Attached files
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| 8-K/A - 8-K/A - American Midstream Partners, LP | amendedamid8-k9x16x1310xqr.htm |
Exhibit 99.1
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Exhibit 99.1
EXPLANATORY NOTE
This Amendment No. 1 on Form 8-K/A (this "Amendment") amends Exhibit 99.1 to the Registrant's Current Report on Form 8-K, which the Registrant previously filed with the Securities and Exchange Commission on October 1, 2013 and which updated certain portions of the Registrant’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2013 (such Exhibit 99.1, the "Original Exhibit"). The Registrant is filing this Amendment solely to reflect revisions to Part I, Item 2 which was included in the Original Exhibit. All other Items of the Original Exhibit are unaffected by this Amendment and such items have not been included in this Amendment. This Amendment No. 1 does not reflect events occurring after the filing date of the Original Exhibit or modify or update disclosures in the Original Exhibit except to amend Part I, Item 2.
Part I, Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
In the second quarter of 2013, Partnership management was approved to commit to a plan to sell certain non-strategic gathering and processing assets which meet specific criteria as held for sale. As a result of the planned divestiture of these non-strategic midstream assets, we began accounting for the results of operations of these disposal groups as discontinued operations. As a result, we have recast certain information included in our condensed consolidated financial statements for all periods presented in this report.
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited consolidated financial statements and the related notes thereto included elsewhere in this Quarterly Report and the audited consolidated financial statements and notes thereto and management’s discussion and analysis of financial condition and results of operations as of and for the year ended December 31, 2012 included in Annual Report on Form 10-K (“Annual Report”) that was filed with the Securities and Exchange Commission (the “SEC”) on April 16, 2013. This discussion contains forward-looking statements that reflect management’s current views with respect to future events and financial performance. Our actual results may differ materially from those anticipated in these forward-looking statements or as a result of certain factors such as those set forth below under the caption “Cautionary Statement Regarding Forward-Looking Statements.”
Cautionary Statement About Forward-Looking Statements
Our reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements”. You can typically identify forward-looking statements by the use of forward-looking words, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast” and other similar words.
All statements that are not statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.
These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. These risks and uncertainties, many of which are beyond our control, include, but are not limited to, the risks set forth in “Item 1A. Risk Factors” and elsewhere in this Quarterly Report, the Annual Report and the following:
• | our ability to access capital to fund growth including access to the debt and equity markets, which will depend on general market conditions and the credit ratings for our debt obligations; |
• | the amount of collateral required to be posted from time to time in our transactions; |
• | our success in risk management activities, including the use of derivative financial instruments to hedge commodity and interest rate risks; |
• | the level of creditworthiness of counterparties to transactions; |
• | changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment; |
• | the timing and extent of changes in natural gas, natural gas liquids and other commodity prices, interest rates and demand for our services; |
• | weather and other natural phenomena; |
• | industry changes, including the impact of consolidations and changes in competition; |
• | our ability to obtain necessary licenses, permits and other approvals; |
• | the level and success of crude oil and natural gas drilling around our existing and recently acquired assets and our success in connecting natural gas supplies to our gathering and processing systems; |
• | our ability to grow through acquisitions or internal growth projects and the successful integration and future performance of such assets; and |
• | general economic, market and business conditions. |
Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in this Quarterly Report will prove to be accurate. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described in “Item 1A. Risk Factors” and elsewhere in this Quarterly Report and our Annual Report. Except as may be required by applicable law, we undertake no obligation to publicly update or advise of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.
Overview
We are a growth-oriented Delaware limited partnership that was formed in August 2009 to own, operate, develop and acquire a diversified portfolio of natural gas midstream energy assets. We are engaged in the business of gathering, treating, processing, fractionating and transporting natural gas through our ownership and operation of eleven gathering systems, four processing facilities, two interstate pipelines and four intrastate pipelines. We also own a 50% undivided, non-operating interest in a processing plant located in southern Louisiana. Our primary assets, which are strategically located in Alabama, Louisiana, Mississippi, and Texas, provide critical infrastructure that links producers and suppliers of natural gas to diverse natural gas markets, including various interstate and intrastate pipelines, as well as utility, industrial and other commercial customers. We currently operate approximately 1,400 miles of pipelines that gather and transport over 600 MMcf/d of natural gas.
Significant financial highlights and challenges during the three months ended March 31, 2013, include the following:
• | We distributed $4.0 million to our unitholders or $0.4325 per unit for the fourth quarter during the three months ended March 31, 2013; |
• | For the three months ended March 31, 2013, gross margin decreased to $12.5 million or 0.7% compared to the same period in 2012; and |
• | On January 24, 2013, the Partnership entered into the second waiver to the credit facility that extended the waiver period with respect to the Consolidated Total Leverage Ratio to March 31, 2013 (and the waiver period was subsequently extended to April 16, 2013). |
Significant operational highlights and challenges during the three months ended March 31, 2013, include the following:
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• | Throughput attributable to the Partnership totaled 687.5 MMcf/d for the first quarter of 2013 representing a 9.6% decrease compared to the same period in 2012; |
• | The Partnership saw a decline in volumes on one of its offshore pipeline systems as a result of a producer's work on one of its platforms which provided access to an alternative market that offer competitive terms. The Partnership continues to work with this producer to negotiate the return of a portion of historical volumes to the offshore pipeline system, although the contract terms may change for this portion of volumes going forward and may have a material negative impact on financial results. While the Partnership expects this portion of volumes to return during the first half of 2013, the reduced volumes during the first quarter of 2013 resulted in a negative financial impact of approximately $1.0 million; |
• | Incremental condensate production associated with our 87.4% undivided interest in the Chatom system totaled 38.6 Mgal/d for the first quarter of 2013 which contributed to our overall of increase in condensate production of 613% for the three months ended March 31, 2013; and |
• | As previously disclosed, certain assets were impacted by Hurricane Isaac to which the Partnership is insured for named windstorms on the affected assets after a $1.0 million deductible. Insurance proceeds of $0.6 million were received during the three months ended March 31, 2013. |
Recent Developments
On April 15, 2013, the Partnership, our general partner and AIM Midstream Holdings, LLC, an affiliate of American Infrastructure MLP Fund, entered into agreements with High Point Infrastructure Partners, LLC, an affiliate of ArcLight Capital Partners, LLC (“High Point”), pursuant to which High Point (i) acquired 90% of our general partner, which holds all of our general partner units and incentive distribution rights, and all of our subordinated units from AIM Midstream Holdings and (ii) contributed certain midstream assets and $15.0 million in cash to us in exchange for 5,142,857 convertible preferred units (the “Series A Preferred Units”) issued by the Partnership. As a result of these transactions, which were also consummated on April 15, 2013, High Point acquired both control of our general partner and a majority of our outstanding limited partnership interests. Please read "— ArcLight Transactions." Contemporaneously with the consummation of these transactions, we also entered into a Fourth Amendment to our credit agreement that, among other things, provides for the permanent waiver of any recent covenant breaches relating to consolidated total leverage ratio, modifies the covenant relating to total leverage ratio through the quarter ended December 31, 2014 and requires us to reduce the quarterly cash distribution that would otherwise be payable in respect of our subordinated units or Series A Preferred Units for the first, second, third and fourth quarters of 2013. Please read "— Fourth Amendment to Credit Agreement" and "—Liquidity and Capital Resources — Our Credit Facility" for more information about our credit facility, covenant violations and related waivers and the Fourth Amendment.
ArcLight Transactions
Purchase Agreement
On April 15, 2013, AIM Midstream Holdings and High Point entered into a Purchase Agreement, pursuant to which High Point purchased from AIM Midstream Holdings all of the Partnership's 4,526,066 subordinated units and 90% of the limited liability company interests in our general partner, which holds all of our general partner units and incentive distribution rights. The transactions contemplated by the Purchase Agreement were consummated on April 15, 2013. Of the cash consideration paid to AIM Midstream Holdings, $12.5 million is being held in escrow until its release upon satisfaction of certain conditions.
Contribution Agreement
On April 15, 2013, the Partnership and High Point entered into a Contribution Agreement, pursuant to which High Point contributed to us 100% of the limited liability company interests in certain of its subsidiaries that own midstream assets located in southern and offshore Louisiana (the “High Point Assets”) and $15.0 million in cash in exchange for 5,142,857 newly issued Series A Preferred Units. Of the $15.0 million cash consideration paid by High Point, approximately $2.5 million was used to pay certain transaction expenses of High Point, and the remaining approximately $12.5 million was used to repay borrowings outstanding under the Partnership's June 2012 amended credit facility in connection with the Fourth Amendment. The transactions contemplated by the Contribution Agreement were consummated on April 15, 2013.
Third Amended & Restated Agreement of Limited Partnership
On April 15, 2013, our general partner entered into the Third Amended & Restated Agreement of Limited Partnership (the “Amended Partnership Agreement”) of the Partnership providing for the creation and designation of the rights, preferences, terms and conditions of the Series A Preferred Units.
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Under the terms of the Amended Partnership Agreement, during the period that commences with the quarter that ends on June 30, 2013 and ending with the earlier of the quarter that includes a conversion of the Series A Preferred Units and the quarter beginning October 1, 2014 (the “Coupon Conversion Quarter”), the Series A Preferred Units will each receive quarterly distributions (the “Series A Quarterly Distributions”) in an amount equal to (i) 0.01428571 of additional Series A Preferred Units (subject to customary anti-dilution adjustments) (the "PIK Distribution") and (ii) $0.25 in cash (with the additional Series A Preferred Units and cash portion relating to the quarter ending June 30, 2013 being prorated based on the number of days in such quarter that follow the date on which the Series A Preferred Units were issued). Commencing with the Coupon Conversion Quarter, the Series A Preferred Units will receive the Series A Quarterly Distributions in an amount equal to the greater of (a) the amount of aggregate distributions that would be payable had such Series A Preferred Units converted into Common Units and (b) a fixed rate of 0.023571428 multiplied by the conversion price, which will initially be $17.50 per Series A Preferred Unit (subject to customary anti-dilution adjustments) (the “Conversion Price”), paid in arrears within 45 days after the end of each quarter and prior to distributions with respect to the common units and subordinated units. The record date for the determination of holders entitled to receive Series A Quarterly Distributions will be the same as the record date for determination of common unit holders entitled to receive quarterly distributions.
If we fail to pay in full any Series A Quarterly Distribution, the amount of such unpaid distribution will accrue, accumulate and bear interest at a rate of 6.0% per annum from the first day of the quarter immediately following the quarter for which such distribution is due until paid in full.
The Series A Preferred Units have voting rights that are identical to the voting rights of the common units and will vote with the common units as a single class, with each Series A Preferred Unit entitled to one vote for each common unit into which such Series A Preferred Unit is convertible. The Series A Preferred Units also have separate class voting rights on any matter, including a merger, consolidation or business combination, that adversely affects, amends or modifies any of the rights, preferences, privileges or terms of the Series A Preferred Units. Moreover, the general partner may not take any of the following actions without the prior written consent of High Point or any of its affiliates, as long as High Point or such affiliates together hold at least 50% of the Series A Preferred Units and Subordinated Units held by High Point immediately following the issuance of the Series A Preferred Units on April 15, 2013:
• | cause or permit us to invest in, or dispose of, the equity securities or debt securities of any person or otherwise acquire or dispose of any interest in any person, to acquire or dispose of interest in any joint venture or partnership or any similar arrangement with any person, or to acquire or dispose of assets of any person, or to make any capital expenditure (other than maintenance capital expenditures), or to make any loan or advance to any person if the total consideration (including cash, equity issued and debt assumed) paid or payable, or received or receivable, by us exceeds $15,000,000 in any one or series of related transactions or in the aggregate exceeds $50,000,000 in any twelve-month period; |
• | cause or permit us to (i) incur, create or guarantee any indebtedness that exceeds (x) $75,000,000 in any one or series of related transactions to the extent the proceeds of such financing are used to refinance our existing indebtedness, or (y) $25,000,000 in any twelve-month period to the extent such indebtedness increases our aggregate indebtedness or (ii) incur, create or guarantee any indebtedness with a yield to maturity exceeding ten percent (10)%; |
• | authorize or permit the purchase, redemption or other acquisition of Partnership interests (or any options, rights, warrants or appreciation rights relating to the Partnership interests) by us; |
• | select or dismiss, or enter into any employment agreement or amendment of any employment agreement of, the chief executive officer and the chief financial officer of the Partnership or its subsidiary, American Midstream, LLC; |
• | enter into any agreement or effect any transaction between us or any of our subsidiaries, on the one hand, and any affiliate of the Partnership or the general partner, on the other hand, other than any transaction in the ordinary course of business and determined by the board of directors of the general partner to be on an arm's length basis; or |
• | cause or permit us or any of our subsidiaries to enter into any agreement or make any commitment to do any of the foregoing. |
The Series A Preferred Units are convertible in whole or in part into common units at any time after January 1, 2014 or, prior to that date, with the consent of the required lenders under the June 2012 amended credit agreement, at the holder's election. The number of common units into which a Series A Preferred Unit is convertible will be an amount equal to (i) the sum of $17.50 and all accrued and accumulated but unpaid distributions, divided by (ii) the Conversion Price, which will initially be $17.50 per Series A Preferred Unit (subject to customary anti-dilution adjustments) (the “Conversion").
In the event that the Partnership issues, sells or grants any common units or convertible securities at an indicative per Common Unit price that is less than $17.50 (subject to customary anti-dilution adjustments), then the Conversion Rate will be adjusted according to a formula to provide an increase in the number of common units into which Series A Preferred Units are convertible.
Prior to the consummation of any recapitalization, reorganization, consolidation, merger, spin-off or other business combination in which the holders of common units are to receive securities, cash or other assets (a “Partnership Event”), we are obligated to make an irrevocable written offer, subject to consummation of the Partnership Event, to each holder of Series A Preferred Units
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to redeem all (but not less than all) of such holder's Series A Preferred Units for a price per Series A Preferred Unit payable in cash equal to the greater of:
• | the sum of $17.50 and all accrued and accumulated but unpaid distributions for each Series A Preferred Unit; and |
• | an amount equal to the product of: |
(i) the number of common units into which each Series A Preferred Unit is convertible; and
(ii) the sum of:
(A) the cash consideration per common unit to be paid to the holders of common units pursuant to the Partnership Event, plus
(B) the fair market value per common unit of the securities or other assets to be distributed to the holders of the common units pursuant to the Partnership Event.
Upon receipt of such a redemption offer from us, each holder of Series A Preferred Units may elect to receive such cash amount or a preferred security issued by the person surviving or resulting from such Partnership Event and containing provisions substantially equivalent to the provisions set forth in the Amended Partnership Agreement with respect to the Series A Preferred Units without material abridgement.
Upon any liquidation and winding up of the Partnership or the sale of substantially all of the assets of the Partnership, the holders of Series A Preferred Units generally will be entitled to receive, in preference to the holders of any of the Partnership's other securities, an amount equal to the sum of the $17.50 multiplied by the number of Series A Preferred Units owned by such holders, plus all accrued but unpaid distributions on such Series A Preferred Units.
Change of Control of the General Partner and the Partnership
Through the acquisition of the 90% interest in our general partner, the acquisition of all of our 4,526,066 subordinated units and the issuance of the 5,142,857 Series A Units, High Point acquired control of our general partner and a majority of our outstanding limited partner interests. In connection with High Point's acquisition of control of our general partner, each of Robert B. Hellman, Jr., Edward O. Diffendal and L. Kent Moore resigned from the board of directors of our general partner. Mr. Hellman also resigned as chairman of the board of directors of our general partner. These resignations occurred on April 15, 2013. High Point, as the owner of 90% of the limited liability company interests in our general partner, will have the right to fill the board vacancies created by these resignations. Effective April 15, 2013, High Point appointed Messrs. Bergstrom, Erhard and Revers to the board of directors of our general partner.
Fourth Amendment to Credit Agreement
On April 15, 2013, a subsidiary of the Partnership, American Midstream, LLC, as borrower (the “Borrower”) and the Partnership entered into a Fourth Amendment with its lenders under its June 2012 amended credit agreement. The Fourth Amendment provides for the following:
• | Permits the consummation of the ArcLight Transactions and the PIK Distribution according to the terms of the Amended Partnership Agreement; |
• | The aggregate commitments of the lenders under the June 2012 amended credit agreement will be reduced to $175 million if an equity contribution of $12.5 million has not been made by AIM Midstream Holdings and used to repay borrowings under the June 2012 amended credit facility by October 1, 2013; |
• | The total outstanding borrowings under the June 2012 amended credit facility shall not exceed $175 million until such equity contribution by AIM Midstream Holdings has occurred; |
• | The margins relating to our (i) Eurodollar-based loans range from 2.50% to 4.75% depending on the Consolidated Total Leverage ratio then in effect, and (ii) base rate loans range from 1.5% to 3.75%; |
• | The definition of Consolidated Total Indebtedness will not include the Series A Preferred Units or certain surety bonds relating to the High Point Assets; |
• | The definition of Consolidated EBITDA (the consolidated EBITDA for the quarters ending June 30 and September 30, 2013 will be annualized for purposes of the Consolidated Total Leverage Ratio) will: |
◦ | include, on a pro forma basis, the consolidated EBITDA of the High Point Subsidiaries as if they were owned by the Partnership beginning on January 1, 2013; |
◦ | exclude any insurance proceeds attributable to any event occurring prior to January 1, 2013; and |
◦ | exclude any one-time, non-recurring transaction expenses of the Partnership incurred in connection with the ArcLight Transactions or the Fourth Amendment. |
• | Starting with the quarter ending March 31, 2013 and ending with the quarter ending December 31, 2013, unless the Partnership has permanently cancelled at least 20% of the number of subordinated units outstanding on April 15, 2013, the Partnership must reduce any quarterly cash distribution on either its subordinated units or Series A Preferred Units (at the Partnership's election) by an aggregate of $0.4 million per quarter, and such reduction may not be replaced by in-kind distributions of Partnership securities; |
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• | The maximum Consolidated Total Leverage Ratio permitted as of the end of any fiscal quarter cannot exceed the ratio set forth below: |
Fiscal Quarter Ending | Consolidated Total Leverage Ratio |
June 30, 2013 | 5.90:1.00 |
September 30, 2013 | 5.90:1.00 |
December 31, 2013 | 5.75:1.00 |
March 31, 2014 | 5.75:1.00 |
June 30, 2014 | 5.75:1.00 |
September 30, 2014 | 5.50:1.00 |
December 31, 2014 | 5.25:1.00 |
March 31, 2015 and each fiscal quarter thereafter | 4.50:1.00 |
• | The Partnership agrees to cooperate with and pay the fees and expenses incurred by Bank of America, N.A., the administrative agent for the June 2012 amended credit agreement, in connection with its engagement of FTI Consulting to advise and assist it in an assessment of the Partnership's financial condition; and |
• | The lenders permanently waived the Partnership's failure to comply with covenants relating to the Partnership's Consolidated Total Leverage Ratio for the quarters ended December 31, 2012 and March 31, 2013. |
Subsequent Events
Distribution
On April 26, 2013, we announced a distribution of $0.4325 per unit payable on May 15, 2013 to unitholders of record on May 7, 2013 amounting to $3.7 million.
Our Operations
We manage our business and analyze and report our results of operations through two business segments:
• | Gathering and Processing. Our Gathering and Processing segment provides “wellhead-to-market” services to producers of natural gas and oil, which include transporting raw natural gas from various receipt points through gathering systems, treating the raw natural gas, processing raw natural gas to separate the NGLs from the natural gas, performing fractionation and selling or delivering pipeline quality natural gas as well as NGLs to various markets and pipeline systems. |
• | Transmission. Our Transmission segment transports and delivers natural gas from producing wells, receipt points or pipeline interconnects for shippers and other customers, which include local distribution companies (“LDCs”), utilities and industrial, commercial and power generation customers. |
Gathering and Processing Segment
Results of operations from our Gathering and Processing segment are determined primarily by the volumes of natural gas we gather and process, the commercial terms in our current contract portfolio and natural gas, NGL and condensate prices. We gather and process gas primarily pursuant to the following arrangements:
• | Fee-Based Arrangements. Under these arrangements, we generally are paid a fixed cash fee for gathering and processing and transporting natural gas. |
• | Fixed-Margin Arrangements. Under these arrangements, we purchase natural gas from producers or suppliers at receipt points on our systems at an index price less a fixed transportation fee and simultaneously sell an identical volume of natural gas at delivery points on our systems at the same, undiscounted index price. By entering into back-to-back purchases and sales of natural gas, we are able to lock in a fixed-margin on these transactions. We view the segment gross margin earned under our fixed-margin arrangements to be economically equivalent to the fee earned in our fee-based arrangements. |
• | Percent-of-Proceeds Arrangements (“POP”). Under these arrangements, we generally gather raw natural gas from producers at the wellhead or other supply points, transport it through our gathering system, process it and sell the residue natural gas, NGLs and condensate at market prices. Where we provide processing services at the processing plants that we own or obtain processing services for our own account in connection with our elective processing arrangements, such as under our Toca contract, we generally retain and sell a percentage of the residue natural gas and resulting NGLs and condensate. However, we also have contracts under which we |
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retain a percentage of the resulting NGLs and do not retain a percentage of residue natural gas, such as for our interest in the Burns Point Plant. Our POP arrangements also often contain a fee-based component.
• | Interest in the Burns Point Plant. We account for our interest in the Burns Point Plant using the proportionate consolidation method. Under this method, we include in our consolidated statement of operations, our value of plant revenues taken in-kind and plant expenses reimbursed to the operator. |
• | Interest in the Chatom Assets. We account for our 87.4% undivided interest in the Chatom Assets pursuant to ASC No. 810-10-65-1, Noncontrolling Interests. Under this method, revenues, expenses, gains, losses, net income or loss, and other comprehensive income are reported in the consolidated financial statements at the consolidated amounts, which include the amounts attributable to the partners' and the noncontrolling interests. The consolidated income statement shall separately present net income attributable to the partners' and the noncontrolling interests. |
Gross margin earned under fee-based and fixed-margin arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. However, a sustained decline in commodity prices could result in a decline in volumes and, thus, a decrease in our fee-based and fixed-margin gross margin. These arrangements provide stable cash flows, but minimal, if any, upside in higher commodity price environments. Under our typical POP arrangement, our gross margin is directly impacted by the commodity prices we realize on our share of natural gas, NGLs and condensate received as compensation for processing raw natural gas. However, our POP arrangements also often contain a fee-based component, which helps to mitigate the degree of commodity-price volatility we could experience under these arrangements. We further seek to mitigate our exposure to commodity price risk through our hedging program. Please read “ — Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.”
Transmission Segment
Results of operations from our Transmission segment are determined primarily by capacity reservation fees from firm transportation contracts and, to a lesser extent, the volumes of natural gas transported on the interstate and intrastate pipelines we own pursuant to interruptible transportation or fixed-margin contracts. Our transportation arrangements are further described below:
• | Firm Transportation Arrangements. Our obligation to provide firm transportation service means that we are obligated to transport natural gas nominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on our part, the shipper pays a specified reservation charge, whether or not the shipper utilizes the capacity. In most cases, the shipper also pays a variable use charge with respect to quantities actually transported by us. |
• | Interruptible Transportation Arrangements. Our obligation to provide interruptible transportation service means that we are only obligated to transport natural gas nominated by the shipper to the extent that we have available capacity. For this service the shipper pays no reservation charge but pays a variable use charge for quantities actually shipped. |
• | Fixed-Margin Arrangements. Under these arrangements, we purchase natural gas from producers or suppliers at receipt points on our systems at an index price less a fixed transportation fee and simultaneously sell an identical volume of natural gas at delivery points on our systems at the same, undiscounted index price. We view fixed-margin arrangements to be economically equivalent to our interruptible transportation arrangements. |
How We Evaluate Our Operations
Our management uses a variety of financial and operational metrics to analyze our performance. We view these metrics as important factors in evaluating our profitability and review these measurements on at least a monthly basis for consistency and trend analysis. These metrics include throughput volumes, gross margin and direct operating expenses on a segment basis, and adjusted EBITDA on a company-wide basis.
Throughput Volumes
In our Gathering and Processing segment, we must continually obtain new supplies of natural gas to maintain or increase throughput volumes on our systems. Our ability to maintain or increase existing volumes of natural gas and obtain new supplies is impacted by (i) the level of work-overs or recompletions of existing connected wells and successful drilling activity in areas currently dedicated to or near our gathering systems, (ii) our ability to compete for volumes from successful new wells in the areas in which we operate, (iii) our ability to obtain natural gas that has been released from other commitments and (iv) the volume of natural gas that we purchase from connected systems. We actively monitor producer activity in the areas served by our gathering and processing systems to pursue new supply opportunities.
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In our Transmission segment, the majority of our segment gross margin is generated by firm capacity reservation fees, as opposed to the actual throughput volumes, on our interstate and intrastate pipelines. Substantially all Transmission segment gross margin is generated under contracts with shippers, including producers, industrial companies, LDCs and marketers, for firm and interruptible natural gas transportation on our pipelines. We routinely monitor natural gas market activities in the areas served by our transmission systems to pursue new shipper opportunities.
Gross Margin and Segment Gross Margin
Gross margin and segment gross margin are metrics that we use to evaluate our performance. We define segment gross margin in our Gathering and Processing segment as revenue generated from gathering and processing operations, less construction, operating and maintenance agreement (“COMA”) income, less the cost of natural gas, NGLs and condensate purchased. Revenue includes revenue generated from fixed fees associated with the gathering and treating of natural gas and from the sale of natural gas, NGLs and condensate resulting from gathering, processing and fractionating activities under fixed-margin and POP arrangements. The cost of natural gas, NGLs and condensate includes volumes of natural gas, NGLs and condensate remitted back to producers pursuant to POP arrangements and the cost of natural gas purchased for our own account, including pursuant to fixed-margin arrangements.
We define segment gross margin in our Transmission segment as revenue generated from firm and interruptible transportation agreements and fixed-margin arrangements, plus other related fees, less COMA income, less the cost of natural gas purchased in connection with fixed-margin arrangements. Substantially all of our gross margin in this segment is fee-based or fixed-margin, with little to no direct commodity price risk.
Effective October 1, 2012, we changed our segment gross margin measure to exclude COMA income. For the three months ended March 31, 2013 and 2012, less than $0.1 million and $0.5 million in COMA income was excluded from our Gathering and Processing segment gross margin, respectively and less than $0.1 million and $0.7 million in COMA income was excluded from our Transmission segment gross margin, respectively.
We define gross margin as the sum of our segment gross margin for our Gathering and Processing and Transmission segments. The GAAP measure most comparable to gross margin is net income.
Direct Operating Expenses
Our management seeks to maximize the profitability of our operations in part by minimizing direct operating expenses without sacrificing safety or the environment. Direct labor costs, insurance costs, ad valorem and property taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities, lost and unaccounted for gas and contract services comprise the most significant portion of our operating expenses. These expenses are relatively stable and largely independent of throughput volumes through our systems, but may fluctuate depending on the activities performed during a specific period.
Adjusted EBITDA
Adjusted EBITDA is a measure used by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:
• | the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; |
• | the ability of our assets to generate cash sufficient to support our indebtedness and make cash distributions to our unitholders and general partner; |
• | our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and |
• | the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities. |
We define adjusted EBITDA as net income, plus interest expense, income tax expense, depreciation expense less amounts attributable to discontinued operations, certain non-cash charges such as non-cash equity compensation, unrealized losses on commodity derivative contracts and selected charges that are unusual or non-recurring, less interest income, income tax benefit, unrealized gains on commodity derivative contracts, COMA income, amortization of commodity put purchase costs, and selected gains that are unusual or non-recurring less amounts attributable to discontinued operations. The GAAP measure most directly comparable to adjusted EBITDA is net income.
Note About Non-GAAP Financial Measures
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Gross margin and adjusted EBITDA are non-GAAP financial measures. Each has important limitations as an analytical tool because it excludes some, but not all, items that affect the most directly comparable GAAP financial measures. Management compensates for the limitations of these non-GAAP measures as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these data points into management’s decision-making process.
You should not consider any of gross margin or adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Gross margin and adjusted EBITDA may be defined differently by other companies in our industry Our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.
For a reconciliation of gross margin to net income, its most directly comparable financial measure calculated and presented in accordance with GAAP, please read Note 14 "Reporting Segments" to our unaudited condensed consolidated financial statements included in “Item 1. Financial Statements” of this Quarterly Report.
The following table reconciles the non-GAAP financial measures of adjusted EBITDA used by management to Net (loss) income attributable to the Partnership, their most directly comparable GAAP measure, for the three months ended March 31, 2013 and 2012 (in thousands):
Three months ended March 31, | |||||||
2013 | 2012 | ||||||
(in thousands) | |||||||
Net income (loss) attributable to the Partnership | $ | (3,553 | ) | $ | 1,691 | ||
Add: | |||||||
Depreciation and accretion expense | 5,646 | 5,127 | |||||
Interest expense | 1,731 | 757 | |||||
Debt issuance costs | 912 | — | |||||
Unrealized (gain) loss on commodity derivatives | 481 | (323 | ) | ||||
Non-cash equity compensation expense | 388 | 331 | |||||
Transaction expenses | 342 | — | |||||
Deduct: | |||||||
COMA income | 106 | 1,206 | |||||
Straight-line amortization of put costs (1) | 27 | 112 | |||||
OPEB plan net periodic benefit (cost) | 18 | 21 | |||||
Gain (loss) on involuntary conversion of property, plant and equipment | 421 | — | |||||
Gain (loss) on sale of assets, net | — | — | |||||
Adjusted EBITDA | $ | 5,375 | $ | 6,244 | |||
(1) | Amounts noted represent the straight-line amortization of the cost of commodity put contracts over the life of the contract. |
General Trends and Outlook
We expect our business to continue to be affected by the key trends discussed under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations — General Trends and Outlook” in the Annual Report.
Results of Operations — Combined Overview
For the three months ended March 31, 2013, gross margin decreased to $12.5 million or 0.7% compared to the same period in 2012. The decrease in gross margin was largely a result of lower realized NGL prices and reduced gathering and processing volumes associated with one of our offshore pipeline systems which in turn negatively impacted our financial performance for the three months ended March 31, 2013 offset by the acquisition of a 87.4% undivided interest in the Chatom system, effective July 1, 2012 which contributed incremental gross margin of $2.7 million for the three months ended March 31, 2013.
We distributed $4.0 million to our unitholders or $0.4325 per unit paid subsequent to the fourth quarter for that quarter.
The following table and discussion presents certain of our historical consolidated financial data for the periods indicated. The results of operations by segment are discussed in further detail following this combined overview.
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Three months ended March 31, | |||||||
2013 | 2012 | ||||||
(in thousands) | |||||||
Statement of Operations Data: | |||||||
Revenue | $ | 59,883 | $ | 44,534 | |||
Unrealized gain (loss) on commodity derivatives | (481 | ) | 323 | ||||
Total revenue | 59,402 | 44,857 | |||||
Operating expenses | |||||||
Purchases of natural gas, NGLs and condensate | 47,301 | 30,768 | |||||
Direct operating expenses | 4,803 | 2,885 | |||||
Selling, general and administrative expenses | 3,425 | 3,329 | |||||
Equity compensation expense (a) | 388 | 331 | |||||
Depreciation and accretion expense | 5,646 | 5,127 | |||||
Total operating expenses | 61,563 | 42,440 | |||||
Gain (loss) on involuntary conversion of property, plant and equipment | 421 | — | |||||
Gain (loss) on sale of assets, net | — | — | |||||
Operating income (loss) | (1,740 | ) | 2,417 | ||||
Other income (expenses): | |||||||
Interest expense | (1,731 | ) | (757 | ) | |||
Net income (loss) from continuing operations | (3,471 | ) | 1,660 | ||||
Discontinued operations | |||||||
Income (loss) from operations of disposal groups | 73 | 31 | |||||
Net income (loss) | (3,398 | ) | 1,691 | ||||
Net income (loss) attributable to noncontrolling interests | 155 | — | |||||
Net income (loss) attributable to the Partnership | $ | (3,553 | ) | $ | 1,691 | ||
Other Financial Data: | |||||||
Gross margin (b) | $ | 12,476 | $ | 12,560 | |||
Adjusted EBITDA (c) | $ | 5,375 | $ | 6,244 | |||
(a) | Represents cash and non-cash costs related to our LTIP. Of these amounts, $0.4 million and $0.3 million, for the three months ended March 31, 2013 and 2012, respectively. |
(b) | For a definition of gross margin and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read Note 14 "Reporting Segments" to our unaudited condensed consolidated financial statements included in this Quarterly Report for a discussion of how we use gross margin to evaluate our operating performance. |
(c) | For a definition of adjusted EBITDA and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP and a discussion of how we use adjusted EBITDA to evaluate our operating performance, please read “—How We Evaluate Our Operations”. |
Three months ended March 31, 2013 Compared to Three months ended March 31, 2012
Revenue. Our revenue for the three months ended March 31, 2013 was $59.9 million compared to $44.5 million for the three months ended March 31, 2012. This increase of $15.4 million was primarily due to the following:
• | Natural gas revenues increased $7.8 million as a result of higher realized natural gas prices of $3.70/Mcf, an increase of $0.96/Mcf period over period, along while natural gas sales volumes remained constant period over period; |
• | NGL revenues remained flat as a result of higher gross NGL production volumes of 2.5 Mgal/d due to higher volumes from the newly acquired Chatom system, effectively July 1, 2012, offset by lower realized NGL prices of $0.88/gal, a decrease of $0.48/gal period over period; |
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• | Condensate revenues increased $9.7 million as a result of higher condensate production of 35.5 Mgal/d due to the newly acquired Chatom system, effective July 1, 2012, offset by lower realized condensate prices of $2.39/gal, a decrease of $0.19/gal period over period; and |
• | Transmission revenues from the transportation of natural gas increased $3.5 million as a result of higher realized natural gas prices on our fixed margin contracts of $0.59/Mcf amounting to $1.2 million and higher transmission throughput of 49.3 MMcf/d or 13% period over period. |
Purchases of Natural Gas, NGLs and Condensate. Our purchases of natural gas, NGLs and condensate for the three months ended March 31, 2013 were $47.3 million compared to $30.8 million for the three months ended March 31, 2012. This increase of $16.5 million was primarily due to higher purchase costs associated with natural gas and NGLs amounting to $7.6 million and $8.0 million, respectively due to higher realized natural gas prices and higher NGL and condensate production related to POP contracts associated with owned processing plants in our Gathering and Processing segment.
Gross Margin. Gross margin for the three months ended March 31, 2013 was $12.5 million compared to $12.6 million for the three months ended March 31, 2012. This decrease of $0.1 million was primarily due to lower gross margin in our Gathering and Processing segment as a result of lower natural gas throughput volumes of 122.4 MMcf/d or 33% in our Gathering and Processing segment amounting to $1.6 million, offset by additional gross margin at our Chatom system, effective July 1, 2012, which contributed incremental gross margin of $2.7 million for the three months ended March 31, 2013.
Direct Operating Expenses. Direct operating expenses for the three months ended March 31, 2013 were $4.8 million compared to $2.9 million in the three months ended March 31, 2012. This increase of $1.9 million was primarily due to: (i) $1.1 million of additional direct operating expenses associated with our newly acquired Chatom system, effective July 1, 2012; (ii) $0.2 million of costs associated with our 2013 integrity management program; and (iii) $0.2 million of costs associated with additional lease expense and other operating expense associated with our Madison County system.
Selling, General and Administrative Expenses ("SG&A"). SG&A expenses for the three months ended March 31, 2013 were $3.4 million compared to $3.3 million for the three months ended March 31, 2012. This increase of $0.1 million was primarily due to increased costs associated with contract services, labor and consulting.
Equity Compensation Expense. Compensation expense related our LTIP for the three months ended March 31, 2013 was $0.4 million compared to $0.3 million for the three months ended March 31, 2012. This increase of $0.1 million was primarily due to the amortization of additional unit based awards granted in 2012.
Depreciation and Accretion Expense. Depreciation expense for the three months ended March 31, 2013 was $5.6 million compared to $5.1 million for the three months ended March 31, 2012. This increase of $0.5 million was due to depreciation associated with newly acquired Chatom system, effectively July 1, 2012 and capital projects placed into service during the period.
Results of Operations — Segment Results
The table below contains key segment performance indicators related to our segment results of operations.
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Three months ended March 31, | |||||||
2013 | 2012 | ||||||
(in thousands except operational data) | |||||||
Segment Financial and Operating Data: | |||||||
Gathering and Processing segment | |||||||
Financial data: | |||||||
Revenue | $ | 45,224 | $ | 31,396 | |||
Unrealized gain (loss) on commodity derivatives | (481 | ) | 323 | ||||
Total revenue | 44,743 | 31,719 | |||||
Purchases of natural gas, NGLs and condensate | $ | 36,700 | $ | 22,392 | |||
Direct operating expenses | $ | 3,404 | $ | 1,802 | |||
Other financial data: | |||||||
Segment gross margin | $ | 8,481 | $ | 8,542 | |||
Operating data: | |||||||
Average throughput (MMcf/d) | 244.9 | 367.3 | |||||
Average plant inlet volume (MMcf/d) (a) (b) | 97.1 | 148.6 | |||||
Average gross NGL production (Mgal/d) (a) (c) | 53.9 | 51.4 | |||||
Average gross condensate production (Mgal/d) (a) (c) | 44.2 | 6.2 | |||||
Average realized prices: | |||||||
Natural gas ($/MMcf) | $ | 3.70 | $ | 2.74 | |||
NGLs ($/gal) | $ | 0.88 | $ | 1.36 | |||
Condensate ($/gal) | $ | 2.39 | $ | 2.58 | |||
Transmission segment | |||||||
Financial data: | |||||||
Total revenue | $ | 14,659 | $ | 13,138 | |||
Purchases of natural gas, NGLs and condensate | $ | 10,601 | $ | 8,376 | |||
Direct operating expenses | $ | 1,399 | $ | 1,083 | |||
Other financial data: | |||||||
Segment gross margin | $ | 3,995 | $ | 4,018 | |||
Operating data: | |||||||
Average throughput (MMcf/d) | 442.6 | 393.3 | |||||
Average firm transportation - capacity reservation (MMcf/d) | 777.7 | 761.3 | |||||
Average interruptible transportation - throughput (MMcf/d) | 129.1 | 56.6 | |||||
(a) | Excludes volumes and gross production under our elective processing arrangements. |
(b) | Includes gross plant inlet volume associated with our interest in the Burns Point processing plant. |
(c) | Includes net NGL production associated with our interest in the Burns Point processing plant. |
Three months ended March 31, 2013 Compared to Three months ended March 31, 2012
Gathering and Processing Segment
Total Revenue. Segment total revenue in the three months ended March 31, 2013 was $44.7 million compared to $31.7 million in the three months ended March 31, 2012. This increase of $13.0 million was primarily due to the following:
• | Higher realized natural gas prices of 35% offset by lower realized NGL prices of 35% and realized condensate prices of 7% period over period as a result of variable commodity prices; |
• | Higher average gross NGL production amounting to 2.5 Mgal/d period over period as a result of our Bazor Ridge system and our acquired 87.4% undivided interest in the Chatom system, effective July 1, 2012 offset by lower production at our Burns Point Plant; |
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• | Higher average gross condensate production amounting to 38.0 Mgal/d period over period as a result of our acquired 87.4% undivided interest in the Chatom system, effective July 1, 2012; offset by |
• | Lower average natural gas throughput volumes amounting to 122.4 MMcf/d or 33% period over period as a result of lower volumes at our Burns Point Plant and Quivira system. Notably, our Quivira system continues to see a lower level volumes on one of its offshore pipeline systems as a result of a producer's work on one of its platforms which provided access to an alternative market that offers competitive terms. The Partnership continues to work with this producer to negotiate the return of a portion of historical volumes to the offshore pipeline system, although the contract terms may change for this portion of volumes going forward and may have a material negative impact on financial results; and |
• | An increase in unrealized losses of $0.8 million period over period on our commodity derivatives which comprised of financial swaps, collars and option contracts used to mitigate commodity price risk that will settled in 2013. For a discussion of our commodity derivative positions, please read “Item 3. Quantitative and Qualitative Disclosures about Market Risk.” |
Purchases of Natural Gas, NGLs and Condensate. Our purchases of natural gas, NGLs and condensate for the three months ended March 31, 2013 were $36.7 million compared to $22.4 million for the three months ended March 31, 2012. This increase of $14.3 million was primarily due to higher purchase costs associated with natural gas and NGLs amounting to $7.6 million and $8.0 million, respectively due to higher realized natural gas prices and higher NGL and condensate production related to POP contracts associated with owned processing plants.
Segment Gross Margin. Segment gross margin for the three months ended March 31, 2013 was $8.5 million compared to $8.5 million for the three months ended March 31, 2012. The amounts were consistent primarily due to the following:
• | Incremental segment gross margin of $2.7 million associated with higher average condensate production of 38.0 Mgal/d as a result of the newly acquired Chatom system, effective July 1, 2012; |
• | Lower segment gross margins of $1.6 million associated with our Burns Point Plant and Quivira system. Notably, our Quivira system continues to see a lower level of volumes on one of its offshore pipeline systems as a result of a producer's work on one of its platforms which provided access to an alternative market that offers competitive terms; |
• | Lower segment gross margin of $0.7 million associated with lower NGL sales volumes at our Bazor Ridge and Gloria systems due to lower realized NGL prices related to POP contracts; and |
• | An increase in realized gains of $0.2 million period over period on our commodity derivatives which comprised of financial swaps, collars and option contracts which were used to mitigate commodity price risk that settled in 2013. |
Direct Operating Expenses. Direct operating expenses for the three months ended March 31, 2013 were $3.4 million compared to $1.8 million for the three months ended March 31, 2012. This increase of $1.6 million was primarily due to the operating costs associated with our 87.4% undivided interest in the Chatom system, effective July 1, 2012 amounting to $1.1 million; and incremental costs associated with the 2013 integrity management program amounting to $0.2 million.
Transmission Segment
Revenue. Segment total revenue for the three months ended March 31, 2013 was $14.7 million compared to $13.1 million for the three months ended March 31, 2012. This increase of $1.6 million in segment revenue was primarily due to -
• | Higher realized natural gas prices on our fixed margin contracts of $0.59/Mcf amounting to $1.2 million; |
• | Total natural gas throughput volumes on our Transmission systems for the three months ended March 31, 2013 was 442.6 MMcf/d compared to 393.3 MMcf/d for the three months ended March 31, 2012 representing a 13% increase period over period. |
Purchases of Natural Gas, NGLs and Condensate. Purchases of natural gas, NGLs and condensate for the three months ended March 31, 2013 were $10.6 million compared to $8.4 million for the three months ended March 31, 2012. This increase of $2.2 million was primarily due to higher realized natural gas prices, which resulted in higher natural gas purchase costs associated with our fixed margin agreements on MLGT and Midla.
Segment Gross Margin. Segment gross margin for the three months ended March 31, 2013 was $4.0 million compared to $4.0 million for the three months ended March 31, 2012. This decrease of less than $0.1 million was primarily due to lower firm transportation revenues offset by slightly higher interruptible transportation revenue from our Midla system.
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Direct Operating Expenses. Direct operating expenses for the three months ended March 31, 2013 were $1.4 million compared to $1.1 million for the three months ended March 31, 2012. This increase of $0.3 million is primarily due to line loss associated with our Midla system amounting $0.4 million.
Liquidity and Capital Resources
Our business is capital intensive and requires significant investment for the maintenance of existing assets and the acquisition and development of new systems and facilities.
Our Credit Facility
On June 27, 2012, we amended that August 2011 credit facility to increase the commitments from an aggregate principal amount of $100 million to an aggregate principal amount of $200 million, evidenced by a credit agreement with Bank of America, N.A., as Administrative Agent, Collateral Agent and L/C Issuer; Comerica Bank and Citicorp North America, Inc., as Co-Syndication Agents; BBVA Compass, as Documentation Agent; and the other financial institutions party thereto.
That June 2012 amended credit facility provided for a maximum borrowing equal to the lesser of (i) $200 million or (ii) 4.50 times adjusted consolidated EBITDA. Prior to the Third Amendment described below, we could elect to have loans under the June 2012 amended credit facility bear interest either at a Eurodollar-based rate plus a margin ranging from 2.25% to 3.50% depending on our total leverage ratio then in effect, or a base rate which is a fluctuating rate per annum equal to the highest of (a) the Federal Funds Rate plus 1/2 of 1%, (b) the rate of interest in effect for such day as publicly announced from time to time by Bank of America as its “prime rate”, or (c) the Eurodollar Rate plus 1.00% plus a margin ranging from 1.25% to 2.50% depending on the total leverage ratio then in effect. We also paid a commitment fee of 0.50% per annum on the undrawn portion of the revolving loan.
For the three months ended March 31, 2013 and 2012, the weighted average interest rate on borrowings under our credit facility was approximately 4.34% and 3.72%, respectively.
Our obligations under each of our credit facilities, including the current June 2012 amended credit facility, are secured by a first mortgage in favor of the lenders in our real property. Advances made under the June 2012 amended credit facility are guaranteed on a senior unsecured basis by our subsidiaries (“Guarantors”). These guarantees are full and unconditional and joint and several among the Guarantors. The terms of the June 2012 amended credit facility include covenants that restrict our ability to make cash distributions and acquisitions in some circumstances. The remaining principal balance of loans and any accrued and unpaid interest will be due and payable in full on the maturity date, August 1, 2016.
The June 2012 amended credit facility also contains customary representations and warranties (including those relating to organization and authorization, compliance with laws, absence of defaults, material agreements and litigation) and customary events of default (including those relating to monetary defaults, covenant defaults, cross defaults and bankruptcy events). The primary financial covenants contained in the June 2012 amended credit facility are (i) a total leverage ratio test (which, prior the Fourth Amendment could not exceed 4.50) and a minimum interest coverage ratio test (which, prior to the Third Amendment could not less be than 2.50).
As of December 31, 2012, the total leverage ratio test, one of the primary financial covenants that we were required to maintain under our June 2012 amended credit facility, exceeded the leverage covenant. As a result, on December 26, 2012, the Partnership entered into the Third Amendment and Waiver to Credit Agreement, dated as of December 26, 2012 (the “Third Amendment”). The Third Amendment provided for a waiver of the Partnership's compliance with the Consolidated Total Leverage Ratio with respect to the quarter ending December 31, 2012 and for one month thereafter. The Third Amendment also required the Partnership to provide certain financial and operating information of the Partnership on a monthly basis for 2013 and for any month after 2013 in which the Consolidated Total Leverage Ratio of the Partnership is in excess of 4.00 to 1.00. The remaining material terms and conditions of the June 2012 amended credit facility, including pricing, maturity and covenants, remained unchanged by the Third Amendment.
On January 24, 2013, the Partnership entered into the second waiver to the June 2012 amended credit facility that extended the waiver period with respect to the Consolidated Total Leverage Ratio to March 31, 2013 (and subsequently extended to April 16, 2013). Additional covenants during the waiver period included i) total outstanding borrowings under the June 2012 amended credit facility could not exceed $150 million; ii) restrictions on certain acquisitions; iii) an increase to the Eurodollar rate by 0.50%; iv) additional fees of 0.125% of the principal amount on each of February 28, 2013 and March 31, 2013; and v) execution of a compliance certificate.
At December 31, 2012, our total indebtedness was approximately $130.9 million, which caused our total leverage to EBITDA ratio to be approximately 5.7-to-1. Prior to the Fourth Amendment to our June 2012 amended credit agreement, the maximum
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value permitted under the June 2012 amended credit agreement for that ratio could not exceed 4.5 to 1.0. As of March 31, 2013, outstanding debt under our June 2012 amended credit facility was approximately $139 million, which further exceeded the maximum Consolidated Total Leverage Ratio as of that date and constituted a default under the June 2012 amended credit agreement. Please read “Recent Developments — Fourth Amendment to Credit Agreement” for a description of the Fourth Amendment.
On April 15, 2013, we repaid approximately $12.5 million in outstanding borrowings under the June 2012 amended credit agreement and entered into the Fourth Amendment to our June 2012 amended credit agreement in connection with the ArcLight Transactions. As a result, we had approximately $130 million of outstanding borrowings as of April 15, 2013 and approximately $45 million of available borrowing capacity as a result of the reduction of our borrowing capacity to a total of $175 million as described below. Until June 30, 2013, we will not be required to meet a Consolidated Leverage Ratio under our June 2012 amended credit facility. We expect that we will have availability under our June 2012 amended credit facility and be able to meet the Fourth Amendment's Consolidated Leverage Ratio once it is reinstated on June 30, 2013, but there can be no assurance that will be the case or what that availability might be. Please see “Recent Developments — ArcLight Transactions” for more information about the ArcLight Transactions.
The principal indicators of our liquidity at March 31, 2013 were our cash on hand and availability under our June 2012 amended credit facility as it existed prior to the Fourth Amendment as discussed below. As of March 31, 2013, our available liquidity was $9.1 million, comprised of cash on hand of less than $0.1 million and $9.1 million available under our June 2012 amended credit facility as it existed at that time. As of May 10, 2013, our available liquidity was $40.9 million.
In the near term, we expect our sources of liquidity to include cash generated from operations, borrowings under our June 2012 amended credit facility and issuances of debt and equity securities. As a result of the contribution of the High Point assets to the Partnership (with the resultant expected increase in the Partnership's EBITDA for the trailing twelve months), the Fourth Amendment, and the PIK Distribution on the Series A Preferred Units and the Preferred Unit Distribution Waiver, we expect to generate sufficient cash flow from operations and borrowings under our June 2012 amended credit facility, as needed, to:
• | pay the required distribution on the Series A Convertible Preferred Units (a portion of which is payable in-kind in additional Series A Preferred Units (“Series A PIK Units”), less the Preferred Unit Distribution Waiver; |
• | pay at least the minimum quarterly distribution on all outstanding common units, subordinated units, and general partner units; and |
• | meet our requirements for working capital and capital expenditures, |
in each case until at least April 16, 2014. Please see “Recent Developments — ArcLight Transactions” for more information about the ArcLight Transactions.
We depend on our June 2012 amended credit facility for future capital needs and may use it to fund a portion of cash distributions to unitholders, as necessary, depending on the level of our operating cashflow. We are required to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control, including events and circumstances that may stem from the condition of financial markets and commodity price levels. Our failure to comply with any of the covenants under our June 2012 amended credit facility could result in a default, which could cause all of our existing indebtedness to become immediately due and payable. We were unable to maintain compliance with consolidated total leverage ratio required by our June 2012 amended credit agreement as it existed prior to the Fourth Amendment during the quarters ended December 31, 2012 and March 31, 2013 but we were able to obtain wavers from the lenders for these covenant breaches.. On April 15, 2013, we entered into a Fourth Amendment to our June 2012 amended credit agreement that, among other things, modified the maximum permitted consolidated total leverage ratio. The maximum consolidated total leverage ratio permitted by the Fourth Amendment varies by quarter, initially permitting a ratio of 5.90 to 1.00 for the quarter ending June 30, 2013 and then gradually lowering to 4.50 to 1.00 commencing with the quarter ending March 31, 2015. The Partnership believes that the consummation of the ArcLight Transactions will allow it to comply with the Consolidated Total Leverage to EBTIDA ratio in the Fourth Amendment until at least April 16, 2014. However, no assurances can be given that the ArcLight Transactions will achieve the necessary ratios or that the contributed business can yield the necessary cash flows.
Working Capital
Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our liabilities as they become due. Our working capital requirements are primarily driven by changes in accounts receivable and accounts payable. These changes are impacted by changes in the prices of commodities that we buy and sell. In general, our working capital requirements increase in periods of rising commodity prices and decrease in periods of declining commodity prices. However, our working capital needs do not necessarily change at the same rate as commodity prices because both accounts receivable and accounts payable are impacted by commodity prices. In addition, the timing of payments received from our customers or paid to our suppliers can also cause fluctuations in working capital because we settle with most of our larger suppliers and customers on
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a monthly basis and often near the end of the month. We expect that our future working capital requirements will be impacted by these same factors.
Our working capital deficit was $0.3 million at March 31, 2013.
Cash Flows
The following table reflects cash flows for the applicable periods:
Three months ended March 31, | |||||||
2013 | 2012 | ||||||
(in thousands) | |||||||
Net cash provided by (used in): | |||||||
Operating activities | $ | 1,103 | $ | 4,183 | |||
Investing activities | (7,492 | ) | (963 | ) | |||
Financing activities | 5,858 | (3,933 | ) | ||||
Three months ended March 31, 2013 Compared to Three months ended March 31, 2012
Operating Activities. Net cash provided by operating activities was $1.1 million for the three months ended March 31, 2013 compared to $4.2 million for the three months ended March 31, 2012. Net cash provided by operating activities for the three months ended March 31, 2013 decreased period over period primarily due to i) a decrease in gross margin largely as a result of lower realized NGL prices and reduced gathering and processing volumes associated with one of our offshore pipeline systems partially offset by the acquisition of a 87.4% undivided interest in the Chatom system, effective July 1, 2012 which contributed incremental gross margin of $2.7 million for the three months ended March 31, 2013; ii) an increase in direct operating expenses of $2.5 million due to the acquisition of a 87.4% undivided interest in the Chatom system, effective July 1, 2012, of $1.1 million and an increase in integrity management expenses of $0.2 million; offset by iii) net positive changes in operating assets and liabilities of $0.9 million due to accruals of expected future operating cash receipts and cash payments; and iv) an increase in proceeds received from the settlement of commodity derivatives of $0.3 million.
One of the primary sources of variability in our cash flows from operating activities is fluctuation in commodity prices, which we partially mitigate by entering into commodity derivatives. Average throughput volume changes also impact cash flow, but have not been as volatile as commodity prices. Our long-term cash flows from operating activities are dependent on commodity prices, average throughput volumes, costs required for continued operations and cash interest expense.
Investing Activities. Net cash used in investing activities was $7.5 million for the three months ended March 31, 2013 compared to $1.0 million for the three months ended March 31, 2012. Cash used in investing activities for the three months ended March 31, 2013 increased year over year primarily due to i) $5.7 million used to fund the development of our Madison County system and ii) $1.2 million used to fund maintenance capital primarily associated improvements at our Bazor Ridge system.
Financing Activities. Net cash provided in financing activities was $5.9 million for the three months ended March 31, 2013 compared to net cash used of $3.9 million for the three months ended March 31, 2012. Cash provided by financing activities for the three months ended March 31, 2013 increased year over year primarily due to an increase of $10.0 million in net borrowings from our June 2012 amended credit facility to fund growth opportunities and maintenance capital.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
Capital Requirements
The midstream energy business can be capital intensive, requiring significant investment for the maintenance of existing assets and the acquisition and development of new systems and facilities. We categorize our capital expenditures as either:
• | maintenance capital expenditures, which are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity; or |
• | expansion capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term. |
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Historically, our maintenance capital expenditures have not included all capital expenditures required to maintain volumes on our systems. It is customary in the regions in which we operate for producers to bear the cost of well connections, but we cannot be assured that this will be the case in the future. For the three months ended March 31, 2013, capital expenditures totaled $8.1 million including new development of $5.6 million, expansion capital expenditures of $0.4 million, maintenance capital expenditures of $1.9 million and reimbursable project expenditures (capital expenditures for which we expect to be reimbursed for all or part of the expenditures by a third party) of $0.2 million. Although we classified our capital expenditures as expansion and maintenance, we believe those classifications approximate, but do not necessarily correspond to, the definitions of estimated maintenance capital expenditures and expansion capital expenditures under our partnership agreement.
We anticipate that we will continue to make significant expansion capital expenditures in the future. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives. As a result of the contribution of the High Point assets to the Partnership, the Fourth Amendment, the PIK Distribution on the Series A Preferred Units and the Preferred Unit Distribution Waiver, we expect to generate sufficient cash flow from operations and borrowings under our June 2012 amended credit facility, as needed, to meet our requirements for future expansion capital expenditures until at least April 16, 2014.
We depend on our June 2012 amended credit facility for future capital needs and may use it to fund a portion of cash distributions to unitholders, as necessary, depending on the level of our operating cashflow. We are required to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control, including events and circumstances that may stem from the condition of financial markets and commodity price levels. Our failure to comply with any of the covenants under our June 2012 amended credit facility could result in a default, which could cause all of our existing indebtedness to become immediately due and payable. We were unable to maintain compliance with consolidated total leverage ratio required by our June 2012 amended credit agreement as it existed prior to the Fourth Amendment during the quarters ended December 31, 2012 and March 31, 2013 but we were able to obtain wavers from the lenders for these covenant breaches. On April 15, 2013, we entered into a Fourth Amendment to our June 2012 amended credit agreement that, among other things, modified the maximum permitted consolidated total leverage ratio. The maximum consolidated total leverage ratio permitted by the Fourth Amendment varies by quarter, initially permitting a ratio of 5.90 to 1.00 for the quarter ending June 30, 2013 and then gradually lowering to 4.50 to 1.00 commencing with the quarter ending March 31, 2015.
Integrity Management
Certain operating assets require an ongoing integrity management program under regulations of the U.S. Department of Transportation, or DOT. These regulations require transportation pipeline operators to implement continuous integrity management programs over a seven-year cycle. Our current program addresses sixteen high consequence areas, or HCAs, that required further testing pursuant to DOT regulations. We expect to incur approximately $2.0 million in integrity management expenses for the year ended December 31, 2013 associated with these HCAs to complete the current integrity management program.
Over the course of the seven-year cycle, we expect to incur an average of $1.5 million in integrity management expenses per year .
Because DOT regulations require integrity management activities for each HCA to be performed within seven years from when they were last performed, we expect to incur the following expenses:
Year | Integrity Management Expense | ||
(in thousands) | |||
2013 | $ | 2,000 | |
2014 | 5,015 | ||
2015 | 839 | ||
2016 | 675 | ||
2017 | — | ||
2018 | — | ||
2019 | 2,080 | ||
Total | $ | 10,609 | |
Distributions
We intend to pay a quarterly distribution though we do not have a legal obligation to make distributions except as provided in our partnership agreement.
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On February 14, 2013, we paid a distribution for the fourth quarter 2012 of $0.4325 per unit, or $4.0 million.
Contractual Obligations
The table below summarizes our obligations and other commitments as of March 31, 2013.
Payments Due by Period | |||||||||||||||||||||||||||
(in thousands) | |||||||||||||||||||||||||||
Total | 2013 | 2014 | 2015 | 2016 | 2017 | Thereafter | |||||||||||||||||||||
Operating leases and service contracts | $ | 2,210 | $ | 317 | $ | 447 | $ | 420 | $ | 176 | $ | 140 | $ | 710 | |||||||||||||
Asset retirement obligations | 8,329 | — | — | — | 7,867 | — | 462 | ||||||||||||||||||||
Total | $ | 10,539 | $ | 317 | $ | 447 | $ | 420 | $ | 8,043 | $ | 140 | $ | 1,172 | |||||||||||||
Critical Accounting Policies
There were no changes to our significant accounting policies from those disclosed in the Annual Report.
Recent Accounting Pronouncements
In January 2013, the FASB issued Accounting Standards Update ("ASU") No. 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which clarifies that ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities, applies to financial instruments or derivative transactions accounted for under ASC 815. The amendments require disclosures to present both gross and net amounts of derivative assets and liabilities that are subject to master netting arrangements with counterparties. We currently present our derivative assets and liabilities net on our statement of financial position. We have provided additional disclosures regarding the gross amounts of derivative assets and liabilities in Note 5 "Derivatives" in accordance with these new standards updates.
In February 2013, the FASB issued ASU No. 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income ("AOCI"), which requires entities to present either in a single note or parenthetically on the face of the financial statements (i) the amount of significant items reclassified from each component of AOCI and (ii) the income statement line items affected by the reclassifications. We adopted this guidance during the first quarter of 2013 which did not have a material impact on our condensed consolidated financial statements as there are currently no items reclassified from AOCI.
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