amounts recognized in accumulated other comprehensive loss consist of:
Net actuarial loss (gain)		$	1,599			$	(7,520	)

 

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WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

NOTES TO FINANCIAL STATEMENTS (Continued)

 

The accumulated benefit obligation for all plans was $66.3 million and $55.9 million at December 31, 2014 and 2013, respectively.

The components of net periodic benefit cost are as follows:

 

		Year Ended December 31, 2014				Year Ended December 31, 2013				Eleven Months Ended December 31, 2012
		(In thousands)
Components of net periodic benefit cost:
Service cost		$	1,262			$	1,451			$	1,348
Interest cost			2,477				2,223				2,107
Expected return on plan assets			(3,363	)			(3,085	)			(2,746	)
Amortization of:
Actuarial gain			(187	)			—				—
Total net periodic pension cost		$	189			$	589			$	709

These costs are included in the accompanying statements of operations in Cost of sales and Selling and administrative expenses.

Assumptions

The weighted-average assumptions used to determine the benefit obligations as of the end of each year were as follows:

 

		December 31, 2014		December 31, 2013
Discount rate		3.85%		4.55%
Measurement date		December 31, 2014		December 31, 2013

The discount rate is adjusted annually based on an Aa corporate bond index adjusted for the difference in the duration of the bond index and the duration of the benefit obligations. This rate is calculated using a yield curve, which is developed using the average yield for bonds in the tenth to ninetieth percentiles, which excludes bonds with outlier yields.

The following table provides the assumptions used to determine net periodic benefit cost:

 

		Year Ended December 31, 2014		Year Ended December 31, 2013
Discount rate		4.55%		3.65%
Expected return on plan assets		7.40%		7.40%
Rate of compensation increase		N/A		N/A
Measurement date		December 31, 2013		December 31, 2012

The Company establishes the expected long-term rate of return at the beginning of each fiscal year based upon historical returns and projected returns on the underlying mix of invested assets. The Company utilizes modern portfolio theory modeling techniques in the development of its return assumptions. This technique

 

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WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

NOTES TO FINANCIAL STATEMENTS (Continued)

 

projects rates of return that can be generated through various asset allocations that lie within the risk tolerance set forth the Company. The risk assessment provides a link between a pension plan’s risk capacity, management’s willingness to accept investment risk and the asset allocation process, which ultimately leads to the return generated by the invested assets.

Plan Assets

The Company’s investment goals are to maximize returns subject to specific risk management policies. The Company sets the expected return on plan assets based on historical trends and forecasts provided by its third-party fund managers. Its risk management policies permit investments in mutual funds, and prohibit direct investments in debt and equity securities and derivative financial instruments. The Company addresses diversification by the use of mutual fund investments whose underlying investments are in fixed income and equity securities, both domestic and international. These mutual funds are readily marketable and can be sold to fund benefit payment obligations as they become payable.

The weighted-average target asset allocation of the Company’s pension trusts were as follows at December 31, 2014:

 

		Target Allocation
Asset category
Cash and equivalents			0% - 10%
Equity securities funds			20% - 60%
Debt securities funds			40% - 80%
Other			0% - 10%

The fair value of the Company’s pension plan assets by asset category is as follows:

 

		December 31, 2014
						Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
		Fair Value				Level 1				Level 2				Level 3
		(In thousands)
Pooled separate accounts:
Large-cap blend(a)		$	3,163			$	—			$	3,163			$	—
International blend(b)			26,080				—				26,080				—
Fixed income domestic(c)			2,402				—				2,402				—
Fixed income long-term(d)			5,946				—				5,946				—
Stable value(e)			7,499				—				7,499				—
Registered investment companies—growth fund			3,442				3,442				—				—
		$	48,532			$	3,442			$	45,090			$	—

 

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WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

NOTES TO FINANCIAL STATEMENTS (Continued)

 

		December 31, 2013
						Quoted Prices in Active Markets for Identical Assets				Significant Other Observable Inputs				Significant Unobservable Inputs
		Fair Value				Level 1				Level 2				Level 3
		(In thousands)
Pooled separate accounts:
Large-cap blend(a)		$	21,190			$	—			$	21,190			$	—
International blend(b)			7,566				—				7,566				—
Fixed income domestic(c)			10,270				—				10,270				—
Fixed income long-term(d)			5,186				—				5,186				—
Stable value(e)			2,323				—				2,323				—
		$	46,535			$	—			$	46,535			$	—

 

(a)	Large-cap blend funds seek to provide long-term growth of capital. They seek to provide investment results that approximate the performance of the Standard & Poor’s Composite 1500 Index.

(b)	International blend funds seek to have a diversified portfolio of investments, investing in fixed-income and equity-focused investments in international markets.

(c)	Fixed income domestic funds seek to invest in high-quality corporate bonds with over 15 years to maturity.

(d)	Fixed income long term bond funds seek to achieve performance results similar to the Barclays Capital U.S. Aggregate Bond Index. This fund invests primarily in corporate and government bonds.

(e)	The stable value fund seeks to invest in publicly traded and privately placed debt securities and mortgage loans, and to a lesser extent, real estate and other equity investments in order to provide a guaranteed rate of return.

The Company’s Level 1 assets include securities held by registered investment companies and its common stock, which are both typically valued using quoted market prices of an active market.

The Company’s Level 2 assets include pooled separate accounts, which are valued based on the quoted market prices of the securities underlying the investments.

The Company did not have any Level 3 assets.

Contributions

In 2015, the Company expects to make approximately $1.2 million of pension plan contributions. In 2014, the Company made $0.9 million of pension plan contributions.

Cash Flows

The following benefit payments are expected to be paid from its pension plan assets:

 

		Pension Benefits
		(In thousands)
2015		$	3,116
2016			3,267
2017			3,483
2018			3,480
2019			3,628
Years 2019 – 2023			19,228

 

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WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

NOTES TO FINANCIAL STATEMENTS (Continued)

 

The benefits expected to be paid are based on the same assumptions used to measure the Company’s pension benefit obligation at December 31, 2014 and include estimated future employee service.

 

7.	Asset Retirement Obligations

Changes in the Company’s asset retirement obligations were as follows:

 

		Year Ended December 31, 2014				Year Ended December 31, 2013
Asset retirement obligations, beginning of period		$	17,174			$	17,768
Accretion			1,613				1,670
Liabilities settled			(885	)			(2,210	)
Changes due to amount and timing of reclamation			958				(54	)
Asset retirement obligations, end of year			18,860				17,174
Less current portion			(2,658	)			(1,998	)
Asset retirement obligations, less current portion		$	16,202			$	15,176

As permittee, the Company is responsible for the total amount.

 

8.	Income Taxes

Income tax expense attributable to net income before income taxes consists of (in thousands):

 

		Year Ended December 31, 2014				Year Ended December 31, 2013
Current:
Federal		$	20,254			$	9,306
Deferred:
Federal			(15,962	)			(845	)
Income tax expense		$	4,292			$	8,461

Income tax expense (benefit) attributable to net income before income taxes differed from the amounts computed by applying the U.S. federal statutory income tax rate of 35% to pre-tax income as a result of the following (in thousands):

 

		Year Ended December 31, 2014				Year Ended December 31, 2013				Eleven Months Ended December 31, 2012
Computed tax expense at statutory rate		$	10,364			$	10,221			$	9,782
Increase in income tax expense resulting from:
Tax depletion in excess of book			(4,371	)			(848	)			—
Domestic production activities deduction			(1,710	)			(923	)			(875	)
Other, net			9				11				9
Income tax expense		$	4,292			$	8,461			$	8,916

 

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WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

NOTES TO FINANCIAL STATEMENTS (Continued)

 

The tax effects of temporary differences that give rise to the components of the net deferred tax assets and liabilities consist of the following:

 

		December 31,
		2014				2013
		(In thousands)
Deferred tax assets:
Pension and postretirement medical benefit obligation		$	27,500			$	20,696
Asset retirement obligations			6,601				6,011
Accrued vacation			636				594
Other accrued liabilities			415				409
Total gross deferred tax assets			35,152				27,710
Deferred tax liabilities:
Property, plant, and equipment, principally due to differences in depreciation and depletion			(18,772	)			(33,060	)
Total gross deferred tax liabilities			(18,772	)			(33,060	)
Net deferred tax assets (liabilities)		$	16,380			$	(5,350	)
Deferred tax assets—current		$	903			$	870
Deferred tax assets (liabilities)—noncurrent			15,477				(6,220	)
Net deferred tax assets (liabilities)		$	16,380			$	(5,350	)

As of December 31, 2014, the Company has not recorded a reserve for uncertain tax positions or penalties and interest. The Company does not anticipate a significant change that would require a reserve to be established for uncertain tax positions in the next 12 months. The Company files federal and state income tax returns that are subject to examination by the Internal Revenue Service and certain state tax authorities. The tax years open to examination include 2011 through 2013. As of December 31, 2014, the Company has less than $0.1 million of alternative minimum tax credit carryforwards, which have an indefinite carryover life, with no expiration.

 

9.	Commitments and Contingencies

a) Leases

The gross value of property, plant, equipment under capital leases was $13.8 million and $0.7 million as of December 31, 2014 and 2013, respectively, related to the leasing of mining equipment. The accumulated amortization for these items was $2.5 million and $0.1 million at December 31, 2014 and 2013, respectively.

 

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WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

NOTES TO FINANCIAL STATEMENTS (Continued)

 

Future minimum capital and operating lease payments as of December 31, 2014, are as follows:

 

		Capital Leases				Operating Leases
		(In thousands)
2015		$	2,633			$	174
2016			2,603				115
2017			2,386				115
2018			2,352				115
2019			2,544				77
Thereafter			—				—
Total minimum lease payments			12,518			$	596
Less imputed interest			(887	)
Present value of minimum capital lease payments		$	11,631

Rental expense under operating leases during the years ended December 31, 2014 and 2013 and the eleven months ended December 31, 2012 totaled $1.9 million, $1.3 million and $0.6 million, respectively.

The Company leases certain of its coal reserves from third parties and pays royalties based on either a per ton rate or as a percentage of revenues received. Royalties charged to expense under all such lease agreements amounted to $3.1 million, $7.6 million and $6.6 million, for the years ended December 31, 2014 and 2013 and the eleven months ended December 31, 2012, respectively.

The company is subject to litigation in the ordinary course of business. No material litigation exists.

 

10.	Coal Sales and Major Customers

The customers from which more than 10% of total revenue has been derived and the percentage of total revenue from those customers is summarized as follows (in thousands):

 

		Year Ended December 31, 2014				Year Ended December 31, 2013				Eleven months Ended December 31, 2012
Customer A		$	101,778			$	112,061			$	96,718
Customer B			32,020				23,888				19,617
Customer C			20,853				22,482				18,253
		$	154,651			$	158,431			$	134,588
Percentage of total revenue			91	%			92	%			89	%

 

11.	Related Party Transactions

The Company was allocated audit and tax fees and information technology costs incurred by its Parent. For the years ended December 31, 2014 and 2013 and the eleven months ended December 31, 2012, these fees were $0.8 million, $0.6 million, and $0.3 million, respectively, which are included in Selling and administrative expenses.

 

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WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

NOTES TO FINANCIAL STATEMENTS (Continued)

 

Advances to Parent of $16.5 million for the year ended December 31, 2014 represent the net movement of cash from the Company’s bank accounts to bank accounts held by WCC.

Additionally, in December 2014, the Company entered into an agreement to mine certain coal reserves contributed to WCC in connection with WCC’s acquisition of the GP. Under this lease, the Company will pay a per ton royalty as these coal reserves are mined beginning in 2015.

 

12.	Quarterly Financial Data (unaudited)

Summarized quarterly financial data is as follows:

 

		Three Months Ended
		March 31				June 30				September 30				December 31
		(In thousands)
2014
Revenues		$	43,123			$	39,893			$	41,917			$	45,575
Operating income			8,570				6,712				5,142				8,837
Net income			8,574				6,852				5,234				4,659
2013:
Revenues		$	41,284			$	41,797			$	43,764			$	45,622
Operating income			5,995				7,264				6,527				8,940
Net income			6,025				7,339				6,615				763

 

13.	Accumulated Other Comprehensive Income (Loss)

The following is a summary of accumulated other comprehensive income (loss):

 

		Pension and Postretirement Medical Benefits				Available for Sale Securities				Accumulated Other Comprehensive Income (Loss)
		(In thousands)
Balance at January 31, 2012		$	—			$	—			$	—
2012 activity			(5,003	)			—				(5,003	)
Balance at December 31, 2012			(5,003	)			—				(5,003	)
2013 activity			22,494				—				22,494
Balance at December 31, 2013			17,491				—				17,491
2014 activity			(16,372	)			(107	)			(16,479	)
Balance at December 31, 2014		$	1,119			$	(107	)		$	1,012

Pension and postretirement medical benefit adjustments relate to changes in the funded status of various benefit plans. The unrealized gains and losses associated with recognizing the Company’s “available-for-sale” securities at fair value are recorded through Accumulated other comprehensive income (loss).

 

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WESTMORELAND KEMMERER, INC.

(A Wholly Owned Subsidiary of Westmoreland Coal Company)

NOTES TO FINANCIAL STATEMENTS (Continued)

 

Changes in Accumulated Other Comprehensive Income (Loss)

The following table reflects the changes in accumulated other comprehensive income (loss) by component:

 

		Pension				Postretirement Medical Benefits				Available for Sale Securities				Accumulated Other Comprehensive Income (Loss)
		(In thousands)
Balance at December 31, 2013		$	7,520			$	9,971			$	—			$	17,491
Other comprehensive income (loss) before reclassifications			(8,932	)			(6,776	)			(107	)			(15,815	)
Amounts reclassified from accumulated other comprehensive income (loss)			(187	)			(477	)			—				(664	)
Balance at December 31, 2014		$	(1,599	)		$	2,718			$	(107	)		$	1,012

The following table reflects the reclassifications out of accumulated other comprehensive income (loss) for the year ended December 31, 2014 (in thousands):

 

Details about accumulated other comprehensive income (loss) components		Amount reclassified from accumulated other comprehensive income (loss)(1)				Affected line item in the statement where net income (loss) is presented
Amortization of defined benefit pension items:
Actuarial gains		$	(187	)				(2)
Amortization of postretirement medical items:
Actuarial gains		$	(477	)				(3)

 

(1)	Amounts in parentheses indicate debits to income/loss.

(2)	These accumulated other comprehensive income (loss) components are included in the computation of net periodic pension cost. (See Note 6—Pension and Other Savings Plans for additional details)

(3)	These accumulated other comprehensive income (loss) components are included in the computation of net periodic postretirement medical cost. (See Note 5—Postretirement Medical Benefits for additional details)

 

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GLOSSARY OF SELECTED TERMS

Ash: Impurities consisting of silica, alumina, calcium, iron and other noncombustible matter that are contained in coal. Since ash increases the weight of coal, it adds to the cost of handling and can affect the burning characteristics of coal.

Bituminous coal: A middle rank coal formed by additional pressure and heat on lignite. It is the most common type of coal with moisture content less than 20% by weight and heating value of 9,500 to 14,000 Btus per pound. It is dense and black and often has well-defined bands of bright and dull material. It may be referred to as soft coal.

British thermal unit or Btu: A measure of the thermal energy required to raise the temperature of one pound of pure liquid water one degree Fahrenheit at the temperature at which water has its greatest density (39 degrees Fahrenheit). On average, coal contains about 11,000 Btu per pound.

Coal seam: A bed or stratum of coal, usually applies to a large deposit.

Compliance coal: Coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per million Btu, as required by Phase II of the Clean Air Act Acid Rain program.

Continuous miner: A machine that simultaneously extracts and loads coal. This is distinguished from a conventional, or cyclic, unit, which must stop the extraction process for loading to commence.

Dozer: A large, powerful tractor having a vertical blade on the front end for moving earth, rocks, etc.

Fossil fuel: Fuel such as coal, crude oil or natural gas formed from the fossil remains of organic material.

High-Btu coal: Coal which has an average heat content of 12,500 Btus per pound or greater.

High-sulfur coal: Coal which, when burned, emits 2.5 pounds or more of sulfur dioxide per million Btu.

Highwall: The unexcavated face of exposed overburden and coal in a surface mine or in a face or bank on the uphill side of a contour mine excavation.

Lignite: The lowest rank of coal with a high moisture content of up to 15% by weight and heat value of 6,500 to 8,300 Btus per pound. It is brownish black and tends to oxidize and disintegrate when exposed to air.

Illinois Basin: Coal producing area in Illinois, Indiana and western Kentucky.

Industrial boilers: Closed vessels that use a fuel source to heat water or generate steam for industrial heating and humidification applications.

Limestone: A rock predominantly composed of the mineral calcite (calcium carbonate (“CaCO2”)).

Metallurgical coal: The various grades of coal suitable for carbonization to make coke for steel manufacture. Its quality depends on four important criteria: volatility, which affects coke yield; the level of impurities including sulfur and ash, which affects coke quality; composition, which affects coke strength; and basic characteristics, which affect coke oven safety. Metallurgical coal typically has a particularly high Btu, but low ash and sulfur content.

Nitrogen oxide (NOx): A gas formed in high temperature environments, such as coal combustion, that is a harmful pollutant and contributes to acid rain.

 

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Northern Appalachia: Coal producing area in Maryland, Ohio, Pennsylvania and northern West Virginia.

Overburden: Layers of earth and rock covering a coal seam, that in surface mining operations must be removed prior to coal extraction.

Preparation plant: A facility for crushing, sizing and washing coal to prepare it for use by a particular customer. The washing process has the added benefit of removing some of the coal’s sulfur content. While usually located on a mine site, one plant may serve multiple mines.

Probable coal reserves: Coal reserves for which quantity and grade and/or quality are computed from information similar to that used for proven coal reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven coal reserves, is high enough to assume continuity between points of observation.

Proven coal reserves: Coal reserves for which (i) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; (ii) grade and/or quality are computed from the results of detailed sampling; and (iii) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of coal reserves are well-established.

Proven and probable coal reserves: Coal reserves which are a combination of proven coal reserves and probable coal reserves.

Reclamation: The restoration of mined land to original contour, use or condition.

Recoverable reserve: The amount of coal that can be extracted from the Reserves. The recovery factor for surface mines is typically between 80% and 90%.

Reserve: That part of a mineral deposit that could be economically and legally extracted.

Selective catalytic reduction, or SCR, device: A means of converting nitrogen oxides, also referred to as NOx, with the aid of a catalyst into diatomic nitrogen (N2) and water (H2O).

Strip ratio: Strip ratio refers to the number of bank cubic yards of overburden or waste that must be removed to extract one ton of coal.

Sub-bituminous Coal: Dull coal that ranks between lignite and bituminous coal. Its moisture content is between 20% and 30% by weight and its heat content ranges from 7,800 to 9,500 Btus per pound.

Sulfur: One of the elements present in varying quantities in coal and which contributes to environmental degradation when coal is burned. Sulfur dioxide is produced as a gaseous byproduct of coal combustion.

Tipple: A structure where coal is loaded in railroad cars or trucks.

Thermal coal (aka Steam coal): Coal burned by electric power plants and industrial steam boilers to produce electricity, steam or both.

Tons: A “short,” or net, ton is equal to 2,000 pounds. A “long,” or British, ton is equal to 2,240 pounds. A “metric” ton is approximately 2,205 pounds. The short ton is the unit of measure referred to in this report.

Total maximum daily load: A calculation of the maximum amount of a pollutant that a body of water can receive per day and still safely meet water quality standards.

 

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Common Units

 

Westmoreland Resource Partners, LP

Common Units Representing Limited Partner Interests

 

 

PROSPECTUS

 

 

BMO Capital Markets

                    , 2015

 

 

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PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

 

Item 13.

Other Expenses of Issuance and Distribution.

Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the SEC registration fee, the amounts set forth below are estimates.

 

SEC registration fee		$	10,022.25
FINRA filing fee
Legal fees and expenses
Accounting fees and expenses
Printing expenses
Miscellaneous
Total

 

Item 14.

Indemnification of Officers and Members of Our Board of Directors.

The section of the prospectus entitled “The Partnership Agreement—Indemnification” discloses that we will generally indemnify officers, directors and affiliates of the general partner to the fullest extent permitted by law from and against all losses, claims, damages or similar events and is incorporated herein by this reference. Subject to any terms, conditions or restrictions set forth in our partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other persons from and against all claims and demands whatsoever.

To the extent that the indemnification provisions of our partnership agreement purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and is therefore unenforceable.

 

Item 15.

Recent Sales of Unregistered Securities.

On December 31, 2014, WCC and the Partnership completed the Initial Kemmerer Contribution in exchange for the issuance by the Partnership to WCC of 4,512,500 common units (on a post-split basis following the 12-to-1 reverse split of the Partnership’s common and general partner units). The Initial Kemmerer Contribution units were issued in reliance on the exemption provided under Section 4(a)(2) of the Securities Act.

We expect to issue up to $20 million in common units and up to $75 million in Series A Convertible Units to WCC in the third quarter of 2015 in connection with the Contribution.

 

Item 16.

Exhibits and Financial Statement Schedules.

 

(a)

Exhibits

 

Exhibit
1.1**		Form of Underwriting Agreement
2.1		Contribution Agreement, dated as of June 1, 2015, by and between Westmoreland Coal Company and Westmoreland Resource Partners, LP (incorporated by reference to Exhibit 2.1 to the Partnership’s Current Report on Form 8-K (Commission File No. 001-34815) filed on June 2, 2015)
3.1		Certificate of Limited Partnership of Westmoreland Resource Partners, LP (incorporated by reference to Exhibit 3.1 to the Partnership’s Registration Statement on Form S-1 (Commission File No. 333-165662) filed on March 24, 2010)
3.2		Certificate of Amendment to Certificate of Limited Partnership of Westmoreland Resource Partners, LP executed as of December 23, 2014 to be effective December 30, 2014 (incorporated by reference to Exhibit 3.1A to the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2014 (Commission File No. 001-34815) filed on March 6, 2015)

 

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Exhibit
3.3		Fourth Amended and Restated Agreement of Limited Partnership of Westmoreland Resource Partners, LP dated December 31, 2014 (incorporated by reference to Exhibit 3.2 to the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2014 (Commission File No. 001-34815) filed on March 6, 2015)
3.4		Certificate of Formation of Westmoreland Resources GP, LLC (incorporated by reference to Exhibit 3.3 to Amendment No. 1 to the Partnership’s Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
3.5		Certificate of Amendment to Certificate of Formation of Westmoreland Resources GP, LLC executed as of December 23, 2014 to be effective December 30, 2014 (incorporated by reference to Exhibit 3.3A to the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2014 (Commission File No. 001-34815) filed on March 6, 2015)
3.6		Third Amended and Restated Limited Liability Company Agreement of Westmoreland Resources GP, LLC dated January 1, 2011 (incorporated by reference to Exhibit 3.2 to the Partnership’s Current Report on Form 8-K (Commission File No. 001-34815) filed on January 4, 2011)
3.7		First Amendment to Third Amended and Restated Limited Liability Company Agreement of Westmoreland Resources GP, LLC executed as of March 12, 2014 to be effective as of June 24, 2013, entered into to correct, clarify, supersede and replace in its entirety the First Amendment to Third Amended and Restated Limited Liability Company Agreement of Westmoreland Resources GP, LLC dated June 24, 2013 (incorporated by reference to Exhibit 3.4B to the Partnership’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014 (Commission File No. 001-34815) filed on May 6, 2014)
5.1**		Opinion of Holland & Hart LLP as to the validity of the common units being registered
8.1**		Opinion of Holland & Hart LLP relating to tax matters
10.1		Investors’ Rights Agreement, dated August 24, 2007, by and among Westmoreland Resource Partners, LP, Westmoreland Resources GP, LLC, AIM Oxford Holdings, LLC, C&T Coal, Inc., Charles C. Ungurean and Thomas T. Ungurean (incorporated by reference to Amendment No. 3 to the Partnership’s Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 9, 2010)
10.2		Amendment to Investors’ Rights Agreement dated June 24, 2013 by and among Westmoreland Resource Partners, LP, Westmoreland Resources GP, LLC, AIM Oxford Holdings, LLC, C&T Coal, Inc., Charles C. Ungurean and Thomas T. Ungurean (incorporated by reference to Exhibit 10.2A to the Partnership’s Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
10.3		Employment Agreement between Westmoreland Resources GP, LLC and Gregory J. Honish, which Employment Agreement was effective on March 29, 2013 (incorporated by reference to Exhibit 10.4D to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2012 filed on April 1, 2013)
10.4		Amendment to Employment Agreement between Westmoreland Resources GP, LLC and Gregory J. Honish, which Amendment was effective on March 3, 2014 (incorporated by reference to Exhibit 10.4E to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2013 filed on March 4, 2014)
10.5		Employment Agreement between Westmoreland Resources GP, LLC and Daniel M. Maher, which Employment Agreement was effective on March 29, 2013 (incorporated by reference to Exhibit 10.5D to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2012 filed on April 1, 2013)

 

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Exhibit
10.6		Amendment to Employment Agreement between Westmoreland Resources GP, LLC and Daniel M. Maher, which Amendment was effective on March 3, 2014(incorporated by reference to Exhibit 10.5E to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2013 filed on March 4, 2014)
10.7		Employment Agreement between Westmoreland Resources GP, LLC and Charles C. Ungurean, which Employment Agreement was effective on June 24, 2013 (incorporated by reference to Exhibit 10.6D to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
10.8		Employee Unitholder Agreement among Westmoreland Resource Partners, LP, Westmoreland Resources GP, LLC and Gregory J. Honish (incorporated by reference to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
10.9		Westmoreland Resource Partners, LP Amended and Restated Long-Term Incentive Plan dated July 19, 2010 (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K (Commission File No. 001-34815) filed on July 19, 2010)
10.10		First Amendment to Westmoreland Resource Partners, LP Amended and Restated Long-Term Incentive Plan effective December 31, 2013 (incorporated by reference to Annex A to the Information Statement on Schedule 14C (Commission File No. 001-34815) filed on February 4, 2014)
10.11		Form of Long-Term Incentive Plan Award Agreement for Grant of Phantom Units for general use (incorporated by reference to Exhibit 10.11A to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2011 filed on March 14, 2012)
10.12		Form of Long-Term Incentive Plan Award Agreement for Grant of Phantom Units for use with Charles C. Ungurean, Bradley W. Harris, Gregory J. Honish and Daniel M. Maher (incorporated by reference to Exhibit 10.11B to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2011 filed on March 14, 2012)
10.13		Non-Employee Director Compensation Plan adopted on June 28, 2011 and effective on January 1, 2011 (incorporated by reference to Exhibit 10.12 to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2011 filed on March 14, 2012)
10.14		Non-Employee Director Compensation Plan adopted on February 28, 2013 and effective on January 1, 2013 (incorporated by reference to Exhibit 10.12A to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2012 filed on April 1, 2013)
10.15		Form of Non-Employee Director Compensation Plan Award Agreement for Grant of Unrestricted Units (incorporated by reference to Exhibit 10.13 to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2011 filed on March 14, 2012)
10.16		Director Unitholder Agreement, dated December 1, 2009, by and among Westmoreland Resource Partners, LP, Westmoreland Resources GP, LLC and Gerald A. Tywoniuk (incorporated by reference to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
10.17		Acquisition Agreement, dated August 14, 2009, by and among Oxford Mining Company, LLC, Phoenix Coal Inc., Phoenix Coal Corporation and Phoenix Newco, LLC (incorporated by reference to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
10.18		Coal Purchase and Sale Agreement No. 10-62-04-900, dated May 21, 2004, by and between Oxford Mining Company, Inc. and American Electric Power Service Corporation, agent for Columbus Southern Power Company (incorporated by reference to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)

 

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Exhibit
10.19		Amendment No. 2004-1 to Coal Purchase and Sale Agreement, dated October 25, 2004 (incorporated by reference to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
10.20		Amendment No. 2005-1 to Coal Purchase and Sale Agreement, dated April 8, 2005 (incorporated by reference to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
10.21		Amendment No. 2006-3 to Coal Purchase and Sale Agreement, dated December 5, 2006 (incorporated by reference to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
10.22		Amendment No. 2008-6 to Coal Purchase and Sale Agreement, dated December 29, 2008 (incorporated by reference to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
10.23		Amendment No. 2009-1 to Coal Purchase and Sale Agreement, dated May 21, 2009 (incorporated by reference to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
10.24		Amendment No. 2009-3 to Coal Purchase and Sale Agreement, dated December 15, 2009 (incorporated by reference to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
10.25		Amendment No. 2010-1 to Coal Purchase and Sale Agreement, dated January 11, 2010 (incorporated by reference to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
10.26		Amendment No. 2010-2 to Coal Purchase and Sale Agreement, dated February 4, 2010 (incorporated by reference to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
10.27		Amendment No. 2010-3 to Coal Purchase and Sale Agreement, dated April 16, 2010 (incorporated by reference to Amendment No. 3 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 9, 2010)
10.28		Amendment No. 2011-5 to Coal Purchase and Sale Agreement, dated October 26, 2011 (incorporated by reference to Exhibit 10.16K to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2011 filed on March 14, 2012)
10.29		Amendment No. 2012-1 to Coal Purchase and Sale Agreement, dated March 21, 2012 (incorporated by reference to Exhibit 10.16L to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended March 31, 2012 filed on May 9, 2012)
10.30		Amendment No. 2012-2 to Coal Purchase and Sale Agreement, dated July 30, 2012 (incorporated by reference to Exhibit 10.16M to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended September 30, 2012 filed on November 7, 2012)
10.31		Amendment No. 2013-2 to Coal Purchase and Sale Agreement, dated February 6, 2013 (incorporated by reference to Exhibit 10.16N to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2012 filed on April 1, 2013)
10.32		Amendment No. 2013-5 to Coal Purchase and Sale Agreement, dated June 26, 2013 (incorporated by reference to Exhibit 10.16O to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)

 

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Exhibit
10.33		Amendment No. 2014-1 to Coal Purchase and Sale Agreement, dated January 6, 2014 (incorporated by reference to Exhibit 10.16P to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2013 filed on March 4, 2014)
10.34		Amendment No. 2014-2 to Coal Purchase and Sale Agreement, dated February 27, 2014 (incorporated by reference to Exhibit 10.16Q to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2013 filed on March 4, 2014)
10.35		Amendment No. 2015-1 to Coal Purchase and Sale Agreement, dated February 26, 2015 (incorporated by reference to Exhibit 10.16R to the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2014 (Commission File No. 001-34815) filed on March 6, 2015)
10.36**		Coal Purchase and Sale Agreement No. 10-62-15-900, dated February 26, 2015, by and between Oxford Mining Company, LLC and AEP Generation Resources, Inc.
10.37		Non-Compete Agreement by and among Westmoreland Resource Partners, LP, C&T Coal, Inc., Charles C. Ungurean, Thomas T. Ungurean and Westmoreland Resources GP, LLC (incorporated by reference to Amendment No. 3 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 9, 2010)
10.38		Administrative and Operational Services Agreement, dated August 24, 2007, by and among Westmoreland Resource Partners, LP, Oxford Mining Company, LLC and Westmoreland Resources GP, LLC (incorporated by reference to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
10.39		Employment Agreement between Westmoreland Resources GP, LLC and Bradley W. Harris (incorporated by reference to Exhibit 10.19 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended September 30, 2012 filed on November 7, 2012)
10.40		Amendment to Employment Agreement between Westmoreland Resources GP, LLC and Bradley W. Harris dated as of March 3, 2014 (incorporated by reference to Exhibit 10.19A to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2013 filed on March 4, 2014)
10.41		Employment Agreement between Westmoreland Resources GP, LLC and Michael B. Gardner, which Employment Agreement was effective on March 29, 2013 (incorporated by reference to Exhibit 10.20B to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2012 filed on April 1, 2013)
10.42		Amendment to Employment Agreement between Westmoreland Resources GP, LLC and Michael B. Gardner dated as of March 3, 2014 (incorporated by reference to Exhibit 10.20C to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2013 filed on March 4, 2014)
10.43		Retention bonus letter agreement between Westmoreland Resources GP, LLC and Bradley W. Harris dated as of March 29, 2013 (incorporated by reference to Exhibit 10.21 to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2012 filed on April 1, 2013)
10.44		Retention bonus letter agreement between Westmoreland Resources GP, LLC and Daniel M. Maher dated as of March 29, 2013 (incorporated by reference to Exhibit 10.22 to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2012 filed on April 1, 2013)
10.45		Retention bonus letter agreement between Westmoreland Resources GP, LLC and Gregory J. Honish dated as of March 29, 2013 (incorporated by reference to Exhibit 10.23 to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2012 filed on April 1, 2013)

 

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Exhibit
10.46		Financing Agreement, dated as of June 24, 2013, by and among Oxford Mining Company, LLC, as borrower, Westmoreland Resource Partners, LP, as a guarantor, the other guarantors party thereto, the lenders party thereto, and Cerberus Business Finance, LLC, as collateral agent and administrative agent for such lenders (incorporated by reference to Exhibit 10.24 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
10.47		Financing Agreement, dated as of June 24, 2013, by and among Oxford Mining Company, LLC, as borrower, Westmoreland Resource Partners, LP, as a guarantor, the other guarantors party thereto, the lenders party thereto, and Obsidian Agency Services, Inc., as collateral agent and administrative agent for such lenders (incorporated by reference to Exhibit 10.25 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
10.48		Intercreditor Agreement dated June 24, 2013 (incorporated by reference to Exhibit 10.26 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
10.49		Warrant Issuance Agreement dated June 24, 2013 (incorporated by reference to Exhibit 10.27 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
10.50		Form of Warrant (to purchase common units of Westmoreland Resource Partners, LP) issued pursuant to the Warrant Issuance Agreement dated June 24, 2013 (incorporated by reference to Exhibit 10.28 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
10.51		Form of Warrant (to purchase subordinated units of Westmoreland Resource Partners, LP) issued pursuant to the Warrant Issuance Agreement dated June 24, 2013 (incorporated by reference to Exhibit 10.29 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
10.52		Form of Warrant (to purchase subordinated units of Westmoreland Resource Partners, LP) executed as of March 12, 2014 to be effective as of June 24, 2013, issued to correct, clarify, supersede and replace in its entirety the Warrant (to purchase subordinated units of Westmoreland Resource Partners, LP) issued pursuant to the Warrant Issuance Agreement dated June 24, 2013 (incorporated by reference to Exhibit 10.29A to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended March 31, 2014 filed on May 6, 2014)
10.53		Form of Warrant (to purchase Class B Units of Westmoreland Resources GP, LLC) issued pursuant to the Warrant Issuance Agreement dated June 24, 2013 (incorporated by reference to Exhibit 10.30 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
10.54		Investors’ Rights Agreement, dated as of June 24, 2013, by and among Westmoreland Resource Partners, LP, Westmoreland Resources GP, LLC, AIM Oxford Holdings, LLC, and the lenders party to the Financing Agreement, dated as of June 24, 2013, by and among Oxford Mining Company, LLC, as borrower, Westmoreland Resource Partners, LP, as a guarantor, the other guarantors party thereto, such lenders, and Obsidian Agency Services, Inc., as collateral agent and administrative agent for such lenders (incorporated by reference to Exhibit 10.31 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
10.55		Mediation Settlement Agreement dated July 15, 2014 between Oxford Mining Company—Kentucky, LLC and Big Rivers Electric Corporation (incorporated by reference to Exhibit 10.32 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2014 filed on August 5, 2014)

 

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Exhibit
10.56		Settlement Agreement effective July 15, 2014 between Oxford Mining Company—Kentucky, LLC and Big Rivers Electric Corporation, supplementing the Mediation Settlement Agreement dated July 15, 2014 between them (incorporated by reference to Exhibit 10.33 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2014 filed on August 5, 2014)
10.57		Contribution Agreement, dated as of October 16, 2014, between Westmoreland Resource Partners, LP and Westmoreland Coal Company (incorporated by reference to Annex B of the Preliminary Proxy Statement filed on October 24, 2014)
10.58		Membership Interests Redemption Agreement, effective as of October 1, 2014, among Oxford Mining Company, LLC, Harrison Resources, LLC and CONSOL of Ohio LLC (incorporated by reference to Exhibit 10.35 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended September 30, 2014 filed on October 30, 2014)
10.59		Financing Agreement, dated as of December 31, 2014, by and among Oxford Mining Company, LLC, Westmoreland Resource Partners, LP and each of its other subsidiaries, the lenders party thereto and U.S. Bank National Association (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8K filed on January 7, 2015)
16.1		Letter from Grant Thornton LLP to the Securities and Exchange Commission dated March 16, 2015 (incorporated by reference to Exhibit 16.1 to the Partnership’s Current Report on Form 8-K (Commission File No. 001-34815) filed on March 16, 2015)
21.1		List of Subsidiaries of Westmoreland Resource Partners, LP (incorporated by reference to Exhibit 21.1 to the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2014 (Commission File No. 001-34815) filed on March 6, 2015)
23.1*		Consent of Grant Thornton LLP
23.2*		Consent of Ernst & Young LLP
23.3*		Consent of John T. Boyd Company
23.4**		Consent of Holland & Hart LLP (included in Exhibit 5.1)
23.5**		Consent of Holland & Hart LLP (included in Exhibit 8.1)
24.1*		Powers of Attorney (included on the signature page)

 

*	Filed herewith.

**	To be filed by amendment.

 

(b)	Financial Statement Schedules.

Schedules have been omitted because the required information is included in the consolidated financial statements and the notes thereto, which have been incorporated herein by reference, information therein is not applicable or the omitted schedules are not required.

 

Item 17.

Undertakings.

(a) The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

(b) Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers, and controlling persons of the registrant pursuant to the provisions described in Item 15 above, or

 

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otherwise, the registrant has been advised that in the opinion of the SEC that indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against any liability (other than the payment by the registrant of expenses incurred or paid by a director, officer, or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by a director, officer, or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of the issue.

(c) The undersigned Registrant hereby further undertakes that:

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance under Rule 430A and contained in a form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4), or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered herein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

 

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Englewood, State of Colorado, on June 1, 2015.

 

Each person whose signature appears below hereby appoints Jennifer S. Grafton and Kevin A. Paprzycki, and each of them, either of whom may act without the joinder of the other, as his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement, or any Registration Statement (including any amendment thereto) for the same offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he might or would do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or either of them or their or his substitute and substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in their indicated capacities, which are with the general partner of the registrant, on the dates indicated.

 

Signature		Title		Date
/s/ Keith E. Alessi Keith E. Alessi		Chairman of the Board, Director, and Chief Executive Officer (principal executive officer)		June 1, 2015
/s/ Kevin A. Paprzycki Kevin A. Paprzycki		Director, Chief Financial Officer and Treasurer (principal financial officer)		June 1, 2015
/s/ Michael J. Meyer Michael J. Meyer		Controller (principal accounting officer)		June 1, 2015
/s/ Jennifer S. Grafton Jennifer S. Grafton		Director and Chief Legal Officer		June 1, 2015
/s/ Robert T. Clutterbuck		Director		June 1, 2015
Robert T. Clutterbuck

 

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Signature		Title		Date
/s/ Keith D. Horton Keith D. Horton		Director		June 1, 2015
/s/ Kurt D. Kost Kurt D. Kost		Director		June 1, 2015
/s/ Gerald A. Tywoniuk Gerald A. Tywoniuk		Director		June 1, 2015
/s/ Charles C. Ungurean Charles C. Ungurean		Director		June 1, 2015

 

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INDEX TO EXHIBITS

 

Exhibit
1.1**		Form of Underwriting Agreement
2.1		Contribution Agreement, dated as of June 1, 2015, by and between Westmoreland Coal Company and Westmoreland Resource Partners, LP (incorporated by reference to Exhibit 2.1 to the Partnership’s Current Report on Form 8-K (Commission File No. 001-34815) filed on June 2, 2015)
3.1		Certificate of Limited Partnership of Westmoreland Resource Partners, LP (incorporated by reference to Exhibit 3.1 to the Partnership’s Registration Statement on Form S-1 (Commission File No. 333-165662) filed on March 24, 2010)
3.2		Certificate of Amendment to Certificate of Limited Partnership of Westmoreland Resource Partners, LP executed as of December 23, 2014 to be effective December 30, 2014 (incorporated by reference to Exhibit 3.1A to the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2014 (Commission File No. 001-34815) filed on March 6, 2015)
3.3		Fourth Amended and Restated Agreement of Limited Partnership of Westmoreland Resource Partners, LP dated December 31, 2014 (incorporated by reference to Exhibit 3.2 to the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2014 (Commission File No. 001-34815) filed on March 6, 2015)
3.4		Certificate of Formation of Westmoreland Resources GP, LLC (incorporated by reference to Exhibit 3.3 to Amendment No. 1 to the Partnership’s Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
3.5		Certificate of Amendment to Certificate of Formation of Westmoreland Resources GP, LLC executed as of December 23, 2014 to be effective December 30, 2014 (incorporated by reference to Exhibit 3.3A to the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2014 (Commission File No. 001-34815) filed on March 6, 2015)
3.6		Third Amended and Restated Limited Liability Company Agreement of Westmoreland Resources GP, LLC dated January 1, 2011 (incorporated by reference to Exhibit 3.2 to the Partnership’s Current Report on Form 8-K (Commission File No. 001-34815) filed on January 4, 2011)
3.7		First Amendment to Third Amended and Restated Limited Liability Company Agreement of Westmoreland Resources GP, LLC executed as of March 12, 2014 to be effective as of June 24, 2013, entered into to correct, clarify, supersede and replace in its entirety the First Amendment to Third Amended and Restated Limited Liability Company Agreement of Westmoreland Resources GP, LLC dated June 24, 2013 (incorporated by reference to Exhibit 3.4B to the Partnership’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014 (Commission File No. 001-34815) filed on May 6, 2014)
5.1**		Opinion of Holland & Hart LLP as to the validity of the common units being registered
8.1**		Opinion of Holland & Hart LLP relating to tax matters
10.1		Investors’ Rights Agreement, dated August 24, 2007, by and among Westmoreland Resource Partners, LP, Westmoreland Resources GP, LLC, AIM Oxford Holdings, LLC, C&T Coal, Inc., Charles C. Ungurean and Thomas T. Ungurean (incorporated by reference to Amendment No. 3 to the Partnership’s Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 9, 2010)
10.2		Amendment to Investors’ Rights Agreement dated June 24, 2013 by and among Westmoreland Resource Partners, LP, Westmoreland Resources GP, LLC, AIM Oxford Holdings, LLC, C&T Coal, Inc., Charles C. Ungurean and Thomas T. Ungurean (incorporated by reference to Exhibit 10.2A to the Partnership’s Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)

 

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Exhibit
10.3		Employment Agreement between Westmoreland Resources GP, LLC and Gregory J. Honish, which Employment Agreement was effective on March 29, 2013 (incorporated by reference to Exhibit 10.4D to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2012 filed on April 1, 2013)
10.4		Amendment to Employment Agreement between Westmoreland Resources GP, LLC and Gregory J. Honish, which Amendment was effective on March 3, 2014 (incorporated by reference to Exhibit 10.4E to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2013 filed on March 4, 2014)
10.5		Employment Agreement between Westmoreland Resources GP, LLC and Daniel M. Maher, which Employment Agreement was effective on March 29, 2013 (incorporated by reference to Exhibit 10.5D to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2012 filed on April 1, 2013)
10.6		Amendment to Employment Agreement between Westmoreland Resources GP, LLC and Daniel M. Maher, which Amendment was effective on March 3, 2014(incorporated by reference to Exhibit 10.5E to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2013 filed on March 4, 2014)
10.7		Employment Agreement between Westmoreland Resources GP, LLC and Charles C. Ungurean, which Employment Agreement was effective on June 24, 2013 (incorporated by reference to Exhibit 10.6D to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
10.8		Employee Unitholder Agreement among Westmoreland Resource Partners, LP, Westmoreland Resources GP, LLC and Gregory J. Honish (incorporated by reference to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
10.9		Westmoreland Resource Partners, LP Amended and Restated Long-Term Incentive Plan dated July 19, 2010 (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K (Commission File No. 001-34815) filed on July 19, 2010)
10.10		First Amendment to Westmoreland Resource Partners, LP Amended and Restated Long-Term Incentive Plan effective December 31, 2013 (incorporated by reference to Annex A to the Information Statement on Schedule 14C (Commission File No. 001-34815) filed on February 4, 2014)
10.11		Form of Long-Term Incentive Plan Award Agreement for Grant of Phantom Units for general use (incorporated by reference to Exhibit 10.11A to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2011 filed on March 14, 2012)
10.12		Form of Long-Term Incentive Plan Award Agreement for Grant of Phantom Units for use with Charles C. Ungurean, Bradley W. Harris, Gregory J. Honish and Daniel M. Maher (incorporated by reference to Exhibit 10.11B to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2011 filed on March 14, 2012)
10.13		Non-Employee Director Compensation Plan adopted on June 28, 2011 and effective on January 1, 2011 (incorporated by reference to Exhibit 10.12 to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2011 filed on March 14, 2012)
10.14		Non-Employee Director Compensation Plan adopted on February 28, 2013 and effective on January 1, 2013 (incorporated by reference to Exhibit 10.12A to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2012 filed on April 1, 2013)
10.15		Form of Non-Employee Director Compensation Plan Award Agreement for Grant of Unrestricted Units (incorporated by reference to Exhibit 10.13 to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2011 filed on March 14, 2012)

 

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Exhibit
10.16		Director Unitholder Agreement, dated December 1, 2009, by and among Westmoreland Resource Partners, LP, Westmoreland Resources GP, LLC and Gerald A. Tywoniuk (incorporated by reference to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
10.17		Acquisition Agreement, dated August 14, 2009, by and among Oxford Mining Company, LLC, Phoenix Coal Inc., Phoenix Coal Corporation and Phoenix Newco, LLC (incorporated by reference to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
10.18		Coal Purchase and Sale Agreement No. 10-62-04-900, dated May 21, 2004, by and between Oxford Mining Company, Inc. and American Electric Power Service Corporation, agent for Columbus Southern Power Company (incorporated by reference to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
10.19		Amendment No. 2004-1 to Coal Purchase and Sale Agreement, dated October 25, 2004 (incorporated by reference to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
10.20		Amendment No. 2005-1 to Coal Purchase and Sale Agreement, dated April 8, 2005 (incorporated by reference to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
10.21		Amendment No. 2006-3 to Coal Purchase and Sale Agreement, dated December 5, 2006 (incorporated by reference to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
10.22		Amendment No. 2008-6 to Coal Purchase and Sale Agreement, dated December 29, 2008 (incorporated by reference to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
10.23		Amendment No. 2009-1 to Coal Purchase and Sale Agreement, dated May 21, 2009 (incorporated by reference to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
10.24		Amendment No. 2009-3 to Coal Purchase and Sale Agreement, dated December 15, 2009 (incorporated by reference to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
10.25		Amendment No. 2010-1 to Coal Purchase and Sale Agreement, dated January 11, 2010 (incorporated by reference to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
10.26		Amendment No. 2010-2 to Coal Purchase and Sale Agreement, dated February 4, 2010 (incorporated by reference to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
10.27		Amendment No. 2010-3 to Coal Purchase and Sale Agreement, dated April 16, 2010 (incorporated by reference to Amendment No. 3 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 9, 2010)
10.28		Amendment No. 2011-5 to Coal Purchase and Sale Agreement, dated October 26, 2011 (incorporated by reference to Exhibit 10.16K to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2011 filed on March 14, 2012)
10.29		Amendment No. 2012-1 to Coal Purchase and Sale Agreement, dated March 21, 2012 (incorporated by reference to Exhibit 10.16L to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended March 31, 2012 filed on May 9, 2012)

 

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Exhibit
10.30		Amendment No. 2012-2 to Coal Purchase and Sale Agreement, dated July 30, 2012 (incorporated by reference to Exhibit 10.16M to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended September 30, 2012 filed on November 7, 2012)
10.31		Amendment No. 2013-2 to Coal Purchase and Sale Agreement, dated February 6, 2013 (incorporated by reference to Exhibit 10.16N to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2012 filed on April 1, 2013)
10.32		Amendment No. 2013-5 to Coal Purchase and Sale Agreement, dated June 26, 2013 (incorporated by reference to Exhibit 10.16O to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
10.33		Amendment No. 2014-1 to Coal Purchase and Sale Agreement, dated January 6, 2014 (incorporated by reference to Exhibit 10.16P to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2013 filed on March 4, 2014)
10.34		Amendment No. 2014-2 to Coal Purchase and Sale Agreement, dated February 27, 2014 (incorporated by reference to Exhibit 10.16Q to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2013 filed on March 4, 2014)
10.35		Amendment No. 2015-1 to Coal Purchase and Sale Agreement, dated February 26, 2015 (incorporated by reference to Exhibit 10.16R to the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2014 (Commission File No. 001-34815) filed on March 6, 2015)
10.36		Non-Compete Agreement by and among Westmoreland Resource Partners, LP, C&T Coal, Inc., Charles C. Ungurean, Thomas T. Ungurean and Westmoreland Resources GP, LLC (incorporated by reference to Amendment No. 3 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 9, 2010)
10.37		Administrative and Operational Services Agreement, dated August 24, 2007, by and among Westmoreland Resource Partners, LP, Oxford Mining Company, LLC and Westmoreland Resources GP, LLC (incorporated by reference to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
10.38		Employment Agreement between Westmoreland Resources GP, LLC and Bradley W. Harris (incorporated by reference to Exhibit 10.19 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended September 30, 2012 filed on November 7, 2012)
10.39		Amendment to Employment Agreement between Westmoreland Resources GP, LLC and Bradley W. Harris dated as of March 3, 2014(incorporated by reference to Exhibit 10.19A to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2013 filed on March 4, 2014)
10.40		Employment Agreement between Westmoreland Resources GP, LLC and Michael B. Gardner, which Employment Agreement was effective on March 29, 2013 (incorporated by reference to Exhibit 10.20B to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2012 filed on April 1, 2013)
10.41		Amendment to Employment Agreement between Westmoreland Resources GP, LLC and Michael B. Gardner dated as of March 3, 2014 (incorporated by reference to Exhibit 10.20C to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2013 filed on March 4, 2014)
10.42		Retention bonus letter agreement between Westmoreland Resources GP, LLC and Bradley W. Harris dated as of March 29, 2013 (incorporated by reference to Exhibit 10.21 to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2012 filed on April 1, 2013)

 

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Table of Contents

Exhibit
10.43		Retention bonus letter agreement between Westmoreland Resources GP, LLC and Daniel M. Maher dated as of March 29, 2013 (incorporated by reference to Exhibit 10.22 to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2012 filed on April 1, 2013)
10.44		Retention bonus letter agreement between Westmoreland Resources GP, LLC and Gregory J. Honish dated as of March 29, 2013 (incorporated by reference to Exhibit 10.23 to the Annual Report on Form 10-K (Commission File No. 001-34815) for the year ended December 31, 2012 filed on April 1, 2013)
10.45		Financing Agreement, dated as of June 24, 2013, by and among Oxford Mining Company, LLC, as borrower, Westmoreland Resource Partners, LP, as a guarantor, the other guarantors party thereto, the lenders party thereto, and Cerberus Business Finance, LLC, as collateral agent and administrative agent for such lenders (incorporated by reference to Exhibit 10.24 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
10.46		Financing Agreement, dated as of June 24, 2013, by and among Oxford Mining Company, LLC, as borrower, Westmoreland Resource Partners, LP, as a guarantor, the other guarantors party thereto, the lenders party thereto, and Obsidian Agency Services, Inc., as collateral agent and administrative agent for such lenders (incorporated by reference to Exhibit 10.25 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
10.47		Intercreditor Agreement dated June 24, 2013 (incorporated by reference to Exhibit 10.26 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
10.48		Warrant Issuance Agreement dated June 24, 2013 (incorporated by reference to Exhibit 10.27 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
10.49		Form of Warrant (to purchase common units of Westmoreland Resource Partners, LP) issued pursuant to the Warrant Issuance Agreement dated June 24, 2013 (incorporated by reference to Exhibit 10.28 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
10.50		Form of Warrant (to purchase subordinated units of Westmoreland Resource Partners, LP) issued pursuant to the Warrant Issuance Agreement dated June 24, 2013 (incorporated by reference to Exhibit 10.29 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
10.51		Form of Warrant (to purchase subordinated units of Westmoreland Resource Partners, LP) executed as of March 12, 2014 to be effective as of June 24, 2013, issued to correct, clarify, supersede and replace in its entirety the Warrant (to purchase subordinated units of Westmoreland Resource Partners, LP) issued pursuant to the Warrant Issuance Agreement dated June 24, 2013 (incorporated by reference to Exhibit 10.29A to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended March 31, 2014 filed on May 6, 2014)
10.52		Form of Warrant (to purchase Class B Units of Westmoreland Resources GP, LLC) issued pursuant to the Warrant Issuance Agreement dated June 24, 2013 (incorporated by reference to Exhibit 10.30 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)

 

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Exhibit
10.53		Investors’ Rights Agreement, dated as of June 24, 2013, by and among Westmoreland Resource Partners, LP, Westmoreland Resources GP, LLC, AIM Oxford Holdings, LLC, and the lenders party to the Financing Agreement, dated as of June 24, 2013, by and among Oxford Mining Company, LLC, as borrower, Westmoreland Resource Partners, LP, as a guarantor, the other guarantors party thereto, such lenders, and Obsidian Agency Services, Inc., as collateral agent and administrative agent for such lenders (incorporated by reference to Exhibit 10.31 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2013 filed on August 6, 2013)
10.54		Mediation Settlement Agreement dated July 15, 2014 between Oxford Mining Company—Kentucky, LLC and Big Rivers Electric Corporation (incorporated by reference to Exhibit 10.32 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2014 filed on August 5, 2014)
10.55		Settlement Agreement effective July 15, 2014 between Oxford Mining Company—Kentucky, LLC and Big Rivers Electric Corporation, supplementing the Mediation Settlement Agreement dated July 15, 2014 between them (incorporated by reference to Exhibit 10.33 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2014 filed on August 5, 2014)
10.56		Contribution Agreement, dated as of October 16, 2014, between Westmoreland Resource Partners, LP and Westmoreland Coal Company (incorporated by reference to Annex B of the Preliminary Proxy Statement filed on October 24, 2014)
10.57		Membership Interests Redemption Agreement, effective as of October 1, 2014, among Oxford Mining Company, LLC, Harrison Resources, LLC and CONSOL of Ohio LLC (incorporated by reference to Exhibit 10.35 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended September 30, 2014 filed on October 30, 2014)
10.58		Financing Agreement, dated as of December 31, 2014, by and among Oxford Mining Company, LLC, Westmoreland Resource Partners, LP and each of its other subsidiaries, the lenders party thereto and U.S. Bank National Association (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8K filed on January 7, 2015)
16.1		Letter from Grant Thornton LLP to the Securities and Exchange Commission dated March 16, 2015 (incorporated by reference to Exhibit 16.1 to the Partnership’s Current Report on Form 8-K (Commission File No. 001-34815) filed on March 16, 2015)
21.1		List of Subsidiaries of Westmoreland Resource Partners, LP (incorporated by reference to Exhibit 21.1 to the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2014 (Commission File No. 001-34815) filed on March 6, 2015)
23.1*		Consent of Grant Thornton LLP
23.2*		Consent of Ernst & Young LLP
23.3*		Consent of John T. Boyd Company
23.4**		Consent of Holland & Hart LLP (included in Exhibit 5.1)
23.5**		Consent of Holland & Hart LLP (included in Exhibit 8.1)
24.1*		Powers of Attorney (included on the signature page)

 

*	Filed herewith.

**	To be filed by amendment.

 

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