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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

 

FORM 10-K

 

(Mark One)

☒    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the annual period ended: December 31, 2014

OR

☐    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from             to             

Commission file number: 333-173751

 

ALTA MESA HOLDINGS, LP

(Exact name of registrant as specified in its charter)

 

 

 

Registrant’s telephone number, including area code: 281-530-0991

Securities registered pursuant to Section 12(b) of the Act:

None

Securities registered pursuant to Section 12(g) of the Act:

None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities
Act:    ☐  Yes    ☒  No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act:    ☒  Yes    ☐  No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ☐    No  ☒ 

(Explanatory Note: The registrant is a voluntary filer and is not subject to the filing requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934.   However, the registrant has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant would have been required to file such reports) as if it were subject to such filing requirements.)

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files.)    Yes  ☒    No   ☐ 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (S229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ☒ 

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 definition of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one)

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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ◻ No ☒ 

 

 

 

TABLE OF CONTENTS

 

 

 

 

 

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could”, “should”, “will”, “play”, “believe”, “anticipate”, “intend”, “estimate”, “expect”, “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in this report. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.

Forward-looking statements may include statements about our:

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development and production of oil and natural gas. These risks include, but are not limited to, commodity price volatility, low prices for oil and/or natural gas, global economic conditions, inflation, increased operating costs, lack of availability of drilling and production equipment and services, environmental risks, weather risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating oil and natural gas reserves and in projecting future rates of production, reductions in cash flow, access to capital, and the other risks described under “Item 1A. Risk Factors” in this report.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas 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 reservoir engineers.  Specifically, future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates.  Prices for oil or natural gas at their current levels after the severe decline in the second half of 2014 are currently below the average calculated for 2014, and sustained lower prices will cause the twelve month weighted average price to decrease over time as the lower prices are reflected in the average price, which may reduce the estimated quantities and present values of our reserves. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.

Should one or more of the risks or uncertainties described in this report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we may issue.

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Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this report.

PART I

Item 1. Business

Our Company

Alta Mesa Holdings, LP (“Alta Mesa,” the “Company,” “us,” “our,” or “we”) is a privately held company engaged primarily in onshore oil and natural gas acquisition, exploitation, exploration and production whose focus is to maximize the profitability of our assets in a safe and environmentally sound manner. We seek to maintain a portfolio of assets in plays with known resources where we identify a large inventory of lower risk drilling, development, and enhanced recovery and exploitation opportunities. Our operations are located within the continental United States.  Our core properties are located in Oklahoma, Louisiana, and Texas. We believe there are decades of future development potential in our balanced portfolio of assets — principally historically prolific fields in the Sooner Trend in Oklahoma, the Weeks Island Complex fields in South Louisiana, and the Eagle Ford Shale in South Texas. We maximize the profitability of our assets by focusing on sound engineering, enhanced geological techniques including 3-D seismic analysis, and proven drilling, stimulation, completion, and production methods.

As of December 31, 2014, our estimated total proved oil and natural gas reserves were approximately 56.9 MMBOE, of which 52% were classified as proved developed reserves. Our proved reserve mix is approximately 55% oil, 30% natural gas, and 15% natural gas liquids.  Excluding our Eagle Ford Shale assets, we maintain operational control of the majority of our properties, either through directly operating them, or through operating arrangements with minority interest holders.

Our areas of focus are typically characterized by multiple hydrocarbon pay zones, and because in many cases we are re-developing fields and areas originally discovered and developed by major oil and natural gas companies and other independent producers, our assets are typically served by existing infrastructure. As a result, we believe that our business model lowers geological, mechanical, and market-related risks. We focus on properties within our core operating areas that we believe have significant development and exploration opportunities and where we can apply our technical experience and economies of scale to increase production and proved reserves while lowering lease operating and capital costs. Additionally, we have consistently created value through workovers and re-completions of existing wells, infill drilling, operations improvements, secondary recovery and 3-D seismic-driven drilling. We expect to continue production growth in our core areas by exploiting known resources with continued well workovers, development drilling, and disciplined exploration.

The success of our business is highly dependent on the price we receive for our oil, natural gas liquids and natural gas.  Beginning in the third quarter of 2014, the price for oil began a large decline, and current prices for oil are significantly less than they have been over the last several years.  These lower commodity prices have brought significant and immediate changes affecting our industry.  Low commodity prices affect our business in numerous ways, including:

 

 

In response to the lower oil and natural gas prices, we have taken a number of actions to conserve our liquidity, including:

 

We have reduced our capital expenditures and operating costs in response to recent decline in commodity prices, and our long term strategy remains intact.  While we cannot predict the length or depth of the current oil price decline, or the timing and extent of a potential price rebound, we have moved quickly and decisively regarding what we can control: our operating costs and the timing and levels of capital spending on projects we operate or control.

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For a more in-depth discussion of 2014 results, and our capital resources and liquidity, please see Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-K.

 

Overview of 2014

During 2014, we concentrated our efforts on developing our three core properties: Sooner Trend, Weeks Island Complex, and Eagleville in the Eagle Ford Shale play.  We continue to emphasize oil-rich reserves and production.  Highlights from 2014 include:

Recent Acquisitions and Divesture Activity

In March 2014, we sold a portion of our proved oil reserves, approximately 7.5 MMBOE, in our Eagleville field in South Texas.  The transaction provided us $171 million in cash, of which $169 million was used to reduce the outstanding borrowings under our revolving credit facility.  The sale was structured to provide us with continuing net revenues based on 50% of our original working interest in 2014, declining to 30% in 2015, 15% in 2016, and zero in 2017, and we will continue to develop additional Eagleville wells at 70% of our original working interest.  Total reserves we retained are estimated as 7.7 MMBOE, of which 67% were considered proved undeveloped based on classifications from our reserve report as of December 31, 2014.  This partial sale of our Eagleville assets provided us cash for investment in new areas without relinquishing our position in the Eagle Ford Shale, which we continue to view as a high-quality core property with years of development potential.

On August 7, 2014, we sold our interests in the Anne Parsons field for a cash payment of $9.2 million, which was subsequently adjusted to $8.6 million for customary settlement adjustments through December 31, 2014.  As of the date of sale, estimated proved reserves associated with these properties were 4.8 BCFE.  This East Texas field produced primarily natural gas and natural gas liquids.

On September 19, 2014, we sold our remaining interests in the Hilltop field for a cash payment of $41.6 million, which was subsequently adjusted to $38.9 million for customary settlement adjustments through December 31, 2014.  As of the date of sale, estimated proved reserves associated with these properties were 29.8 BCFE.  This East Texas field produced primarily dry gas. 

On December 31, 2014, we sold our interests in a partially constructed pipeline and gas processing plant at cost to Northwest Gas Processing, LLC (“NWGP”), an affiliate of our Class B partner, High Mesa, Inc. (“High Mesa”) and formerly named Alta Mesa Investment Holdings, Inc. (“AMIH”) for an aggregate of $34.0 million, which was comprised of $25.5 million in cash and $8.5 million in promissory note. Immediately after the consummation of the transaction, the $8.5 million promissory note was transferred from NWGP to High Mesa Services, LLC (“HMS”), a subsidiary of the Parent company High Mesa. We did not recognize any gain or loss on the sale as the midstream assets were sold at cost.  This transaction also relieved us from the capital expenditures that would have been required to complete the construction of the pipeline and facilities.  The $25.5 million was funded subsequent to year-end on January 2, 2015.

 

Outlook

As a result of the significant decline in oil prices and in order to preserve our liquidity, we have reduced our anticipated capital expenditures for 2015 to $148 million, as follows:

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Our Strategy

Our objective is to increase reserves and production by applying sound engineering and geological analyses, combined with safe and cost-effective operations, in areas we have identified as under-developed and over-looked.

Our Strengths

We believe that the following strengths provide us with significant competitive advantages and position us to continue to achieve our business objective and execute our strategies:

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Recent Partnership Changes

We are structured as a private partnership.  Since our inception, we have funded exploration, development and operating activities primarily through cash from operations, as well as capital raised from equity contributed by our founder, capital contributed by a private equity partner, borrowings under our bank credit facilities, and proceeds from the issuance of $450 million principal amount of senior secured notes.  From September 2006 until March 2014, our private equity partner was High Mesa,  an affiliate of Denham Commodity Partners Fund IV LP (“DCPF IV”) and Denham Capital Management LP (collectively with DCPF ICV, “Denham”), a private equity firm focused on energy and commodities.

On March 25, 2014, a syndicate led by Highbridge Principal Strategies LLC (“Highbridge”) invested in High Mesa and enabled High Mesa to complete a $350 million recapitalization.  Immediately following the recapitalization, High Mesa used a portion of the proceeds to redeem all of the shares of High Mesa held by Denham.  Highbridge received convertible PIK preferred stock in High Mesa and senior PIK notes from High Mesa and nominated one member to our Board of Directors. High Mesa remains our sole Class B Partner.

In connection with the recapitalization, Alta Mesa GP, our general partner, High Mesa, as holder of 100% of our Class B Units, and all of our Class A Limited Partners entered into a Second Amended and Restated Limited Partnership Agreement which provided for the contribution of 50% of the interest held by the Class A Limited Partners to High Mesa in exchange for common stock in High Mesa.  The Class A interests contributed to High Mesa were terminated.  The amended partnership agreement provides for certain drag-along rights, including the mandatory contribution to High Mesa by the Class A Limited Partners of their remaining Class A Units upon an initial public offering.  Immediately after closing the recapitalization, High Mesa also purchased all of the Class A Units held by Macquarie Bank Limited and RBS Equity Corporation.

The partnership agreement was further amended to provide that all distributions under the amended partnership agreement shall first be made to holders of Class B Units, until all principal and interest has been extinguished under the senior PIK notes issued by High Mesa to Highbridge.  After such extinguishment of the senior PIK notes, distributions shall then be made to holders of Class A and Class B Units pursuant to the distribution formulas set forth in the amended partnership agreement.

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Reserve and Production Overview

The following table describes our proved reserves and production profile as of December 31, 2014:

 

 

Our Properties

Sooner Trend, Oklahoma

Our assets in the Sooner Trend in Oklahoma are located in large mature oil fields with multiple pay zones at depths from less than 2,000 feet to 7,500 feet. These assets have historically been predominantly shallow-decline, long-lived oil fields originally drilled on 80-acre vertical well spacing and waterflooded to varying degrees.

Our activity in these fields is focused on horizontal drilling and multi-stage fracturing of the Meramec section of the Mississippian Lime and the Oswego Lime, as well as the definition of similar exploitation opportunities in the Woodford Shale, Hunton Lime, and other formations.  We also maintain production in the historically principal field pay zones that had been unitized for water flooding.  We continue to develop our waterflood opportunities, including the use of horizontal wells.  In 2014, we added production and reserves in the Mississippian Lime formation by drilling new horizontal wells.  We have applied the knowledge obtained by this effort to define our approach for 2015 and beyond to target the Mississippian Lime, the Oswego Lime, the Hunton Lime, and other zones with horizontal drilling and multi-stage hydraulic fracturing.

As of December 31, 2014, we had a 72% average working interest in 308 gross producing wells, and had identified 93 PUD locations in this area. We produced 1,734 MBOE net to us from our properties in Oklahoma in 2014.

During 2014 we spent approximately $142 million in Sooner Trend for the drilling and completion of wells, as well as other expenditures for facilities.  As of December 31, 2014, we had one drilling rig operating in Sooner Trend for horizontal development, which we plan to maintain during 2015 targeting the Mississippian Lime, Hunton Lime, and other zones with horizontal drilling.    We will also participate in other horizontal wells as a non-operator, primarily targeting the Oswego Lime, Meramec and Hunton Lime.    We have allocated approximately $84 million of our 2015 capital expenditure budget to our Sooner Trend properties.

 

Weeks Island Complex, South Louisiana

 

The Weeks Island Complex, located in Iberia and St. Mary Parish, Louisiana, contains some of our largest proved developed oil reserves and consists of the Weeks Island and Cote Blanche Island fields.    

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Weeks Island field, located in Iberia Parish, Louisiana, is a historically-prolific oil field with 55 potential pay zones that are structurally and stratigraphically trapped around a piercement salt dome, which we believe offer significant future opportunities for added production and reserves. The field was discovered in 1945 by Shell and Shell’s interest in the field was purchased in 1998 by The Meridian Resource Corporation, which we acquired in 2010. Since mid-2011 we have continuously employed at least one drilling rig and one completion rig in Weeks Island to exploit its potential for development through new drilling, recompletions, and sidetracking out of existing wells. We expect to continue development activity in this field in 2015.

We increased our ownership in this field in 2013 with an acquisition of approximately 1.8 MMBOE proved reserves from our former working interest partner, Stone Energy Offshore, L.L.C.  for cash consideration of approximately $45 million plus related abandonment costs, which was later modified through settlement adjustments to approximately $42 million cash.  As of December 31, 2014, we had a 97% average working interest in 46 gross producing wells, and had identified 11 PUD locations in this field.  

The Cote Blanche Island field, located in St. Mary Parish, was acquired by Alta Mesa with an effective date of July 1, 2014.  The field is a salt dome structure and production from the Miocene sands was discovered in 1948 by Texaco, three years after the discovery at Weeks Island. The geology is similar to Weeks Island and Alta Mesa plans on utilizing the same geologic interpretation methods and engineering development techniques at Cote Blanche that are used at Weeks Island to increase reserves and production.  The evaluation of this field is still in the early stages and we have already identified multiple drilling locations.  There are currently 5 producing wells and Alta Mesa owns a 100% working interest with an average revenue interest of 83%.    

As of December 31, 2014, we had a 96% average working interest in a total of 51 gross producing wells, and had identified 13 PUD locations in the Weeks Island Complex. We produced 1,837 MBOE net to us from the area in 2014.  We have allocated approximately $31 million of our 2015 capital expenditure budget to Weeks Island Complex and plan to utilize at least one workover rig in during 2015, as well as a drilling rig for a portion of the year.

 

South Texas Eagle Ford Shale

 

Our Eagleville field is located primarily in Karnes County, Texas and produces primarily from the Eagle Ford Shale. The Eagle Ford Shale is typically developed with horizontal wells. Since beginning development of the property in 2010, our assets have grown to 173 gross producing wells with an average working interest of 9%, six wells in which we have an overriding royalty interest, and four wells in progress as of December 31, 2014. The wells are primarily operated by Murphy Oil Corporation (“Murphy”), which has a multi-year development program. Production from the Eagleville field in 2014 was 1,010 MBOE net to us.

 

We sold a significant portion of our Eagleville reserves in March 2014, including a portion of our interest in all wells that were producing as of December 31, 2013.  The cash purchase price was initially $173 million, and was subsequently adjusted to approximately $171 million for settlement adjustments through December 31, 2014.  The sale has an effective date of January 1, 2014.  We retained a declining net profits interest in the producing wells based on 50% of our original working interest in 2014, 30% in 2015, 15% in 2016, and zero in 2017.  Also included in the sale was a  30% undivided interest in all our Eagleville mineral leases and interests, and 30% of our working interest in all our wells in progress on December 31, 2013 or drilled after January 1, 2014.  As of year-end 2014, we had an estimated 109 PUD drilling locations, of which 16 are in wells in which we will have an overriding royalty interest rather than a working interest.

 

We estimate the proved developed and undeveloped reserves sold were approximately 7.5 MMBOE, and we retained proved reserves of approximately 7.7 MMBOE, 67%  of which were proved undeveloped as of December 31, 2014.

 

We have allocated approximately $7 million of our 2015 capital expenditure budget to Eagleville.  As of December 31, 2014, Murphy was continuously operating one drilling rig on our acreage.

Other Assets

We conduct operations in other areas, including Urbana, Cold Springs and Cold Springs West in East Texas, Blackjack Creek oil field in Florida, and other fields in South Texas and South Louisiana.  We continually evaluate the operations in these areas to determine future development, expansion, acquisition opportunities, and strategic divestiture plans.  Inventories of prospective and partially developed acreage include holdings in South Texas, South Louisiana, West Virginia, and other areas.  Total impairment expense from these other areas was $74.9 million and $143.2 million in 2014 and 2013 respectively, with the largest single item in 2014 being $31.7 million for fields in South Louisiana.  We have allocated approximately $26 million of our 2015 capital expenditure budget to these properties.

Our Oil and Natural Gas Reserves

The table below summarizes our estimated net proved reserves as of December 31, 2014:

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The table above represents estimates only. Reserves estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Furthermore, different reserve engineers may make different estimates of reserves and cash flow based on the same available data and these differences may be significant. Therefore, these estimates are not precise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from those estimated. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.  Prices for oil or natural gas at their current levels after the significant decline in prices in the second half of 2014 are currently below the average calculated for 2014.  Sustained lower prices will cause the unweighted arithmetic average to decrease over time as the lower prices are reflected in the average price, which may result in the estimated quantities and present values of our reserves being reduced and may necessitate future write-downs. 

Internal Controls Over Reserve Estimates and Qualifications of Technical Persons

Our policies and practices regarding internal controls over the recording of reserves is structured to objectively and accurately estimate our oil and gas reserves quantities and present values in compliance with rules, regulations and guidance provided by the SEC, as well as established industry practices used by independent engineering firms and our peers, and in accordance the SPE 2007 Standards promulgated by the Society of Petroleum Engineers.  The reserve estimation process begins with our Corporate Planning and Reserves department, which gathers and analyzes much of the data used in estimating reserves. Working and net revenue interests are cross-checked and verified by our land department.  Lease operating and capital expenses are provided by our accounting department and reviewed by the Corporate Planning and Reserves department.  Our Vice President of Corporate Planning and Reserves is the technical person primarily responsible for overseeing the preparation of our reserve estimates. His qualifications include the following:

Our methodologies include reviews of production trends, material balance calculations, analogy to comparable properties, and/or volumetric analysis. Performance methods are preferred. Reserve estimates for developed non-producing properties and for undeveloped properties are based primarily on volumetric analysis or analogy to offset production in the same or similar fields.

We maintain internal controls including the following to ensure the reliability of reserves estimations:

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In addition, a third-party engineering firm, Ryder Scott Company, L. P. (“Ryder Scott”), audited 85% of our 2014 proved reserves and 91% of our estimated PV-10.

A copy of the audit letter issued by Ryder Scott is filed with this report as Exhibit 99.1. The qualifications of the technical person at Ryder Scott primarily responsible for overseeing the audit of our reserve estimates are set forth below.

Kevin Gangluff earned a B.S. in Chemical Engineering at the University of Notre Dame and a Masters of Business Administration at the University of Texas at Austin.  Mr. Gangluff is a licensed Professional Engineer in the State of Texas. Based on his educational background, professional training and more than thirty years of practical experience in the estimation and evaluation of petroleum reserves and resources, Mr. Gangluff has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

The audit by Ryder Scott conformed to the meaning of “reserves audit” as presented in the SEC’s Regulation S-K, Item 1202.

A reserves audit and a financial audit are separate activities with unique and different processes and results. These two activities should not be confused. As currently defined by the SEC within Regulation S-K, Item 1202, a reserves audit is the process of reviewing certain of the pertinent facts interpreted and assumptions underlying a reserves estimate prepared by another party and the rendering of an opinion about the appropriateness of the methodologies employed, the adequacy and quality of the data relied upon, the depth and thoroughness of the reserves estimation process, the classification of reserves appropriate to the relevant definitions used, and the reasonableness of the estimated reserves quantities. A financial audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. A financial audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

Proved Undeveloped Reserves

At December 31, 2014, we had proved undeveloped reserves (“PUDs”) of 27.2 MMBOE, or approximately 48% of total proved reserves. The PUDs are primarily in our Eagleville field in the Eagle Ford play in South Texas, in Weeks Island Complex, and in Sooner Trend.

Total PUDs at December 31, 2013 were 25.4 MMBOE, or 42% of our total proved reserves.  The following table reflects the changes in PUDs during 2014: 

 

PUDs converted to proved developed reserves were primarily in the Eagleville Field.  Total expenditures for the PUDs converted to proved developed reserves were approximately $90.7 million.  Extensions and discoveries were primarily in our Sooner Trend, Eagleville, and Weeks Island Complex fields.  PUD acquisitions include interests in Weeks Island Complex fields and PUD reserves sold were from dispositions in Eagleville, Anne Parsons and Hilltop fields.  Negative revisions were primarily associated with our non-core properties in the Blackjack Creek field in Florida. These reserves were moved out of the PUD reserve category in compliance with the SEC five year rule.  Estimated future development costs, including plugged and abandonment cost (“P&A”),  for PUDs remaining are approximately $349 million at December 31, 2014.

Under current SEC requirements, PUD reserves may only be booked if they relate to wells scheduled to be drilled within five years of the original date of booking unless specific circumstances justify a longer time.  We will be required to remove our PUDs if we do not drill those reserves within the required five year time frame, unless specific circumstances justify a longer time.  All of our PUDs at December 31, 2014 are scheduled to be drilled within five years of the date they were initially recorded except for one sidetrack development in a producing well which will be drilled after the current zones are depleted.    Lower prices for oil and natural gas as seen in the recent decline may cause us in the future to forecast less capital to be available for development of our PUDs, which may cause us to decrease the amount of our PUDs we expect to develop within the five year time frame.  In addition, lower oil and

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natural gas prices may cause our PUDs to become uneconomic to develop, which would cause us to remove them from the proved undeveloped category. 

   

Production, Prices and Production Cost History

The following table sets forth certain information regarding the production volumes, average prices received and average production costs associated with our sale of oil, natural gas, and natural gas liquids for the periods indicated below.  The data below include the effects of the amounts we reclassified from natural gas volumes and revenues to natural gas liquids volumes and revenues for the years 2013 and 2012.  See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Results of Operations: Year Ended December 31, 2013 v. Year Ended December 31, 2012,  Natural gas liquids revenues for more detailed information.

 

 

 

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The following table provides a summary of our production, average sales prices and average production costs for the Sooner Trend area, which contributes approximately 50% of our total proved reserves as of December 31, 2014.  The largest field in Sooner Trend contributes 15% or more of our total proved reserves as of December 31, 2014. 

 

 

 

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates.  Prices for oil or natural gas at their current levels after the severe decline in 2014 are currently below the average calculated for 2014, and sustained lower prices will cause the twelve month weighted average price to decrease over time as the lower prices are reflected in the average price.

 

Delivery Commitments

As of December 31, 2014, we had no commitments to provide a fixed quantity of oil or natural gas.

Drilling Activity

The following table sets forth, for each of the three years ended December 31, 2014, 2013 and 2012, the number of net productive and dry exploratory and developmental wells completed, regardless of when drilling was initiated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value.

 

 

 

As of December 31, 2014, we were drilling 39 gross (21.7 net) wells.

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Productive Wells

The following table sets forth information with respect to our ownership interest in productive wells as of December 31, 2014:

 

 

Of the total well count for 2014, 7 gross wells (6.99 net) are multiple completions.     

Productive wells are producing wells, shut-in wells we deem capable of production, wells that are waiting for completion, plus wells that are drilled/cased and completed, but waiting for pipeline hook-up.  A gross well is a well in which a working interest is owned.  The number of net wells represents the sum of fractional working interests the company owns in gross wells.

Developed and Undeveloped Acreage Position

The following table sets forth information with respect to our gross and net developed and undeveloped oil and natural gas acreage under lease as of December 31, 2014, all of which is located in the United States:

 

 

As is customary in the oil and natural gas industry, we can generally retain an interest in undeveloped acreage through drilling activity that establishes commercial production sufficient to maintain the leases or by paying delay rentals during the remaining primary term of leases. The oil and natural gas leases in which we have an interest are for varying primary terms and, if production under a lease continues from developed lease acreage beyond the primary term, we are entitled to hold the lease for as long as oil or natural gas is produced. The oil and natural gas properties consist primarily of oil and natural gas wells and interests in leasehold acreage, both developed and undeveloped.

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Undeveloped Acreage Expirations

The following table sets forth information with respect to our gross and net undeveloped oil and natural gas acreage under lease as of December 31, 2014, all of which is located in the United States, that will expire over the following three years by core area unless production is established within the spacing units covering the acreage prior to the expiration dates:

 

 

Marketing and Customers

The market for our oil and natural gas production depends on factors beyond our control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, the demand for oil and natural gas, the marketing of competitive fuels and the effect of state and federal regulation. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

We sell the oil and natural gas from several properties we operate primarily under a contract with ARM Energy Management, LLC (“AEM”).  We are part owner of AEM at less than 10%.  AEM purchases our oil and natural gas and sells it under short-term contracts generally with month-to-month pricing based on published regional indices, with differentials for transportation, location, and quality taken into account.  AEM remits monthly proceeds of its sales to us, and receives a 1% marketing fee.   Sales to AEM commenced in June 2013.  The agreement will terminate in 2018, with additional provisions for extensions beyond five years, and for early termination beginning in January 2015.  During the second half of 2013, we sold the majority of our production from operated fields to AEM.  Production from non-operated fields, the most significant of which were our Eagleville field in South Texas and our Hilltop field in East Texas, was marketed on our behalf by the operators of those properties.  Production from Eagleville is sold by the operator, Murphy.  Production from Hilltop sold was primarily by the operator of the majority of our wells in the field, EnCana.

Natural gas liquids are sold under various contracts with processors typically in the vicinity of the production at spot market rates, after processing costs.

For the year ended December 31, 2014, revenues from AEM were $220.9 million, or 51.1% of total revenue excluding hedging activities.  Based on revenues excluding hedging activities, one other major customer, Murphy accounted for 10% or more of our revenues, with revenues excluding hedging activities of $61.2 million.

 We believe that the loss of any of our significant direct or indirect customers, or of AEM, would not have a material adverse effect on us because alternative purchasers are readily available.  Trade accounts receivable are not collateralized or otherwise secured.

Competition

We encounter intense competition from other oil and natural gas companies in all areas of our operations, including the acquisition of producing properties and undeveloped acreage. Our competitors include major integrated oil and natural gas companies, numerous independent oil and natural gas companies and individuals. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources and have been engaged in the oil and natural gas business for a much longer time than us. These companies may be able to pay more for productive oil and natural gas properties, exploratory prospects, and mineral leases and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Larger competitors may be able to absorb the decline in prices for oil and natural gas and the burden of any changes in federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.

We are also affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which have delayed development, exploitation and

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exploration activities. We are unable to predict when, or if, such shortages may occur or how they would affect our exploitation and development program.

We compete for capital in the domestic financial marketplace to fund our exploration and development activities to the extent our operations cannot support them at any given time. See Item 1A, Risk Factors, “Our exploration, exploitation, development and acquisition operations will require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.”

Title to Properties

As is customary in our industry, a preliminary review of title records, which may include opinions or reports of appropriate professionals or counsel, is made at the time we acquire properties. We believe that our title to all of the various interests set forth above is satisfactory and consistent with the standards generally accepted in the oil and gas industry, subject only to immaterial exceptions that do not detract substantially from the value of the interests or materially interfere with their use in our operations. The interests owned by us may be subject to one or more royalty, overriding royalty, or other outstanding interests (including disputes related to such interests) customary in the industry. The interests may additionally be subject to obligations or duties under applicable laws, ordinances, rules, regulations, and orders of arbitral or governmental authorities. In addition, the interests may be subject to burdens such as net profits interests, liens incident to operating agreements and current taxes, development obligations under oil and gas leases, and other encumbrances, easements, and restrictions, none of which detract substantially from the value of the interests or materially interfere with their use in our operations.

Employees

As of December 31, 2014, we had 225 full-time employees. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We believe our relationships with our employees are good. From time to time, we utilize the services of independent contractors to perform various field and other services. See “Item 13. Certain Relationships and Related Party Transactions, and Director Independence.”

Insurance

In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We currently have insurance policies that include coverage for general liability (includes sudden and accidental pollution), physical damage to our oil and gas properties, control of well, auto liability, marine liability, worker’s compensation and employer’s liability, among other things.

Currently, we have general liability insurance coverage up to $1 million per occurrence, which includes sudden and accidental environmental liability coverage for the effects of pollution on third parties arising from our operations. Our insurance policies contain maximum policy limits and in most cases, deductibles (generally ranging from $25,000 to $1.8 million) that must be met prior to recovery. These insurance policies are subject to certain customary exclusions and limitations. In addition, we maintain excess liability coverage, which is in addition to and triggered if the general liability per occurrence limit is reached.

Our offshore activities are limited to non-operator positions in five older fields acquired in 2010. Our offshore reserves are not a significant portion of our total reserves; the fields are in declining production with no drilling activity. Our consolidated balance sheets include asset retirement liabilities which we believe are sufficient to cover the eventual costs of dismantlement and abandonment. We believe that due to the nature of the operations in these fields, and the limited activity, the risk of environmental damage is not as high as it would be in an actively drilling offshore field. Our insurance program includes property damage, pollution liability, and control of well. The property damage coverage extends to total loss of the equipment (not the reserves) with replacement cost coverage retained on one of the five fields. The pollution coverage, which is applicable to both offshore and onshore events, is $10 million per incident with a $100,000 deductible.

We require all of our third-party contractors, including those that perform hydraulic fracturing operations, to sign master service agreements in which they agree to indemnify us for injuries and deaths of the service provider’s employees as well as contractors and subcontractors hired by the service provider. Similarly, we generally agree to indemnify each third-party contractor against claims made by our employees and other contractors. Additionally, each party generally is responsible for damage to its own property. We do not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations.

We re-evaluate the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. No assurance can be given that we will be

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able to maintain insurance in the future at rates that we consider reasonable and we may elect to self-insure or maintain only catastrophic coverage for certain risks in the future.

Environmental Matters and Regulation

Our operations are subject to stringent and complex federal, state and local laws, rules, and regulations that govern the protection of the environment, as well as the discharge of materials into the environment. These laws, rules, and regulations may, among other things:

These laws, rules, and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal, state and local agencies frequently revise environmental laws and regulations, and such changes could result in increased costs for environmental compliance, such as waste handling, permitting, or cleanup for the oil and natural gas industry and could have a significant impact on our operating costs. In general, the oil and natural gas industry recently has been the subject of increased legislative and regulatory attention with respect to environmental matters.  For example, the EPA has identified environmental compliance by the energy extraction sector as one of its enforcement initiatives for 2014-2016.

The following is a summary of some of the existing laws, rules, and regulations to which our business operations are subject.

Solid and Hazardous Waste Handling

The federal Resource Conservation and Recovery Act and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous solid waste. Although oil and natural gas waste generally is exempt from regulations as hazardous waste under RCRA, we generate waste as a routine part of our operations that may be subject to RCRA and not all states similarly exempt oil and gas waste from hazardous waste regulation. Although a substantial amount of the waste generated in our operations is regulated as non-hazardous solid waste rather than hazardous waste, there is no guarantee that the EPA or individual states will not adopt more stringent requirements for the handling of non-hazardous waste or categorize some of our waste as hazardous in the future. Any such change could result in an increase in our costs to manage and dispose of waste, which could have a material adverse effect on our results of operations and financial position.

Comprehensive Environmental Response, Compensation, and Liability Act

CERCLA imposes joint and several liability for costs of investigation and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances (“Hazardous Substances”). These classes of persons, or so-called potentially responsible parties (“PRPs”) include the current and past owners or operators of a site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance found at a site where a release has occurred. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes.

Although CERCLA generally exempts “petroleum” from the definition of Hazardous Substance, in the course of our operations, we have generated and will generate wastes that may fall within CERCLA’s definition of Hazardous Substances and may have disposed of these wastes at disposal sites owned and operated by others. Comparable state statutes may not provide a comparable

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exemption for petroleum. We may also be the owner or operator of sites on which Hazardous Substances have been released. To our knowledge, neither we nor our predecessors have been designated as a PRP by the EPA under CERCLA; we also do not know of any prior owners or operators of our properties that are named as PRPs related to their ownership or operation of such properties. In the event contamination is discovered at a site on which we are or have been an owner or operator or to which we sent Hazardous Substances, we could be liable for the costs of investigation and remediation and natural resources damages.

We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, Hazardous Substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including offsite locations, where such materials have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of Hazardous Substances, wastes, or hydrocarbons were not under our control. These properties and the materials disposed or released on them may be subject to CERCLA or RCRA and analogous state laws. In the future, we could be required to remediate property, including groundwater, containing or impacted by previously disposed materials (including wastes disposed or released by prior owners or operators, or property contamination, including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination.

Clean Water Act

The Federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including discharges, spills and leaks of produced water and other oil and natural gas wastes, into waters of the United States, a term broadly defined. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures, for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In the event of an unauthorized discharge of wastes, we may be liable for penalties and cleanup and response costs.

Oil Pollution Act

The primary federal law related to oil spill liability is the Oil Pollution Act which amends and augments oil spill provisions of the Clean Water Act and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. A liable “responsible party” includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge, or in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist to the liability imposed by OPA, they are limited. In the event of an oil discharge or substantial threat of discharge, we may be liable for costs and damages.

Safe Drinking Water Act and Hydraulic Fracturing

Many of our development projects require hydraulic fracturing procedures to economically develop the formations. Generally, we perform two types of hydraulic fracturing. In our Sooner Trend, and Eagle Ford Shale (Eagleville Field, South Texas) plays, we perform hydraulic fracturing in horizontally drilled wells. These procedures are more extensive, time-consuming and expensive than hydraulic fracturing of vertical wells. We also perform hydraulic fracturing in vertical wells in our East Texas and South Texas fields, including primarily Urbana and Cold Springs (both in East Texas); among the target zones are the Wilcox and Frio formations.

Currently, most hydraulic fracturing activities are regulated at the state level, as the Safe Drinking Water Act exempts most hydraulic fracturing (except for hydraulic fracturing activities involving the use of diesel) from the definition of underground injection. The EPA had released guidance on permitting of hydraulic fracturing activities using diesel. Congress has periodically considered legislation to amend the federal SDWA to remove the exemption from permitting and regulation provided to injection for hydraulic fracturing and to require the disclosure and reporting of the chemicals used in hydraulic fracturing. This type of legislation if adopted could lead to additional regulation and permitting requirements that could result in operational delays or increased operating costs, making it more difficult to perform hydraulic fracturing and increasing our costs of compliance and operation.

The EPA has commenced a wide-ranging study on the effects of hydraulic fracturing on drinking water resources. A first progress report of the study was issued in December 2012, with a final draft expected in 2015. 

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As noted above, the EPA has announced that one of its enforcement initiatives for 2014 to 2016 would be to focus on environmental compliance by the energy extraction sector. This study and enforcement initiative could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. Consequently, these studies and initiatives could spur further legislative or regulatory action regarding hydraulic fracturing or similar production operations.

Many states and other regional and local regulatory authorities have enacted or are considering regulations on hydraulic fracturing, including disclosure requirements and regulations that could restrict or prohibit drilling in general or hydraulic fracturing in particular, in certain circumstances. Some states have also considered or adopted other restrictions or regulations on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; restrictions on access to, and usage of, water; and restrictions on the type of chemical additives that may be used in hydraulic fracturing operations.  In compliance with the law enacted in Texas, we have disclosed and will continue to disclose hydraulic fracturing data. Further, the Bureau of Land Management has adopted final rules regulating hydraulic fracturing on public lands.  These rules include requirements on drillers to disclose the chemicals used in hydraulic fracturing operations and new requirements for well casing, groundwater protections, and wastewater storage.  We are currently evaluating the impact of these rules on our operations.  The EPA has also announced an initiative under the Toxic Substance Control Act to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals and has announced that it is working on regulations for wastewater generated by hydraulic fracturing.

We diligently review best practices and industry standards, and comply with all regulatory requirements in the protection of potable water sources. Protective practices include, but are not limited to, setting multiple strings of protection pipe across the potable water sources and cementing these pipes from setting depth to surface, continuously monitoring the hydraulic fracturing process in real time, and disposing of all non-commercially produced fluids in certified disposal wells at depths below the potable water sources. There have not been any incidents, citations or suits related to our hydraulic fracturing activities involving environmental concerns.

If new legislation is enacted or other new requirements or restrictions regarding hydraulic fracturing are adopted, we could incur substantial compliance costs and the requirements could negatively impact our ability to conduct fracturing activities on our assets.

National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands (including offshore leasing) may be subject to the National Environmental Policy Act (the “NEPA”), which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. As a result of the events in the Gulf of Mexico, the NEPA process is being reviewed and may become more stringent. This process has the potential to delay or impose additional conditions and costs upon the development of oil and natural gas projects.

Air Emissions

Our operations are subject to local, state and federal regulations for the control of emissions from sources of air pollution. Federal and state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permits. Federal and state laws designed to control hazardous air pollutants might require installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could bring lawsuits for civil penalties or require us to forego construction, modification or operation of certain air emission sources.

On April 17, 2012, the EPA issued final rules that subject oil and natural gas production, processing, transmission, and storage operations to regulation under the NSPS and NESHAP programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Before January 1, 2015, these standards require owners/operators to reduce VOC emissions from natural gas not sent to the gathering line during well completion either by flaring using a completion combustion device or by capturing the natural gas using green completions. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale. The standards are applicable to newly fractured wells and also existing wells that are refractured. Further, the finalized regulations also establish specific new requirements for emission from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and other equipment. These rules may require changes to our operations, including the installation of

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new equipment to control emissions. We have evaluated the effect these rules will have on our business and are taking steps to ensure compliance.

Climate Change Regulation and Legislation

More stringent laws and regulations relating to climate change and greenhouse gases (“GHGs”) may be adopted in the future and could cause us to incur material expenses in complying with them. Both houses of Congress have actively considered legislation to reduce emissions of GHGs, but no legislation has yet passed.  In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions; although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants.  The EPA recently announced its intention to take measures to require or encourage reductions in methane emissions, including from oil and natural gas operations.  Those measures include the development of NSPS regulations in 2016 for reducing methane from new and modified oil and gas production sources and natural gas processing and transmission sources.

In addition, the EPA has adopted a mandatory GHG emissions reporting program that imposes reporting and monitoring requirements on various types of facilities and industries. In November 2010, the EPA expanded its GHG reporting rule to include onshore and offshore oil and natural gas production, processing, transmission, storage, and distribution facilities, requiring reporting of GHG emissions from such facilities on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. Our operations are subject to GHG reporting requirements, and we have complied with respect to the initial reporting year 2011 and continue to comply.

Because of the lack of any comprehensive legislative program addressing GHGs, there is a great deal of uncertainty as to how and when federal regulation of GHGs might take place. Some members of Congress have expressed the intention to promote legislation to curb the EPA’s authority to regulate GHGs. In addition to possible federal regulation, a number of states, individually and regionally, also are considering or have implemented GHG regulatory programs. These potential regional and state initiatives may result in so-called cap and trade programs, under which overall GHG emissions are limited and GHG emissions are then allocated and sold, and possibly other regulatory requirements, that could result in our incurring material expenses to comply, e.g., by being required to purchase or to surrender allowances for GHGs resulting from our operations. The federal, regional and local regulatory initiatives also could adversely affect the marketability of the oil and natural gas we produce. The impact of such future programs cannot be predicted, but we do not expect our operations to be affected any differently than other similarly situated domestic competitors.

Other Laws and Regulations

Our operations are also subject to regulations governing the handling, transportation, storage and disposal of naturally occurring radioactive materials. Furthermore, owners, lessees and operators of natural gas and oil properties are also subject to increasing civil liability brought by surface owners and adjoining property owners. Such claims are predicated on the damage to or contamination of land resources occasioned by drilling and production operations and the products derived therefrom, and are often based on negligence, trespass, nuisance, strict liability or fraud.

The Endangered Species Act was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities that would harm the species or that would adversely affect that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service designates the species’ protected habitat as part of the effort to protect the species. A protected habitat designation or the mere presence of threatened or endangered species could result in material restrictions to our use of the land and may materially delay or prohibit land access for our development.  We cannot guarantee that the U.S. Fish and Wildlife Service will not list additional species or additional habitat, which could adversely affect our ability to develop in impacted areas.

OSHA and Other Laws and Regulation

To the extent not preempted by other applicable laws, we are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes, where applicable. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements.

We believe that we are in substantial compliance with all existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. We did not incur any material capital expenditures for remediation or pollution control activities

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for the years ended December 31, 2014, 2013 and 2012. Additionally, we are not aware of any environmental issues or claims that will require material capital expenditures during 2014 or that will otherwise have a material impact on our financial position or results of operations in the future. However, we cannot provide assurance that the passage of more stringent laws and regulations in the future will not have a negative impact our business activities, financial condition or results of operations.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Drilling and Production

Our operations are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states and some counties and municipalities in which we operate also regulate one or more of the following:

State laws regulate the size and shape of drilling and spacing units or proration units and govern the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally limit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction and an ad valorem tax with respect to the assessed value of the oil and natural gas mineral property.

In addition, eleven states have enacted surface damage statutes (“SDAs”). These laws are designed to compensate the surface owners/users for damage caused by mineral development. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain bonding requirements and specific expenses for exploration and producing activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs.

We do not control the availability of transportation and processing facilities used in the marketing of our production. For example, we may have to shut-in a productive natural gas well because of a lack of available natural gas gathering or transportation facilities.

If we conduct operations on federal, state or Indian oil and natural gas leases, these operations must comply with numerous regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Bureau of Land Management, the Bureau of Ocean Energy Management or other appropriate federal or state agencies.

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Federal Regulation of Natural Gas, Oil and Natural Gas Regulation

The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas are subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. FERC’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas. FERC regulates the rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines under the Natural Gas Act as well as under Section 311 of the Natural Gas Policy Act. Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, nondiscriminatory basis.

The Company’s sales of oil and natural gas liquids are also affected by the availability, terms and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil and natural gas liquids by pipelines are regulated by the FERC under the Interstate Commerce Act. The FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil and natural gas liquids pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil and natural gas liquids pipeline rates.

 

The pipelines used to gather and transport natural gas being produced by the Company are also subject to regulation by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), the Pipeline Safety Act of 1992, as reauthorized and amended (“Pipeline Safety Act”), and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. In August 2011, the PHMSA issued an Advance Notice of Proposed Rulemaking regarding pipeline safety, including questions regarding the modification of regulations applicable to gathering lines in rural areas.

 

As an alternative to pipeline transportation, any transportation of the Company’s crude oil, natural gas liquids and purity components (ethane, propane, butane, iso-butane, and natural gasoline) by rail will also be subject to regulation by the DOT’s PHMSA and the DOT’s Federal Railroad Administration (“FRA”) under the Hazardous Materials Regulations at 49 CFR Parts 171-180 (“HMR”), including Emergency Orders by the FRA and new regulations being proposed by the PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids.

Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties. Sales of oil, condensate, and natural gas liquids are not currently regulated and are made at market prices.

State Natural Gas Regulation

Various states regulate the drilling for, and the production, gathering, intrastate transportation and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.

Other Regulation

In addition to the regulation of oil and natural gas pipeline transportation rates, the oil and natural gas industry generally is subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity.

General Corporate Information

Alta Mesa Holdings, LP is a Texas limited partnership founded in 1987 with principal offices at 15021 Katy Freeway, Suite 400, Houston, Texas 77094. We can be reached at (281) 530-0991 and our website address is www.altamesa.net. Information on the website is not part of this report.

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Item 1A. Risk Factors

Each of the following risk factors could adversely affect our business, operating results and financial condition. It is not possible to foresee or identify all such factors. Investors should not consider this list an exhaustive statement of all risks and uncertainties. This report also contains forward-looking statements that involve risks and uncertainties. Our actual results may differ from those anticipated in these forward-looking statements as a result of both the risks described below and factors described elsewhere in this report. Please read the section above entitled “Cautionary Statement Regarding Forward-Looking Statements” for further discussion of these matters.

Our exploration, exploitation, development and acquisition operations will require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.

The oil and natural gas industry is capital intensive. We have made and expect to continue to make substantial capital expenditures in our business for the exploration, exploitation, development and acquisition of oil and natural gas reserves. Our capital expenditures for 2014 totaled $411 million including $18 million for acquisitions. As a result of the recent significant decline in oil prices and in order to preserve our liquidity, we have reduced our budgeted capital expenditures for 2015 to approximately $148 million. We have funded development and operating activities primarily through equity capital raised from a private equity partner, through borrowings under our bank credit facilities, through the issuance of our senior notes, and through internal operating cash flows. We intend to finance our future capital expenditures predominantly with cash flows from operations. If necessary, we may also access capital through proceeds from potential asset dispositions, borrowings under our senior secured revolving credit facility and the future issuance of debt and/or equity securities. Our cash flow from operations and access to capital are subject to a number of variables, including:

If our revenues or the borrowing base under our senior secured revolving credit facility decrease as a result of lower commodity prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to conduct our operations at expected levels. Our senior secured revolving credit facility may restrict our ability to obtain new debt financing. If additional capital is required, we may not be able to obtain debt and/or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our senior secured revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, results of operation, financial conditions and ability to make payments on our outstanding indebtedness.

External financing may be required in the future to fund our growth. We may not be able to obtain additional financing, and financing under our senior secured revolving credit facility may not be available in the future. Without additional capital resources, we may be unable to pursue and consummate acquisition opportunities as they become available, and we may be forced to limit or defer our planned oil and natural gas development program, which will adversely affect the recoverability and ultimate value of our oil and natural gas properties, in turn negatively affecting our business, financial condition and results of operations.

Oil and natural gas prices are highly volatile and continued depressed prices can significantly affect our financial condition and results of operations.

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Our revenue, profitability and cash flow depend upon the prices for oil and natural gas. The prices we receive for oil and natural gas production are volatile and a decrease in prices can significantly affect our financial results and impede our growth, including our ability to maintain or increase our borrowing capacity, to repay current or future indebtedness and to obtain additional capital on attractive terms. Changes in oil and natural gas prices have a significant impact on the value of our reserves and on our cash flows.

Historically, world-wide oil and natural gas prices and markets have been subject to significant change, and may continue to be in the future. In particular, the prices of oil and natural gas declined dramatically in the second half of 2014.  For example, during 2014, based on daily settlements of monthly contracts traded on the NYMEX, the price for a barrel (bbl) of oil ranged from a high of $105.15 for the June 2014 contract to a low of $59.29 for the December 2014 contract and the price for an Mmbtu of natural gas ranged from a high of $5.56 for the February 2014 contract to a low of $3.73 for November 2014 contract.

Continued depressed oil and natural gas prices, further price declines or any other unfavorable market conditions could have a material adverse effect on our financial condition and on the carrying value of our proved reserves.  The average realized price, excluding hedge settlements, at which we sold oil in 2014 was $92.27 per barrel compared to $102.81 per barrel in 2013, and $103.72 per barrel in 2012. Because the oil price we are required to use to estimate our future net cash flows is the average price over the twelve months prior to the date of determination of future net cash flows, the full effect of falling prices may not be reflected in our estimated net cash flows for several quarters.  We review the carrying value of our properties on a quarterly basis and once incurred, a write-down in the carrying value of our properties is not reversible at a later date, even if prices increase.

Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, such as:

Substantially all of our production is sold to purchasers under contracts with market-based prices. Continued lower oil and natural gas prices will reduce our cash flows and may reduce the present value of our reserves. If oil and natural gas prices remain at current levels, we anticipate that the borrowing base under our senior secured revolving credit facility, which is revised periodically, may be reduced, which would negatively impact our borrowing ability. Additionally, prices could reduce our cash flows to a level that would require us to borrow to fund our 2015 capital budget. Lower oil and natural gas prices may also reduce the amount of oil and natural gas that we can produce economically. Substantial decreases in oil and natural gas prices could render uneconomic a significant portion of our identified drilling locations. This may result in significant downward adjustments to our estimated proved reserves. As a result, a substantial or extended decline in oil and natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

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Lower oil and natural gas prices may cause us to record non-cash write-downs, which could negatively impact our results of operations.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics, and other factors, we may be required to write down the carrying value of our properties. A write-down constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.

We will depend on successful exploration, exploitation, development and acquisitions to maintain reserves and revenue in the future.

In general, the volume of production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on each reservoir’s characteristics. Except to the extent that we conduct successful exploration and development activities or acquire properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. Our future oil and natural gas production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. Additionally, the business of exploring for, developing, or acquiring reserves is capital intensive. Recovery of our reserves, particularly undeveloped reserves, will require significant additional capital expenditures and successful drilling operations. To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of oil and natural gas reserves would be impaired. In addition, we are dependent on finding partners for our exploratory activity. To the extent that others in the industry do not have the financial resources or choose not to participate in our exploration activities, we may be adversely affected.

Our estimated proved oil and natural gas reserve quantities and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.

Numerous uncertainties are inherent in estimating quantities of oil and natural gas reserves. Our estimates of our proved reserve quantities are based upon our estimated net proved reserves as of December 31, 2014. The process of estimating oil and natural gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir, and these reports rely upon various assumptions, including assumptions regarding future oil and natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling and production. Any significant variance in our assumptions and actual results could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. Specifically, future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates.  Prices for oil or natural gas at their current levels after the significant decline in the third quarter of 2014 are currently below the average calculated for 2014, and sustained lower prices will cause the twelve month weighted average price to decrease over time as the lower prices are reflected in the average price, which may result in the estimated quantities and present values of our reserves being reduced. 

The Standardized Measure of discounted future net cash flows from our proved reserves or “PV-10” will not necessarily be the same as the current market value of our estimated proved oil and natural gas reserves.

It should not be assumed that the Standardized Measure of future net cash flows from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we based the estimated discounted future net cash flows from our proved reserves on the twelve-month unweighted arithmetic average of the closing prices on the first day of each month for the preceding twelve months from the date of the report without giving effect to derivative transactions.  Actual future net cash flows from our oil and natural gas properties will be affected by factors such as:

Prices for oil or natural gas at their current levels after the significant decline in prices in the second half of 2014 are currently below the average calculated for 2014 and sustained lower prices will cause the unweighted arithmetic average to decrease over time

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as the lower prices are reflected in the average price, which may reduce both in the estimated quantities and present values of our reserves and which may necessitate write-downs in the value of our oil and natural gas properties.

The timing of both our production and our incurrence of expenses in connection with the development and production of our oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating the Standardized Measure may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Actual future prices and costs may differ materially from those used in the present value estimate. If oil and natural gas prices decline by 10%, then the Standardized Measure as of December 31, 2014 would decrease approximately $212 million.

Approximately 48% of our total estimated proved reserves at December 31, 2014 were proved undeveloped reserves requiring substantial capital expenditures and may ultimately prove to be less than estimated.

Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. At December 31, 2014, approximately 27.2 MMBOE of our total estimated proved reserves were undeveloped. The reserve data included in our reserve reports assumes that substantial capital expenditures will be made to develop non-producing reserves. The calculation of our estimated net proved reserves as of December 31, 2014 assumes that we will spend $349 million, including plugged and abandonment cost, to develop our estimated proved undeveloped reserves, including an estimated $109 million in 2015. Although cost and reserve estimates attributable to our natural gas and oil reserves have been prepared in accordance with industry standards, we cannot be sure that the estimated costs are accurate. We may need to raise additional capital in order to develop our estimated proved undeveloped reserves over the next five years and we cannot be certain that additional financing will be available to us on acceptable terms, if at all. Additionally, continued declines in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical.  As a result of depressed oil and gas prices, we have reduced the budgeted capital expenditures for the development of undeveloped reserves in 2015.  These delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves. Further, our drilling efforts may be delayed or unsuccessful, and actual reserves may prove to be less than current reserve estimates, which could have a material adverse effect on our financial condition, future cash flows and results of operations.

As part of our exploration and development operations, we have expanded, and expect to further expand, the application of horizontal drilling and multi-stage hydraulic fracture stimulation techniques. The utilization of these techniques requires substantially greater capital expenditures as compared to the completion cost of a vertical well. The incremental capital expenditures are the result of greater measured depths and additional hydraulic fracture stages in horizontal wellbores.

We may experience difficulty in achieving and managing future growth.

Future growth may place strains on our resources and cause us to rely more on project partners and independent contractors, possibly negatively affecting our financial condition and results of operations. Our ability to grow will depend on a number of factors, including:

Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of hydrocarbons, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable geoscientists to know whether hydrocarbons are, in fact, present in those structures and the amount of hydrocarbons. We are employing 3-D seismic technology with respect to certain of our projects. The use of 2-D and 3-D seismic and other advanced technologies requires greater pre-drilling

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expenditures than traditional drilling strategies, and we could incur greater drilling and testing expenses as a result of such expenditures, which may result in a reduction in our returns or losses. As a result, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline.

We often gather 2-D and 3-D seismic data over large areas. Our interpretation of seismic data delineates those portions of an area that we believe are desirable for drilling. Therefore, we may choose not to acquire option or lease rights prior to acquiring seismic data, and, in many cases, we may identify hydrocarbon indicators before seeking option or lease rights in the location. If we are not able to lease those locations on acceptable terms, we will have made substantial expenditures to acquire and analyze 2-D and 3-D seismic data without having an opportunity to attempt to benefit from those expenditures.

We will rely on drilling to increase our levels of production. If our drilling is unsuccessful, our financial condition will be adversely affected.

The primary focus of our business strategy is to increase production levels by drilling wells. Although we were successful in drilling in the past, we cannot provide assurance that we will continue to maintain production levels through drilling. Our drilling involves numerous risks, including the risk that we will not encounter commercially productive oil or natural gas reservoirs. We must incur significant expenditures to drill and complete wells. The costs of drilling and completing wells are often uncertain, and it is possible that we will make substantial expenditures on drilling and not discover reserves in commercially viable quantities.  Additionally, in the current depressed oil price environment, we have reduced our capital expenditures for drilling in 2015.  As a result, we may not be able to increase or maintain production through our drilling activity. 

We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.

In the future we may make acquisitions of businesses that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets.

The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. Our failure to achieve consolidation savings, to incorporate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

In addition, our partnership agreement, our senior secured revolving credit facility and the indenture governing our senior notes impose certain limitations on our ability to enter into mergers or combination transactions. Our partnership agreement, our senior secured revolving credit facility and the indenture governing our senior notes also limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.

Our business is subject to operational risks that will not be fully insured, which, if they were to occur, could adversely affect our financial condition or results of operations.

Our business activities are subject to operational risks, including:

In addition, a portion of our natural gas production is processed to extract natural gas liquids at processing plants that are owned by others. If these plants were to cease operations for any reason, we would need to arrange for alternative transportation and processing facilities. These alternative facilities may not be available, which could cause us to shut in our natural gas production. Further, such alternative facilities could be more expensive than the facilities we currently use.

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Any of these events could adversely affect our ability to conduct operations or cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution or other environmental contamination, loss of wells, regulatory penalties, suspension of operations, and attorney’s fees and other expenses incurred in the prosecution or defense of litigation.

As is customary in the industry, we maintain insurance against some but not all of these risks. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition and results of operations.

Our hedging activities could result in financial losses or could reduce our net income.

To achieve more predictable cash flows and to reduce our exposure to fluctuations in the prices of oil and natural gas, we have and may continue to enter into hedging arrangements for a significant portion of our production. As of December 31, 2014, we have hedged approximately 78% of our total forecasted PDP production through 2018 at average annual floor prices ranging from $4.19 per MMBtu to $4.50 per MMBtu for natural gas and $80.00 per Bbl to $89.16 per Bbl for oil, with the majority of the hedged volumes in 2015-2016. If we experience a sustained material interruption in our production, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flows from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. Lastly, an attendant risk exists in hedging activities that the counterparty in any derivative transaction cannot or will not perform under the instrument and that we will not realize the benefit of the hedge.

Our ability to use hedging transactions to protect us from future price declines will be dependent upon prices at the time we enter into future hedging transactions and our future levels of hedging, and as a result our future net cash flows may be more sensitive to commodity price changes.

Our policy has been to hedge a significant portion of our near-term estimated production. However, our price hedging strategy and future hedging transactions will be determined at our discretion. We are not under an obligation to hedge a specific portion of our production. The prices at which we hedge our production in the future will be dependent upon commodities prices at the time we enter into these transactions, which may be substantially higher or lower than current prices. Accordingly, our price hedging strategy may not protect us from significant declines in prices received for our future production. Conversely, our hedging strategy may limit our ability to realize cash flows from commodity price increases. It is also possible that a substantially larger percentage of our future production will not be hedged as compared with the next few years, which would result in our oil and natural gas revenues becoming more sensitive to commodity price changes.

Our hedging transactions expose us to counterparty credit risk.

Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract.  This risk of counterparty non-performance is of particular concern given the disruptions that have occurred in the financial markets and the significant decline in oil and natural gas prices which could lead to sudden changes in a counterparty’s liquidity, and impair their ability to perform under the terms of the derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.  Furthermore, the bankruptcy of one or more of our hedge providers or some other similar proceeding or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed to us by the distressed entity or entities. 

During periods of falling commodity prices our hedge receivable positions increase, which increases our exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.

The adoption of derivatives legislation and regulations by the U.S. Congress related to derivative contracts could have an adverse impact on our ability to hedge risks associated with our business.

Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) establishes federal oversight and regulation of over-the-counter (“OTC”) derivatives and requires the Commodity Futures Trading Commission (the “CFTC”) and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the OTC market.  Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions and/or exemptions still remain to be finalized. In one of its rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC approved on November 5, 2013, a proposed rule imposing position limits for certain futures and option contracts in various commodities (including natural gas) and for swaps that are their economic equivalents. Certain specified types of hedging transactions are exempt from these position limits, provided that such

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hedging transactions satisfy the CFTC’s requirements for “bona fide hedging” transactions or positions. Similarly, the CFTC has issued a proposed rule on margin requirements for swap transactions, which proposes an exemption for commercial end-users, entering into uncleared swaps in order to hedge commercial risks affecting their business, from any requirement to post margin to secure such swap transactions. 

In addition, the CFTC has issued a final rule authorizing an exception for commercial end-users using swaps to hedge their commercial risks from the otherwise applicable mandatory obligation under the Dodd-Frank Act to clear all swap transactions through a derivatives clearing organization and to trade all such swaps on an exchange.  The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations.  All of the above regulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate our exposure to commodity price volatility and other commercial risks affecting our business.

While it is not possible at this time to predict when the CFTC will issue final rules applicable to position limits or margin requirements, depending on our ability to satisfy the CFTC’s requirements for a commercial end-user using swaps to hedge or mitigate our commercial risks, these rules and regulations may require us to comply with position limits, margin requirements and with certain clearing and trade-execution requirements in connection with our financial derivative activities. The Dodd-Frank Act may also require our current counterparties to financial derivative transactions to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties, and may cause some entities to cease their current business as hedge providers. These changes could reduce the liquidity of the financial derivatives markets thereby reducing the ability of commercial end-users to have access to financial derivatives to hedge or mitigate their exposure to commodity price volatility. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available capital for other commercial operations purposes), materially alter the terms of future swaps relative to the terms of our existing bilaterally negotiated financial derivative contracts, and reduce the availability of derivatives to protect against commercial risks we encounter.

If we reduce our use of derivative contracts as a result of the new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures.  Finally, the legislation was intended, in part, to reduce the volatility of oil, natural gas and natural gas liquids prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas and natural gas liquids.  Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices.  Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations, or cash flows.

We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenues.

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources than us. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties to consummate transactions in a highly competitive market. Many of our larger competitors not only drill for and produce oil and natural gas, but also engage in refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and natural gas properties, and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, these companies may have a greater ability to continue drilling activities during periods of low commodity prices, to contract for drilling equipment, to secure trained personnel, and to absorb the burden of present and future federal, state, local and other laws and regulations. The oil and natural gas industry has periodically experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. Competition has been strong in hiring experienced personnel, particularly in the engineering and technical, accounting and financial reporting, tax and land departments. In addition, competition is strong for attractive oil and natural gas producing properties, oil and natural gas companies, and undeveloped leases and drilling rights. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations.

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or competitive pressures may force us to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition, and results of operations could be materially adversely affected.

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Deficiencies of title to our leased interests could significantly affect our financial condition.

If an examination of the title history of a property reveals that an oil or natural gas lease or other developed rights has been purchased in error from a person who is not the owner of the mineral interest desired, our interest would substantially decline in value. In such cases, the amount paid for such oil or natural gas lease or leases or other developed rights would be lost. It is management’s practice, in acquiring oil and natural gas leases or undivided interests in oil and natural gas leases or other developed rights, not to incur the expense of retaining lawyers to examine the title to the mineral interest to be acquired. Rather, we will rely upon the judgment of oil and natural gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental or county clerk’s office before attempting to acquire a lease or other developed rights in a specific mineral interest.

Prior to drilling an oil or natural gas well, however, it is the normal practice in the oil and natural gas industry for the person or company acting as the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed oil or natural gas well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, such as obtaining affidavits of heirship or causing an estate to be administered. Such curative work entails expense, and it may happen, from time to time, that the operator may elect to proceed with a well despite defects to the title identified in the preliminary title opinion. Our failure to obtain perfect title to our leaseholds may adversely impact our ability in the future to increase production and reserves.

We are vulnerable to risks associated with operating in the inland waters region of South Louisiana.

Our operations and financial results could be significantly impacted by unique conditions in the inland waters region of South Louisiana because we explore and produce in that area. As a result of this activity, we are vulnerable to the risks associated with operating in the inland waters region of South Louisiana, including those relating to:

Our ability to pursue our business strategies may be adversely affected if we incur costs and liabilities due to a failure to comply with environmental regulations or a release of hazardous substances into the environment.

We may incur significant costs and liabilities as a result of environmental requirements applicable to the operation of our wells, gathering systems and other facilities. These costs and liabilities could arise under a wide range of federal, state and local environmental laws and regulations, including, for example:

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Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes, including RCRA, CERCLA, OPA and analogous state laws and regulations, impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances or other waste products have been disposed of or otherwise released. More stringent laws and regulations, including any related to climate change, greenhouse gases, and hydraulic fracturing, may be adopted in the future. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other materials into the environment.

 

Our operations are substantially dependent on the availability of water.  Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

 

Water is an essential component of both the drilling and hydraulic fracturing processes.  Historically, we have been able to purchase water from local land owners and other sources for use in our operations. Some areas in which we have operations have experienced drought conditions, which could result in restrictions on water use.  If drought conditions were to occur, our ability to obtain water could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly.  If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows.

Climate change legislation or regulations restricting emissions of greenhouse gases (“GHGs”) could result in increased operating costs and reduced demand for the oil and natural gas we produce.

In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions; although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants.  The EPA has recently announced its intention to take measures to require or encourage reductions in methane emissions from oil and gas operations.  Those measures may include the development of NSPS regulations in 2016 for reducing methane from new and modified oil and gas production sources and natural gas processing and transmission sources. 

EPA requires the reporting of GHG emissions from specified large GHG emission sources in the United States including from onshore and offshore oil and natural gas production, processing, transmission, storage and distribution facilities. Reporting of GHG emissions from such facilities is required on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011.  Although both houses of Congress, in past sessions, have considered legislation to reduce emissions of GHGs, no comprehensive program has been enacted by Congress.  In the absence of a comprehensive federal program, many states, either individually or through multistate regional initiatives, are considering or have begun implementing legal measures to reduce emissions of GHGs. The adoption and implementation of any statutes, regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas that we produce.

Significant physical effects of climatic change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in preparing for or responding to those effects.

In an interpretive guidance on climate change disclosure, the SEC indicates that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, our development and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low lying areas, disruption of our production activities because of climate related damages to our facilities and our costs of operation potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects, or increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change.

Federal legislation and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is used in many of our operations to stimulate production of hydrocarbons, particularly natural gas. Congress has considered legislation to amend the SDWA to remove the exemption currently available to hydraulic fracturing, which would place additional regulatory burdens upon hydraulic fracturing operations including requirements to obtain a permit prior to commencing operations adhering to certain construction requirements, to establish financial assurance, and to require reporting and

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disclosure of the chemicals used in those operations. This legislation has not passed. The SDWA does not exempt hydraulic fracturing activities using diesel. The EPA has developed guidance for permitting of hydraulic fracturing activities using diesel.

The EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, issued a progress report in December 2012, and expects to deliver the final results of the study in 2015.  The Bureau of Land Management has adopted final rules regulating hydraulic fracturing on public lands.  These rules include requirements on drillers to disclose the chemicals used in hydraulic fracturing operations and new requirements for well casing, groundwater protections, and wastewater storage.  We are currently evaluating the impact of these rules on our operations.  Additionally the EPA has announced an initiative under the Toxic Substances Control Act to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals and is working on regulations for wastewater generated by hydraulic fracturing.

In addition, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances and that require the disclosure of the chemicals used in hydraulic fracturing operations. Any other new laws or regulations that impose new obligations on, or significantly restrict hydraulic fracturing, could make it more difficult or costly for us to perform hydraulic fracturing activities and thereby affect our determination of whether a well is commercially viable and increase our cost of doing business.

Further, in April 2012, the EPA issued final rules that subject oil and natural gas production, processing, transmission, and storage operations to regulation under the NSPS and NESHAP programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Before January 1, 2015, these standards require owners/operators to reduce VOC emissions from natural gas not sent to the gathering line during well completion either by flaring using a completion combustion device or by capturing the natural gas using green completions. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale. The standards are applicable to newly fractured wells and also existing wells that are refractured. Further, the finalized regulations also establish specific new requirements for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and other equipment. Compliance with such regulations could require modifications to the operations of our natural gas exploration and production operations including the installation of new equipment, which could result in significant costs.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute development and exploitation plans on a timely basis and within budget, and consequently could adversely affect our anticipated cash flow.

We utilize third-party services to maximize the efficiency of our operation. The cost of oil field services typically fluctuates based on demand for those services. While we currently have excellent relationships with oil field service companies, there is no assurance that we will be able to contract for such services on a timely basis or that the cost of such services will remain at a satisfactory or affordable level. Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our development and exploitation operations, which could have a material adverse effect on our business, financial condition or results of operations.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

Our exploration and production operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Failure or delay in obtaining regulatory approvals or drilling permits could have a material adverse effect on our ability to develop our properties, and receipt of drilling permits with onerous conditions could increase our compliance costs. In addition, regulations regarding conservation practices and the protection of correlative rights affect our operations by limiting the quantity of oil and natural gas we may produce and sell.

We are subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration, production and transportation of oil and natural gas. The possibility exists that new laws, regulations or enforcement policies could be more stringent and significantly increase our compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our financial position could be adversely affected.

We have limited control over activities on properties we do not operate, which could reduce our production and revenues.

We have limited control over properties, especially our Eagleville field, which we do not operate or do not otherwise control operations. If we do not operate or otherwise control the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of the underlying properties. The failure of an operator of our wells to adequately perform operations, an operator’s financial difficulties, including as a result of the severe decline in oil and natural gas

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prices in 2014, or an operator’s breach of the applicable agreements could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others, therefore, depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology.

High Mesa, as our Class B limited partner, has the ability to take actions that conflict with the interests of other investors.

High Mesa, an affiliate of a private equity fund focused on energy and commodities, is the holder of our Class B limited partner interest. Under our partnership agreement, the Class B limited partner has certain significant rights, including, without limitation:

The interests of the Class B limited partner could conflict with the interests of our other investors, such as the holders of our senior notes. For example, if we encounter financial difficulties or are unable to pay our debts as they mature, the interests of the Class B limited partner may conflict with the interests of the holders of our senior notes. The Class B limited partner also may have an interest in pursuing acquisitions, divestitures, financings or other transactions that, in its judgment, could enhance its investment, even though such transactions might involve risks to our other investors, including the holders of our senior notes. 

We may not be able to repurchase our outstanding senior notes upon a change of control.

Under the terms of the indenture for the senior notes, if we experience certain specific change of control events, we will be required to offer to repurchase all of our outstanding notes at 101% of the principal amount of such senior notes plus accrued and unpaid interest to the date of repurchase. We may not have available funds sufficient to pay the change of control purchase price for any or all of the senior notes that might be tendered in the change of control offer.

The definition of change of control in the indenture governing the senior notes includes a phrase relating to the direct or indirect sale, transfer, conveyance or other disposition of “all or substantially all” of our and our restricted subsidiaries’ assets, taken as a whole. Although there is a limited body of case law interpreting the phrase “substantially all”, there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a holder of senior notes to require us to repurchase such senior notes as a result of a sale, transfer, conveyance or other disposition of “less than all of our and our restricted subsidiaries” assets taken as a whole to another person or group may be uncertain. Our limited partnership agreement permits High Mesa to cause our general partner to initiate a sale of our company to a third-party, which sale may be deemed to be a change of control. High Mesa may exercise this right at a time that we do not have sufficient capital or are otherwise prohibited from repurchasing the senior notes. In addition, our senior secured revolving credit facility contains, and any future credit agreement likely will contain, restrictions or prohibitions on our ability to repurchase the senior notes under certain circumstances. If these change of control events occur at a time when we are prohibited from repurchasing the senior notes, we may seek the consent of our lenders to purchase the senior notes or could attempt to refinance the borrowings that contain these prohibitions or restrictions. If we do not obtain our lenders’ consent or refinance these borrowings, we will not be able to repurchase the senior notes. Accordingly, the holders of the senior notes may not receive the change of control purchase price for their notes in the event of a sale or other change of control, which will give the trustee and the holders of the senior notes the right to declare an event of default and accelerate the repayment of the senior notes.

Our private equity partner and its affiliates are not limited in their ability to compete with us for acquisition or drilling opportunities. This could cause conflicts of interest and limit our ability to acquire additional assets or businesses.

Our partnership agreement with our private equity partner does not prohibit it or its affiliates from owning assets or engaging in businesses that compete directly or indirectly with us. For instance, our private equity partner and its affiliates may acquire, develop or dispose of additional oil or natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets. Highbridge is part of a larger family of funds, which has significantly greater resources than we have, which may make it more difficult for us to compete for acquisition candidates if our private equity partner or its affiliates were to compete against us.

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We depend on key personnel, the loss of any of whom could materially adversely affect future operations.

Our success will depend to a large extent upon the efforts and abilities of our executive officers and key operations personnel. The loss of the services of one or more of these key employees could have a material adverse effect on us. We do not maintain key-man life insurance with respect to any of our employees. Our business will also be dependent upon our ability to attract and retain qualified personnel. Acquiring and keeping these personnel could prove more difficult or cost substantially more than estimated. This could cause us to incur greater costs, or prevent us from pursuing our development and exploitation strategy as quickly as we would otherwise wish to do.

We may encounter obstacles to marketing our oil and natural gas, which could adversely impact our revenues.

The marketability of our production will depend in part upon the availability and capacity of natural gas gathering systems, pipelines and other transportation facilities owned by third parties. Transportation space on the gathering systems and pipelines we utilize is occasionally limited or unavailable due to repairs or improvements to facilities or due to space being utilized by other companies that have priority transportation agreements.  Additionally, new fields may require the construction of gathering systems and other transportation facilities.  These facilities may require us to spend significant capital that would otherwise be spent on drilling.  Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand.  Various proposals and proceedings that might affect the petroleum industry are pending before Congress, the Federal Energy Regulatory Commission, or FERC, various state legislatures, and the courts. The industry historically has been heavily regulated and we cannot provide assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue nor can we predict what effect such proposals or proceedings may have on our operations.  The availability of markets is beyond our control. If market factors dramatically change, the impact on our revenues could be substantial and could adversely affect our ability to produce and market oil and natural gas.

We may experience a temporary decline in revenues and production if we lose one of our significant customers.

Historically, we have been dependent upon a few customers for a significant portion of our revenue. To the extent any significant customer reduces the volume of its oil or natural gas purchases from us, we could experience a temporary interruption in sales of, or a lower price for, our oil and natural gas production and our revenues could decline.

Our debt agreements contain restrictive covenants that may limit our ability to respond to changes in market conditions or pursue business opportunities.

Our senior secured revolving credit facility and the indenture for the senior notes contain restrictive covenants that limit our ability to, among other things:

In addition, our senior secured revolving credit facility requires us to maintain certain financial ratios and tests, such as leverage ratios. The requirement that we comply with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.  As of December 31, 2014, we were in compliance with all of the financial covenants under our credit facility. Failure to maintain these covenants could preclude us from borrowing under our revolving credit facility and require us to immediately pay down any outstanding drawn amounts under the credit agreement, which could affect cash flows or restrict business.

Any significant reduction in our borrowing base under our revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations, and we may not have sufficient funds to repay borrowings under our revolving credit facility if required as a result of a borrowing base redetermination.

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Availability under our revolving credit facility is currently subject to a borrowing base of $375 million. The borrowing base is subject to scheduled semiannual and other elective collateral borrowing base redeterminations based on the value of our oil and natural gas reserves as determined by the lenders under our credit facility, and other factors deemed relevant by our lenders. Recent declines in prices for oil and natural gas may cause our banks to reduce the borrowing base under our revolving credit facility.  As of December 31, 2014, we had outstanding borrowings of $319.5 million. We intend to continue borrowing under our revolving credit facility in the future as needed. Any significant reduction in our borrowing base as a result of such borrowing base redeterminations or otherwise may negatively impact our liquidity and our ability to fund our operations and, as a result, may have a material adverse effect on our financial position, results of operation and cash flow. Further if, the outstanding borrowings under our revolving credit facility were to exceed the borrowing base as a result of any such redetermination, we would be required to repay the excess. We may not have sufficient funds to make such repayments. If we do not have sufficient funds and we are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

 If we are unable to comply with the restrictions and covenants in our debt agreements, there could be a default under the terms of such agreements, which could result in an acceleration of repayment.

If we are unable to comply with the restrictions and covenants in our debt agreements, there could be a default under the terms of these agreements. Our ability to comply with these restrictions and covenants, including meeting financial ratios and tests, may be affected by events beyond our control. As a result, we cannot assure that we will be able to comply with these restrictions and covenants or meet such financial ratios and tests. Any default under these agreements governing our indebtedness that is not waived by the required lenders or holders, as the case may be, could prevent us from paying principal, premium, if any, and interest on the notes and substantially decrease the market value of the notes. If we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, and interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants in the instruments governing our indebtedness (including covenants in our senior secured revolving credit facility and the indenture governing the senior notes), we could be in default under the terms of the agreements governing such indebtedness. In the event of such a default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under our credit facility could terminate their commitments to lend, cease making further loans and institute foreclosure proceedings against our assets, and we could be forced into bankruptcy or liquidation. Borrowings under other debt instruments that contain cross-acceleration or cross-default provisions may also be accelerated and become due and payable. If any of these events occur, our assets might not be sufficient to repay in full all of our outstanding indebtedness and we may be unable to find alternative financing. Even if we could obtain alternative financing, it might not be on terms that are favorable or acceptable to us. Additionally, we may not be able to amend our debt agreements or obtain needed waivers on satisfactory terms.

Our borrowings under our senior secured revolving credit facility expose us to interest rate risk.

Our earnings are exposed to interest rate risk associated with borrowings under our senior secured revolving credit facility. Our senior secured revolving credit facility carries a floating interest rate based upon short-term interest rate indices. If interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition. We may use interest rate hedges in an effort to mitigate this risk, but those efforts may not prove successful.

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To service our indebtedness, we require a significant amount of cash, and our ability to generate cash will depend on many factors beyond our control.

Our ability to make payments on and to refinance our indebtedness, and to fund planned capital expenditures depends in part on our ability to generate cash in the future. This ability is, to a certain extent, subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. We cannot provide assurance that we will generate sufficient cash flow from operations, that we will realize operating improvements on schedule, or that future borrowings will be available to us in an amount sufficient to enable us to service and repay our indebtedness or to fund our other liquidity needs. If we are unable to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:

However, any alternative financing plans that we undertake, if necessary, may not allow us to meet our debt obligations.

We cannot provide assurance that any refinancing or debt restructuring would be possible, that any assets could be sold or that, if sold, the timing of the sales and the amount of proceeds realized from those sales would be favorable to us or that additional financing could be obtained on acceptable terms. Our inability to generate sufficient cash flows to satisfy our debt obligations, including our obligations under the senior notes, or to obtain alternative financing, could materially and adversely affect our business, financial condition, results of operations and prospects.

Future disruptions in the global credit markets may make equity and debt markets less accessible, create a shortage in the availability of credit, and lead to credit market volatility that could limit our ability to grow.

The recovery from the global economic crisis of 2008 and resulting recession has been slow and uneven. Continuing concerns regarding the worldwide economic outlook and sovereign debt crisis in Europe have contributed to increased economic uncertainty and diminished expectations for the global economy. A slowdown in the current economic recovery or a return to a recession would negatively impact demand for petroleum products and prices for natural gas and oil. Disruptions in the capital and credit markets, as was experienced during 2008 and 2009, could adversely affect our ability to meet our liquidity needs or to refinance our indebtedness, including our ability to draw on our existing credit facility or enter into new credit facilities. 

There are inherent limitations in all control systems, and misstatements due to error or fraud that could seriously harm our business may occur and not be detected.

Our management, including our Chief Executive Officer and Chief Financial Officer, do not expect that our internal controls and disclosure controls will prevent all possible error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, an evaluation of controls can only provide reasonable assurance that all material control issues and instances of fraud, if any, in our Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Further, controls can be circumvented by the individual acts of some persons or by collusion of two or more persons. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. A failure of our controls and procedures to detect error or fraud could seriously harm our business and results of operations. 

Cyber-attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations.

Our business has become increasingly dependent on digital technologies to conduct certain exploration, development, production and financial activities. We depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third party partners. Unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our exploration or production operations. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyber-attack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions. While we have not experienced cyber-attacks, there is no assurance that we will not suffer such

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attacks and resulting losses in the future. Further, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties

Information regarding our properties is contained in “Item 1. Business” contained herein.

Item 3. Legal Proceedings

We are party to various litigation matters arising in the ordinary course of business. We do not believe the outcome of such disputes or legal actions will have a material adverse effect on our consolidated financial statements. Accruals for losses associated with litigation are made when losses are deemed probable and can be reasonably estimated.

Board of Commissioners of the Southeast Louisiana Flood Protection Authority – East:    On July 24, 2013, the Board of Commissioners of the Southeast Louisiana Flood Protection Authority – East sued us and approximately 100 other energy companies for long-term damage to the wetlands in southeast Louisiana.  Case No. 2013-6911 was filed in state court and subsequently remanded to federal court.  The plaintiff seeks damages and injunctive relief in the form of abatement and restoration of wetlands, alleging that the activities of the oil and gas industry over the past century have contributed significantly to the degradation of the wetlands that protect the populated areas in and around New Orleans from storm surge and other extreme weather effects.  The plaintiff alleges damages from increased costs of providing man-made storm protection structures, and emphasizes the destructive effect of canals built by the oil and gas industry.  Legal arguments include breach of the restoration and maintenance clauses of contracts with the State of Louisiana for drilling, dredging, and right-of-way agreements for pipelines.  Other legal arguments include negligence, strict liability, natural servitude of drain, public nuisance and private nuisance.   Our wholly-owned subsidiary The Meridian Resource Company, LLC is named as a defendant with 32 wells, two dredging permits and four right of way agreements in the relevant area.  Almost all of these wells are inactive.  In June 2014, Act 544 of the Louisiana Legislature was enacted, stating that the plaintiff does not have the authority to bring this suit.  However, the constitutionality of Act 544 may be litigated, and this development does not end the litigation to which we are a party.

On February 13, 2015, the case was dismissed by the U.S. District Judge.  As of December 31, we have not provided any amount for this matter in our consolidated financial statements.

Environmental claims:  Various landowners have sued our wholly owned subsidiary The Meridian Resource Corporation and its subsidiaries (“Meridian”), which we acquired in 2010, in lawsuits concerning several fields in which Meridian has historically had operations. The lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs’ lands from alleged contamination and otherwise from Meridian’s oil and natural gas operations. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of the various environmental claims or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any amount for these claims in our financial statements at December 31, 2014.

Due to the nature of our business, some contamination of the real estate property owned or leased by us is possible. Environmental site assessments of the property would be necessary to adequately determine remediation costs, if any. Management has established a liability for soil contamination in Florida of $1.1 million at December 31, 2014 and 2013, based on our undiscounted engineering estimates.  The obligations are included in other long-term liabilities in the accompanying consolidated balance sheets.  No accrual for environmental claims has been made other than the balance noted above.

Item 4. Mine Safety Disclosures

Not applicable.

PART II

Item 5. Market For Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities

No class of our limited partnership interests has been registered under the Exchange Act, and there is no established public trading market for our equity.

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As of March 26, 2015,  four holders of our limited partnership interests held 100% of such interests.

Distributions to our partners are determined by the terms of our partnership agreement.  See also, “Risk Factors — High Mesa, as our Class B limited partner, has the ability to take actions that conflict with the interests of other investors.” We are also currently restricted in our ability to pay dividends under our senior secured revolving credit facility. Historically, limited distributions have been made with the approval of our Board of Directors.

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Item 6. Selected Financial Data

The following table presents our selected financial data for the periods indicated. The data have been derived from our audited consolidated financial statements for such periods. For further information that will help you better understand the summary data, you should read this financial data in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and related notes and other financial information included elsewhere in this report.  The following information is not necessarily indicative of our future results.

 

 

 

 

 

 

 

 

 

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with the “Selected Financial Data” and the consolidated financial statements and related notes included elsewhere in this report. The following discussion and analysis contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, the volatility of oil and natural gas prices, production timing and volumes, estimates of proved reserves, operating costs and capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this report, particularly in “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements,” all of which are difficult to predict. As a result of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

We have been engaged in the onshore oil and natural gas acquisition, exploitation, exploration and production in the United States since 1987.  Currently, we are focusing our drilling efforts in our core properties in Sooner Trend area of the Anadarko Basin in Oklahoma, in our Weeks Island Complex area in South Louisiana, and in our Eagleville field in the Eagle Ford Shale play in South Texas.  We maintain operational control of the majority of our properties, either through directly operating them, or through operating arrangements with minority interest holders.  Our operations also include other oil and natural gas interests in Texas and Louisiana.

The amount of revenue we generate from our operations will fluctuate based on, among other things:

In order to mitigate the impact of changes in oil and natural gas prices on our cash flows, we are a party to hedging and other price protection contracts, and we intend to enter into such transactions in the future to reduce the effect of price volatility on our cash flows.

Substantially all of our oil and natural gas activities are conducted jointly with others and, accordingly, amounts presented reflect our proportionate interest in such activities. Inflation has not had a material impact on our results of operations and is not expected to have a material impact on our consolidated results of operations in the future.

Outlook

The relatively low level of natural gas prices prompted our shift in emphasis to oil and liquids over the past several years.  Accordingly, the success of our business is significantly affected by the price of oil due to our current focus on development of oil reserves and exploration for oil.  Oil prices are subject to significant changes.  Beginning in the third quarter of 2014, the price for oil began a dramatic decline, and current prices for oil are significantly less than they have been over the last several years.  Factors affecting the price of oil include worldwide economic conditions, including the European credit crisis, geopolitical activities, including developments in the Middle East, Ukraine, and South America, worldwide supply disruptions, weather conditions, actions taken by the Organization of Petroleum Exporting Countries and the value of the U.S. dollar in international currency markets.  Sustained low oil and natural gas prices could have a material adverse effect on our financial condition, the carrying value of our oil and natural gas properties, our proved reserves and the amount of our borrowing base under our credit facility. 

Oil prices for next month futures contracts for West Texas Intermediate traded on the NYMEX (“NYMEX WTI”) averaged approximately $97 per Bbl in 2013 and $93 per Bbl in 2014.  NYMEX WTI futures reached a high average price of $105 per BbL in June 2014 and closed at an average price of $59 per BbL in December 2014. 

Natural gas prices are also subject to significant changes.  Declining prices in the last several years reached a low point in May 2012 when NYMEX Henry Hub futures contract closed at $2.04 per MMbtu.  Since then, prices have generally increased, averaging approximately $3.65 per MMbtu in 2013 and $4.42 per MMbtu in 2014.  NYMEX Henry Hub futures reached a high price of $5.56 per MMbtu in February 2014 and closed at a price of $4.28 per MMbtu in December 2014. 

Depressed oil and natural gas prices have impacted our earnings by necessitating impairment write-downs in some of our natural gas properties, either directly by decreasing the market values of the properties, or indirectly, by lowering rates of return on oil and natural gas development projects and increasing the chance of impairment write-downs.  We recorded non-cash impairment expenses of $74.9 million and $143.2 million during the years ended December 31, 2014 and 2013, respectively.  The 2014 write-downs were primarily due to downward revisions in proved reserves in some fields and decreased prices for oil, natural gas and natural gas liquids. 

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Our impairments were primarily related to our non-core fields.  For further information, see “Results of Operations: Year Ended December 31, 2014 v. Year Ended December 31, 2013:  Impairment Expense.”

Sustained low oil or natural gas prices may require us to further write down the value of our oil and natural gas properties and/or revise our development plans, which may cause certain of our undeveloped well locations to no longer be deemed proved.  As a result of the depressed commodity prices and in order to preserve our liquidity, we have reduced our budgeted capital expenditures for 2015. This could cause a reduction in the borrowing base under our credit facility. Low prices may also reduce our cash available for distribution, acquisitions and for servicing our indebtedness.

Our derivative contracts are reported at fair value on our consolidated balance sheets and are highly sensitive to changes in the price of oil and natural gas. Changes in these derivative assets and liabilities are reported in our consolidated statement of operations as gain / loss from derivative contracts which include both the non-cash increase or decrease in the fair value of derivative contracts, as well as the effect of cash settlements of derivative contracts during the period. In 2014, we recognized a net gain on our derivative contracts of $96.6 million, which includes $9.5 million in cash settlements received for derivative contracts. The objective of our hedging program is that, over time, the combination of settlement gains and losses from derivative contracts with ordinary oil and natural gas revenues will produce relative revenue stability. However, in the short term, both settlements and fair value changes in our derivative contracts can significantly impact our results of operations, and we expect these gains and losses to continue to reflect changes in oil and natural gas prices.

We have hedged approximately 78% of our forecasted production of proved developed producing reserves through 2018 at weighted average annual floor prices ranging from $4.19 per MMbtu to $4.50 per MMbtu for natural gas and $80.00 per Bbl to $89.16 per Bbl for oil.  If oil and/or natural gas prices continue to decline for an extended period of time, we may be unable to replace expiring hedge contracts or enter new contracts for additional oil and natural gas production at favorable prices.

The primary factors affecting our production levels are capital availability, the effectiveness and efficiency of our production operations, the success of our drilling program and our inventory of drilling prospects. In addition, we face the challenge of natural production declines. We attempt to overcome this natural decline primarily through development of our existing undeveloped reserves, enhanced completions and well recompletions, and other enhanced recovery methods. Our future growth will depend on our ability to continue to add reserves in excess of production. Our ability to add reserves through drilling and other development techniques is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. Any delays in drilling, completing or connecting our new wells to gathering lines will negatively affect our production, which will have an adverse effect on our revenues and, as a result, cash flow from operations.

 

Recent Developments and Acquisition and Divestiture Activity

On March 25, 2014, our Class B partner, High Mesa completed a $350 million recapitalization with an investment from Highbridge.  Proceeds from the investment were used in part to purchase the investment of Denham Capital Management, L.P. in High Mesa.  Highbridge received convertible paid in kind (“PIK”) preferred stock in High Mesa and senior PIK notes from High Mesa.  We expanded our Board of Directors to include one member nominated by Highbridge and one new management member, our Chief Financial Officer, Michael A. McCabe.  High Mesa remains our sole Class B partner.

On March 25, 2014, we sold a portion of our proved oil reserves, approximately 7.5 MMBOE, in our Eagleville field in South Texas.  The initial cash purchase price was $173 million, subsequently adjusted to approximately $171 million for settlement adjustments through December 31, 2014.  Proceeds were used to reduce the outstanding borrowings under our revolving credit facility.  The sale was structured to provide us with continuing net revenues based on 50% of our original working interest in 2014, declining to 30% in 2015, 15% in 2016, and zero in 2017, and we will continue to develop additional Eagleville wells at 70% of our original working interest.  Total reserves we retained are estimated as 7.7 MMBOE, of which 67% is considered proved undeveloped based on classifications from our reserve report as of December 31, 2014.  This partial sale of our Eagleville assets provided us cash for investment in new areas without relinquishing our position in the Eagle Ford Shale.

On August 7, 2014, we sold our interests in the Anne Parsons field for a cash payment of $9.2 million, subsequently adjusted to $8.6 million for customary settlement adjustments through December 31, 2014.  As of the date of sale, estimated proved reserves associated with these properties were 4.8 BCFE.  This East Texas field produced primarily natural gas and natural gas liquids.

On September 19, 2014, we sold our remaining interests in the Hilltop field for a cash payment of $41.6 million, which was subsequently adjusted to $38.9 million for customary settlement adjustments through December 31, 2014.  As of the date of sale, estimated proved reserves associated with these properties were 29.8 BCFE.  This East Texas field produced primarily dry gas. 

On December 10, 2014 we announced that a subsidiary, Alta Mesa Eagle, LLC, had entered into an agreement to sell certain oil and gas producing properties in the Eagle Ford Shale area to ReOil Eagle I, LLC for a total potential price of $210 million, subject to customary purchase price adjustments. On January 29, 2015, we announced the termination of the Purchase and Sale Agreement due

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to ReOil's failure to deposit initial negotiated funds into an escrow account and for non-fulfillment of certain other obligations in the agreement. 

On December 31, 2014, we sold our interests in a partially constructed pipeline and gas processing plant at cost to NWGP, an affiliate of High Mesa for an aggregate of $34.0 million, which was comprised of $25.5 million in cash and $8.5 million in promissory note.  Immediately after the consummation of the transaction, the $8.5 million promissory note was transferred from NWGP to HMS, a subsidiary of the Parent company High Mesa.  We did not recognize any gain or loss on the sale as the midstream assets were sold at cost.  This transaction also relieved us from the capital expenditures that would have been required to complete the construction of the pipeline.  The transaction was funded on January 2, 2015.

 

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Results of Operations: Year Ended December 31, 2014 v. Year Ended December 31, 2013

 

 

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Revenues

Oil revenues for the year ended December 31, 2014 increased $50.0 million, or 17%, to $347.8 million from $297.8 million for 2013. The increase in revenue was attributable to increased production volumes partially offset by lower average prices. Approximately $89.8 million of the increase in oil revenues for 2014 was due to an increase in production of 873 MBbls, or 30% over the same period for 2013. This increase is primarily due to new production from our Sooner Trend field, which increased 766 MBbls, from 306 MBbls in 2013 to 1,072 MBbls in 2014, and to our Weeks Island field, which increased production by 441 MBbls, from 1,053 MBbls in 2013 to 1,494 MBbls in 2014.  The average price of oil exclusive of settlements of derivative contracts decreased 10% in 2014; the overall price including settlements of derivative contracts decreased 7% from $100.67 per Bbl in 2013 to $93.38 per Bbl in 2014 resulting in a decrease in oil revenues of approximately $39.8 million.

For the years ended December 31, 2014, 2013 and 2012, we revised our reporting for oil, gas and natural gas liquids revenues.  Formerly, we reported all revenues “net” of realized gains and losses on related hedging activities, while we reported unrealized gains and losses on a separate revenue line item on the consolidated statements of operations. We are now reporting oil, gas and natural gas liquids revenues at “gross,” which does not include the effects of related hedging activities. Realized and unrealized gains and losses on related hedging activities are now recorded together on a separate revenue line item on the consolidated statements of operations. This change had no effect on our income (loss) from operations or net income (loss) for the periods stated.

Natural gas revenues for the year ended December 31, 2014 increased $3.7 million, or 6%, to $65.0 million from $61.3 million for 2013. The increase in natural gas revenue was attributable to higher average prices during 2014 partially offset by decreased production volumes.  The average price of natural gas exclusive of settlements of derivative contracts increased 22% in 2014 resulting in an increase in natural gas revenues of approximately $11.8 million.  The overall price including settlements of derivative contracts, decreased 5% from $5.14 per Mcf in 2013 to $4.87 per Mcf in 2014.  This was partially offset by approximately $8.1 million due to a decrease in production of 2.2 Bcf, or 13%. The decline is due to an emphasis on liquids-rich assets in our capital spending. Hilltop field, our largest natural gas field in 2013, produced 2.8 Bcf in 2014, compared to 5.8 Bcf in 2013.  We curtailed capital expenditures in the field in both 2013 and 2014, leading to production declines unmitigated by new production.   In addition, we sold a substantial portion of our working interest in the field, comprising proved reserves of approximately 11.2 BCFE, in October 2013, and the remaining working interests in the field in the third quarter of 2014.  

Natural gas liquids revenues increased during 2014 to $18.3 million from $15.3 million for 2013. A 35% increase in volumes from 398 MBbls in 2013 to 537 MBbls in 2014 was partially offset by a decrease in our average price of 11%, from $38.37 per Bbl in 2013 to $34.04 per Bbl in 2014. The increase in volume is due primarily to an increase in production in the Sooner Trend field during 2014 of 192 MBbls.  The decline in prices is due to increased supply of natural gas liquids as a result of increased liquids-targeted drilling.

In 2013, we revised our reporting for natural gas liquids produced in our Oklahoma properties.  Whereas we had previously reported all volumes and revenues for 2012 as attributable to a single stream of rich natural gas, we began recording revenues for natural gas liquids from Oklahoma separately in 2013.  For comparability, we reclassified approximately $3.3 million in revenues from natural gas to natural gas liquids for the year 2012.  The related volumetric reclassification included a reduction of 397 MMcf of natural gas produced, and an addition of 92 MBbls of natural gas liquids produced for the year 2012.  These reclassifications had no impact on previously reported total revenues, net income (loss), cash flows, or partners’ capital (deficit).  The analysis of the increase in revenues from 2012 to 2013 included herein is based on the figures for each year after reclassifications.

Other revenues were $1.0 million during 2014 as compared to $1.2 million during 2013. The decrease is partially the result of a decrease in rental income from our drilling rig, which we sold during the third quarter of 2013.

Gain (loss) on sale of assets was a gain of $87.5 million in 2014 as compared to a loss of $2.7 million in 2013.  The divestiture of a portion of our oil and gas properties in Eagleville Field and the divestiture of the remainder of our Hilltop Field properties during 2014 resulted in a gain of $72.5 million and 15.9 million, respectively.  The loss on sale of assets of $2.7 million in 2013 was primarily related to the sale of a single well in South Texas and to the sale of our drilling rig. 

Gain (loss) - oil and natural gas derivative contracts was a gain of $96.6 million for 2014 as compared to a loss of $17.2 million for 2013. The significant fluctuation from period to period is due to the volatility of oil and natural gas prices, changes in our outstanding hedging contracts during these periods, and revisions to our presentation of oil, gas and natural gas liquids revenues for 2014 and 2013. 

Expenses

Lease and plant operating expense increased $3.4 million to $73.8 million in 2014 as compared to $70.4 million in 2013. On a per unit basis, lease and plant operating expense decreased 5% from $11.60 to $10.99 per BOE for 2013 and 2014, respectively. In

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general, lease operating expenses are higher for liquids-rich properties. Oil as a percentage of production on an equivalent basis increased from 48% in 2013 to 56% in 2014. Natural gas as a percentage of equivalent production during the same periods decreased from 46% to 36%. Components of the expense that reflected increases included chemical and fuel usage, salt water disposal, compression and marketing and gathering, totaling $ 5.8 million.  The increase was partially offset by a decrease in repairs, maintenance and field services of $2.9 million.

Production and ad valorem taxes increased $1.8 million to $28.2 million, or 7%, for 2014, as compared to $26.4 million for 2013.  Production taxes increased $ 1.9 million.  Ad valorem taxes decreased $ 0.1 million. On a per unit basis, the production and ad valorem taxes decreased 3% from $4.34 to $4.20 per BOE for 2013 and 2014, respectively.

Workover expense decreased $4.7 million to $9.0 million from $13.7 million for 2014 and 2013, respectively. This expense varies depending on activities in the field and is attributable to many different properties.

Exploration expense includes the costs of our geology department, costs of geological and geophysical data, delay rentals, expired leases, and dry holes. Exploration expense increased $28.8 million to $61.9 million for 2014 from $33.1 million for 2013. The majority of the 2014 activity was due to $30.3 million in dry hole costs, primarily related to dry holes in New Mexico, South Louisiana, and South Texas; and $23.2 million in G&G seismic costs, primarily in Sooner Trend and South Louisiana; and delay rentals and expired lease expense of $6.1 million. As of December 31, 2014, our property, plant, and equipment balance includes $13.3 million in exploratory well costs which are deferred, pending determination of proved reserves.  Such costs will be charged to exploration expense if the wells are ultimately classified as dry holes.  Alternatively, some costs may be charged to impairment expense if the fair value of proved reserves discovered is less than the capitalized cost.

Depreciation, depletion and amortization increased $23.2 million to $141.8 million for 2014 as compared to an expense of $118.6 million for 2013. On a per unit basis, this expense increased 8% from $19.53 to $21.12 per BOE for 2013 and 2014, respectively. The rate is a function of capitalized costs of proved properties, proved reserves and production by field.

Impairment expense decreased $68.3 million to $74.9 million in 2014 from $143.2 million in 2013. This expense varies with the results of exploratory and development drilling, as well as with well performance and price declines which may render some projects uneconomic, resulting in impairment. See “Critical Accounting Policies and Estimates — Impairment” below for more details related to impairment. The decreasing trend in natural gas prices resulted in a significant impairment in 2014, primarily due to extremely low prices for natural gas.  The impairments in 2014 were primarily due to write-downs of both prospect costs and developed fields.  Prospects impaired included three projects in West Virginia  and South Louisiana, for which impairment totaled approximately $0.7 million. Several developed fields were impaired due to downward revisions in reserves based on both performance and on development drilling results that were below expectations.  The most significant of these were in South Louisiana $31.6 million, East Texas $28.6 million and South Texas $9.6 million. 

Accretion expense is related to our obligation for retirement of oil and natural gas wells and facilities. We record these liabilities when we place the assets in service, using discounted present values of the estimated future obligation. We then record accretion of the liabilities as they approach maturity. Accretion expense was $2.2 million and $2.1 million in 2014 and 2013, respectively.

General and administrative expense increased $22.2 million to $69.2 million in 2014 from $47.0 million in 2013. The increase is primarily due to non-recurring capital restructuring expenditures of $13.9 million, increases in salary and benefits totaling $7.1 million primarily due to increased headcount, performance bonus and deferred compensation expense, and settlement expense of $3.4 million.  These increases were partially offset by a decrease in other corporate expenditures of $2.3 million. On a per unit basis, general and administrative expenses increased 33% from $7.74 to $10.30 per BOE for 2013 and 2014, respectively.

Interest expense, net increased $0.7 million to $55.8 million in 2014 from $55.1 million in 2013. This increase is primarily due to higher interest of $0.7 million on our credit facility during 2014 as compared to 2013 due to higher outstanding balances.

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Results of Operations: Year Ended December 31, 2013 v. Year Ended December 31, 2012

 

 

 

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Revenues

Oil revenues for the year ended December 31, 2013 increased $76.0 million, or 34%, to $297.8 million from $221.8 million for 2012. The increase in revenue was attributable to increased production volumes partially offset by a slightly lower average price. Approximately $78.7 million of the increase in oil revenues in 2013 was due to an increase in production of 759 MBbls, or 36% over the same period in 2012. This increase is primarily due to new production from our Eagleville field, which increased 354 MBbls, from 652 MBbls in 2012 to 1,006 MBbls in 2013, and our Weeks Island field, which increased production by 312 MBbls, from 741 MBbls in 2012 to 1,053 MBbls in 2013. Our Sooner Trend field in Oklahoma also increased production by 120 MBbls, from 186 MBbls in 2012 to 306 MBbls in 2013. The average price of oil exclusive of settlements of derivative contracts decreased 1% resulting in a decrease in oil revenues of approximately $2.7 million.  The overall price including settlements of derivative contracts decreased 2% from $103.18 per Bbl in 2012 to $100.67 per Bbl in 2013.

Natural gas revenues for the year ended December 31, 2013 increased $3.8 million, or 7%, to $61.4 million from $57.6 million for 2012. The increase in natural gas revenue was attributable to higher average prices partially offset by decreased production volumes during 2013. The average price of natural gas exclusive of settlements of derivative contracts increased 37% in 2013 from $2.69 per Mcf in 2012 to $3.68 per Mcf in 2013 resulting in an increase in natural gas revenues of approximately $16.5 million.  The overall price including settlements from derivative contracts increased 14% from $4.49 per Mcf in 2012 to $5.14 per Mcf in 2013.  This increase was partially offset by a decrease in production of 4.7 Bcf resulting in decreased natural gas revenues of $12.7 million.  This decline is primarily due to an emphasis on liquids-rich assets in our capital spending. Hilltop field, our largest natural gas field in 2013, produced 5.8 Bcf in 2013, compared to 10.0 Bcf in 2012.  We curtailed capital expenditures in the field in both 2012 and 2013, leading to production declines unmitigated by new production.   In addition, we sold a substantial portion of our working interest in the field, comprising approximately 11.2 BCFE, in October 2013.  

Natural gas liquids revenues decreased during 2013 to $15.3 million from $15.6 million for 2012. A 9% increase in volumes from 365 MBbls in 2012 to 398 MBbls in 2013 was offset by a decrease in our average price of 10%, from $42.75 per Bbl in 2012 to $38.37 per Bbl in 2013. The increase in volume is due primarily to an increase in production in the Eagleville field during 2013 of 30 MBbls.  The decline in prices is due to increased supply of natural gas liquids as a result of increased liquids-targeted drilling.

In 2013, we revised our reporting for natural gas liquids produced in our Oklahoma properties.  Whereas we had previously reported all volumes and revenues for 2012 as attributable to a single stream of rich natural gas, we began recording revenues for natural gas liquids from Oklahoma separately in 2013.  For comparability, we reclassified approximately $3.3 million in revenues from natural gas to natural gas liquids for the year 2012.  The related volumetric reclassification included a reduction of 397 MMcf of natural gas produced, and an addition of 92 MBbls of natural gas liquids produced for the year 2012.  These reclassifications had no impact on previously reported total revenues, net income, cash flows, or partners’ capital (deficit).    The analysis of the increase in revenues from 2012 to 2013 included herein is based on the figures for each year after reclassifications.

Other revenues were $1.2 million during 2013 as compared to $4.6 million during 2012. The decrease is partially the result of a decrease in rental income from our drilling rig, which we sold during the third quarter of 2013. In addition, other revenues in 2012 reflect $2.0 million in sales of prospects, which did not recur in 2013.

Loss on sale of assets of $2.7 million in 2013 was primarily related to the sale of a well in South Texas and to the sale of our drilling rig.  The sale of a portion of our Hilltop field did not result in a material gain or loss.

Gain (loss) - oil and natural gas derivative contracts was a loss of $17.2 million for 2013 as compared to a loss of $19.8 million for 2012. The significant fluctuation from period to period is due to the volatility of oil and natural gas prices, changes in our outstanding hedging contracts during these periods, and revisions to our presentation of oil, gas and natural gas liquids revenues for 2014 and 2013.

Expenses

Lease and plant operating expense increased $1.4 million to $70.4 million in 2013 as compared to $69.0 million in 2012. On a unit basis, lease and plant operating expense increased 2% from $11.38 per BOE to $11.60 per BOE for 2012 and 2013, respectively. In general, lease operating expenses are higher for liquids-rich properties. Oil as a percentage of production on an equivalent basis increased from 35% in 2012 to 48% in 2013. Natural gas as a percentage of equivalent production during the same periods decreased from 59% to 46%. Components of the expense that reflected increases included chemical and fuel usage and field services, totaling $4.4 million.  The increase was partially offset by a decrease in marketing and gathering fees of $3.3 million. The marketing and gathering decrease is primarily due to lower production of natural gas in our Hilltop field.

Production and ad valorem taxes increased $2.9 million to $26.4 million, or 12%, for 2013, as compared to $23.5 million for 2012.  Production taxes increased $5.3 million, primarily due to the shift in product mix to a higher percentage of oil.  Oil revenues for

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2013 reflect an increase of $71.0 million over oil revenues for 2012.  Ad valorem taxes decreased $2.4 million primarily due to adjustments based on final property tax assessments for 2012. On a per unit basis, the total expense increased to $4.34 per BOE for 2013 from $3.87 per BOE for 2012. 

Workover expense increased $0.9 million to $13.6 million from $12.7 million for 2013 and 2012, respectively. This expense varies depending on activities in the field and is attributable to many different properties.

Exploration expense includes the costs of our geology department, costs of geological and geophysical data, delay rentals, expired leases, and dry holes. Exploration expense increased $11.2 million to $33.1 million for 2013 from $21.9 million for 2012. The majority of the increase was due to an increase of $6.8 million in dry hole costs, primarily related to a well in South Louisiana during the third quarter of 2013, and to an increase in delay rentals and expired lease expense of $4.5 million. As of December 31, 2013, our property, plant, and equipment balance includes $18.4 million in exploratory well costs which are deferred, pending determination of proved reserves.  Such costs will be charged to exploration expense if the wells are ultimately classified as dry holes.  Alternatively, some costs may be charged to impairment expense if the fair value of proved reserves discovered is less than the capitalized cost.

Depreciation, depletion and amortization increased $9.3 million to $118.6 million for 2013 as compared to an expense of $109.3 million for 2012. On a per unit basis, this expense increased to $19.53 per BOE from $18.01 per BOE for 2013 and 2012, respectively. The rate is a function of capitalized costs of proved properties, proved reserves and production by field.

Impairment expense increased $47.0 million to $143.2 million in 2013 from $96.2 million in 2012. This expense varies with the results of exploratory and development drilling, as well as with well performance and price declines which may render some projects uneconomic, resulting in impairment. See “Critical Accounting Policies and Estimates — Impairment” below for more details related to impairment. The decreasing trend in natural gas prices resulted in a significant impairment in 2012, primarily due to extremely low prices for natural gas.  The impairments in 2013 were primarily due to write-downs of both prospect costs and developed fields.  Prospects impaired included three projects in Texas, West Virginia, and South Louisiana, for which impairment totaled approximately $46 million. Several developed fields were impaired due to downward revisions in reserves based on both performance and on development drilling results that were below expectations.  The most significant of these were our Urbana field in East Texas, written down approximately $37 million, the Hayes and South Hayes field in South Louisiana, written down approximately $18 million, our Cold Springs field in East Texas, written down approximately $14 million, and our Hilltop field in East Texas, written down approximately $12 million.  Urbana and Cold Springs fields  were also impacted by decreases in prices for natural gas liquids, ethane in particular.

Accretion expense is related to our obligation for retirement of oil and natural gas wells and facilities. We record these liabilities when we place the assets in service, using discounted present values of the estimated future obligation. We then record accretion of the liabilities as they approach maturity. Accretion expense was $2.1 million and $1.8 million in 2013 and 2012, respectively.

General and administrative expense increased $6.8 million to $47.0 million in 2013 from $40.2 million in 2012. The increase is primarily due to increases in salary and benefits totaling $7.1 million that were due to increased headcount and bonuses, and to bad debt expense of $1.1 million.  These increases were partially offset by a decrease in consulting expenses of $1.0 million. On a per unit basis, general and administrative expenses increased from $6.63 per BOE in 2012 to $7.74 per BOE in 2013.

Interest expense, net increased $13.3 million to $55.1 million in 2013 from $41.8 million in 2012. This increase is primarily due to higher interest of $11.6 million on our senior notes. In October 2012, we issued an additional $150 million of the senior notes. Interest on our credit facility increased $1.6 million during 2013 as compared to 2012 due to higher outstanding balances.

Litigation settlement is related to the settlement of our litigation with Gastar, under which Gastar paid us $1.3 million in damages in 2012.

Liquidity and Capital Resources

Our principal requirements for capital are to fund our day-to-day operations, our exploration and development activities, and to satisfy our contractual obligations, primarily for the payment of debt interest and any amounts owed during the period related to our hedging positions.

Our 2014 capital budget was primarily focused on the development of existing core areas through exploitation and development. Currently, we plan to spend a total of approximately $148 million during 2015 for exploration and development, of which approximately 80% is allocated to our properties in Sooner Trend, Weeks Island Complex and Eagle Ford Shale.  We reduced our anticipated capital expenditures for 2015 in response to the significant decline in oil prices in 2014 and in order to preserve our liquidity.  Our future drilling plans, plans of our drilling operators and capital budgets are subject to change based upon various factors, some of which are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, actions of our operators, gathering system and pipeline

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transportation constraints and regulatory approvals. Because a large percentage of our acreage is held by production, we have the ability to materially decrease our drilling and recompletion budget in response to market conditions with decreased risk of losing significant acreage.

We expect to fund our 2015 capital budget predominantly with cash flows from operations, supplemented by borrowings under our credit facility.  If necessary, we may also access capital through proceeds from potential asset dispositions and the future issuances of debt and/or equity securities, subject to the distribution of proceeds therefrom as set forth in our partnership agreement. We strive to maintain financial flexibility and may access capital markets as necessary to maintain substantial borrowing capacity under our senior secured revolving credit facility, facilitate drilling on our large undeveloped acreage position and permit us to selectively expand our acreage position. In the event our cash flows are materially less than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may curtail our capital spending.

Senior Notes

We have $450 million in outstanding registered senior notes due October 15, 2018 that carry a stated interest rate of 9.625% and an effective interest rate of 9.7825%.  Interest is payable semi-annually each April 15th and October 15th.  The senior notes are unsecured and are general obligations of the Company, and effectively rank junior to any of our existing or future secured indebtedness, which includes the credit facility. The senior notes are unconditionally guaranteed on a senior unsecured basis by each of our material subsidiaries.

The senior notes contain an optional redemption provision available beginning October 15, 2015 allowing us to retire the principal outstanding, in whole or in part, at 102.406%.  Additional optional redemption provisions allow for retirement at 100.0% beginning on October 15, 2016.

Credit Facility

We have a senior secured revolving credit facility (“credit facility”) with Wells Fargo Bank, N.A. as the administrative agent, which matures May 23, 2016. As of December 31, 2014, the credit facility was subject to a $375 million borrowing base limit, and we had $319.5 million outstanding under the credit facility. Our restricted subsidiaries are guarantors of the credit facility.

The borrowing base is redetermined each May 1 and November 1. During the first quarter of 2014, the borrowing base was reduced from $385 million to $285 million as a result of the sale of a portion of our Eagleville properties, and the cash proceeds from the sale were used to pay down the outstanding balance under the credit facility.  The borrowing base was increased to $350 million as of August 5, 2014 and again on November 1, 2014 to $375 million.  As of March 26, 2015, outstanding borrowing under the credit facility was $310.5 million, letters of credit totaling $0.9 million were outstanding, and the available unused portion of the borrowing base was $63.6 million.  If oil and natural gas prices remain at current levels, we anticipate that the borrowing base under our senior secured revolving credit facility may be reduced.    

Our credit facility provides for two alternative interest rate bases and margins. Eurodollar loans accrue interest generally at the one-month London Interbank Offered Rate plus a margin ranging from 2.00% to 2.75%, depending on the utilization of our borrowing base. “Reference rate” loans accrue interest at the prime rate of Wells Fargo Bank, N.A., plus a margin ranging from 1.00% to 1.75%, depending on the utilization of our borrowing base. The average rate on all loans outstanding as of December 31, 2014 under the credit facility was 2.89%, which was based on the Eurodollar option.

The credit facility and the indenture governing the senior notes and additional senior notes include covenants requiring us to maintain certain financial covenants including a current ratio, leverage ratio, and interest coverage ratio. At December 31, 2014, we were in compliance with the covenants. The terms of the credit facility also restrict our ability to make distributions and investments.

Cash Flows Provided by Operating Activities

Operating activities provided cash of $184.9 million in 2014, as compared to $172.5 million in 2013. The $12.4 million increase in operating cash flows was attributable to various factors. Cash-based items of net income, including revenues (exclusive of unrealized commodity gains or losses), operating expenses and taxes, general and administrative expenses, and the cash portion of our interest expense, resulted in a net increase of approximately $11.4 million in earnings and a positive impact on cash flow. The changes in our working capital accounts provided $2.2 million as compared to having provided $1.2 million in cash in 2013.

Operating activities provided cash of $172.5 million in 2013, as compared to $147.2 million for 2012. The $25.3 million increase in operating cash flows was attributable to various factors. Cash-based items of net income, including revenues (exclusive of unrealized commodity gains or losses), operating expenses and taxes, general and administrative expenses, and the cash portion of our interest expense, resulted in a net increase of approximately $31.3 million in earnings and a positive impact on cash flow. This was partially offset by changes in our working capital accounts, which provided $1.2 million of cash flows as compared to having provided

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$7.2 million in cash in 2012. This reduction resulted in a total decrease of $6.0 million in cash flow from changes in working capital, which as noted above, partially offset the positive effects of increased cash items in our earnings.

Cash Flows Used in Investing Activities

Investing activities used cash of $155.7 million for the year ended December 31, 2014 as compared to cash used in investing of $336.1 million for the year ended December 31, 2013. The decrease in cash used in investing activities was primarily related to proceeds from sale of assets partially offset by increased expenditures for drilling and development.  In 2014, the sale of a portion of our interest in our Eagleville field provided net proceeds of approximately $168.0 million; the sale of our remaining interests in the Hilltop field provided net proceeds of approximately $41.6 million; and the sale of our interest in the Anne Parsons field in East Texas provided proceeds of approximately $8.6 million.  In the third quarter of 2014, we placed the net proceeds from our sale of Hilltop field into a restricted cash account with a qualified intermediary available for use in a like-kind exchange under Section 1031 of the U.S. Internal Revenue Code.  As of December 31, 2014, the investment of funds in this restricted cash account, net of expenditures for qualifying property during the period, resulted in a use of cash of $24.6 million.  There is no comparable investment in restricted cash in 2013. 

Investing activities used cash of $336.1 million for the year ended December 31, 2013 as compared to cash used in investing of $255.1 million for the year ended December 31, 2012. The increase in cash used in investing activities was primarily related to increased expenditures for drilling and development.  Significant acquisitions expenditures in 2013 included $42.2 million for additional interest in our Weeks Island field from our former working interest partner, Stone Energy Offshore, L.L.C., with additional expenditures for several smaller properties for a total of $51.4 million.  Acquisitions in 2012 totaling $30.3 million were for various smaller packages of producing properties.

Cash Flows Provided by Financing Activities

Financing activities used cash of $0.4 million during 2014 as compared to cash provided by financing of $164.4 million during 2013, a decrease of $164.8 million.  During 2014, we used proceeds from the Eagleville divesture to reduce the outstanding balance under our credit facility of $169.3 million, although we also drew down $169.5 million. The increase in 2013 reflected the effect of a drawdown from our credit facility.

Financing activities provided cash of $164.4 million during 2013 as compared to cash provided by financing of $111.0 million during 2012, an increase of $53.4 million. Both periods reflected the effect of drawdowns from our credit facility.

Risk Management Activities — Commodity Derivative Instruments

Due to the risk of low oil and natural gas prices, we periodically enter into price-risk management transactions (e.g., swaps, collars, puts, calls, and financial basis swap contracts) for a portion of our oil and natural gas production. In certain cases, this allows us to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. The commodity derivative instruments apply to only a portion of our production, and provide only partial price protection against declines in oil and natural gas prices, and may partially limit our potential gains from future increases in prices. At December 31, 2014, commodity derivative instruments were in place covering approximately 74% of our projected oil production and approximately 120% of our natural gas production from proved developed properties for 2015. See Note 6 to our consolidated financial statements as of December 31, 2014, “Derivative Financial Instruments”, for further information.

Contractual Obligations

The following table summarizes our contractual obligations as of December 31, 2014:

 

 

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In addition to the items above, we have a contingent commitment to pay an amount up to a maximum of approximately $2.2 million for properties acquired in 2008 and prior years. The additional purchase consideration will be paid if certain product price conditions are met. We have a commitment in which we must make a contingent payment of up to $2.0 million if we decide to forego certain drilling activities.

Off-Balance Sheet Arrangements

As of December 31, 2014 we had no guarantees of third party obligations. Our off-balances sheet obligations include the obligations under operating leases, the $2.2 million contingent properties payment, and the $2.0 million drilling commitment noted in “Contractual Obligations” above.  We also have bonds posted in the aggregate amount of $24.2 million, primarily to cover future abandonment costs, and $0.9 million in letters of credit provided under our credit facility.  We typically enter into short-term drilling contracts which are customary in the oil and gas industry.  We have no other off-balance sheet arrangements that are reasonably likely to materially affect our liquidity and capital resources.

We have no plans to enter into any additional off-balance sheet arrangements in the foreseeable future.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). As used herein, the following acronyms have the following meanings: “FASB” means the Financial Accounting Standards Board; the “Codification” refers to the Accounting Standards Codification, the collected accounting and reporting guidance maintained by the FASB; “ASC” means Accounting Standards Codification and is generally followed by a number indicating a particular section of the Codification; and “ASU” means Accounting Standards Update, followed by an identification number, which are the periodic updates made to the Codification by the FASB.

The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and natural gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the most significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under accounting principles generally accepted in the United States. We also describe the most significant estimates and assumptions we make in applying these policies.

Use of Estimates. The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.

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Reserve estimates significantly impact depreciation and depletion expense and potential impairments of oil and natural gas properties and are subject to change based on changes in oil and natural gas prices and trends and changes in estimated reserve quantities. We analyze estimates, including those related to oil and natural gas reserves, the value of oil and natural gas properties, oil and natural gas revenues, bad debts, asset retirement obligations, derivative contracts, income taxes and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates.

Property and Equipment. Oil and natural gas producing activities are accounted for using the successful efforts method of accounting. Under the successful efforts method, lease acquisition costs and all development costs, including unsuccessful development wells, are capitalized.

Unproved Properties — Acquisition costs associated with the acquisition of leases are recorded as unproved properties and capitalized as incurred. These consist of costs incurred in obtaining a mineral interest or right in a property, such as a lease in addition to options to lease, broker fees, recording fees and other similar costs related to activities in acquiring properties. Unproved properties are classified as unproved until proved reserves are discovered, at which time related costs are transferred to proved oil and natural gas properties.

Exploration Expense — Exploration expenses, other than exploration drilling costs, are charged to expense as incurred. These expenses include seismic expenditures and other geological and geophysical costs, expired leases, and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized pending determination of whether the well has discovered proved commercial reserves. If the exploratory well is determined to be unsuccessful, the cost of the well is transferred to expense. Exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made.

Proved Oil and Natural Gas Properties — Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering, and storing oil and natural gas are capitalized. All costs incurred to drill and equip successful exploratory wells, development wells, development-type stratigraphic test wells, and service wells, including unsuccessful development wells, are capitalized.

Impairment — The capitalized costs of proved oil and natural gas properties are reviewed at least quarterly for impairment following the guidance provided in ASC 360-10-35, Property, Plant and Equipment, Subsequent Measurement, whenever events or changes in circumstances indicate that the carrying amount of a long-lived asset or asset group exceeds its fair market value and is not recoverable. The determination of recoverability is based on comparing the estimated undiscounted future net cash flows at a producing field level to the carrying value of the assets. If the future undiscounted cash flows, based on estimates of anticipated production from proved reserves and future crude oil and natural gas prices and operating costs, are lower than the carrying cost, the carrying cost of the asset or group of assets is reduced to fair value. For our proved oil and natural gas properties, we estimate fair value by discounting the projected future cash flows at an appropriate risk-adjusted discount rate.

Unproved properties are assessed at least annually to determine whether they have been impaired. Individually significant properties are assessed for impairment on a property-by-property basis, while individually insignificant unproved leasehold costs may be assessed in the aggregate. If unproved leasehold costs are found to be impaired, an impairment allowance is provided and a loss is recognized in the consolidated statement of operations.

Depreciation, Depletion and Amortization — Depreciation, depletion and amortization (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method based upon estimated proved reserves. Assets are grouped for DD&A on the basis of reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for lease and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves.

Revenue Recognition. We recognize oil, natural gas and natural gas liquids revenues when products are delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured. We use the sales method of accounting for recognition of natural gas imbalances. Revenue from the drilling rig has been recorded when services were performed.  The drilling rig was sold in 2013. 

Derivative Financial Instruments. We use derivative contracts to hedge the effects of fluctuations in the prices of oil, natural gas and interest rates. We account for such derivative instruments in accordance with ASC 815, Derivatives and Hedging, which establishes accounting and disclosure requirements for derivative instruments and requires them to be measured at fair value and recorded as assets or liabilities in the consolidated balance sheet (see Note 5 of the accompanying Notes to Consolidated Financial Statements for further information on fair value).

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Under ASC 815, hedge accounting is used to defer recognition of unrealized changes in the fair value of such financial instruments, for those contracts which qualify as fair value or cash flow hedges, as defined in the guidance. Historically, we have not designated any of our derivative contracts as fair value or cash flow hedges. Accordingly, the changes in fair value of the contracts are included in earnings as “Gain (loss) — oil and natural gas derivative contracts.”  Cash flows from settlements of derivative contracts are classified as operating cash flows.   All gains, losses, and settlements related to interest rate swaps are included in interest expense; cash flows related to interest rate swaps are included in operating cash flows.

Income Taxes. We have elected under the Internal Revenue Code provisions to be treated as individual partnerships for tax purposes. Accordingly, items of income, expense, gains and losses flow through to the partners and are taxed at the partner level. Accordingly, no tax provision for federal operations taxes is included in the consolidated financial statements.

We are subject to the Texas margin tax, which is considered a state income tax, and is included in “Benefit from (provision for) state income tax” on the consolidated statement of operations. We record state income tax (current and deferred) based on taxable income as defined under the rules for the margin tax.

Acquisitions. Acquisitions are accounted for as purchases using the acquisition method of accounting. Accordingly, the results of operations are included in our consolidated statements of operations from the closing date of the acquisitions. Purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair value at the time of the acquisition.

Asset Retirement Obligations. We estimate the present value of future costs of dismantlement and abandonment of our wells, facilities, and other tangible, long-lived assets, recording them as liabilities in the period incurred. We follow ASC 410, Asset Retirement and Environmental Obligations. ASC 410 requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The fair value of the ARO is measured using expected future cash outflows for abandonment discounted generally at our cost of capital at the time of recognition.

Investment . Our investment consists of a 10.17% ownership interest in a drilling company, Orion Drilling Company, LLC (“Orion”). The investment is accounted for under the cost method. Under this method, our share of earnings or losses of the investment are not included in the consolidated statements of operations. Distributions from Orion are recognized in current period earnings as declared.

Deferred Financing Costs. Deferred financing costs are amortized using the straight-line method over the term of the related debt, so long as this approximates the interest rate method.

Recent Accounting Pronouncements

In April 2014, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.  ASU 2014-08 narrows the definition of “discontinued operations” to dispositions that represent a strategic shift that has or will have a significant impact on the entity’s operations and financial results.  The ASU requires additional disclosures regarding assets and liabilities held for sale, and income and losses, including gain or loss on sale, and cash flows from discontinued operations.  In addition, the ASU requires disclosures for disposals of individually significant components of the business which do not qualify as discontinued operations, including general information about the disposition and disclosure of the pretax profit or loss from the component for the period of disposal and all comparable historic periods presented.  ASU 2014-08 is effective for all fiscal years beginning after December 15, 2014, and can be adopted early for certain asset dispositions and reclassifications of assets from “held and used” to “held for sale.”  We early adopted ASU 2014-08 as of January 1, 2014 and have provided disclosures in accordance with this new guidance in Note 3. 

In May 2014, the FASB issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606).  The update provides guidance concerning the recognition and measurement of revenue from contracts with customers.  Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues.  ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2016. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. We are currently evaluating the impact of adopting this standard on our consolidated financial statements, and whether to use the full retrospective approach or the modified retrospective approach.  

In August 2014, the FASB issued Accounting Standards Update 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern.  The new standard requires management to assess the company’s ability to continue as a going

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concern.  Disclosures are required if there is substantial doubt as to the company’s continuation as a going concern within one year after the issue date of financial statements.  The standard provides guidance for making the assessment, including consideration of management’s plans which may alleviate doubt regarding the company’s ability to continue as a going concern. ASU 2014-15 is effective for years beginning after December 15, 2016.  We do not expect the adoption of this pronouncement to have a material impact on our consolidated financial statements.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

We are exposed to certain market risks that are inherent in our consolidated financial statements that arise in the normal course of business. We may enter into derivative instruments to manage or reduce market risk, but we do not enter into derivative agreements for speculative purposes.

We do not designate these derivative instruments as hedges for accounting purposes. Accordingly, the changes in the fair value of these instruments are recognized currently in earnings.

Commodity Price Risk and Hedges

Our major market risk exposure is to prices for oil, natural gas and natural gas liquids. These prices have historically been volatile. As such, future earnings are subject to change due to changes in these prices. Realized prices are primarily driven by the prevailing worldwide price for oil and regional prices for natural gas. We have used, and expect to continue to use, oil and natural gas derivative contracts to reduce our exposure to the risks of changes in the prices of oil and natural gas. Pursuant to our risk management policy, we engage in these activities as a hedging mechanism against low prices and price volatility associated with pre-existing or anticipated sales of oil and natural gas.

As of December 31, 2014, we have hedged approximately 78% of our forecasted production from proved developed reserves through 2018 at average annual floor prices ranging from $4.19 per MMBtu to $4.50 per MMBtu for natural gas and $80.00 per Bbl to $89.16 per Bbl for oil. Forecasted production from proved reserves is estimated in our December 2014 reserve report using prices, costs and other assumptions required by SEC rules. Our actual production will vary from the amounts estimated in the report, perhaps materially. Please read the disclosures under “Our estimated oil and natural gas reserve quantities and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or the underlying assumptions will materially affect the quantities and present value of our reserves” in “Item 1A. Risk Factors” above.

The fair value of our oil and natural gas derivative contracts and basis swaps at December 31, 2014 was a net asset of $87.1 million. A 10% increase or decrease in oil and natural gas prices with all other factors held constant would result in an unrealized loss or gain, respectively, in the fair value (generally correlated to our estimated future net cash flows from such instruments) of our oil and natural gas commodity contracts of approximately $20.8 million (decrease in value) or $18.6 million (increase in value), respectively, as of December 31, 2014. 

Interest Rates

We are subject to interest rate risk on our long-term fixed interest rate debt and variable interest rate borrowings. Although in the past we have used interest rate swaps to mitigate the effect of fluctuating interest rates on interest expense, we currently have no open interest rate derivative contracts. A 1% increase in interest rates (100 LIBOR basis points) would increase interest expense on our variable rate debt by approximately $3.2 million, based on the balance outstanding at December 31, 2014.

Item 8. Financial Statements and Supplementary Data

The consolidated financial statements and supplementary financial information required to be filed under this item are presented beginning on page F-1 in Part IV, Item 15 of this annual report and are incorporated herein by reference.

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

In accordance with Exchange Act Rule 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive

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Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2014 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act. We have performed an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our internal control over financial reporting. Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2014. Because of its inherent limitations, internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collision or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with established policies or procedures may deteriorate. 

Our management used the criteria set forth in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission  (2013 framework) to perform its assessment. Based on this assessment, our management, including our Chief Executive Officer and our Chief Financial Officer, concluded, that as of December 31, 2014, our internal control over financial reporting was effective based on those criteria.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the quarter ended December 31, 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers, and Corporate Governance

As is the case with many partnerships, we do not directly employ officers, directors or employees. Our operations and activities are managed by the Board of Directors of our general partner, Alta Mesa Holdings GP, LLC (“Alta Mesa GP”), and the officers and directors of Alta Mesa Services, LP (“Alta Mesa Services”), an entity wholly owned by us. References to our directors are references to the directors of Alta Mesa GP. References to our officers and employees are references to the officers and employees of Alta Mesa Services.

All of our executive management personnel are employees of Alta Mesa Services and devote all of their time to our business and affairs. We also utilize a significant number of employees of Alta Mesa Services to operate our properties and provide us with certain general and administrative services. Under the shared services and expenses agreement, we reimburse Alta Mesa Services for its operational personnel who perform services for our benefit. See “Item 13. Certain Relationships and Related Party Transactions, and Director Independence — Shared Services and Expenses Agreement.”

Board Leadership Structure

Our Chairman is Michael E. Ellis, our Chief Operating Officer and founder of the Company. Our Board of Directors has no policy regarding the separation of the positions of Chief Executive Officer and Chairman. We also do not have a lead independent director.

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Board Oversight of Risk

Like all businesses, we face risks in our business activities. Many of these risks are discussed under the caption “Risk Factors” elsewhere in this report. The Board of Directors has delegated to management the primary responsibility of risk management, while it has retained oversight of management in that regard.

In addition, our Board of Directors considers our practices regarding risk assessment and risk management, reviews our contingent liabilities, reviews our oil and natural gas reserve estimation practices, as well as major legislative and regulatory developments that could affect us. Our Board reviews and attempts to mitigate risks which may result from our compensation policies.

Executive Officers and Directors

The following table sets forth the names, ages and offices of our present directors and executive officers as of December 31, 2014. Members of our Board of Directors are elected for one-year terms.

 

 

The following is a biographical summary of the business experience of these directors and executive officers:

Harlan H. Chappelle joined Alta Mesa as President,  CEO and director in November 2004, and has led us in a period of significant growth, building a strong management and technical team, focusing us on our greatest opportunities, making strategic acquisitions, and restructuring our financing. Mr. Chappelle has over 30 years in field operations, engineering, management, marketing and trading, acquisitions and divestitures, and field re-development. He has worked for Louisiana Land & Exploration Company, Burlington Resources, Southern Company, and Mirant. Mr. Chappelle retired as a Commander from the U.S. Navy Reserve. He has a Bachelor of Chemical Engineering from Auburn University and a Master of Science in Petroleum Engineering from The University of Texas at Austin.

Don Dimitrievich was appointed to our Board of  Directors as Highbridge’s director nominee in March 2014. Mr. Dimitrievich is a Managing Director at Highbridge Principal Strategies, an alternative investment management organization that together with its affiliates manages approximately $29 billion in capital for institutional investors, pension funds, endowments and foundations.  At Highbridge, Mr. Dimitrievich oversees Highbridge Principal Strategies’ direct credit investment strategy for the energy and power sectors. Highbridge has invested over $1.5 billion in direct energy-related investments. Prior to joining Highbridge in 2012, Mr. Dimitrievich was a Managing Director of Citi Credit Opportunities, a credit-focused principal investment group. At Citi Credit Opportunities, Mr. Dimitrievich oversaw the energy and power portfolio and invested over $800 million in mezzanine, special situation and equity co-investments, and secondary market opportunities. Mr. Dimitrievich began his career as a corporate attorney in the New York office of Skadden, Arps, Slate, Meagher & Flom LLP from 1998 to 2004 focusing on energy mergers and acquisitions and capital markets transactions.  Mr. Dimitrievich also serves on the board of Energy & Exploration Partners, Inc. Mr. Dimitrievich has a Law degree with Great Distinction from McGill University in Montreal, Canada and earned a Chemical Engineering degree with Great Distinction from Queen’s University in Kingston, Canada.

Michael E. Ellis founded Alta Mesa in 1987 after beginning his career with Amoco, and is our Chairman and Chief Operating Officer, as well as Vice President of Engineering. Mr. Ellis manages all day-to-day engineering and field operations of Alta Mesa. He built our asset base by starting with small earn-in exploitation projects, then progressively growing the company with successive acquisitions of fields from major oil companies, and consistent success in exploration and development drilling. He has over 30 years’ experience in management, engineering, exploration, and acquisitions and divestitures. Mr. Ellis holds a Bachelor of Science in Civil Engineering from West Virginia University.    Mr. Ellis is the spouse of Mickey Ellis, our director. 

Mickey Ellis has served as a director since our inception in 1987. Ms. Ellis is actively involved in the leadership of charitable organizations, as a Board Member of Houston Area Respite Care and The Confessing Movement of the United Methodist Church, Treasurer of the National Charity League Star Chapter, Committee Member on several committees within Mission Bend United Methodist Church, and Building Relocation Coordinator for Mission Bend Christian Academy. She is a major fundraiser for the Susan G. Komen Foundation, and an active volunteer for CanCare. Ms. Ellis is the spouse of Michael E. Ellis, our Chairman, Chief Operating Officer and Vice President of Engineering. 

Michael A. McCabe, our CFO as well as a Vice President, joined Alta Mesa in September 2006 and became a director in 2014. Mr. McCabe has over 25 years of corporate finance experience, with a focus on the energy industry. From 2004 until 2006,

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Mr. McCabe served as President and sole owner of Bridge Management Group, Inc., a private consulting firm primarily providing advisory services to us and to MultiFuels, Inc., a Houston based developer of natural gas storage facilities. He has served in senior positions with Bank of Tokyo, Bank of New England, and Key Bank. Mr. McCabe holds a Bachelor of Science in Chemistry and Physics from Bridgewater State University, a Masters of Science in Chemical Engineering from Purdue University and a Master of Business Administration in Financial Management from Pace University.

David Murrell has served as our Vice President, Land and Business Development since 2006. Mr. Murrell is a Certified Professional Landman and has over 25 years of experience in Gulf Coast leasing, exploration and development programs, contract management and acquisitions and divestitures. He created a structured land management system for Alta Mesa, and built a team of lease analysts, landmen, and field representatives that has facilitated our company’s growth. Mr. Murrell earned a Bachelor of Business Administration in Petroleum Land Management from the University of Oklahoma.

Qualifications of Directors

Mr. Chappelle’s experience as our Chief Executive Officer since 2004, combined with his significant equity ownership of us, and over 30 years of experience in the oil and gas industry uniquely qualify him to serve as a director of our general partner.

Mr. Ellis is our founder; his experience in that capacity and as one of our executive officers since 1987 provide him intimate knowledge of our operations, finances and strategy and uniquely qualifies him to serve as the Chairman of our general partner.

Ms. Ellis’ role in working with us since our inception in 1987 provides her with valuable knowledge of our business and operations and uniquely qualifies her to serve as a director of our general partner. 

Mr. Dimitrievich provides the Board with significant financial and energy expertise which uniquely qualifies him to serve as a director of our general partner.

Mr. McCabe’s experience as our Chief Financial Officer since 2006 and over 25 years of corporate finance experience uniquely qualifies him to serve on our Board.

Audit and Compensation Committee

We do not have a formal compensation committee and our full Board serves as our audit committee. Because we do not have and are not seeking to list any securities on a national securities exchange or on an inter-dealer quotation system, we are not subject to a number of the corporate governance requirements of the SEC or of any national securities exchange or inter-dealer quotation system. For example, we are not required to have a board of directors comprised of a majority of independent directors or to have an audit committee comprised of independent directors. Accordingly, our Board of Directors has not made any determination as to whether any of the members of our Board of Directors or committees thereof would qualify as independent under the listing standards of any national securities exchange or any inter-dealer quotation system or under any other independence definition. Additionally, for the same reason, we have not yet determined whether any of our directors is an audit committee financial expert.

Code of Ethics

The Board of Directors has adopted a Code of Ethics for Senior Financial Officers. The Code of Ethics is posted on the investor relations section of our website at www.altamesa.net and is available free of charge upon written request to 15021 Katy Freeway, Suite 400, Houston, Texas 77094.

Item 11. Executive Compensation

Compensation Discussion and Analysis

This Compensation Discussion and Analysis, describes our compensation objectives and the principles underlying our compensation policy relating to 2014 compensation for our named executive officers.

Our Board of Directors is responsible for overseeing our executive remuneration programs and the fair and competitive compensation of our executive officers and meets each year to review our compensation program and to determine compensation levels for the ensuing fiscal year.

Objectives of Our Compensation Program

Our executive compensation program is intended to motivate our executive officers to achieve strong financial and operating results for us. In addition, our program is designed to achieve the following objectives:

•attract and retain highly qualified executive officers by providing reasonable total compensation levels competitive with that of executives holding comparable positions in similarly situated organizations;

•provide total compensation that is justified by individual performance; and

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•reward our executives for their contributions to our overall performance as well as for their individual performance.

What Our Compensation Program is Designed to Reward

Our strategy is to increase reserves and production by applying advanced engineering analytics and enhanced geological techniques in areas we have identified as underdeveloped and overlooked. Our compensation program is designed to reward performance that contributes to the achievement of our business strategy. In addition, we reward qualities that we believe help achieve our strategy, such as teamwork; individual performance in light of general economic and industry specific conditions; performance that supports our core values; resourcefulness; the ability to manage our existing corporate assets; the ability to explore new avenues to increase oil and natural gas production and reserves; level of job responsibility; and tenure with us.

Elements of Our Compensation Program and Why We Pay Each Element

To accomplish our objectives, our compensation program is comprised of the following elements: base salary, cash bonus, long term incentives and benefits. Our Board of Directors approved and adopted a deferred compensation and supplemental executive retirement plan in 2013 and a performance appreciation rights plan in 2014.

We pay base salary in order to recognize each executive officer’s unique value and historical contributions to our success in light of salary norms in the industry and the general marketplace; to match competitors for executive talent; to provide executives with sufficient, regularly-paid income; and to reflect an executive’s position and level of responsibility.

We include an annual cash bonus as part of our compensation program because we believe this element of compensation helps to motivate executives to achieve key corporate objectives by providing annual recognition of achievement. The annual cash bonus also allows us to be competitive from a total remuneration standpoint.

We provide a deferred compensation and supplemental retirement plan to certain key employees, including all our executive officers, to provide additional flexibility and tax planning advantages to them.  In addition, the retirement benefits enhance employee compensation on a discretionary basis and encourage their continued service to us.

We grant performance appreciation rights units as long term compensation to certain key employees, including our executive officers, who make significant contributions to us.  The units are payable on a fixed determination date between five and ten years from the date of the award, and therefore, provide the grantee with a significant interest in us tied to long-term performance.

We offer benefits such as a 401(k) plan and payment of insurance premiums in order to provide a competitive remuneration package as well as a measure of financial security to our employees.  In 2013 we introduced a deferred compensation plan offered to all employees, to provide flexibility and tax planning advantages to them.

How We Determine Each Element of Compensation

In determining the elements of compensation, we consider our ability to attract and retain executives as well as various measures of company and industrial performance including debt levels, revenues, cash flow, capital expenditures, reserves of oil and natural gas and costs. We did not retain a consultant with respect to determining 2014 compensation.

Messrs. Ellis, Chappelle, McCabe, and Murrell are parties to employment agreements with Alta Mesa Services. The employment agreements automatically renew annually, subject to prior notice of cancellation by either Alta Mesa Services or the executive. These employment agreements establish set minimum base salaries for each officer.  On March 25, 2014, these employment agreements were amended and restated and the salaries for each officer were set at $485,000, $485,000, $435,000, and $360,000 per annum, to Messrs. Ellis, Chappelle, McCabe and Murrell, respectively, which we believe are competitive with other independent oil and natural gas companies with whom we compete for managerial talent. In addition, the employment agreements provide that the executives are each entitled to an annual bonus equal to a percentage of his respective annual base salary if performance criteria set by the Board for the applicable period are met. The agreements also provide for benefits such as reimbursement of business expenses and participation in employee benefit plans.

Base salary. In reviewing base salaries, the Board takes into account a combination of subjective factors, primarily relying on their own personal judgment and experience. Subjective factors the Board considers include individual achievements, our performance, level of responsibility, experience, leadership abilities, increases or changes in duties and responsibilities and contributions to our performance. Mr. Ellis and Mr. Chappelle participate in and are present during the Board’s review and determination of their respective base salaries. For 2014, the Board set the base salaries for Messrs. Ellis, Chappelle and McCabe at $485,000, $485,000 and $435,000, respectively. In addition, the Board determined Mr. Murrell’s salary of $360,000 for 2014 was appropriate.

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Bonus.  A portion of each executive’s total compensation may be paid as bonus compensation. The Board takes into consideration our achievements during the year and each executive’s contribution toward such achievements. While performance criteria may be set, the Board takes into account subjective factors in determining if these criteria were met. Bonuses for any one year are usually determined and paid in the second or third quarter of the following year. Accordingly, bonus compensation for our executive officers for 2014 has not yet been determined,  other than for Mr. McCabe whose 2014 bonus of $400,000 was approved and paid in January 2015. However, bonuses paid in 2014 for 2013 performance ranged from approximately 87% to 235% of base salary.

On September 23, 2014, the Board of Directors approved and adopted a long term compensation plan, the Alta Mesa Holdings, LP Amended and Restated Performance Appreciation Rights Plan (the “PARs Plan”) effective September 24, 2014, to provide long term incentive compensation to key employees and consultants who make significant contributions to us to align our employees with our long term performance. The PARs Plan is administered by the Board, which will determine from time to time which participants will participate in the PARs Plan, the number of PARs to be granted to each participant, the initial stipulated designated value of each PAR, the designated value of each PAR as of its valuation date, the vesting schedule of each PAR, and any other terms and conditions of the PAR award. Under the PARs Plan, there are special provisions for accelerated vesting and valuation of a PAR award in the event of a Liquidity Event as follows: (i) a sale of the all of the assets of High Mesa, (ii) a disposition of all of the equity securities of High Mesa, (iii) an initial public offering of the equity securities of High Mesa or any of its subsidiaries that hold all or substantially all of the assets or (iv) a public offering resulting in gross proceeds of at least $300,000,000.  

A total of one million (1,000,000) PARs are available for grants to participants under the PARs Plan. The aggregate designated value of all 1,000,000 PARs is equal to ten percent (10%) of the fair market value of the aggregate interests of all the Class A Limited Partners in Alta Mesa GP.

Absent an intervening Liquidity Event, payment of a PAR award is made on the fixed determination date elected in advance by the recipient of the PAR award, with such fixed determination date occurring no earlier than five years and no later than ten years from the grant date. All payments made under the PARs Plan in any year are subject to a floating annual cap on the amount of all PAR awards paid under the PARs Plan in a given year (the “Annual Cap”). The Annual Cap is equal to 2.5% multiplied by the fair market value of the aggregate interests of all the Class A Limited Partners in Alta Mesa GP minus $400,000,000 (i.e., [2.50% x (FMV - $400,000,000)]. If the Annual Cap applies in a year, the amount payable to a PAR award holder on the fixed determination date is his pro-rata amount of the aggregate payments to be made on that date as adjusted for the amount of Annual Cap remaining for that year. Any amounts in excess of the Annual Cap are paid in the next following year, again subject to the Annual Cap.

Upon the occurrence of a payment event, the participant will be entitled to receive a cash amount equal to the increase, if any, between the initial stipulated designated value of the PAR as of its grant date and the designated value of the PAR as of its payment valuation date. No PARs will be settled in shares; rather, all PAR exercises will be settled solely in cash. Participants will have no rights whatsoever as a shareholder of Alta Mesa GP or of a subsidiary in respect of any PARs.

In 2014, the Board awarded 60,000 PARs to Michael A McCabe, of which 50,000 units vested immediately, and the remaining 10,000 units vest over a three year period.  The stipulated initial designated value (“SIDV”) is $10.00 per unit, and payout is based on the increase of the value of the units over the SIDV as determined at the earlier of a liquidity event at High Mesa or at a fixed determination date which is at least five years from the date of issuance of the award.  The Board also granted 15,000 PARs to David Murrell, which vest over a five year period.  The SIDV of 10,000 of the units is $40 per unit, and the remaining 5,000 units have a SIDV of $30 per unit and payout is based on the increase of the value of the units over the SIDV at the earlier of a liquidity event at High Mesa or at a fixed determination date which is at least five years from the date of issuance of the award. 

Benefits.  We provide company benefits or perquisites that we believe are standard in the industry to all of our employees. These benefits consist of a group medical and dental insurance program for employees and their qualified dependents and a 401(k) employee savings and protection plan. The costs of these benefits are paid for entirely by us. We do not provide employee life insurance amounts surpassing the Internal Revenue Service maximum. We make matching contributions to the 401(k) contribution of each qualified participant. We pay all administrative costs to maintain the plan. In addition, we provide Messrs. Ellis, Chappelle, McCabe, and Murrell with company automobiles. Beginning annually in 2014, we will also reimburse each officer up to $5,000 annually for tax preparation and planning.

Nonqualified Deferred Compensation. We established a nonqualified deferred compensation plan in 2013, the Alta Mesa Holdings, L.P. Supplemental Executive Retirement Plan (the “Retirement Plan”), to provide additional flexibility and tax planning advantages to our executives and other key highly compensated employees.  The terms of such contributions may include a specified vesting schedule, intended to encourage continuous service to us.  If no schedule is specified with the award, the Retirement Plan provides for vesting based on years of service, with full vesting at three years.  Participants may withdraw vested funds from the Retirement Plan in accordance with the distribution schedule established when the contributions are elected or awarded, with the option of deferring a very short time or until retirement.  In 2014, one elective employer contribution was made for the account of

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Michael A. McCabe in the amount of $3.0 million.  The Board of Directors elected to make this distribution subject to a three-year vesting schedule, with 50% vested immediately and 16.67% to vest each subsequent year.

Other Compensation. As part of his employment agreement, we provide Mr. McCabe an apartment near our headquarters and pay his commuting expenses to and from his permanent home to Houston. In 2014, these housing and commuting expenses totaled approximately $114,000. We agreed to provide these benefits to Mr. McCabe because our Board believed it was necessary to retain Mr. McCabe’s services despite the fact that his permanent residence is outside of the Houston area. The Board considered the value of this additional compensation in evaluating Mr. McCabe’s total compensation package.

How Elements of Our Compensation Program are Related to Each Other

We view the various components of compensation as related but distinct and emphasize “pay for performance” with a portion of total compensation reflecting a risk aspect tied to our financial and strategic goals. We determine the appropriate level for each compensation component based in part, but not exclusively, on our view of internal equity and consistency, and other considerations we deem relevant, such as rewarding extraordinary performance.

Assessment of Risk

Our Board takes risk into account when making compensation decisions and has concluded that the executive compensation program as it is currently structured does not encourage excessive risk or unnecessary risk-taking.

Accounting and Tax Considerations

We have structured our compensation program to comply with Internal Revenue Code Section 409A. If an executive is entitled to nonqualified deferred compensation benefits that are subject to Section 409A, and such compensation does not comply with Section 409A, then the benefits are taxable in the first year they are not subject to a substantial risk of forfeiture. In such case, the service provider is subject to regular federal income tax, interest and an additional federal income tax of 20% of the benefit includible in income.

Under the PARs Plan, participants are granted Performance Appreciation Rights (“PARs”) with a stipulated initial value.  The PARs vest over time (as specified in each grant, typically five years) and entitle the owner to receive a cash amount equal to the increase, if any, between the initial stipulated value and the designated value of the PAR on the payment valuation date.  The payment valuation date is the earlier of a liquidity event (as defined in the Plan, but generally intended to be either a recapitalization or an initial public offering of Company equity) or as selected by the participant, but no earlier than five years from the end of the year of the grant.  In the case of a liquidity event, the designated value of all PARs is to be based on the net sale proceeds (as defined in the Plan) from the liquidity event.  After any payment valuation date, regardless of payment or none, vested PARs expire.  We are unable to express an opinion with respect to the likelihood of a qualifying liquidity event which would result in any payment under the Plan or to estimate any amount which may become payable under the Plan.  We consider the possibility of payment at a fixed determination date absent a positive liquidity event to be remote.  Therefore, we have not provided any amount for this contingent liability in our consolidated financial statements at December 31, 2014.

Compensation Committee Report

As we do not have a formal compensation committee, our entire Board of Directors serves as our compensation committee. Our Board of Directors has reviewed and discussed the above Compensation Discussion and Analysis with management and, based on such review the related discussions and such other matters deemed relevant and appropriate to the Board of Directors, and the Board of Directors recommended that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.

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Summary Compensation

The following table summarizes, with respect to our named executive officers, information relating to the compensation earned for services rendered in all capacities during the fiscal years ended December 31, 2014, 2013 and 2012.  None of the named executive officers participate in a defined benefit pension plan.

 

 

 

 

 

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Narrative Disclosure to Summary Compensation Table

Employment agreements

Mr. Chappelle

Mr. Chappelle entered into an amended and restated employment agreement on March 25, 2014 that provides that he will act as President and Chief Executive Officer until March 25, 2018, subject to automatic one year renewals of the term if neither party submits a notice of termination at least 60 days prior to the end of the then-current term. This agreement may be terminated by either party, at any time, subject to severance obligations in the event Mr. Chappelle is terminated by us without cause or he dies or is disabled.

Mr. Chappelle’s employment agreement provides for a minimum base salary of $485,000 and an annual bonus equal to a percentage of his base salary paid during each such annual period, such percentage to be established by our Board of Directors in the Board’s sole discretion.

Mr. Ellis

Mr. Ellis entered into an amended and restated employment agreement on March 25, 2014 that provides that he will act as Vice President and Chief Operating Officer until March 25, 2018, subject to automatic one year renewals of the term if neither party submits a notice of termination at least 60 days prior to the end of the then-current term. This agreement may be terminated by either party, at any time, subject to severance obligations in the event Mr. Ellis is terminated by us without cause or he dies or is disabled.

Mr. Ellis’ employment agreement provides for a minimum base salary of $485,000 and an annual bonus equal to a percentage of his base salary paid during each such annual period, such percentage to be established by our Board of Directors in the Board’s sole discretion.

Mr. McCabe

Mr. McCabe entered into an amended and restated employment agreement on March 25, 2014 that provides that he will act as Vice President and Chief Financial Officer until March 25, 2018, subject to automatic one year renewals of the term if neither party submits a notice of termination at least 60 days prior to the end of the then-current term. This agreement may be terminated by either party, at any time, subject to severance obligations in the event Mr. McCabe is terminated by us without cause or he dies or is disabled.

Mr. McCabe’s employment agreement provides for a minimum base salary of $435,000 and an annual bonus equal to a percentage of his base salary paid during each such annual period, such percentage to be established by our Board of Directors in the Board’s sole discretion.

Mr. McCabe’s employment agreement also provides that he is allowed to work from his residence in Massachusetts as well as in our Houston office so long as he is capable of performing his duties assigned to him. In his employment agreement, we also agree to provide Mr. McCabe with suitable housing (or a housing allowance) and an automobile or reimbursement for the lease of an automobile while he is in Houston.

Mr. Murrell

Mr. Murrell entered into an amended and restated employment agreement on March 25, 2014 that provides that he will act as Vice President of Land and Business Development until March 25, 2015, subject to automatic one year renewals of the term if neither party submits a notice of termination at least 60 days prior to the end of the then-current term. This agreement may be terminated by either party, at any time, subject to severance obligations in the event Mr. Murrell is terminated by us without cause or he dies or is disabled.

Mr. Murrell’s employment agreement provides for a minimum base salary of $360,000 and an annual bonus equal to a percentage of his base salary paid during each such annual period, such percentage to be established by our Board of Directors in the Board’s sole discretion, subject to a minimum of $50,000.

Grants of Plan-Based Awards for Fiscal Year 2014 

There were no grants of plan-based awards to our named executive officers during the fiscal year ended December 31, 2014.

Outstanding Equity Awards Value at 2014 Fiscal Year-End

There were no outstanding equity awards for our named executive officers as of December 31, 2014.

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Option Exercises and Equity Awards Vested in Fiscal Year 2014 

There were no exercises of equity awards and no vesting of equity awards for our named executive officers during fiscal 2013.

Pension Benefits

We do not provide pension benefits for our named executive officers.

Nonqualified Deferred Compensation

We established a nonqualified deferred compensation plan in 2013, the Retirement Plan,  to provide additional flexibility and tax planning advantages to our executives and other key highly compensated employees.  The Board of Directors administers the Retirement Plan, and at its sole discretion, designates employees eligible to participate.  Participants may defer up to 90% of their salary and up to 100% of their cash bonus under the program.   The Board of Directors may also, at its sole discretion, make elective employer contributions on behalf of selected participants.  The terms of such contributions may include a specified vesting schedule, intended to encourage continuous service to us.  If no schedule is specified with the award, the Retirement Plan provides for vesting based on years of service, with full vesting at three years.  Participants may withdraw vested funds from the Retirement Plan in accordance with the distribution schedule established when the contributions are elected or awarded, with the option of deferring a very short time or as long as until retirement from us.  The Retirement Plan is an unsecured and unfunded promise to pay the participants, who are our general creditors. 

In 2013, no amounts of salary or bonus were elected to be deferred under the Retirement Plan by any named executive.  In 2013, one elective employer contribution was made for the account of David Murrell.  The Board of Directors elected to make this distribution subject to a four-year vesting schedule, with 20% vested immediately and 20% to vest each subsequent year. In 2014, one elective employer contribution was made for the account of Michael A. McCabe.  The Board of Directors elected to make this distribution subject to a three-year vesting schedule, with 50% vested immediately and 16.67% to vest each subsequent year. 

 

 

Termination of Employment and Change–in–Control Provisions

Messrs. Chappelle, Ellis, McCabe and Murrell are parties to employment agreements that provide them with post–termination benefits in a variety of circumstances. The amount of compensation payable in some cases may vary depending on the nature of the termination, whether as a result of retirement/voluntary termination, involuntary not–for–cause termination, termination following a change of control and in the event of disability or death of the executive. The discussion below describes the varying amounts payable in each of these situations. It assumes, in each case, that the officer’s termination was effective as of December 31, 2014. In presenting this disclosure, we describe amounts earned through December 31, 2014 and, in those cases where the actual amounts to be paid out can only be determined at the time of such executive’s separation from us, our estimates of the amounts which would be paid out to the executives upon their termination.

Provisions Under the Employment Agreements

Under the employment agreements, if the executive’s employment with us terminates, the executive is entitled to unpaid salary for the full month in which the termination date occurred. However, if the executive is terminated for cause, the executive is only entitled to receive accrued but unpaid salary through the termination date. In addition, if the executive’s employment terminates, the executive is entitled to unpaid vacation days for that year which have accrued through the termination date, reimbursement of reasonable business expenses that were incurred but unpaid as of the termination date, a pro rata portion of the annual bonus for that year and COBRA coverage as required by law. Salary and accrued vacation days are payable in cash lump sum less applicable withholdings. Business expenses are reimbursable in accordance with normal procedures.

If the executive’s employment is involuntarily terminated by us (except for cause or due to the death of the executive) or if the executive’s employment is terminated due to disability or retirement or by the executive for good reason, we are obligated to pay as additional compensation an amount in cash equal to two years,  of the executive’s base salary in effect as of the termination date.

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Under the terms of Mr. Murrell’s employment agreement, as of December 31, 2014,  upon such involuntary termination, he would also be paid 50% of the annual bonus then in effect.  Mr. Murrell’s amended and restated employment agreement now provides for 18 months’ base salary and two times the annual bonus then in effect.  Assuming termination as of December 31, 2014, for both Messrs. Chappelle and Ellis, the termination benefit would have been $970,000; for Mr. McCabe, $870,000; and for Mr. Murrell, $720,000. In addition, all vested amounts in the executive’s deferred supplemental retirement account would be distributed.  Assuming termination as of December 31, 2014,  Mr. McCabe and Mr. Murrell, would have received a distribution of $1,500,000 and $130,000.  Our executives are each entitled under their employment agreements to continued group health plan coverage following the termination date for the executive and the executive’s eligible spouse and dependents for the maximum period for which such qualified beneficiaries are eligible to receive COBRA coverage, which is 18 months. The executive shall not be required to pay more for COBRA coverage than officers who are then in active service for us and receiving coverage under the plan. Assuming termination as of December 31, 2014, for each of Messrs. Chappelle, Ellis, McCabe, and Murrell, this amount would have been $18.00 to each. Our total cost of providing this benefit would have been $32,971 for Mr. Chappelle, $48,170 for Mr. Ellis, $32,971 for Mr. McCabe, and $32,971 for Mr. Murrell.

“Cause” means:

“Good reason” means the occurrence of any of the following, if not cured and correct by us or our successor, within 60 days after written notice thereof is provided by the executive to us or our successor:

“Retirement” means the termination of the executive’s employment for normal retirement at or after attaining age 70, provided that the executive has been with us for at least five years.

The employment agreements do not separately provide for benefits upon a change of control.

Termination benefits under our supplemental executive retirement plan define “cause” as above for the employment agreements.  Under the terms of the Plan, termination for any reason other than cause would result in a distribution of the participant’s vested balance in the account.  The terms of the Plan also include a change of control provision, under which all balances in the Plan become immediately vested if the participant is terminated during the first year after the change in control for any reason other than cause.  Normal retirement age is defined under the Plan as 65 years of age.

Compensation of Directors

The employee and non-employee members of the Board of Directors do not receive compensation for their services as directors. However, our directors may be reimbursed for their expenses in attending Board meetings.

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Compensation Committee Interlocks and Insider Participation

We do not currently have a compensation committee. None of our executive officers has served as a director or member of the compensation committee of any other entity whose executive officers served as a director or member of our compensation committee.

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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The following table sets forth as of March 26, 2015 the limited partnership interests in Alta Mesa beneficially owned by:

 

 

 

Additionally, our general partner, Alta Mesa GP, is owned by Mr. and Ms. Ellis and High Mesa, Inc.  

Securities Authorized for Issuance under Equity Compensation Plans

We do not have any equity compensation plans.

Item 13. Certain Relationships and Related Transactions, and Director Independence

We do not have any formal policy with respect to the review and approval of related party transactions.    A “Related Party Transaction” is any transaction, arrangement or relationship where we are a participant, the Related Party (defined below) had, has or will have a direct or indirect material interest and the aggregate amount involved is expected to exceed $120,000 in any calendar year. “Related Party” includes (a) any person who is or was (at any time during the last fiscal year) an executive officer, director or nominee for election as a director; (b) any person or group who is a beneficial owner of more than 5% of our voting securities; (c) any immediate family member of a person described in provisions (a) or (b) of this sentence; or (d) any entity in which any of the foregoing persons is employed, is a partner or has a greater than 5% beneficial ownership interest. 

Ownership in Us and Our General Partner 

Michael E. Ellis, our Chairman and Chief Operating Officer, and his spouse Mickey Ellis, one of our directors, own 85.05% of our Class A interests. Our general partner, Alta Mesa GP, is owned by Alta Mesa Resources, LP, an entity owned by Michael E. Ellis, Mickey Ellis, and High Mesa. Our general partner has a 0.1% interest in us.

During 2014 and 2013 Michael E. Ellis, our founder, Chief Operating Officer, and Chairman of the Board, received capital distributions from us of $516,500 and $17,500, respectively.

 

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Founder Notes

We were founded in 1987 by Michael E. Ellis and we or our subsidiaries have over time entered into promissory notes to repay Mr. Ellis for contributions of working capital and other amounts. On March 25, 2014, these notes were amended and restated.  The maturity date of the notes was extended to December 31, 2021.  The interest rate and interest payment terms were not changed.    The founder notes bear simple interest at 10% with a balance of $24.5 million and $23.3 million at December 31, 2014 and December 31, 2013, respectively. Interest and principal are payable at maturity. The notes are convertible into shares of our Class B partner, High Mesa common stock upon certain conditions in the event of an initial public offering.

These founder notes are unsecured and are subordinate to all debt.  In connection with the March 25, 2014 recapitalization of our Class B partner, the founder notes were amended and restated to subordinate them to the paid in kind (“PIK”) notes of our Class B partner.  The founder notes were also subordinated to the rights of the holders of Class B units to receive distributions under our amended partnership agreement and subordinated to the rights of the holders of Series B Preferred Stock to receive payments.

Land Consulting Services

David Murrell, our Vice President, Land and Business Development, is the principal of David Murrell & Associates, which provides land consulting services to us. The primary employee of David Murrell & Associates is his spouse, Brigid Murrell. Services are provided at a pre-negotiated hourly rate based on actual time employed by us. Total expenditures under this arrangement for the years ended December 31, 2014, 2013 and 2012, were approximately $150,000, $175,000 and $116,000. The contract may be terminated by either party without penalty upon 30 days’ notice.

Employee and Distribution

David McClure, our Vice President, Louisiana Operations, and the son-in-law of our CEO, Harlan H. Chappelle, received total compensation of $450,000, $390,000, and $327,000 for the years ended December 31, 2014, 2013 and 2012. Additionally, his position provides him with the use of a company vehicle, similar to our other Vice Presidents whose duties include field oversight.

David Pepper, one of our Landmen, and the nephew of our Vice President, Land and Business Development David Murrell, received total compensation of $260,000, $125,000, and $105,000 for the years ended December 31, 2014, 2013 and 2012. Additionally, his position provides him with the use of a company vehicle, similar to our other Landman whose duties include field oversight.

Midstream Asset Sale

On December 31, 2014, we sold our interests in a partially constructed pipeline and gas processing plant at cost to an affiliate of our Class B unitholder, High Mesa for $25.5 million cash and short-term note receivable of $8.5 million, while recording no gain or loss on the sale at December 31, 2014.  On January 2, 2015, the receivable of $25.5 million was paid. The $8.5 million note receivable, dated December 31, 2014, bears interest at 8% per annum, interest payable only in quarterly installments beginning January 1, 2015, and matures on December 31, 2019.  Immediately after the consummation of the transaction, the $8.5 million promissory note was transferred from NWGP to HMS, a subsidiary of the Parent company High Mesa.    

Director Independence

Our Board of Directors consists of five members, two of whom are non-employee directors. Because we only have debt securities registered with the SEC under the Exchange Act and because we do not have a class of securities listed on any national securities exchange, national securities association or inter-dealer quotation system, we are not required to have a board of directors comprised of a majority of independent directors under SEC rules or any listing standards. Accordingly, our Board of Directors has not made any determination as to whether the non-employee directors satisfy any independence requirements applicable to board members under the rules of the SEC or any national securities exchange, inter-dealer quotation system or any other independence definition.

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Item 14. Principal Accountant Fees and Services

Our Board of Directors selected BDO USA, LLP (“BDO”), an independent registered public accounting firm, to audit our consolidated financial statements for the fiscal year ended December 31, 2014.  Our Board of Directors had previously selected UHY LLP (“UHY”), an independent registered public accounting firm, to audit our consolidated financial statements for the fiscal years ended December 31, 2013 and 2012. The Texas practice of UHY was sold to BDO during 2014. As a result, UHY resigned as our independent registered public accounting firm on December 1, 2014, and the Board of Directors engaged BDO as the Company’s independent registered public accountant for our fiscal year ending December 31, 2014.   Aggregate fees for professional services rendered to us by BDO and UHY for the years ended December 31, 2014 and 2013 were as follows:

Audit Fees

 

The audit fees for the years ended December 31, 2014 and 2013, respectively, were for professional services rendered for the audits of our consolidated financial statements and review of our quarterly financial statements. 

Audit-related fees

Audit-related fees for the years 2014 and 2013 include fees for the audit of our 401(k) employee savings plan.

Pre-Approval Policies and Procedures

We currently have no Board committees. Our Board of Directors has adopted policies regarding the pre-approval of auditor services. Specifically, the Board of Directors approves all services provided by the independent public accountants at its March meeting. All additional services must be pre-approved on a case-by-case basis. Our Board of Directors reviews the actual and budgeted fees for the independent public accountants periodically at regularly scheduled board meetings. All of the services provided by BDO and UHY during fiscal 2014 and 2013 were approved by the Board of Directors.    The Board of Directors also considers whether the provision of the foregoing services is compatible with maintaining the auditor’s independence and has concluded that the foregoing non-audit services and non-audit-related services, did not adversely affect the independence of our auditors. 

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a)Documents filed as part of this report:

1.Financial Statements:

(i)Independent Registered Public Accounting Firms’ Reports 

(ii)Consolidated Balance Sheets as of December 31, 2014 and 2013

(iii)Consolidated Statements of Operations for each of the three years in the period ended December 31, 2014

(iv)Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2014 

(v)Consolidated Statements of Changes in Partners’ Capital (Deficit) for each of the three years in the period ended December 31, 2014 

(vi)Notes to Consolidated Financial Statements

(vii)Supplemental Oil and Natural Gas Information (Unaudited)

2.Financial Statement Schedules:

(i)All schedules are omitted as they are not applicable, not required or the required information is included in the consolidated financial statements or notes thereto.

3.Exhibits:

 

 

*Filed herewith.

 

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SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

ALTA MESA HOLDINGS, L.P.

(Registrant)

 

 

Dated March 26, 2015 

In accordance with the Exchange Act, this report has been signed below on the 26th day of March, 2015, by the following persons on behalf of the registrant and in the capacities indicated.

 

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GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS

The definitions set forth below apply to the indicated terms as used in this Annual Report on Form 10-K. All volumes of natural gas referred to are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.

“3-D seismic”. (Three-Dimensional Seismic Data) Geophysical data that depicts the subsurface strata in three dimensions. 3-D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than two-dimensional seismic data.

“Bbl”. One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.

“Bcf”. One billion cubic feet of natural gas.

“Bcfe”. One billion cubic feet of natural gas equivalent with one barrel of oil converted to six thousand cubic feet of natural gas. The ratio of six thousand cubic feet of natural gas to one Bbl of oil or natural gas liquids is commonly used in the oil and natural gas business and represents the approximate energy equivalency of six thousand cubic feet of natural gas to one Bbl of oil or natural gas liquids, and does not represent the sales price equivalency of natural gas to oil or natural gas liquids. Currently, the sales price of one Bbl of oil or natural gas liquids is significantly higher than the sales price of six thousand cubic feet of natural gas.

“Basin”. A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

“BOE”.  One barrel of oil equivalent determined using the ratio of six Mcf of natural gas to one barrel of oil, condensate or natural gas liquids. The ratio of six Mcf of natural gas to one Bbl of oil or natural gas liquids is commonly used in the oil and natural gas business and represents the approximate energy equivalency of six Mcf of natural gas to one Bbl of oil or natural gas liquids, and does not represent the sales price equivalency of natural gas to oil or natural gas liquids. Currently, the sales price of one Bbl of oil or natural gas liquids is significantly higher than the sales price of six Mcf of natural gas.

“Btu or British Thermal Unit”. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

“Completion”. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“DD&A”. Depreciation, depletion and amortization.

“De-bottlenecking”. The process of increasing production capacity of existing facilities through the modification of existing equipment to remove throughput restrictions.

“Delineation”. The process of placing a number of wells in various parts of a reservoir to determine its boundaries and production characteristics.

“Developed acreage”. The number of acres that are allocated or assignable to productive wells or wells capable of production.

“Developed oil and natural gas reserves”. Developed oil and natural gas reserves are reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the related equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

“Development well”. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

“Dry hole”. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

“Dry hole costs”. Costs incurred in drilling a well, assuming a well is not successful, including plugging and abandonment costs.

“Enhanced recovery”. The recovery of oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Enhanced recovery methods are often applied when production slows due to depletion of the natural pressure.

“Exploratory well”. A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.

“Farm-in or farm-out”. An agreement under which the owner of a working interest in an oil and natural gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or

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reversionary interest in the lease. The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out”.

“Fault”. A break or planar surface in brittle rock across which there is observable displacement.

“Field”. An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

“Formation”. A layer of rock which has distinct characteristics that differs from nearby rock.

“Fracing, fracture stimulation technology, hydraulic fracturing”. The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to keep the channel open, so that fluids or natural gases may more easily flow through the formation.

“Gross acres or gross wells”. The total acres or wells, as the case may be, in which a working interest is owned.

“Horizontal drilling”. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

“Infill wells”. Wells drilled into the same pool as known producing wells so that oil or natural gas does not have to travel as far through the formation.

“Lease operating expenses”. The expenses of lifting oil or natural gas from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, workover, ad valorem taxes, insurance and other expenses incidental to production, but excluding lease acquisition or drilling or completion expenses.

“MBbl”. One thousand barrels of crude oil, condensate or natural gas liquids.

“Mcf”. One thousand cubic feet of natural gas.

“Mcfe”. One thousand cubic feet equivalent determined using the ratio of six Mcf of natural gas to one barrel of oil, condensate or natural gas liquids. The ratio of six Mcf of natural gas to one Bbl of oil or natural gas liquids is commonly used in the oil and natural gas business and represents the approximate energy equivalency of six Mcf of natural gas to one Bbl of oil or natural gas liquids, and does not represent the sales price equivalency of natural gas to oil or natural gas liquids. Currently, the sales price of one Bbl of oil or natural gas liquids is significantly higher than the sales price of six Mcf of natural gas.

“Mcfe/d”. Mcfe per day.

“MMBtu”. One million British thermal units.

“MMcf”. One million cubic feet of natural gas.

“MMcfe”. Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

“MMcfe/d”. MMcfe per day.

“MMBbl”. One million barrels of crude oil, condensate or natural gas liquids.

“NGLs” or “natural gas liquids.” Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

“NYMEX”. The New York Mercantile Exchange.

“Net Acres”. The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.

“Non-operated working interests”. The working interest or fraction thereof in a lease or unit, the owner of which is without operating rights by reason of an operating agreement.

“Pay”. A reservoir or portion of a reservoir that contains economically producible hydrocarbons. The overall interval in which pay sections occur is the gross pay; the smaller portions of the gross pay that meet local criteria for pay (such as a minimum porosity, permeability and hydrocarbon saturation) are net pay.

“Productive well”. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

“Prospect”. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

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“PDNP”. Proved developed non-producing reserves.

“PDP”. Proved developed producing reserves.

“Proved reserves”. Proved oil and natural gas reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward from known reservoirs, and under existing economic conditions, operating methods and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

“Proved undeveloped reserves (“PUD”)”. Proved undeveloped oil and natural gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undrilled acreage is considered proved where adjacent undrilled portions of the reservoir can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.  In addition, reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty and these locations must have a development plan that calls for development within five years, unless specific circumstances justify a longer time.  In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.  Finally, reserves which can be produced through the application of improved recovery techniques, including injection, may be included upon successful testing of a pilot project in a representative area or analogous reservoir or if other evidence using reliable technology establishes the reasonable certainty of the engineering analysis.  Such improved recovery techniques must be approved for development by all necessary parties and entities including governmental entities. 

“PV-10”. When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC. PV-10 is not a financial measure calculated in accordance with generally accepted accounting principles (“GAAP”) and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. Our PV-10 is the same as our standardized measure for the periods presented in this report.

“Recompletion”. The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

“Reserve life index”. A measure of the productive life of an oil and natural gas property or a group of properties, expressed in years.

“Reservoir”. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“Spacing”. The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

“Standardized measure”. Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission, without giving effect to non — property related expenses such as certain general and administrative expenses, debt service and future federal income tax expenses or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Our standardized measure includes future obligations under the Texas gross margin tax, but it does not include future federal income tax expenses because we are a partnership and are not subject to federal income taxes. Our standardized measure is the same as our PV-10 for the periods presented in this report.

“Undeveloped acreage”. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

“Unit”. The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

“Waterflood”. The injection of water into an oil reservoir to “push” additional oil out of the reservoir rock and into the wellbores of producing wells. Typically an enhanced recovery process.

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“Wellbore”. The hole drilled by the bit that is equipped for natural gas production on a completed well. Also called well or borehole.

“Working interest”. The right granted to the lessee of a property to explore for and to produce and own natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.