Item 1.
Business.
Overview
We are a domestically-focused, growth-oriented limited partnership engaged in the business of (i) gathering, compressing, treating, processing and transporting natural gas; fractionating and transporting natural gas liquids (“NGLs”); crude oil and condensate logistics and marketing; and natural gas marketing and trading, which collectively we call our “Midstream Business”; and (ii) developing and producing interests in oil and natural gas properties, which we call our “Upstream Business.”
Our objective is to grow our business in a manner that enhances our ability to increase cash distributions to our unitholders. To do so, we focus on achieving operational excellence in our businesses and executing accretive low-risk acquisitions and organic growth opportunities, and we allocate a portion of our cash flows to fund growth-related capital expenditures.
We are uniquely positioned as a publicly-traded partnership, or master limited partnership (“MLP”), that is engaged in both the midstream and upstream sectors of the oil and natural gas value chain. Our diversification broadens our spectrum of potential organic growth and acquisition opportunities, gives us a potential advantage in acquiring asset packages that involve both midstream and upstream assets, and enables us to exploit vertical integration synergies in selected regions of our operations.
Our Midstream Business is located in four significant natural gas producing regions: (i) the Texas Panhandle; (ii) East Texas/Louisiana; (iii) South Texas; and (iv) the Gulf of Mexico. These four regions are productive, mature, natural gas producing basins that have historically experienced significant drilling activity. On October 1, 2012, we completed our acquisition of two of BP America Production Company's ("BP") gas processing facilities, and the associated gathering systems, that are located in the Texas Panhandle (the "newly-acquired Panhandle System"). The newly-acquired Panhandle System included:
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two natural gas processing plants - the Sunray Plant and the Hemphill Plant - with a total capacity of approximately 218 MMcf/d; and
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an associated gathering system composed of approximately 2,551 miles of pipeline with approximately 1,935 connected wells.
As of December 31, 2012, our natural gas gathering systems across all our regions comprised approximately 8,134 miles of natural gas gathering pipelines with approximately 4,426 well connections, 19 natural gas processing plants with approximately 787 MMcf/d of plant processing capacity and 286,219 horsepower of compression. Our Midstream Business averaged 590 MMcf/d of gathered volumes and 490 MMcf/d of processed volumes during the fourth quarter of 2012.
Our Upstream Business has long-lived, high working interest properties located in four significant oil and gas producing regions: (i) South Alabama (which includes the associated gathering, processing and treating assets); (ii) Mid-Continent (which includes areas in Oklahoma, Arkansas and the Texas Panhandle); (iii) Permian (which includes areas in West Texas); and (iv) East Texas/South Texas/Mississippi/Louisiana. As of December 31, 2012, these working interest properties included 559 gross operated productive wells and 1,249 gross non-operated wells with net production to us of approximately 82.7 MMcfe/d and proved reserves of approximately 194.4 Bcf of natural gas, 13.0 MMBbls of crude oil, and 12.9 MMBbls of natural gas liquids, of which 76% are proved developed.
We report on our businesses in five accounting segments, as outlined in Note 14 of our consolidated financial statements. The Midstream Business's financial results are reported in the following segments: (i) Texas Panhandle, (ii) East Texas and Other Midstream and (iii) Marketing and Trading. We report our Upstream Business as one segment. Our final reporting segment is our functional (Corporate) Segment, in which we account for our risk management, intersegment eliminations and other corporate activities including general and administrative expenses.
Ownership Structure
The diagram below depicts our ownership structure as of February 25, 2013. The ownership percentages shown below are calculated on a fully-diluted basis:
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(a)
"NGP" refers collectively to Natural Gas Partners VII, L.P., a Delaware limited partnership; Natural Gas Partners VIII, L.P., a Delaware limited partnership; and such other entities as set forth on that certain Schedule 13D/A filed with the Securities and Exchange Commission on March 15, 2012 including, without limitation, Montierra Minerals & Production, L.P., a Texas limited partnership and Montierra Management LLC, a Texas limited liability company. For a discussion of certain members of management's ownership in the Montierra entities, see Part III, Item 12 -Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters, incorporating by reference our to-be-filed proxy statement for our 2013 Annual Meeting of Unitholders.
Our Business Strategy
Our primary business objective is to manage our diversified midstream and upstream properties to generate cash flow and grow distributions over time. To meet this objective, we intend to execute the following business strategies:
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Maximizing the profitability of our existing assets. In our Midstream Business, we intend to maximize the profitability of our existing assets by adding new volumes of natural gas to our gathering and processing assets under economically favorable terms. We strive to provide superior customer service, enhance utilization, and improve operating margins and efficiencies. In our Upstream Business, we strive to improve the recoveries of oil and natural gas from our existing wellbores, as well as focus on reducing our per unit operating expenses to maximize the amount of hydrocarbons and valuable by-products we can profitably extract.
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Maintaining a disciplined financial policy. We intend to continue to pursue a disciplined financial policy by maintaining a prudent capital structure and managing our exposure to interest rate and commodity price risk. We target a total leverage ratio (outstanding debt to Adjusted EBITDA) of 3.5:1.0 or less on a sustained basis. Since our initial public offering in October 2006, we have financed 58% of our approximately $1.85 billion in acquisitions with the issuance of our common units. We plan to continue with our historical pattern of financing our growth with a balanced combination of equity and debt. Maintaining a balanced capital structure allows us to use our available capital to selectively pursue attractive investments or acquisition opportunities.
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Expanding our operations through organic growth projects. In our Midstream Business, we intend to leverage our existing infrastructure and customer relationships by expanding our asset base to meet new or increased demand for midstream services. We also look for opportunities to invest in attractive projects in areas outside our existing asset base. In our Upstream Business, we intend to exploit our substantial inventory of attractive, lower-risk drilling opportunities as the primary source of organic growth. We measure the success of organic growth projects based on internal rate of return targets.
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Continuing to reduce our exposure to commodity price risk. We intend to continue to operate our business in a manner that reduces our exposure to commodity price risk in the near term and on an opportunistic basis over the long term. Where commercially practical, we strive to reduce commodity exposure in our Midstream Business by entering into fee-based gathering and processing agreements with our producer customers. In addition, we use a variety of hedging instruments to reduce our exposure to commodity price risk and enhance the stability of our cash flows in both our businesses. Our commodity derivatives are primarily in the form of swaps and collars that are designed to provide a fixed price (swaps) or defined range of prices (collars) that we will receive. We generally hedge a substantial portion of our expected midstream and upstream equity volumes for forward periods of up to four years. We actively monitor our hedge portfolio for opportunities to enter into additional hedges to support our cash flow objectives.
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Pursuing acquisitions. We pursue acquisitions which we believe will result in long-term accretion to our distributable cash flow per common unit. We believe that our capital structure, which no longer includes incentive distribution rights, positions us to compete more effectively for future acquisitions. In our Midstream Business, we generally seek to acquire assets that serve producing areas with high levels of drilling activity. In our Upstream Business, we generally seek to acquire operated assets that contain a mix of oil and natural gas reserves, have shallow decline rates, and offer an appropriate balance of current production with meaningful, lower-risk development opportunities. We will pursue acquisition opportunities that we believe will provide the highest risk-adjusted returns available to us and are complementary to our existing asset base across the midstream and upstream sectors.
Competitive Strengths
We believe that we are well positioned to execute our business strategies successfully because of the following competitive strengths:
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Geographically and operationally diverse asset base focused on mature, prolific oil and natural gas basins. Our portfolio of assets is diversified both from a geographic and operational perspective. Our midstream assets are strategically located in active, mature regions including the Tonkawa, Cleveland and Granite Wash plays in the Texas Panhandle and the Austin Chalk and Haynesville Shale plays in East Texas and Louisiana. Our Midstream Business provides us with the potential to grow throughput volumes and cash flows based, among other things, on our existing and potential customers' drilling plans and the expected performance of their wells. In addition, we have recently
added businesses related to natural gas marketing and trading and crude oil and condensate logistics and marketing in the Texas Panhandle and Alabama. Our upstream assets are diversified among numerous established, lower-cost producing basins in Alabama, Texas, Oklahoma and Arkansas with a balanced mix of crude oil, NGL and natural gas production.
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Significant inventory of lower-risk organic growth opportunities. In our Midstream Business, we had identified approximately $68 million of opportunities to build additional infrastructure in our core areas of the Texas Panhandle and East Texas/Louisiana as of December 31, 2012. In our Upstream Business, we have a significant inventory of lower-risk drilling opportunities and other development projects in our core areas of operation. As of December 31, 2012, we had approximately 600 gross drilling locations, 135 of which were associated with proved reserves; we expect this inventory will allow us to maintain and grow production and proved reserves for several years. In our Upstream Business we have a high degree of operational control that allows us to manage our drilling plans to increase or stabilize our cash flow. We currently intend to drill or complete 32 gross (12.5 net) wells during 2013, for which we have budgeted approximately $78 million of drilling and completion capital expenditures.
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Strong financial profile. We have strong liquidity and sufficient financial flexibility to fund our anticipated capital needs and future growth opportunities. As of December 31, 2012 we had approximately $192.5 million of unused capacity under our credit facility, based on our outstanding debt and expected total commitments (before taking into account covenant-based capacity limitations). Our financial profile also is strengthened by our extensive commodity hedge portfolio, which serves to reduce our cash flow volatility in response to changes in oil, natural gas liquids and natural gas prices.
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Experienced, knowledgeable management team with a proven record of performance. Our management team has a proven record of enhancing value through investing in, acquiring and integrating midstream and upstream assets. Our senior management team has an average of approximately 20 years of industry-related experience and a substantial economic interest in us through direct and indirect ownership of our common units.
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Affiliation with Natural Gas Partners. Founded in 1988, Natural Gas Partners manages a $10.8 billion family of investment funds organized to make direct equity investments in private energy enterprises. Natural Gas Partners owns a significant equity position in us. Natural Gas Partners historically has provided us with increased exposure to acquisition opportunities. We expect that our relationship with Natural Gas Partners may continue to provide us with several significant benefits, including on-going exposure to acquisition opportunities and access to a significant group of transactional and financial professionals with a successful track record of investing in energy assets. We have agreements with Natural Gas Partners that restrict its control of our board of directors and its voting rights with respect to our common units.
History
Our Partnership, formed in May 2006, is the legal successor to Eagle Rock Pipeline, L.P. as a result of our initial public offering in October 2006. We have historically grown through acquisitions and organic growth projects.
The following is a table that depicts our significant acquisitions/dispositions by date, transaction type, cost, financing sources and business over the past five years:
Table of Significant Acquisitions/Dispositions in the Past Five Years
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(a)
Amount includes approximately $2.9 million of cash received from the Minerals Business after the effective date of the sale.
The following is a chart that depicts the costs of our organic growth projects by year and reportable segment over the past five years:
Table of Organic Growth Project Costs in the Past Five Years
The following graph depicts our historical trends in Adjusted EBITDA and quarterly distribution rate per common unit over the past three years:
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Note: "Hedge resets" (in which we paid our hedge counterparties to increase the strike price of existing swaps) contributed $2.2 million to Adjusted EBITDA for the first quarter of 2010.
For a definition of Adjusted EBITDA and reconciliation to GAAP, see Part II, Item 6. Selected Financial Data-Non-GAAP Financial Measures.
Due to our enhanced liquidity position resulting from the Recapitalization and Related Transactions described below, our debt reduction efforts and improved economic conditions, we increased our distribution rate for the fourth quarter of 2010 and throughout 2011. In the first quarter of 2012, natural gas and NGL prices experienced a substantial and extended decline. As a result, we held the distribution rate flat throughout 2012.
Recapitalization and Related Transactions
In 2010, we completed a series of transactions (the "Recapitalization and Related Transactions") which simplified our capital structure and provided us with added financial liquidity. This series of transactions included:
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the contribution, and resulting cancellation, of our incentive distribution rights and 20,691,495 subordinated units held by Eagle Rock Holdings, L.P. ("Holdings") which occurred on May 24, 2010;
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the sale of all of our fee mineral and royalty interests, as well as our equity investment in Ivory Working Interests, L.P., (collectively "the Minerals Business") to Black Stone Minerals Company, L.P. for total consideration of $174.5 million which sale was completed on May 24, 2010;
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a rights offering, which was launched on June 1, 2010 and expired on June 30, 2010, and for which we received gross proceeds of $53.9 million and issued 21,557,164 common units and 21,557,164 warrants and;
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an option, which was exercised on July 30, 2010 by the issuance to Holdings of 1,000,000 newly-issued common units, to capture the value of the controlling interest in us through (a) acquiring our general partner entities from Holdings and immediately thereafter eliminating our 844,551 outstanding general partner units owned by Holdings and (b) reconstituting our Board to allow our common unitholders not affiliated with NGP to elect the majority of our directors.
An investment in our common units involves risks associated with our business, regulatory and legal matters, our limited partnership structure and the tax characteristics of our common units. Please read carefully the risks described under Part I, Item 1A.
Item 1A.
Risk Factors.
Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses.
If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay a distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment.
Risks Related to Our Business
We may not have sufficient cash from operations following the establishment of cash reserves to enable us to make cash distributions at any particular level or at all.
The amount of cash available to us to distribute on our units may fluctuate from quarter to quarter based on, among other things:
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the level of production of oil and natural gas we gather, treat, compress, process, transport and sell; and the volume of NGLs we capture, transport and sell in our Midstream Business;
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the level of oil, natural gas, NGLs and condensate that we produce in our Upstream Business;
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volatility in the realized prices for oil, natural gas, NGLs and condensate that we and others produce;
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the effectiveness of our hedging program and the creditworthiness of our hedging counterparties;
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our level of indebtedness, debt service requirements and need to reduce outstanding indebtedness;
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our ability to borrow funds and access capital markets;
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the level of our operating and general and administrative costs;
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our decisions regarding the level and use of available cash for growth versus maintenance capital expenditures;
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our operators’ and other producers’ drilling activities and success of such programs; and
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the level of competition from other upstream and midstream energy companies.
As a result of these factors, the amount of cash we distribute to our unitholders may be significantly less than the current distribution level, or the distribution may be suspended. In addition, under our partnership agreement, our General Partner may determine to establish any cash reserve necessary for the proper conduct of our business including reserves for future capital expenditures, future credit needs and to better ensure continued compliance with our credit facility and the indenture governing our 8.375% Senior Notes Due 2019 (the "senior notes") before making distributions to our unitholders.
Our general partner also determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, and issuances of additional partnership securities, which, together with establishing reserves, can affect the amount of cash available for distribution to our unitholders. As a result, we may make distributions during periods when we record losses and may not make distributions during periods when we record net income.
Because of the natural decline in production from existing wells, our success depends on our ability to obtain new sources of production and supplies of oil, natural gas and NGLs, which are dependent on certain factors, many of which are beyond our control. Our success is also dependent on developing current reserves. Any decrease in production or supplies of oil, natural gas or NGLs could adversely affect our business and operating results.
The volume of gas that we gather, process and/or produce is dependent on the level of production from hydrocarbon-producing wells. The production rate of these wells naturally will decline over time, and as a result, our cash flows associated with them will also decline over time. In order to maintain or increase the throughput levels of our assets we must continually obtain new supplies of natural gas to offset these declines.
In our Midstream Business, the primary factors affecting our ability to obtain new supplies of natural gas and NGLs and attract new customers to our assets include: (i) the level of successful drilling activity by producers near our systems and (ii) our ability to compete for volumes from successful new wells. The level of drilling activity is dependent on economic and business factors that are beyond our control. The primary factor that impacts producers’ drilling decisions is natural gas prices. A sustained decline in natural gas prices could result in a decrease in exploration and development activities in the fields served by our gathering systems and our natural gas treating and processing plants, which would lead to reduced utilization of these assets. Other factors that impact production decisions include producers’ capital budgets, the ability of producers to obtain capital and necessary drilling and other governmental permits and regulatory changes. Because of these factors, even if new
natural gas reserves are discovered in areas served by our assets, we and other producers may choose not to develop those reserves.
In our Upstream Business, we also have risks inherent with declining reserves. Our producing reservoirs experience production rate declines that vary depending upon reservoir characteristics and other factors. The overall production decline rate of our upstream business may change when additional wells are drilled, when we make acquisitions and under other circumstances. Our future cash flows and income, and our ability to maintain and to increase distributions to unitholders, are partly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations. Factors that may hinder our ability to acquire additional reserves or develop current reserves include competition, access to capital, prevailing oil and natural gas prices, the costs incurred by us to develop and exploit current and future oil and natural gas reserves, and the number and attractiveness of properties for sale.
Natural gas, NGLs, crude oil and other commodity prices are volatile, and an adverse movement in these prices could adversely affect our cash flow and our ability to make distributions.
We are subject to risks related to frequent and often substantial fluctuations in commodity prices. In the past, the prices of natural gas, NGLs and crude oil have been extremely volatile, and we expect this volatility to continue. A drop 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, all of which can affect our ability to pay distributions.
Changes in natural gas, NGL and crude oil prices have a significant impact on the value of our reserves and on our cash flows. In 2012, the settlement price of the prompt month NYMEX natural gas contract ranged from $1.91 per MMBtu to $3.90 per MMBtu, and the settlement price of prompt month NYMEX crude oil contract ranged from $77.69 per barrel to $109.77 per barrel.
The prices for natural gas, NGLs and crude oil depend upon the supply and demand for these products, which in turn depend on a large number of complex, interrelated factors that are beyond our control. These factors include:
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the overall level of economic activity in the United States and the world;
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the impact of weather or other force majeure events;
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political and economic conditions and events in, as well as actions taken by, foreign oil and natural gas producing nations;
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significant crude oil or natural gas discoveries;
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application of new technologies that make the development of large resource plays economically attractive;
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the availability of local, intrastate and interstate transportation systems for natural gas, NGLs and crude oil;
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the availability and marketing of competitive fuels;
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delays or cancellations of crude oil and natural gas drilling and production activities;
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the impact of energy conservation efforts, including technological advances affecting energy consumption; and
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the extent of governmental regulation and taxation.
Lower natural gas, NGL or crude oil prices may not only decrease our revenues and net proceeds, but may also reduce the amount of natural gas, NGLs or crude oil that our Upstream Business and our Midstream Business's producer-customers can economically produce. As a result, especially during periods of low commodity prices, we or our producer customers may decide to shut in or curtail production, or to plug and abandon marginal wells, which could have a material adverse effect on our future cash flows.
Low commodity prices may result in additional write-downs of our asset carrying values.
In our Upstream Business, low oil and natural gas prices may result in substantial downward adjustments to our estimated proved reserves. Furthermore, if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Low oil and natural gas prices also may result in reduced drilling activity and declines in future cash flows within our Midstream Business.
We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated future cash flows of
our assets, the carrying value may not be recoverable and therefore may require a write-down. During the year ended December 31, 2012, we incurred total impairment and other charges of $177.0 million, primarily as a result of (i) reduced throughput volumes as our producer customers curtailed their drilling activity in response to the continued depressed natural gas price environment, (ii) the loss of significant gathering contracts on various systems, (iii) the substantial damage incurred at our Yscloskey processing plant as a result of Hurricane Isaac in August 2012, (iv) certain leaseholds in our unproved properties that we expect to expire undrilled in 2013 and (v) our proved properties in certain regions that are expected to have reduced operating income resulting from natural production declines, lower future natural gas prices and ongoing relatively high operating costs associated with gas compression.. See Note 5 and Note 12 to our consolidated financial statements for further discussion. During the year ended December 31, 2011, we incurred total impairment charges of $16.3 million, primarily as a result of contract terminations notifications by significant producers in our East Texas and Other Midstream Segment. We may incur additional impairment charges in the future, which could have a material adverse effect on our results of operations and financial position in the period incurred.
Our hedging activities may have a material adverse effect on our earnings, profitability, cash flows and financial condition.
Because we are exposed to risks associated with fluctuating commodity prices, we utilize various financial instruments (swaps, collars, and puts) to mitigate these risks within our overall hedge portfolio. Separate from our hedge portfolio, we capitalize on financial arbitrage opportunities and diversify our credit and performance risk for discrete products on a limited basis through our newly-formed gas marketing and trading subsidiary. It is possible that our various hedging activities may not be effective in reducing our exposure to commodity price risk. For instance, we may not produce or process sufficient volumes to cover our hedges, we may fail to hedge a sufficient portion of our future production or the instruments we use may not adequately correlate with changes in the prices we receive. Our current hedging portfolio is presented in Part II, Item 7A. Qualitative and Quantitative Disclosure About Market Risk. For more information about the activities of our trading and marketing subsidiary, which are not listed within our hedging portfolio, see "Part I, Item 1. Our Two Lines of Business - Midstream Business - Marketing and Trading Segment.
To the extent we hedge our commodity price and interest rate risk, we may forego the benefits we would otherwise experience when commodity prices or interest rates improve. Furthermore, because we have entered into derivative transactions related to only a portion of the commodity volumes and outstanding debt to which we have price and interest rate exposure, we will continue to have direct commodity price and interest rate risk on the unhedged portion. Our actual future supply and production may be significantly higher or lower than we estimated at the time we entered into the commodity derivative transactions for that period. If the actual amount is higher than we estimated, we will have more commodity price risk than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of a corresponding settlement of the underlying physical commodity, which could, in certain circumstances, result in a reduction of our liquidity.
As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain extreme circumstances might actually increase the volatility of our cash flows. In addition, hedging activities may result in substantial losses. Such losses could occur under various circumstances, such as when a counterparty fails to perform its obligations under the applicable hedging arrangement, the hedging arrangement is imperfect or ineffective, or our hedging policies and procedures are not properly followed or otherwise do not work as planned. The steps we take to monitor our hedging activities may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.
Due to the enactment of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank), the hedges we execute are undertaken in a highly regulated market. At this time, significant components of the Dodd-Frank regulatory regime are subject to rulemaking by the Commodity Futures Trading Commission and other regulators. Issues such as our continued ability to pledge non-cash collateral could affect the cost and structure of our hedging program. While we expect these issues to be resolved during the first two quarters of 2013, we cannot be certain when final rules will be issued. Until final rules are issued, we cannot predict the impact to our hedging activities. For related discussion, see the risk factor below regarding Dodd-Frank.
We have significant indebtedness under our revolving credit facility and our senior notes, which may limit our flexibility in obtaining additional financing and in pursuing other business opportunities. In addition, we may incur substantial debt in the future to enable us to maintain or increase our reserve and production levels and to otherwise pursue our business plan. This debt may restrict our ability to make distributions.
As of December 31, 2012, we had $608.5 million outstanding under our senior secured credit facility, leaving approximately $192.5 million of available borrowing capacity as of that date, and $544.6 million outstanding under our senior notes, net of unamortized discount. Our level of outstanding debt could have important consequences to us, including the following:
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our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
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we will need a portion of our cash flow to make interest payments on our debt, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders;
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our debt level will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
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our debt level may limit our flexibility in responding to changing business and economic conditions.
Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. In addition, our ability to service debt under our credit facility will depend on market interest rates, since we anticipate that the interest rates applicable to our borrowings will fluctuate with movements in interest rate markets. If our operating results are not sufficient to service our current or future indebtedness or comply with our financial covenants under our existing credit facility or senior notes, we will be forced to take actions such as eliminating, reducing or further reducing distributions, reducing or delaying our business activities and expenses, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional equity capital. We may not be able to affect any of these actions on satisfactory terms, or at all.
Decreases in commodity prices could result in decreases in the borrowing base under our revolving credit facility, which could materially and adversely affect our operations and financial condition.
Availability under our revolving credit facility is subject to a borrowing base comprised of two components: the upstream component and the midstream component. The upstream component of the borrowing base is determined semi-annually as an amount equal to the loan value of our proved oil and gas reserves. The midstream component of the borrowing base is determined quarterly as an amount equal to the lesser of (i) 55% of the total borrowing base (subject to increase for certain periods following certain material acquisitions up to 60% of the total borrowing base) and (ii) 3.75 times Consolidated EBITDA attributable to our midstream assets for the trailing four fiscal quarters.
As a result, a reduction in the value of our proved oil and gas reserves due to decreases in commodity prices could result in a reduction in the upstream component of our borrowing base. Moreover, because the midstream component of our borrowing base is limited to 55% of the total borrowing base, we have limited ability to offset any reductions in our upstream borrowing base with increases in our midstream borrowing base. If the amount outstanding under our revolving credit facility at any time exceeds the borrowing base at such time, we may be required to repay a portion of our outstanding borrowings. If such an event were to occur, it could materially and adversely affect our operations and financial condition.
Covenants in our credit facility and the indenture governing our senior notes may limit our ability to make distributions, enter into certain types of acquisitions or engage in other business transactions.
Our credit facility and the indenture governing our senior notes contain covenants limiting our ability to make distributions, incur indebtedness, grant liens, make acquisitions, investments or dispositions and engage in transactions with affiliates. Furthermore, our credit facility and the indenture governing our senior notes contain covenants requiring us to maintain certain financial ratios and tests. Any subsequent replacement, restatement or amendment of our credit facility and the indenture governing our senior notes or any new indebtedness could impose similar or greater restrictions.
We may not be able to execute our business strategy if we encounter illiquid capital and commercial credit markets.
One component of our business strategy contemplates pursuing opportunities to acquire assets where we believe growth opportunities are attractive and our business strategies could be applied. We regularly consider and enter into discussions regarding strategic transactions that we believe will present opportunities to pursue our growth strategy.
We will require substantial new capital to finance strategic acquisitions. Any limitations on our access to capital or commercial credit will impair our ability to execute this component of our growth strategy. If the cost of such capital or credit becomes too expensive, our ability to develop or acquire accretive assets will be limited. We may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors that influence our cost of capital include our units’ market
performance, conditions in the commercial credit, debt and equity markets and offering or borrowing costs such as interest rates or underwriting discounts.
Our operations require substantial capital expenditures, which will reduce our cash available for distribution. We may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a decline in our cash flows.
The oil and natural gas industry is capital intensive. We expect to continue to make substantial capital expenditures in our business for the maintenance, growth, construction and acquisition of midstream and upstream assets and oil and natural gas production and reserves. In 2013, our capital expenditure budget is expected to be approximately $208 million, excluding acquisitions. We intend to finance our future capital expenditures with cash flows from operations, borrowings under our credit facility and the issuance of debt and equity securities, when market conditions allow. The incurrence of debt will require that a portion of our cash flows from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. Our cash flows from operations and access to capital are subject to a number of variables, including:
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volume throughput through our pipelines and processing facilities;
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the estimated quantities of our proved reserves;
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the amount of oil and natural gas produced from existing wells;
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the prices at which we sell our production or that of our midstream customers;
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the strike prices of our hedges;
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our operating and general and administrative expenses; and
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our ability to acquire, locate and produce new reserves.
If our revenues or the borrowing base under our 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 sustain our operations at current levels, or to pursue our growth strategy. Our credit facility and the indenture governing our senior notes may restrict our ability to obtain new financing. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations, which in turn could lead to a possible decline in our gathering and processing available capacity or in our natural gas and crude oil reserves and production. Even if we are successful in obtaining additional financing, the terms of such financing could limit our ability to pay distributions to our unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional partnership interests may result in significant unitholder dilution which could have a material adverse effect on our ability to pay distributions at the then-current distribution rate. Further, we may lose opportunities to acquire oil and natural gas properties and businesses.
Our industry is highly competitive, and increased competitive pressure or loss of key customers could adversely affect our business and operating results.
We compete with similar enterprises in our respective areas of operation. Some of our competitors are large oil and natural gas companies that have greater financial resources and access to supplies of oil, natural gas and NGLs than we do.
In our Midstream Business, we rely on certain natural gas producer customers for a significant portion of our natural gas and NGL supply. The number and relative significance of gas suppliers can change for a number of reasons, including the relative success of the producers’ drilling programs, additions or cancellations of gathering and processing agreements, and the acquisition of new systems. Additionally, some of our competitors may expand or construct gathering, processing and transportation systems or may develop their own gathering, processing and transportation systems in lieu of using ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors and our customers. Unless we are able to acquire comparable volumes from other sources, all of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions.
In our Upstream Business, 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 a highly competitive environment. Many of our larger competitors not only drill for and produce oil and natural gas, but also conduct 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 oil and natural gas 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. If a significant customer of ours reduces the volume of its purchases from us, we could experience a temporary interruption in sales of, or lower prices for, our production. As a result our revenues and cash available for distribution could decline which may adversely affect our ability to make cash distributions to our unitholders.
In both the Midstream and Upstream Businesses there is significant competition for experienced personnel, particularly in the engineering, accounting and financial reporting, tax and land departments. In addition, competition is strong for attractive midstream assets, oil and natural gas producing properties, oil and natural gas companies and undeveloped leases and drilling rights. We may often be outbid by competitors in our attempts to acquire personnel, assets, properties or companies. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations.
If we do not make acquisitions on economically acceptable terms, our future growth will be limited.
Our ability to grow our business depends, in part, on our ability to make acquisitions that are accretive to our cash available for distributions on a per unit basis. If we are unable to make these accretive acquisitions because we are: (i) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (ii) unable to obtain financing for these acquisitions on economically acceptable terms, or (iii) outbid by competitors, then our future growth and ability to increase distributions will be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations per unit because of unforeseen circumstances.
All acquisitions involve potential risks, including, among other things:
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mistaken assumptions about future prices, volumes, revenues and costs of oil and natural gas, including synergies and estimates of the oil and natural gas reserves attributable to a property we acquire;
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inefficiencies and complexities that can arise because of unfamiliarity with new assets, operations and the businesses associated with them, including their markets and geographic service areas;
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the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate;
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mistaken assumptions about the overall costs of equity or debt;
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decrease in our liquidity as a result of our using a significant portion of our available cash or borrowing capacity to finance the acquisition;
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increases in our interest expense or financial leverage if we incur additional debt to finance the acquisition; and
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customer or key employee losses at the acquired businesses.
If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our limited partners will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider.
Our ability to derive benefits from our acquisitions will depend on our ability to successfully integrate the acquired operations.
Achieving the anticipated benefits from acquisitions depends in part upon whether we are able to successfully integrate the assets or businesses of these acquisitions, in an efficient and effective manner. The difficulties combining businesses or assets potentially will include, among other things:
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geographically separated organizations and possible differences in corporate cultures and management philosophies;
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significant demands on management resources, which may distract management's attention from day-to-day business; and
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differences in the disclosure systems, accounting systems, and internal controls and procedures (including accounting controls and internal controls and procedures we are required to maintain under the Sarbanes-Oxley Act of 2002) of the two companies, which may interfere with our ability to make timely and accurate public disclosure.
Any inability to realize the potential benefits of the acquisition, as well as any delays in integration, could have an adverse effect upon the revenues, level of expenses and operating results of the company, after the acquisitions, which may affect the value of our common units after the acquisition.
Failure of the natural gas, NGLs, condensate or other products produced at our plants or shipped on our pipelines to meet the specifications of interconnecting pipelines or markets could result in curtailments by the pipelines or markets.
The markets and pipelines to which we deliver natural gas, NGLs, condensate or other products establish specifications for the products they are willing to accept. These specifications include requirements such as hydrocarbon dewpoint, compositions, temperature, and foreign content (such as water, sulfur, carbon dioxide, and hydrogen sulfide), and these specifications can vary by product, pipeline or markets. If the total mix of a product that we deliver to a pipeline or market fails to meet the applicable product quality specifications, the pipeline or market may refuse to accept all or a part of the products scheduled for delivery to it or may invoice us for the costs to handle or damages from receiving the out-of-specification products. In those circumstances, we may be required to find alternative markets for that product or to shut-in the producers of the non-conforming natural gas that is causing the products to be out of specification, potentially reducing our through-put volumes or revenues.
Our businesses depend in part on gathering, transportation and processing facilities. Any limitation in the availability of, or our access to, those facilities would interfere with our ability to market the oil, natural gas and NGLs we produce, and could reduce our cash available for distribution and adversely impact expected increases in oil, natural gas and NGL production from our drilling program.
The marketability of our oil, gas and NGL production depends in part on the accessibility, availability, proximity and capacity of gathering, processing and pipeline systems. The amount of oil, natural gas and NGLs that can be produced and sold is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering, processing or transportation system, weather, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. In addition, some of our wells may be drilled in locations that are not serviced by gathering, processing and transportation facilities, or the gathering and transportation pipelines in the area may not have sufficient capacity to transport additional production. As a result, we may not be able to sell the oil, gas and NGL production from these wells until the necessary gathering, processing and transportation facilities are constructed. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering, processing and transportation facilities, would interfere with our ability to market the oil, gas and NGLs we produce, and could reduce our cash available for distribution and adversely impact expected increases in oil and gas production from our drilling program. Our access to transportation options can also be affected by U.S. federal and state regulations of oil and natural gas production and transportation and other general economic conditions beyond our control. In addition, sulfur is a by-product associated with substantially all of the natural gas production in our upstream operations in Alabama. If we were unable to sell the sulfur we produce, we may be forced to store it or curtail our oil and gas production.
If third-party pipelines and other facilities interconnected to our midstream systems become unavailable to transport or produce natural gas and NGLs, our revenues and cash available for distribution could be adversely affected.
We depend upon third-party pipelines, natural gas gathering systems and other facilities that provide delivery options to and from our pipelines and facilities for the benefit of our midstream customers. Since we do not own or operate any of these pipelines or other facilities, their continuing operation is not within our control. If any of these third-party pipelines and other facilities become unavailable or limited in their ability to transport or produce natural gas and NGLs, our revenues and cash available for distribution could be adversely affected.
Inclement weather, unforeseen events or events of force majeure may limit our ability to operate our business and could adversely affect our operating results.
The weather, unforeseen events or events of force majeure (such as acts of nature or acts of terrorism) in the areas in which we operate can cause disruptions and, in some cases, suspension of our operations (whether directly or by virtue of disrupting or suspending operations of those upon whom we rely in our operations). For example, unseasonably wet or dry weather, extended periods of below freezing weather, hurricanes, lightning strikes, tornadoes, electrical outages, domestic attacks or threats of violence may cause disruptions or suspensions of our operations, which could result in our inability to cause physical delivery of commodities guaranteed under contract or require us to purchase third-party volumes at significantly higher prices to satisfy our delivery obligations. Disruption or suspensions of our operations could adversely affect our operating results.
Our construction of new assets is subject to regulatory, environmental, political, legal and economic risks, and therefore, may not increase revenue as expected; this could adversely affect our results of operations and financial condition.
One of the ways we intend to grow our business is through the construction of new midstream assets. The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. If we undertake these projects, they may not be completed on schedule or at the budgeted cost, or at all.
Our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we expand a pipeline, the construction expenditures may occur over an extended period of time, yet we will not receive any material increases in revenues until the project is completed. Also, we may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate. As a result, new or expanded facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition.
The construction of additions to our existing gathering and transportation assets may require us to obtain new rights-of-way prior to constructing new pipelines. We may be unable to obtain such rights-of-way to connect new natural gas supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our cash flows could be adversely affected.
Our business involves many hazards and operational risks, some of which may not be partially or fully insured or insurable. If a significant accident or event occurs that is not fully insured or interrupts normal operations, our operations and financial results could be adversely affected.
Our operations are subject to many hazards inherent in the drilling, producing, gathering, compressing, treating, processing and transporting of oil, natural gas and NGLs, including:
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damage to production equipment, gathering equipment, pipelines and treating or processing plants, compression and related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters and acts of terrorism;
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inadvertent damage from construction, farm and utility equipment or acts of vandalism;
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leaks of natural gas, poisonous hydrogen sulfide gas, NGLs and other hydrocarbons or losses of natural gas or NGLs as a result of the malfunction of pipeline, equipment or facilities;
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mishandling of fluids, including chemical additives that may be toxic;
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surface spills or underground migration due to uncontrollable flows of oil, natural gas, formation water or well fluids;
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fires and explosions; and
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other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.
These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and attorney's fees and other expenses incurred in the prosecution or defense of litigation and may result in curtailment or suspension of our related operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations and ability to pay distributions to our unitholders.
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. We are not fully insured against all risks inherent to our business. For example, we are not fully insured against all environmental accidents which may include toxic tort claims. If a significant accident or event occurs that is not fully insured, it could adversely affect our operations and financial condition. In addition, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially, and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners of our assets, pursuant to our indemnification rights, for potential environmental liabilities. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition, results of operations and ability to pay distributions to our unitholders.
Increases in interest rates could adversely impact our unit price and our ability to issue additional equity, to incur debt to make acquisitions or for other purposes or to make cash distributions at our intended levels.
Credit markets have experienced a prolonged period of low interest rates. Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity, to incur debt to make acquisitions or for other purposes or to make cash distributions at our intended levels.
Our and other operators’ drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors.
Drilling for oil and gas involves numerous risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. Our and other operators’ drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors, including:
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unexpected drilling conditions;
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drilling, production or transportation facility or equipment failure or accidents;
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mechanical difficulties, such as lost or stuck drilling or service tools;
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abnormally pressured formations or rock compaction;
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increasing costs for or shortages or delays in the availability of drilling rigs, experienced personnel and other services and equipment;
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adverse weather conditions;
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compliance with environmental and governmental requirements;
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title problems;
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unusual or unexpected geological formations;
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pipeline ruptures;
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fires, blowouts, craterings and explosions;
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mishandling of fluids, including chemical additives that may be toxic; and
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surface spills or underground migration due to uncontrollable flows of oil, natural gas, formation water or well fluids.
We do not provide midstream services to all of our upstream activities. Any curtailment to the gathering systems we use to deliver our oil and gas production for processing, storage or further delivery to end markets could require us to find alternative means to transport the oil and natural gas production from the underlying properties, which alternative means could require us to incur additional costs. Additionally, any delay in the drilling of new wells or significant increase in drilling costs could reduce our revenues. Any such curtailment, delay, cancellation, cost increase or revenue reduction may limit our ability to make cash distributions to our unitholders.
Due to our limited industry and geographic diversification in our midstream operations and in our upstream operated properties, adverse developments in our operations or operating areas would reduce our ability to make distributions to our unitholders.
All of our midstream assets are located in the Texas Panhandle, East and South Texas and Louisiana, and all of our upstream operated properties are located in Texas, Oklahoma, Alabama, Arkansas, and Mississippi. Due to our limited diversification in industry type and location, an adverse development in one of these businesses or operating areas would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets and operating areas.
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.
Numerous uncertainties are inherent in estimating quantities of oil and natural gas reserves. 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. Reserve reports rely upon many assumptions, including 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 estimated timing of development expenditures may prove to be
inaccurate. Over time, we may make material changes to reserve estimates that reflect the actual results of drilling and production. Any significant change in our assumptions or actual performance of our wells could affect our estimates of reserves, the classifications of the reserves and our estimates of the future net cash flows associated with the reserves. In addition, since many of our wells are mature and have low production rates, changes in future production costs assumptions could have a significant effect on our proved reserve estimates.
The standardized measure of discounted future net cash flows of our estimated net proved reserves is not the same as the current market value of our estimated net proved reserves. We base the discounted future net cash flows from our estimated net proved reserves on average prices observed in the previous twelve months and on cost estimates we believe reflect the costs at the end of the period. Actual prices received for production and actual costs of such production will be different than these assumptions, perhaps materially.
The timing of both our production and our incurrence of expenses in connection with the development and production of our properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on actual interest rates and the risks associated with our firm in particular or the natural gas and oil industry in general. Any material inaccuracy in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves which could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.
Our ability to manage and grow our business effectively may be adversely affected if we lose key management or operational personnel.
We depend on the continuing efforts of our key management and operational personnel. The departure of any of our key management or operational personnel could have a significant negative effect on our business, operating results, financial condition, and on our ability to compete effectively in the marketplace. Additionally, our ability to hire, train, and retain qualified personnel will continue to be important and will become more challenging as we grow and face more significant competition in the marketplace. Our ability to grow and perhaps even to continue our current level of service to our current customers will be adversely impacted if we are unable to successfully hire, train and retain these important personnel.
We may not successfully balance our purchases and sales of natural gas, which would increase our exposure to commodity price risks.
We purchase from producers and other parties a substantial amount of the natural gas that flows through our natural gas gathering, processing and transportation systems for resale to third parties, including natural gas pipelines, marketers and a reduced number of end-users. We may not be successful in balancing our purchases and sales. A producer or supplier could fail to deliver contracted volumes or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause our purchases and sales to be unbalanced. If our purchases and sales are unbalanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating income and cash flows.
We have limited control over the activities on properties we do not operate, which includes a substantial number of the properties we acquired in the Mid-Continent Acquisition.
Devon Energy Production Co LP, Continental Resources, Inc., Cimarex Energy Co. and others operate some of the properties in which we have an interest, including the properties we acquired in the Mid-Continent Acquisition. We have less ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them versus those fields in which we are the operator. The success and timing of development and exploitation activities on properties operated by others depend upon a number of factors that will be largely outside our control, including:
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the operator's expertise and financial resources;
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the timing and amount of their capital expenditures;
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the rate of production of the reserves;
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approval of other participants to drill wells and implement other work programs;
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the availability of suitable drilling rigs, drilling equipment, production and transportation infrastructure and qualified operating personnel; and
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selection of technology.
Our dependence on the operator and other working interest owners for these projects and our reduced influence or ability to control the operation and future development of these properties could materially adversely affect our business, results of operations, financial condition and ability to pay distributions to our unitholders.
We are exposed to the credit risk of our customers and other counterparties, and a general increase in the nonperformance by counterparties could have an adverse impact on our cash flows, results of operations and financial condition.
We are subject to risks of loss resulting from nonperformance by our customers and other counterparties, such as our lenders and other hedge counterparties. Any deterioration in the financial health of our customers and counterparties or any factors causing reduced access to capital for them may result in the reduction in their ability to pay or otherwise perform on their obligations to us. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. Any increase in the nonperformance by our counterparties, either as a result of recent changes in financial and economic conditions or otherwise, could have an adverse impact on our operating results and could adversely affect our liquidity.
We do not own all of the land on which our pipelines and facilities are located, so our operations could be disrupted by actions of the landowners.
We do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore subject to the possibility of more onerous terms or increased costs to retain necessary land use if we do not have valid rights of way or if such rights of way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash distributions.
Our commodity derivatives trading activities expose us to additional risks associated with selling and marketing products in energy markets.
In 2011, we began conducting commodity derivatives trading activities through our natural gas marketing subsidiary, Eagle Rock Gas Services, LLC. Our portfolio of derivative and other energy contracts may consist of contracts to buy and sell commodities that are settled by the delivery of the commodity or cash. If the values of these contracts change in a direction or manner that we do not anticipate or cannot manage, it could negatively affect our results of operations. In the past, certain marketing and trading companies have experienced severe financial problems due to price volatility in the energy commodity markets. In certain instances this volatility has caused companies to be unable to deliver energy commodities that they had guaranteed under contract. If such a delivery failure were to occur in one of our contracts, we might incur additional losses to the extent of amounts, if any, already paid to, or received from, counterparties. As a result, our business, results of operations, financial condition and ability to pay distributions to our unitholders may be adversely affected.
Risks Inherent in an Investment in Us
The amount of cash we have available for distribution to holders of our common units depends primarily on our cash flow and not solely on profitability.
The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.
NGP controls a substantial portion of our common units and appoints three of our directors, and thus it could exert certain significant influence over us.
Currently, NGP beneficially owns 51,386,169 common units, representing over 35% of our outstanding common units. In addition, pursuant to our partnership agreement, NGP is entitled to appoint three of the nine members of our board of directors. As a result, NGP could exert certain significant influence over us. NGP may have interests that do not align with our interests and with the interests of our unitholders, which could have an adverse impact on our results of operations or cash available for distribution to unitholders. In addition, NGP's level of control may make any potential takeover bids more costly or difficult in the future.
Unitholders have less ability to influence management's decisions than holders of common stock in a corporation.
Unlike the holders of common stock in a corporation, unitholders have more limited voting rights on matters affecting our business, and therefore a more limited ability to influence management's decisions regarding our business. Our partnership agreement provides that our general partner may not withdraw and may not be removed at any time for any reason whatsoever. In addition, if unitholders are dissatisfied with the performance of our general partner, they only have the right to elect five of the nine directors.
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.
Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.
We expect that we will distribute all of our available cash to our unitholders. As a result, we expect that we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.
In addition, because we distribute all of our available cash, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement, our credit facility or the indenture governing our senior notes on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.
If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to continue to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.
Our partnership agreement contains provisions that modify and limit our general partner's fiduciary duties to our unitholders.
Our partnership agreement contains provisions that modify and limit our general partner's fiduciary duties to our unitholders. Our partnership agreement also contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement:
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provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action in good faith, and our general partner will not be subject to any other or different standard imposed by our partnership agreement, Delaware law or any other law, rule or regulation or at equity;
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provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, and our partnership agreement specifies that the satisfaction of this standard requires that our general partner must believe that the decision is in the best interests of our partnership;
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provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
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provides that our general partner will not be in breach of its obligations under the partnership agreement or its fiduciary duties to us or our unitholders if the resolution of a conflict is:
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approved by the conflicts committee of our general partner, although our general partner is not obligated to seek such approval;
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approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;
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on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
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fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
In connection with a situation involving a conflict of interest, any determination by our general partner involving the resolution of the conflict of interest must be made in good faith, provided that, if our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
We have the right to borrow to make distributions. Repayment of these borrowings will decrease cash available for future distributions, and covenants in our credit facility may restrict our ability to make distributions.
Our partnership agreement allows us to borrow to make distributions. We may borrow under our credit facility to make distributions. The primary purpose of these borrowings would be to mitigate the effects of short term fluctuation in our cash flow that would otherwise cause volatility in our quarter to quarter distributions.
The terms of our credit facility may restrict our ability to pay distributions if we do not satisfy the financial and other covenants in the facility.
We may issue additional units without limited partner approval, which would dilute ownership interests.
Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
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our unitholders’ proportionate ownership interest in us will decrease;
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the amount of cash available for distribution on each unit may decrease;
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the ratio of taxable income to distributions may increase;
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the relative voting strength of each previously outstanding unit may be diminished; and
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the market price of the common units may decline.
Our management team, directors and NGP may sell common units in the public markets, which sales could have an adverse impact on the trading price of the common units.
Currently, our management team, directors and NGP (including through their interests in Montierra) beneficially own an aggregate of 53,826,301 common units, including 1,228,762 common units which are still subject to a vesting requirement. The resale of any of these common units in the public markets could have an adverse impact on the price of the common units or on any trading market that may develop.
Liability of a limited partner may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. Limited partners could be liable for any and all of our obligations as a general partner if:
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a court or government agency determined that we were conducting business in a state but had not complied with that particular state's partnership statute; or
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the right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
Our simplified capital structure (i.e. only one common class of equity outstanding) could result in slower distribution growth and less certainty of minimum distributions.
Unlike many publicly-traded partnerships, we do not have incentive distribution rights. Incentive distribution rights generally entitle the general partner of a publicly-traded partnership to increasing percentages of the cash distributed by the partnership in excess of a specified level and are designed to encourage the general partner and its affiliates to grow distributions of the partnership through, among other things, the sale or contribution of additional assets to the partnership on an accretive basis. Since we no longer have an independently-controlled general partner with incentive distribution rights in us, we could have difficulty consummating accretive transactions at the same rate as, and see slower distribution growth than, other publicly-traded partnerships.
Unlike many publicly-traded partnerships, we also do not have subordinated units. Subordinated units generally are not entitled to receive any distributions until the common units have received a specified minimum quarterly distribution plus any arrearages from prior quarters. The practical effect of the existence of subordinated units in lieu of common units is to increase the likelihood that a specified minimum quarterly distribution will be distributed on the outstanding common units. Accordingly, there may be more risk that we will not distribute a specified minimum amount each quarter (either present or in arrears) on our common units than there would exist if a portion of our outstanding units were subordinated units rather than common units.
Risks Related to Governmental Regulation
We are subject to compliance with stringent environmental laws and regulations that may expose us to significant costs and liabilities, and future regulations may be more stringent.
Our operations are subject to stringent and complex federal, state and local environmental laws and regulations. These laws and regulations may impose numerous obligations on our operations including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to limit or prevent releases of materials from our pipelines and facilities, and the imposition of substantial liabilities for pollution resulting from our operations. Failure or delay in obtaining regulatory approvals or drilling permits by us or our operators 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 spacing, and density of wellbores may limit the quantity of oil and natural gas that may be produced and sold.
Numerous governmental authorities, such as the federal Environmental Protection Agency ("EPA") and analogous state agencies in which states we operate have the power to enforce compliance with these laws and regulations, oftentimes requiring difficult and costly actions. Failure to comply may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, assessment of monetary penalties and the issuance of injunctions limiting or preventing some or all of our operations. Certain environmental statutes and analogous state laws impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed of or otherwise released. 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 waste products into the environment.
There is risk of incurring significant environmental costs and liabilities in connection with our operations as a result of our handling of petroleum hydrocarbons and wastes; operation of our wells, gathering systems and other facilities; air emissions and water discharges related to our operations and historical industry operations and waste disposal practices. Most of our midstream assets have been used for midstream activities for a number of years, oftentimes by third parties, whose treatment and disposal or release of petroleum hydrocarbons or wastes was not under our control. Private parties, including the owners of properties through which our gathering systems pass and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. We may not be able to recover some or any of these costs from insurance. See Part I, Item 1. Business-Regulation of Our Operations.
Changes in environmental laws and regulations occur frequently and such laws and regulations tend to become more stringent over time. Stricter laws, regulations or enforcement policies could significantly increase our compliance costs and have a material adverse effect on our operations or financial position. For example, in response to the April 2010 Macondo well incident the Bureau of Ocean Energy Management (“BOEM”) and the Bureau of Safety and Environmental Enforcement (“BSEE”) and the Office of Natural Resource Revenue ("ONRR"), in addition to their regulatory predecessors, adopted a series of regulatory initiatives that impose a variety of new safety and operating measures on oil and natural gas exploration and production operators in federal waters in the U.S. Gulf of Mexico that are intended to help prevent a similar incident in the future. Additional proposed changes in laws, regulations, guidance and policy could affect exploration and production operators in federal waters of the U.S. Gulf of Mexico and, in turn, adversely affect our midstream business that relies, in part, on the receipt of natural gas from such operators.
In addition, on August 16, 2012, the EPA published final rules that establish new air emission control requirements for natural gas and NGL production, processing and transportation activities, including New Source Performance Standards (NSPS) to address emissions of sulfur dioxide and volatile organic compounds, and National Emission Standards for Hazardous Air Pollutants (NESHAPS) to address hazardous air pollutants frequently associated with gas production and processing activities. Among other things, these final rules require the reduction of volatile organic compound emissions from natural gas wells through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015. In addition, gas wells are required to use completion combustion device equipment (i.e., flaring) by October 15, 2012 if emissions cannot be directed to a gathering line. The new NSPS rule also requires the control of VOC emissions from new/modified tanks associated with oil and gas production and gathering and processing activities that will increase the costs associated with growth and maintenance. Further, the final rules under NESHAPS include maximum achievable control technology (MACT) standards for “small” glycol dehydrators that are located at major sources of hazardous air pollutants and modifications to the leak detection standards for valves. We are currently evaluating the impact of these final rules on our business. Compliance with these requirements, especially the imposition of these green completion requirements, may require modifications to certain of our operations, including the installation of new equipment to control emissions at the well site that could increase our costs or reduce our production, which could have a material adverse effect on our results of operations and cash flows.
We may incur significant costs and liabilities resulting from safety and compliance-related regulations.
Our gathering operations may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. For example, Louisiana's Pipeline Operations Section of the Department of Natural Resources’ Office of Conservation is generally responsible for regulating gathering facilities in Louisiana, and has authority to review and authorize the construction, acquisition, abandonment and interconnection of physical pipeline facilities and may implement new regulations in the future. Historically, apart from pipeline safety, it has not acted to exercise this jurisdiction respecting gathering facilities. We cannot predict what effect, if any,
such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
Additionally, we are required to comply with common purchaser statutes which generally require gatherers to purchase without undue discrimination as to source of supply or producer. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. These statutes restrict our right as an owner of gathering facilities to decide with whom we contract to purchase or gather oil or natural gas. Federal law leaves any economic regulation of natural gas gathering to the states. The states in which we operate have adopted complaint-based regulation of oil and natural gas gathering activities, which allows oil and natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to oil and natural gas gathering access and rate discrimination. Other state regulations may not directly regulate our business, but may nonetheless affect the availability of natural gas for purchase, processing and sale; for example, state regulation of production rates and maximum daily production allowable from gas wells. Although our proprietary gathering lines are currently subject to limited state regulation, there is a risk that state laws will be changed, and this may give producers a stronger basis to challenge the proprietary status of a line, or the rates, terms and conditions of a gathering line providing gathering service. Please see Part I, Item 1. Business-Regulation of Our Operations.
The majority of our gathering systems in Texas have been deemed non-utilities by the TRRC, with the exception being our Turkey Creek gathering system, which is regulated as a utility by the TRRC. Our Hesco Pipeline Company, LLC and the East Texas segment of our DeSoto Pipeline are also regulated by the TRRC. The TRRC has authority over the rates, terms and conditions of service for our DeSoto Pipeline's intrastate transportation activities. Under Texas law, non-utilities are not subject to rate regulation by the TRRC. Should the status of these non-utility facilities change, they would become subject to rate regulation by the TRRC, which could adversely affect the rates that our facilities are allowed to charge their customers. Texas also administers federal pipeline safety standards under the Pipeline Safety Act of 1968. The non-jurisdictional gathering exemption under the Natural Gas Pipeline Safety Act of 1968 presently exempts most of our gathering facilities from jurisdiction under that statute. The “rural gathering exemption,” however, may be restricted in the future. As a result of recent pipeline incidents in other parts of the country, Congress and the Department of Transportation have passed or are considering imposing more stringent pipeline safety requirements. Costs associated with complying with and qualifying our facilities under these and other regulations could be material and have an adverse effect on us, our financial condition, and our results of operations.
We may incur significant costs and liabilities as a result of pipeline integrity management program testing and any related pipeline repair, or preventative or remedial measures, as well as more stringent pipeline safety standards.
The DOT has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in "high consequence areas." The regulations require operators to:
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perform ongoing assessments of pipeline integrity;
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identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
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improve data collection, integration and analysis;
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repair and remediate the pipeline as necessary; and
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implement preventive and mitigating actions.
We currently estimate that we may incur costs of $1.1 million in 2013 for specific plant and pipeline integrity management program testing along certain segments of our pipeline, as required by existing DOT and OSHA regulations to be completed this year. This estimate does not include the costs, if any, for repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which could be substantial.
We may incur significant expenses if anomalous pipeline conditions are discovered or due to the implementation of more stringent pipeline safety standards as a result of new or amended legislation. For example, in January 2012, President Obama signed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“Pipeline Safety Act”), which requires increased safety measures for gas and hazardous liquids transportation pipelines. Among other things, the Pipeline Safety Act directs the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, and leak detection system installation. The Pipeline Safety Act also directs owners and operators of interstate and intrastate gas transmission pipelines to verify their records confirming the maximum allowable pressure of pipelines in certain class locations and high consequence areas, requires promulgation of regulations for conducting tests to confirm the material strength of pipe operating above 30% of specified minimum yield strength in high consequence areas, and increases the maximum penalty for violation of pipeline
safety regulations from $1 million to $2 million. PHMSA is also considering changes to its natural gas transmission pipeline regulations to, among other things, expand the scope of “high consequence areas,” strengthen integrity management requirements applicable to existing operators; strengthen or expand non-integrity pipeline management standards relating to such matters as valve spacing, automatic or remotely-controlled valves, corrosion protection, and gathering lines; and add new regulations to govern the safety of underground natural gas storage facilities including underground storage caverns and injection or withdrawal well piping that are not regulated today. We cannot predict the final outcome of these legislative or regulatory efforts or the precise impact that compliance with any resulting new requirements may have on our business.
The adoption of derivatives legislation by the United States Congress and its implementation by the Commodity Futures Trading Commission and SEC could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
In 2010, Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act ("Dodd-Frank"), which among other things, establishes a comprehensive framework for the regulation of derivatives, or swaps. The SEC, which has jurisdiction over security-based swaps, and the Commodity Futures Trading Commission (the "CFTC"), which has jurisdiction over swaps, have issued regulations to implement this new statutory regime. Once fully implemented, and subject to certain exemptions that may be available to us, entities such as Eagle Rock that enter into swaps will be subject to, among other things, swap recordkeeping and reporting requirements; clearing, trade execution and margin requirements (e.g., posting of collateral). Our swap counterparties may be subject to even greater regulatory requirements and may be subject to regulated capital requirements. Dodd-Frank also provides for the imposition of position limits for referenced futures contracts, including with respect to certain energy commodities, and economically equivalent futures, options and swaps. The CFTC promulgated regulations imposing position limits, which were vacated by a federal court in September 2012. The CFTC is currently appealing that decision and could in the future re-promulgate position limits rules in a manner that attempts to address the defects identified by the court.
The legislation and related regulations could increase our cost of compliance, increase the cost and alter the terms of derivatives transactions, and adversely impact the number and creditworthiness of available swap counterparties. All of this could impact our available liquidity, require us to divert funds away from our core business and reduce our ability to hedge and otherwise manage our financial and commercial risks related to commodity price fluctuations.
If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Any of these consequences could have a material, adverse effect on us, our financial condition, and our results of operations.
A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.
FERC has developed tests for determining which facilities constitute gathering facilities exempt from Federal Energy Regulatory Commission (FERC) regulation under the Natural Gas Act of 1938 (NGA). From time to time, FERC may reconsider the elements of such tests. We cannot predict when and under what circumstances FERC may elect to re-examine activities that could fall within the scope of our business with respect to gathering.
We believe that, currently, the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC and the courts. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, and in some instances complaint-based rate regulation. Although our natural gas gathering and intrastate transportation operations are generally exempt from direct FERC regulation, FERC has jurisdiction over natural gas markets and intrastate pipelines engaged in interstate transportation services. FERC’s policies and practices across the range of its oil and natural gas regulatory activities, such as its policies on open access transportation, ratemaking, price transparency, market manipulation, capacity release and market center promotion, indirectly affect intrastate markets. In recent years, FERC has pursued policies to increase competition, which could increase FERC's regulation over Eagle Rock DeSoto Pipeline.
Our Eagle Rock DeSoto Pipeline, L.P. (“DeSoto Pipeline”) transports gas in interstate commerce on its Central and North Texas Systems and is therefore subject to FERC regulation under Section 311 of the NGPA.
Our Eagle Rock DeSoto Pipeline is subject to FERC regulation under Section 311 of the Natural Gas Policy Act, or NGPA. In October 2008, DeSoto Pipeline filed a request for FERC approval to continue to use DeSoto Pipeline's currently-effective rate for NGPA Section 311 service, which is based on a city-gate transportation rate approved by the TRRC as being fair and equitable and not in excess of a cost-based rate. In March 2009, FERC approved a settlement authorizing DeSoto Pipeline to continue to charge the currently-effective rate for NGPA Section 311 service, subject to a requirement that on or before May 1, 2010, DeSoto Pipeline must either file a new application for rate approval with FERC or file an election to use its then-effective rates for intrastate city-gate transportation service on file with the TRRC. If the latter, then DeSoto Pipeline was required to make a filing with the TRRC for a cost-based rate determination. On September 14, 2010, the FERC granted an extension of time to May 1, 2012 for DeSoto Pipeline to file a new application for rate approval or to file the election. On April 23, 2012 DeSoto Pipeline filed an application with the TRRC for a cost-based review of the reasonableness of the currently-effective transportation rate to be used for NGPA Section 311 service, and on May 1, 2012, DeSoto Pipeline filed with the FERC a notice of its election to continue to use DeSoto Pipeline's rates for intrastate city-gate transportation service on file with the TRRC for NGPA Section 311 service. Action on both filings is pending. Any failure on our part to comply with the rates approved by the FERC for Section 311 service, to comply with the terms and conditions of service established in our FERC-approved Statement of Operating Conditions, or to comply with applicable FERC regulations, the NGPA, or certain state laws and regulations could result in an alteration of the jurisdictional status of DeSoto Pipeline and the imposition of civil and/or criminal penalties.
A change in the regulations related to a state's use of eminent domain could inhibit our ability to secure rights-of-way for future pipeline construction projects.
Certain states where we operate are considering the adoption of laws and regulations that would limit or eliminate a state's ability to exercise eminent domain over private property. This, in turn, could make it more difficult or costly for us to secure rights-of-way for future pipeline construction and other projects. Further, states may amend their procedures for certain entities within the state to use eminent domain. For example, in response to a recent decision from the Texas Supreme Court, the TRRC may alter the process for a pipeline company to claim common carrier status under Texas law.
Climate change laws or regulations restricting emissions of "greenhouse gases" could result in increased operating costs and a decreased demand for oil and natural gas that we produce or process.
In response to findings that emissions of carbon dioxide, methane, and other greenhouse gases, or “GHGs,” present an endangerment to public health and the environment because emissions of such gases are contributing to the warming of the earth's atmosphere and other climate changes, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that would require a reduction in emissions of GHGs from motor vehicles and also may trigger construction and operating permit review for GHG emissions from certain stationary sources. The EPA has asserted that the final motor vehicle GHG emission standards triggered Prevention of Significant Deterioration (“PSD”) and Title V permit requirements for stationary sources, commencing when the motor vehicle standards took effect on January 2, 2011. The EPA has published its final rule to address the permitting of GHG emissions from stationary sources under the PSD and Title V permitting programs, pursuant to which these permitting programs have been “tailored” to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. It is widely expected that facilities required to obtain PSD permits for their GHG emissions also will be required to reduce those emissions according to “best available control technology” standards for GHG that have yet to be fully developed. With regards to the monitoring and reporting of GHGs, on November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule published in October 2009 to include onshore and offshore oil and natural gas production and onshore oil and natural gas processing, transmission, storage, and distribution activities. Facilities containing petroleum and natural gas systems that emit 25,000 metric tons or more of CO2 equivalent per year are now required to report annual GHG emissions to EPA, with the first report for emissions occurring in 2011 due on September 28, 2012. These EPA rulemakings could adversely affect our operations by limiting drilling opportunities, restricting or delaying our ability to obtain air permits for new or modified facilities, or imposing materially increased costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances, or comply with new regulatory or reporting requirements.
In addition, both houses of Congress have actively considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. These allowances would be expected to escalate significantly in cost over time. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits 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 we produce or the oil, natural gas and NGLs we gather and process or fractionate. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our upstream and midstream operations.
Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. We routinely utilize hydraulic fracturing techniques in many of our oil and natural gas well drilling and completion programs. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the EPA has asserted federal regulatory authority over hydraulic fracturing involving fluids that contain diesel fuel under the Safe Drinking Water Act's Underground Injection Control Program and has released draft permitting guidance for hydraulic fracturing operations that use diesel fuel in fracturing fluids in those states where EPA is the permitting authority. EPA accepted comments on the draft guidance in 2012, but has not yet finalized the permitting guidance. In addition, legislation has been introduced before Congress that would provide for federal regulation of hydraulic fracturing and would require disclosure of the chemicals used in the fracturing process. Moreover, on November 23, 2011, the EPA announced that it was granting in part a petition to initiate a rulemaking under the Toxic Substances Control Act, relating to chemical substances and mixtures used in the hydraulic fracturing process. Further, on May 4, 2012, the Department of the Interior's Bureau of Land Management (“BLM”) issued a proposed rule to regulate hydraulic fracturing on public and Indian land. The rule would require companies to publicly disclose the chemicals used in hydraulic fracturing operations to the BLM after fracturing operations have been completed and includes provisions addressing well-bore integrity and flowback water management plans.
Certain states where we operate, including Texas have adopted, and other states are considering adopting, regulations and legislation that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. For example, Texas adopted a law in June 2011 requiring disclosure to the Texas Railroad Commission ("TRRC") and the public of certain information regarding the components used in the hydraulic-fracturing process. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells.
We use a significant amount of water in our hydraulic fracturing operations. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our exploration and production operations, could adversely impact our operations. Moreover, new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. For example, in October 2011, the EPA announced that it plans to develop standards for disposal of wastewater produced from shale gas operations to publicly owned treatment works (POTWs), which will be proposed in 2014. The regulations will be developed under the EPA's Effluent Guidelines Program under the authority of the Clean Water Act. Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted, all of which could have an adverse affect on our operations and financial condition.
A number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA is conducting a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. The Agency released a progress report outlining work currently underway on December 21, 2012 and is expected to release results of the study in 2014. These on-going or proposed studies, depending on their course and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act, the Toxic Substance Control Act, and/or other regulatory mechanisms. President Obama created the Interagency Working Group on Unconventional Natural Gas and Oil by Executive Order on April 13, 2012, which is charged with coordinating and aligning federal agency research and scientific studies on unconventional natural gas and oil resources.
If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing
becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.
Certain of our properties, including some of our operations in Oklahoma, are located on Native American tribal lands and are subject to various federal and tribal approvals and regulations, which may increase our costs and delay or prevent our efforts to conduct planned operations.
Various federal agencies within the U.S. Department of the Interior, particularly the Bureau of Indian Affairs, Bureau of Land Management and the Office of Natural Resources Revenue, along with each Native American tribe, promulgate and enforce regulations pertaining to gas and oil operations on Native American tribal lands. These regulations and approval requirements relate to such matters as lease provisions, drilling and production requirements, environmental standards and royalty considerations. In addition, each Native American tribe is a sovereign nation having the right to enforce laws and regulations and to grant approvals independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees, requirements to employ Native American tribal members and other conditions that apply to lessees, operators and contractors conducting operations on Native American tribal lands. Lessees and operators conducting operations on tribal lands are generally subject to the Native American tribal court system. In addition, if our relationships with any of the relevant Native American tribes were to deteriorate, we could face significant risks to our ability to continue the projected development of our leases on Native American tribal lands. One or more of these factors may increase our costs of doing business on Native American tribal lands and impact the viability of, or prevent or delay our ability to conduct, our natural gas or oil development and production operations on such lands.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service ("IRS") were to treat us as a corporation for federal income tax purposes or if we become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution would be substantially reduced.
The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. A publicly traded partnership such as us may be treated as a corporation for federal income tax purposes unless it satisfies a “qualifying income” requirement. Based on our current operations we believe that we satisfy the qualifying income requirement and will be treated as a partnership. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity. We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other tax matter affecting us.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35% and would likely pay state income tax at varying rates. Distributions would generally be taxed again as corporate dividends, and no income, gains, losses or deductions would flow through to the limited partners. Because a tax would be imposed upon us as a corporation, our cash available for distributions would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.
At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. We are, for example, subject to an entity level tax on the portion of our income that is generated in Texas. Imposition of such any such tax on us by any other state will reduce the cash available for distribution.
The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. One such legislative proposal would eliminate the qualifying income exception to
the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes.
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS challenge will reduce our cash available for distribution.
We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest by the IRS will be borne indirectly by our unitholders because the costs will reduce our cash available for distribution.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period would result in the termination of our partnership for federal income tax purposes.
We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest are counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders receiving two Schedules K-1) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. A deferral of depreciation deductions would result in increased taxable income or reduced taxable loss to certain unitholders, although the exact increase or reduction for each unitholder cannot be estimated at this time. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our consolidated financial statements or our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine in a timely manner that a termination occurred. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the tax year in which the technical termination occurs.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. Nonetheless, we allocate certain deductions for depreciation of capital additions based upon the date the underlying property is placed in service. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A unitholder whose units are the subject of a securities loan (eg., a loan to a “short seller” to cover a short sale of units) may be considered as having disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan of their units are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
Unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if no cash distributions were received from us. Although not anticipated, our taxable income for a taxable year may include income without a corresponding receipt of cash by us, such as accrual of future income, original issue discount or cancellation of indebtedness income. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that result from that income.
Tax gain or loss on disposition of our common units could be more or less than expected.
If a unitholder sells common units, they will recognize a gain or loss equal to the difference between the amount realized and the tax basis in those common units. Prior distributions to a unitholder in excess of the total net taxable income allocated for a common unit, which decreased the unitholder’s tax basis in that common unit, will, in effect, become taxable income to the unitholder if the common unit is sold at a price greater than their tax basis in that common unit, even if the price received is less than the original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder's share of our non-recourse liabilities, if a unitholder sells units, the unitholder may incur a tax liability in excess of the amount of cash received from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as individual retirement accounts ("IRAs"), other retirement plans and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable tax rate, and non-U.S. persons will be required to file U.S. federal tax returns and pay tax on their share of our taxable income. Tax-exempt entities or non-U.S. persons should consult a tax advisor before investing in our common units.
We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Due to a number of factors, including our inability to match transferors and transferees of common units, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to the unitholders. It also could affect the timing of these tax benefits or the amount of gain from sales of common units and could have a negative impact on the value of our common units or result in audit adjustments to tax returns of our unitholders.
Unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our common units.
In addition to federal income taxes, a unitholder will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property, now or in the future, even if the unitholder does not live in any of those jurisdictions. A unitholder will likely be required to file state and local income tax returns and pay state and local income taxes in some or all
of these various jurisdictions. Further, a unitholder may be subject to penalties for failure to comply with those return filing requirements. We own assets and conduct business in several states. Many of these states currently impose a personal income tax. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is a unitholder's responsibility to file all United States federal, state and local tax returns.
Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.
The Fiscal Year 2013 Budget proposed by the President recommends elimination of certain key U.S. tax incentives
currently available to oil and natural gas exploration and production companies. Among others, the provisions include: elimination of the ability to fully deduct intangible drilling costs in the year incurred; repeal of the percentage depletion deduction for oil and gas properties; repeal of the manufacturing tax deduction for oil and gas companies; and an increase in the geological and geophysical amortization period for independent producers. It is unclear whether any such changes will be enacted or how soon any such changes would become effective. The passage of this legislation or any other similar changes in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect the taxable income allocable to the unitholders.
Item 1B.
Item 1B.
Unresolved Staff Comments.
Not Applicable.
Item 2.
Item 2.
Properties.
For a complete description of our significant properties, see Item 1. Business, which descriptions are incorporated into this item by this reference. Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that may have been subordinated to the right-of-way grants. We have obtained, where deemed necessary, license or permit agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, waterways, county or parish roads, municipal streets, railroad properties and state highways, as applicable. In some cases, property on which our pipeline was built was purchased in fee.
We believe that we have satisfactory title to our assets. Title to property may be subject to encumbrances and liens on substantially all of our assets as collateral support of our credit facility. We believe that none of these encumbrances will materially detract from the value of our properties or from our interest in these properties or will they materially interfere with their use in the operation of our business.
While we own our facilities, plants and gathering systems, in many cases we do not always own the land upon which the facilities, plants and gathering systems reside. In cases where the land is leased (and not owned), we are ordinarily in long-term leases. From time to time, these long-term leases expire, and we are forced to negotiate new terms at market rates or exit the premises. For more information, see our table of assets within Part I, Item 1 Business - Our Two Lines of Business and Our Five Reporting Segments - Midstream Business.
Item 3.
Item 3.
Legal Proceedings.
Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we are and may, at any given time, be a party to various legal proceedings and litigation arising in the ordinary course of business. However, we are not currently a party to any material litigation. We maintain insurance policies with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent. We cannot, however, give assurance that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices. We have been indemnified up to a certain dollar amount for two lawsuits. If there ultimately is a finding against us in these two indemnified cases, we would expect to make a claim against the indemnification up to limits of the indemnification.
In July 2012, the Alabama Department of Environmental Management (“ADEM”) notified one of our subsidiaries that ADEM had made a determination that alleged violations warrant enforcement action and determined that the alleged violations are appropriate for resolution by Consent Order and proposed the terms of a to-be-mutually agreed-upon Consent Order (“Proposed Consent Order”). Such notification and the Proposed Consent Order were the result of findings made by ADEM relating to our subsidiary's Flomaton/Fanny Church Oil and Gas Production and Treating Facility. The Proposed Consent Order primarily related to allegations of emissions in excess of those allowed by the production rate. Prior to receiving the Proposed Consent Order, we self-reported our emission rates and worked with ADEM to complete a series of quality improvement plans to address the causes of the alleged violations. On November 20, 2012, we executed a revised consent order that became effective on January 11, 2013. The order provides for a civil penalty of $80,000, which was paid on January 31, 2013.
Item 4.
Item 4.
Mine Safety Disclosures.
Not applicable.
PART II
Item 5.
Item 5.
Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.
Our common units are listed on the NASDAQ Global Select Market under the symbol “EROC.” The following table sets forth, for the periods indicated, the high and low sales prices of our common units as reported by the NASDAQ Global Select Market, as well as the amount of cash distributions declared per quarter.
The last reported sale price of our common units on the NASDAQ Global Select Market on February 25, 2013 was $8.98. As of that date, there were 129 holders of record and approximately 36,319 beneficial owners of our common units.
Cash Distribution Policy
We intend to distribute to our unitholders, on a quarterly basis, all of our available cash in the manner described below and as further described in our partnership agreement. Available cash generally means, for any quarter ending prior to liquidation, all cash on hand at the end of that quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the general partner to:
•
provide for the proper conduct of our business, including for future capital expenditures and credit and other needs;
•
comply with applicable law or any partnership debt instrument or other agreement; or
•
provide funds for distributions to unitholders and the general partner in respect of any one or more of the next four quarters.
Under the terms of the agreements governing our debt, we are prohibited from declaring or paying any distribution to unitholders if a default or event of default (as defined in such agreements) exists. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources-Capital Requirements-Revolving Credit Facility.
Our Board of Directors will evaluate our distribution policy from time to time as conditions warrant in the future.
Repurchases of Common Units
The following table sets forth certain information with respect to repurchases of common units during the three months ended December 31, 2012:
All of the units were surrendered by employees to pay tax withholding in connection with the vesting of restricted common units. As a result, we are deeming the surrenders to be “repurchases.” These repurchases were not part of a publicly announced program to repurchase our common units, nor do we have a publicly announced program to repurchase our common units.
Sales of Unregistered Securities
We did not sell our equity securities in unregistered transactions during the twelve months ended December 31, 2012.
Common Unitholder Return Performance Presentation
The performance graph below compares the cumulative total unitholder return on our common units with the cumulative total returns on the Standard & Poor’s 500 Index (the “S&P 500 Index”) and the Alerian MLP Total Return Index (the “Alerian MLP”). The Alerian MLP is a composite of the 50 most prominent energy master limited partnerships and limited liability companies, as determined by Standard & Poor’s using a float-adjusted market capitalization methodology. The graph assumes an investment of $100 in our common units, and in each of the S&P 500 Index and the Alerian MLP on December 31, 2007 and reinvestment of all dividends and distributions. The results shown in the graph are based on historical data and should not be considered indicative of future performance.
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Note: The above graph compares the cumulative total unitholder return on our common units assuming rights associated with Eagle Rock's Rights Offering were distributed effective May 27, 2010, the record date for the Rights Offering, and then immediately sold with the proceeds re-invested in Eagle Rock common units on the same day.
The information contained in the Performance Graph above will not be deemed to be "soliciting material" or to be "filed" with the SEC, nor will such information be incorporated by reference into any future filings of the Securities Act of 1933, as amended (the "Securities Act"), or the Securities Exchange Act of 1934, as amended (the "Exchange Act"), except to the extent that we specifically incorporate it by reference into any such filing.
Item 6.
Item 6. Selected Financial Data.
The following table shows selected historical financial data from our audited consolidated financial statements for the five fiscal years from January 1, 2008 to December 31, 2012. The following financial data should be read in conjunction with our consolidated financial statements and the accompanying notes and "Management's Discussion and Analysis of Financial Condition and Results of Operations" included elsewhere in this report.
Our historical results of operations for the periods presented below may not be comparable either from period to period or going forward due to the following significant transactions:
•
On April 30, 2008, we completed the acquisition of Stanolind Oil and Gas Corp., which we refer to as the Stanolind Acquisition, for an aggregate purchase price of $81.9 million in cash. As a result, financial results for the periods prior to May 2008 do not include the financial results from these assets.
•
On October 1, 2008, we completed the acquisition of Millennium Midstream Partners, L.P., which we refer to as the Millennium Acquisition, for approximately $183.6 million in cash and 3,362,280 (recorded value of $29.3 million) of our common units. As a result, financial results for the periods prior to October 2008 do not include the financial results from these assets.
•
On May 24, 2010, we completed the sale of our Minerals Business (assets acquired from Montierra and MacLondon Acquisitions) to Black Stone for approximately $171.6 million, and resulted in a pre-tax gain in the disposition of approximately $37.7 million. We used these proceeds to pay down amounts outstanding under our senior secured credit facility. Operations related to these assets for 2010 have been recorded as part of discontinued operations. Financial information for these assets for 2008 and 2009 have been retrospectively adjusted to reflect as assets and liabilities held-for-sale and discontinued operations.
•
On June 30, 2010, we closed our Rights Offering, for which we received gross proceeds of $53.9 million. We used these proceeds to pay down amounts outstanding under our senior secured credit facility.
•
On October 19, 2010, we completed the acquisition of certain natural gas gathering systems and related facilities from Centerpoint Energy Field Services, Inc. for $27.0 million of cash. As a result, financial results for the periods prior to October 19, 2010 do not include the financial results from these assets.
•
On May 3, 2011, we completed the acquisition of all the outstanding membership interests of CC Energy II L.L.C. ("Crow Creek Energy") for total consideration of $563.7 million including 28.8 million common units valued at $336.1 million, debt assumed of $212.6 million and cash of approximately $15.0 million. As a result, financial results for the periods prior to May 3, 2011 do not include the financial results from these assets.
•
On May 20, 2011, we sold our Wildhorse Gathering System in our East Texas and Other Midstream Segment. The Wildhorse Gathering System was acquired as part of the Millennium Acquisition on October 1, 2008. Operations related to these assets for 2011 have been recorded as part of discontinued operations. Financial information for these assets for 2008, 2009 and 2010 have been retrospectively adjusted to reflect as assets and liabilities held-for-sale and discontinued operations.
•
On May 27, 2011, the Partnership, along with its subsidiary, Eagle Rock Energy Finance Corp. ("Finance Corp"), as co-issuer, issued $300 million of 8 3/8% senior unsecured notes (the "Senior Notes") through a private placement. The Senior Notes will mature on June 1, 2019, and interest is payable on each June 1 and December 1, commencing December 1, 2011. These Senior Notes were exchanged for registered notes on February 15, 2012.
•
On May 31, 2012, we announced a program through which we may issue common units, from time to time, with an aggregate market value of $100 million. During 2012, we issued 834,327 common units under this program for net proceeds of approximately $7.3 million.
•
On July 13, 2012, the Partnership, along with Finance Corp, issued $250 million of Senior Notes through a private placement. This issuance supplemented our prior $300 million of Senior Notes issued in May 2011. The Senior Notes issued in May 2011 and July 2012 are treated as a single series.
•
On August 17, 2012, we closed an underwritten public offering of 10,120,000 common units for net proceeds of approximately $84.3 million. The net proceeds were used to repay a portion of the outstanding borrowings under our
revolving credit facility in advance of funding the Panhandle Acquisition.
•
On October 1, 2012, we completed the Panhandle Acquisition for total consideration of $230.6 million. As a result, financial results for the periods prior to October 1, 2012 do not include the financial results from these assets.
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(a)
See Part II Item 6. Selected Financial Data - Non-GAAP Financial Measures for reconciliation of “Adjusted EBITDA” to net cash flows from operating activities and net income (loss).
Non-GAAP Financial Measures
We include in this report Adjusted EBITDA, which does not comply with accounting principles generally accepted in the United States ("GAAP"). We provide reconciliations of this non-GAAP financial measure to its most directly comparable financial measures as calculated and presented in accordance with GAAP.
We define Adjusted EBITDA as net income (loss) plus or (minus) income tax provision (benefit); interest-net, including realized interest rate risk management instruments and other expense; depreciation, depletion and amortization expense; impairment expense; other operating expense, non-recurring; other non-cash operating and general and administrative expenses, including non-cash compensation related to our equity-based compensation program; unrealized (gains) losses on commodity and interest rate risk management related instruments; gains (losses) on discontinued operations and other (income) expense. We use Adjusted EBITDA as a measure of our core profitability to assess the financial performance of our assets. Adjusted EBITDA is also used as a supplemental financial measure by external users of our financial statements such as investors, commercial banks and research analysts. For example, the compliance covenant used by our lenders under our revolving credit facility which is designed to measure our viability and our ability to perform under the terms of our revolving credit facility uses Adjusted EBITDA. We believe that investors benefit from having access to the same financial measures that our management team uses in evaluating performance. Adjusted EBITDA is useful in determining our ability to sustain or increase distributions. By excluding unrealized derivative gains (losses), a non-cash, mark-to-market benefit (charge) which represents the change in fair market value of our executed derivative instruments and is independent of our assets’ performance or cash flow generating ability, we believe Adjusted EBITDA reflects more accurately our ability to generate cash sufficient to pay interest costs, support our level of indebtedness, make cash distributions to our unitholders and general partner and finance our maintenance capital expenditures. We further believe that Adjusted EBITDA also describes more accurately the underlying performance of our operating assets by isolating the performance of our operating assets from the impact of an unrealized, non-cash measure designed to describe the fluctuating inherent value of a financial asset. Similarly, by excluding the impact of non-recurring discontinued operations, Adjusted EBITDA provides users of our financial statements a more accurate picture of our current assets’ cash generation ability, independently from that of assets which are no longer a part of our operations. Our Adjusted EBITDA definition may not be comparable to Adjusted EBITDA or similarly titled measures of other entities, as other entities may not calculate Adjusted EBITDA in the same manner as us. For example, we include in Adjusted EBITDA the actual settlement revenue created from our commodity hedges by virtue of transactions occasionally undertaken by us to reset commodity hedges to higher prices or purchase puts or other similar floors, despite the fact that we exclude from Adjusted EBITDA any charge for amortization of the cost of such commodity hedge reset transactions or puts.
Adjusted EBITDA does not include interest expense, income taxes or depreciation and amortization expense. Because we have borrowed money to finance our operations, interest expense is a necessary element of our costs and our ability to generate net income. Because we use capital assets, depreciation and amortization are also necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net income (loss) and net cash flows provided by operating activities determined under GAAP, as well as Adjusted EBITDA, to evaluate our performance and liquidity.
Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flows provided by operating activities or any other measure of financial performance presented in accordance with U.S. GAAP.
The following table provides a reconciliation of Adjusted EBITDA to net cash flows provided by operating activities and net income (loss):
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(a)
Includes $2.9 million related to the release of reserves due to the expiration of repurchase obligations for certain receivables which were sold in previous periods during the year ended December 31, 2011, $3.6 million due to the recovery of $2.2 million of assets previously written off and the release of $1.4 million of liabilities assumed as part of our purchase price allocation for our acquisitions of Escambia Asset Co. LLC and Redman Energy Holdings, L.P. during the year ended December 31, 2009; and $10.7 million related to bad debt expense taken against our outstanding accounts receivable from SemGroup during the year ended December 31, 2008.
(b)
Adjusted EBITDA excludes amortization of commodity hedge costs (including costs of hedge reset transactions) for the years ended December 31, 2010, 2009 and 2008 of $4.0 million, $48.4 million and $13.3 million, respectively. Including these amortization costs, our Adjusted EBITDA for the years ended December 31, 2010, 2009 and 2008, would have been $122.1 million, $124.2 million and $193.1 million, respectively.
The following table summarizes our quarterly financial data for 2012:
During our fiscal year ended December 31, 2012, we recorded the following unusual or infrequently occurring items:
•
On October 1, 2012, we completed the Panhandle Acquisition for an aggregate purchase price of $230.6 million. We commenced recording results of operations relating to this acquisition during the quarter ended December 31, 2012.
•
During our first quarter ended March 31, 2012, we incurred impairment charges of $45.5 million in our East Texas and Other Segment. During our second quarter ended June 30, 2012, we incurred impairment charges of $21.4 million related to our Upstream Segment and East Texas and Other Segment. During our third quarter ended September 30, 2012, we incurred impairment charges of $55.9 million in our Upstream Segment and East Texas and Other Segment. During our fourth quarter ended December 31, 2012, we incurred impairment charges of $54.2 million in our Upstream Segment and East Texas and Other Segment. See Part II, Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion analyzes our financial condition and results of operations and should be read in conjunction with our historical consolidated financial statements and notes included elsewhere in this Annual Report.
OVERVIEW
We are a domestically-focused, growth-oriented, publicly-traded Delaware limited partnership engaged in the following two businesses:
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Midstream Business-gathering, compressing, treating, processing, transporting, marketing and trading natural gas; fractionating, transporting and marketing natural gas liquids ("NGLs"); and crude oil and condensate logistics and marketing; and
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Upstream Business-developing and producing oil and natural gas property interests.
We conduct, evaluate and report on our Midstream Business within three distinct segments-the Texas Panhandle Segment, the East Texas and Other Midstream Segment (which consolidates our former East Texas/Louisiana, South Texas and Gulf of Mexico Segments) and the Marketing and Trading Segment. On October 1, 2012, we completed our acquisition of BP America Production Company's ("BP") Texas Panhandle midstream assets (the "newly-acquired Panhandle System"), as discussed further below. Our Texas Panhandle Segment consists of gathering and processing assets in the Texas Panhandle. Our East Texas and Other Midstream Segment consists of gathering and processing assets in East Texas/Northern Louisiana, South Texas, Southern Louisiana, the Gulf of Mexico and Galveston Bay. Our Marketing and Trading Segment consists of crude oil and condensate logistics and marketing in Texas Panhandle and Alabama and natural gas marketing and trading. During the year ended December 31, 2012, our Midstream Business generated operating loss from continuing operations of $95.9 million compared to operating income from continuing operations of $57.5 million during the year ended December 31, 2011.
We conduct, evaluate and report on our Upstream Business as one segment. On May 3, 2011, we completed our acquisition of CC Energy II L.L.C. (the "Mid-Continent Acquisition"), as discussed below. Our Upstream Segment includes operated and non-operated wells located in the Mid-Continent (which includes areas in Oklahoma, Arkansas and the Texas Panhandle); Permian (which includes areas in West Texas); East Texas / South Texas / Mississippi; and Southern Alabama (which also includes two treating facilities and one natural gas processing plant and related gathering systems). During the year ended December 31, 2012, our Upstream Business generated operating income of $12.4 million compared to operating income of $79.3 million during the year ended December 31, 2011.
The final segment that we report on is our Corporate and Other Segment, which is where we account for our risk management activity (excluding any risk management activity associated with our natural gas marketing and trading activities), intersegment eliminations and our general and administrative expenses. During the year ended December 31, 2012, our Corporate and Other Segment generated an operating loss of $12.6 million compared to an operating loss of $25.2 million during the year ended December 31, 2011. Results reflected net gains, realized and unrealized, on our commodity derivatives of $57.9 million during the year ended December 31, 2012, compared to net gains, realized and unrealized, on our commodity derivatives of $32.5 million during the year ended December 31, 2011. See "Summary of Consolidated Operating Results - Corporate and Other Segment" for a further discussion of the impact of our commodity derivatives.
Acquisitions
On October 1, 2012, we completed the acquisition of BP's Texas Panhandle midstream assets (the "Panhandle Acquisition"), including the Sunray and Hemphill processing plants and associated 2,500 mile gathering system for $230.6 million, which includes certain closing adjustments.
In addition, on October 1, 2012, we entered into a 20-year, fixed-fee Gas Gathering and Processing Agreement with BP under which we will gather and process BP's natural gas production from the existing wells connected to the newly-acquired Panhandle System. Furthermore, BP has committed itself to us under the same agreement, and committed its farmees to us under substantially the same terms, with respect to all future natural gas production from new wells drilled within an initial two-year period from closing, subject to mutually-agreed extensions, and within a two-mile radius of any portion of our gathering system serving such BP connected wells.
On May 3, 2011, we completed the Mid-Continent Acquisition -- the acquisition of all of the outstanding membership interests of CC Energy II L.L.C. ("Crow Creek Energy"), a portfolio company of Natural Gas Partners, VIII, L.P. ("NGP VIII"), for total consideration of $563.7 million consisting of 28.8 million common units valued at $336.1 million at the closing of the acquisition, debt assumed of $212.6 million and cash of approximately $15.0 million. The cash portion of the acquisition consideration and the repayment of Crow Creek Energy’s outstanding debt was funded through borrowings under our revolving credit facility. In addition, we incurred $2.3 million of acquisition-related expenses, which are included within general and administrative expenses for the year ended December 31, 2012. The oil and natural gas properties acquired from Crow Creek Energy are located in multiple basins across Oklahoma, north Texas and Arkansas (the "Mid-Continent Properties") and provide us with an extensive inventory of low-risk development prospects.
Impairment
During the year ended December 31, 2012, we recorded an impairment charges in our Midstream Business for certain assets within our East Texas and Other Midstream Segment of $131.7 million, due to (i) reduced throughput volumes as our producer customers curtailed their drilling activity in response to the continued depressed natural gas price environment, (ii) the loss of significant gathering contracts on various systems and (iii) the substantial damage incurred at the Yscloskey processing plant as a result of Hurricane Isaac in August 2012. During the year ended December 31, 2012, we recorded an impairment and other charges in our Upstream Segment of $45.3 million, due to (i) certain leaseholds in our unproved properties that we expect to expire undrilled in 2013 and (ii) our proved properties in the Barnett Shale, East Texas and Permian regions that are expected to have reduced cash flows resulting from lower natural gas prices and ongoing relatively high operating costs associated with gas compression. In addition, we recorded a loss on the sale of our properties in the Barnett Shale. During the year ended December 31, 2011, we recorded an impairment charge in our Texas Panhandle Segment of $4.6 million, related to the write-down of our idle Turkey Creek plant in our Texas Panhandle Segment. We determined that the assets that made up our Turkey Creek plant could not be used elsewhere within our business, and thus we decided to remove all above ground equipment and structures. During the year ended December 31, 2011, we recorded an impairment charge of $11.7 million in our Upstream Segment related to certain legacy proved undeveloped and unproved properties which we no longer intend to develop based on the current commodity price environment and the performance of offsetting wells. During the year ended December 31, 2010, we recorded $3.5 million in impairment charges within our Upstream Segment related to certain wells in our unproved properties as we determined it would not be economical to develop these unproved locations and $3.1 million in impairment charges within our East Texas and Other Midstream Segment due to the loss of a significant gathering contract.
Pursuant to GAAP, our impairment analysis does not take into account the value of our commodity derivative instruments, which generally increase as the estimates of future prices decline. Further declines in commodity prices and other factors could result in additional impairment charges and changes to the fair value of our derivative instruments.
Potential Impact of New Environmental Standards
We have certain obligations under our existing air emissions permit to lower the sulfur dioxide (SO2) emissions of our Alabama plant operations. In order to fulfill our obligations under the existing permit, our operating subsidiary in Alabama initiated the first phase of an SO2 emissions reduction project at our Big Escambia Creek processing facility in December 2011. This phase of the project involved adding a Superclaus reactor to the existing sulfur recovery unit to achieve the desired reduction in SO2 emissions. The new unit began operations on December 17, 2012, and as of year-end 2012 had resulted in increased sulfur production and reductions in SO2 emissions to levels well below the required permitted levels. The total cost of this phase was approximately $18.1 million net to our interest.
The second and final phase of our SO2 emissions reduction project involves replacing or upgrading certain components of our existing sulfur recovery unit at the Big Escambia Creek processing facility. This phase is designed to improve the operational reliability of the processing facility, further increase the marketable sulfur recovered from the inlet gas stream, reduce the frequency of facility turnarounds, extend the facility's operating life and achieve cost savings across our operations in Southern Alabama. The improvements to our sulfur recovery unit will also further reduce SO2 emissions. helping to ensure our compliance with the National Ambient Air Quality Standards the Environmental Protection Agency enacted in mid-2010. In the first of these planned upgrades, we expect to replace the incinerator portion of the sulfur recovery unit in 2014 at a cost of approximately $15 million net to our interest. We currently expect to complete the final upgrades in 2016.
How We Evaluate Our Operations
Our management uses a variety of financial and operational measures to analyze our performance. We view these measures as important indicators of our profitability and review these measures on a monthly basis for consistency and trend analysis. These measures include volumes, margin, operating expenses and Adjusted EBITDA (defined in Part II, Item 6. Selected Financial Data) on a company-wide basis.
Volumes (by Business)
Midstream Volumes. In our Midstream Business, due to the natural production decline of the wells connected to our systems, we must continually obtain new supplies of natural gas to maintain or increase throughput volumes on our gathering and processing systems. Our ability to maintain existing supplies of natural gas and obtain new supplies is impacted by (1) successful drilling activity and the level of workovers or recompletions of existing connected wells in areas currently dedicated to our pipelines, (2) our ability to compete for volumes from successful new wells in other areas and (3) our ability to obtain natural gas that has been released from other commitments. We routinely monitor producer activity in the areas served by our gathering and processing systems to pursue new supply opportunities.
We rely on producer drilling activity to maintain and grow our midstream volumes. Generally, producer drilling activity is correlated to the current and expected price of natural gas, and to NGLs in producing basins that have liquids-rich gas reservoirs. As such, throughput volume in our existing midstream assets will typically increase in times of rising natural gas and NGL prices and will typically decrease in times of falling natural gas and NGL prices. In producing basins that have liquids-rich gas reservoirs, the rise and fall of throughput volumes tends to correlate more predominately with the rise and fall of NGL prices, in particular when natural gas prices approach or achieve historical lows.
Upstream Volumes. In the Upstream Segment, we continually monitor the production rates of the wells we operate. This information is a critical indicator of the performance of our wells, and we evaluate and respond to any significant adverse changes. We employ an experienced team of engineering and operations professionals to monitor these rates on a well-by-well basis and to design and implement remediation activities when necessary. We also design and implement workover and drilling operations to increase production in order to offset the natural decline of our currently producing wells. Because our rates of return on new workover and drilling activity are determined in part on commodity prices, we may elect to scale back or cancel such activity during periods of low commodity prices. Furthermore, we may elect to shut-in existing production in extreme commodity downturns (i.e., when the realized prices we receive are below our operating costs on a per unit basis).
Net Revenues
Commodity Pricing. Revenues, and the associated cost of natural gas, natural gas liquids and condensate, in our Midstream Business generally are positively correlated to NGL and condensate prices, and may be adversely impacted to the extent the price of NGLs declines in relation to the price of natural gas. We refer to the price of NGLs in relation to the price of natural gas as the "fractionation spread." In our Upstream Segment, our revenues generally will correlate with changes in crude oil, natural gas, NGL and sulfur prices.
Risk Management. We conduct risk management activities to mitigate the effect of commodity price and interest rate fluctuations on our cash flows. Our primary method of risk management in this respect is entering into derivative contracts. The impact of our risk management activities are captured in our Corporate Segment. For a further discussion of our risk management activities, see Part II, Item 7A.
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk.
Risk and Accounting Policies
We are exposed to market risks associated with adverse changes in commodity prices, interest rates and counterparty credit. We may use financial instruments such as swaps, put and call options and other derivatives to mitigate the effects of the identified risks. Adverse effects on our cash flow from changes in crude oil, natural gas, NGL product prices or interest rates could adversely impact our ability to make distributions to our unitholders, meet debt service obligations, fund required capital expenditures, and other similar requirements. Our management has established a comprehensive review of our market risks and has developed risk management policies and procedures to monitor and manage these market risks. Our general partner is responsible for the overall approval of market risk management policies, delegation of transaction authority levels, and for the establishment of a Risk Management Committee ("RMC"). The RMC is composed of officers (including, on an ex officio basis, our chief executive officer) who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The RMC is the entity responsible for creating and implementing a sound approach to managing our credit, commodity price and interest rate risk with respect to our budgetary exposure and stated risk tolerance. As such, the RMC’s responsibilities and authorities are to:
•
Identify sources of financial and credit risk;
•
Establish financial risk management policies (or ensure they are developed by appropriate departments within the partnership);
•
Develop, oversee, review, assess and implement the financial risk management processes and infrastructure;
•
Advise on controls for risk management activities, including credit, hedging transactions and financial risk reporting;
•
Measure and analyze our overall commodity price and interest rate risk exposure, at least quarterly;
•
Recommend and approve derivative hedging transactions to reduce our commodity price and interest rate risk;
•
Report quarterly to the Board of Directors on the performance of the hedge program. These reports disclose, but may not necessarily be limited to, the following: percentage of volumes and debt outstanding hedged; mark-to-market valuations of open positions; and realized hedge settlement; and
•
Monitor and enforce the risk policy and controls for our natural gas marketing subsidiary, Eagle Rock Gas Services, LLC ("ERGS").
The RMC is specifically charged with the following:
•
Establishing an organizational structure for financial risk management controls;
•
Establishing clearly-defined segregation of duties and delegations of authority related to derivatives hedging;
•
Identifying permitted transaction and product types; and
•
Executing derivative transactions on behalf of the Partnership.
The Audit Committee of our Board of Directors monitors the implementation of our policy, and we have engaged an independent firm to provide additional oversight.
We have implemented a Risk Management Policy which allows management to execute hedging instruments, which may include swaps, collars, options and other derivatives, in order to reduce exposure to substantial adverse changes in the prices of commodities and in interest rates. The activities of ERGS are governed under a separate risk policy.We monitor and ensure compliance with our corporate Risk Management Policy through senior level executives in our operations, finance and legal departments. Our Risk Management Policy includes the following provisions:
1. Anti-speculation
Speculative buying and selling of commodity or interest rate products is prohibited. “Speculation” includes, but is not limited to, buying or selling commodity or financial instruments that are not necessary for meeting forecasted production, consumption, or outstanding debt service.
2. Maximum Transaction Term
The maximum term of any hedging transaction should be five (5) years, unless specifically approved by our Board of Directors.
3. Maximum Transaction Volumes
Hedged commodity volumes are not to exceed 80% of the expected production or consumption in any settlement period, and hedged interest rates shall not exceed 100% of total outstanding indebtedness. Neither of these limitations shall be exceeded without the prior approval of the Board of Directors, which (with respect to commodity volumes) we did obtain for 2011 and 2012.
In any quarter, newly-hedged volumes (i.e., added during that quarter) shall not exceed 20% of the expected production, consumption, or indebtedness for any settlement period without the prior approval of the Board of Directors.
4. Portfolio Performance and Value Reporting
Our staff shall prepare performance reports containing an analysis of physical and financial positions of all energy price and interest rate hedge contracts for review by the Risk Management Committee and presentation to the Board of Directors. The frequency and content of performance reports shall be determined by the Risk Management Committee, but in no case will be done less frequently than quarterly.
Payment obligations in connection with our hedging transactions are secured by a first priority lien in the collateral securing our senior secured indebtedness that ranks equal in right of payment with liens granted in favor of our senior secured lenders. As long as this first priority lien is in effect, we will have no obligation to post cash, letters of credit, or other additional collateral to secure these hedges at any time even if our counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in our creditworthiness.
We also have implemented a separate risk policy and controls document for ERGS to ensure appropriate identification, monitoring and control of risk relating to its trading activities. This document establishes the risk management methodologies that limit exposure and track potential changes in portfolio value. The ERGS risk policy and controls document is consistent with our corporate risk objectives, organizational structures and control environment.
See Notes 11 and 12 to our consolidated financial statements for additional discussion of our commodity hedging activities and related fair values.
We have not designated our contracts as accounting hedges based on authoritative guidance. As a result, we mark our derivatives to market with the resulting change in fair value included in our statement of operations.
We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant.
Our Board of Directors also plays an important role in our risk oversight function. The Audit Committee is primarily responsible for the oversight of: (i) the integrity of our financial statements and internal controls, (ii) our compliance with legal and regulatory requirements, (iii) our independent auditor's qualifications, independence and performance of our internal audit function, and (iv) matters related to our hedging activities, litigation/disputes and environmental issues.
See Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -Critical Accounting Policies - Risk Management Activities and Note 11 to our consolidated financial statements for further discussion of the accounting for our derivative contracts.
Commodity Price Risk
We are exposed to the impact of market fluctuations in the prices of crude oil, natural gas, NGLs and other commodities as a result of our gathering, processing, producing and marketing activities, which produce a naturally long position in these commodities. Our profitability and cash flow are affected by changes in prices of these commodities. These prices are impacted by changes in the supply and demand for these commodities, as well as market uncertainty and other factors beyond our control. Historically, changes in the prices of NGLs have generally correlated with changes in the price of crude oil. For a discussion of the volatility of crude oil, natural gas and NGL prices, please read “Risk Factors.”
We manage this commodity price exposure through an integrated strategy that includes management of our contract portfolio, matching sales prices of commodities with purchases, optimization of our portfolio by monitoring basis and other price differentials in our areas of operations, and the use of derivative contracts. Crude oil, natural gas and NGL prices can also indirectly affect our profitability by influencing the level of drilling activity and related opportunities for our service.
We frequently use financial derivatives (“hedges”), which may include swaps, collars and options, among others, to reduce our exposure to commodity price risk. These hedges are only intended to mitigate the risk associated with our natural physical position.
In 2011, we began conducting commodity derivative trading activities through ERGS, our natural gas marketing and trading subsidiary. ERGS's trading portfolio includes transactions that are settled through the physical delivery of the underlying product and financially settled contracts, primarily basis derivatives transacted to capture spread differentials between physical index points where transportation capacity has been subscribed. If the value of these positions change in a direction or manner that we did not anticipate or cannot manage, it could negatively impact our cash flows.
As of December 31, 2012, our commodity hedge portfolio totaled $53.1 million, which consists of assets aggregating $56.5 million less liabilities aggregating $3.4 million. For additional information, see Notes 11 and 12 of our consolidated financial statements for additional discussion of our hedging activities and related fair values.
Effectiveness of Commodity Risk Management Activities
The goal of our commodity risk management activities is to reduce the impact of changing commodity prices on our ability to make future distributions to our unitholders. One way we evaluate the effectiveness of these activities is to analyze the theoretical change in our internal estimates of future Adjusted EBITDA given an assumed change in future commodity prices. Using this method, we estimate that a $10 per barrel increase in NYMEX crude oil prices, a $10 per barrel decrease in NYMEX crude oil prices and a $1 per MMbtu change in NYMEX natural gas prices would result in changes to 2012 Adjusted EBITDA of $10 million and $3 million, respectively, based on $85 per barrel and $3.25 per MMbtu commodity prices.
Users of this information should be aware that these estimates rely on a large number of assumptions that may ultimately prove to be false. These assumptions include, but are not limited to, future production rates, future volumes delivered to our plants and systems, future costs and other economic conditions, and future relationships between crude oil prices and natural gas liquids prices.
Interest Rate Risk
We are exposed to variable interest rate risk as a result of borrowings under our existing credit agreement. To mitigate its interest rate risk, we have entered into various interest rate swaps. These swaps convert the variable-rate term loan into a fixed-rate obligation. The purpose of entering into these swaps is to eliminate interest rate variability by converting LIBOR-based variable-rate payments to fixed-rate payments. Amounts received or paid under these swaps were recorded as reductions or increases in interest expense.
On June 20, 2011, we extended $250 million notional amount of our interest rate swaps from their original maturity dates of December 31, 2012 to a new maturity date of June 22, 2015 and blended the existing swap rate for these extended swaps with the then prevailing interest swap rate, which lowered the rate from 4.095% to $2.95%.
Based upon the transactions discussed in the paragraph above, we estimate that for 2013, a 10% increase or decrease in the current LIBOR rates would impact our interest expense by $0.1 million.
See Notes 11 and 12 of our consolidated financial statements for additional discussion of our interest rate hedging activities and related fair values.
The table below summarizes the changes in commodity and interest rate risk management assets for the applicable periods:
Credit Risk
Our principal natural gas sales customers are large industrial, commercial and utility companies. With respect to the sale of our NGLs and condensates, our principle customers are large natural gas liquids purchasers, fractionators and marketers, and large condensate aggregators that then typically sell to large multi-national petrochemical and refining companies. We also sell a small amount of propane to medium sized, local distributors.
For the year ended December 31, 2012, ONEOK, Inc. and Chevron Corporation, our largest customers, represented 20% and 13%, respectively, of our total sales revenue (including realized and unrealized gains on commodity derivatives). All of our natural gas sales are under 30 day payment term deals, with credit based upon 60 days of deliveries and almost all other product sales contracts are under 30 day payment term arrangements.
This concentration of credit risk may affect our overall credit risk in that these customers may be similarly affected by changes in the natural gas, natural gas liquids, petrochemical and other segments of the energy industry, the economy in general, the regulatory environment and other factors.
In evaluating credit risk exposure we analyze the financial condition of each counterparty before entering into an agreement. Our corporate credit policy lists the resource materials and information required to assess the financial condition of each prospective customer. The credit threshold for each customer is also based upon a time horizon for exposure, which is typically 60 days or less. We establish these credit limits and monitor and adjust them on an ongoing basis. We also require counterparties to provide letters of credit or other collateral financial agreements for exposure in excess of the established threshold. All of our sales agreements contain adequate assurance provisions to permit us to mitigate or eliminate future credit risk, at our sole discretion, by suspending deliveries until obligations and payments are satisfied or by canceling the agreement.
Our derivative counterparties include BNP Paribas, Wells Fargo Bank, National Association, Comerica Bank, Bank of Nova Scotia, The Royal Bank of Scotland plc, Bank of America N.A., J Aron and Company (an affiliate of Goldman Sachs), ING Capital Markets LLC, BBVA Compass Bank, Royal Bank of Canada, Regions Financial Corporation and CITIBANK, N.A.
Item 8.
Item 8.
Financial Statements and Supplementary Data.
Our consolidated financial statements, together with the report of KPMG, LLP ("KPMG") as the independent registered public accounting firm and the report of Deloitte & Touche, LLP ("Deloitte & Touche"), the former independent registered public accounting firm, begin on page of this Annual Report on Form 10-K.
Item 9.
Item 9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Item 9A. Controls and Procedures.
Disclosure Controls and Procedures
The Partnership maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the Partnership's reports under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, and our Audit Committee of the Board of Directors, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures. In addition, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the internal control system are met. Because of the inherent limitations of any internal control system, no evaluation of controls can provide absolute assurance that all control issues, if any, within a company have been detected.
Our management, with the participation of our Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial and accounting officer), evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2012. Based on the evaluation of our disclosure controls and procedures (as defined in the Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) required by Exchange Act Rules 13a-15(b) or 15d-15(b), our principal executive officer and principal financial officer have concluded that as of the end of the period covered by this report, our disclosure controls and procedures were effective at the reasonable assurance level to ensure that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
Changes to Internal Control
There were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d - 15(f) under the Exchange Act) that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management's Annual Report On Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting. Management has conducted (i) an evaluation of the design of our internal control over financial reporting, and (ii) a testing of the effectiveness of our internal control over financial reporting, as it pertains to the calendar year 2012. The evaluation and testing was conducted by our internal auditor, under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Our evaluation and testing followed the “Internal Control-Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Our evaluation and testing was conducted as of the year ended December 31, 2012, which is the period covered by this Annual Report on Form 10-K. Based on our assessment, we believe our internal controls over financial reporting are effective to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles based on the criteria of the COSO Framework.
KPMG LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Partnership included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of the Partnership's internal control over financial reporting as of December 31, 2012, which is included herein.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors of Eagle Rock Energy G&P, LLC and Unitholders of Eagle Rock Energy Partners, L.P.:
We have audited Eagle Rock Energy Partners, L.P. and subsidiaries (collectively, the "Partnership") internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Partnership's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. 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 the policies or procedures may deteriorate.
In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on “criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission”.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Partnership as of December 31, 2012 and 2011, and the related consolidated statements of operations, members' equity, and cash flows for the years then ended, and our report dated February 28, 2013 expressed an unqualified opinion on those consolidated financial statements.
/s/KPMG LLP
Houston, Texas
February 28, 2013
Item 9B.
Item 9B.
Other Information.
None.
PART III
Item 10.
Item 10.
Directors, Executive Officers and Corporate Governance.
Information required to be set forth in Item 10. Directors, Executive Officers and Corporate Governance, has been omitted and will be incorporated herein by reference, when filed, to our proxy statement for our 2013 Annual Meeting of Unitholders to be filed no later than April 30, 2013.
Item 11.
Item 11.
Executive Compensation.
Information required to be set forth in Item 11. Executive Compensation, has been omitted and will be incorporated herein by reference, when filed, to our proxy statement for our 2013 Annual Meeting of Unitholders to be filed no later than April 30, 2013.
Item 12.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.
Information required to be set forth in Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters, has been omitted and will be incorporated herein by reference, when filed, to our proxy statement for our 2013 Annual Meeting of Unitholders to be filed no later than April 30, 2013.
Item 13.
Item 13.
Certain Relationships and Related Transactions, and Director Independence.
Information required to be set forth in Item 13. Certain Relationships and Related Transactions, and Director Independence, has been omitted and will be incorporated herein by reference, when filed, to our proxy statement for our 2013 Annual Meeting of Unitholders to be filed no later than April 30, 2013.
Item 14.
Item 14.
Principal Accounting Fees and Services.
Information required to be set forth in Item 14. Principal Accountant Fees and Services, has been omitted and will be incorporated herein by reference, when filed, to our proxy statement for our 2013 Annual Meeting of Unitholders to be filed no later than April 30, 2013.
PART IV
Item 15.
Item 15.
Exhibits and Financial Statement Schedules.
(a)(1) Financial Statements:
The following financial statements and the Report of Independent Registered Public Accounting Firm are filed as a part of this report on the pages indicated:
(a)(2) Financial Statement Schedules:
All other schedules have been omitted since the required information is not significant or is included in the Consolidated Financial Statements or Notes thereto or is not applicable.
(a)(3) Exhibits:
The following documents are included as exhibits to this report:
*
Filed herewith
**
Management contract or compensatory plan or arrangement required to be filed as an exhibit hereto.
***
Furnished herewith
†
Portions of this exhibit have been omitted pursuant to a request for confidential treatment.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on February 28, 2013.
EAGLE ROCK ENERGY PARTNERS, L.P.
By:
Eagle Rock Energy GP, L.P., its general partner
By:
Eagle Rock Energy G&P, LLC, its general partner
By:
/s/ JOSEPH A. MILLS
Name:
Joseph A. Mills
Title:
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacity and on the dates indicated:
EAGLE ROCK ENERGY PARTNERS, L.P.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors of Eagle Rock Energy G&P, LLC and Unitholders of Eagle Rock Energy Partners, L.P.:
We have audited the accompanying consolidated balance sheets of Eagle Rock Energy Partners, L.P. and subsidiaries (collectively, the "Partnership") as of December 31, 2012 and 2011, and the related consolidated statements of operations, members' equity, and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit. The accompanying consolidated financial statements of the Partnership for the year ended December 31, 2010, were audited by other auditors whose report thereon dated November 14, 2011 expressed an unqualified opinion on those statements, before the adjustments described in Note 14 to the consolidated financial statements.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the 2012 and 2011 consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Partnership as of December 31, 2012 and 2011, and the results of their operations and their cash flows for the year then ended in conformity with U.S. generally accepted accounting principles.
We also have audited the adjustments described in Note 14 that were applied to retrospectively adjust the 2010 consolidated financial statements disclosures for changes made in 2011 to the composition of the Partnership's reportable segments. In our opinion, such adjustments are appropriate and have been properly applied. We were not engaged to audit, review, or apply any procedures to the 2010 consolidated financial statements of the Partnership other than with respect to the adjustments and, accordingly, we do not express an opinion or any other form of assurance on the 2010 consolidated financial statements taken as a whole.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Eagle Rock Energy Partners, L.P.'s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 28, 2013, expressed an unqualified opinion on the effectiveness of the Partnership's internal control over financial reporting.
/s/ KPMG LLP
Houston, Texas
February 28, 2013
F- 2
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Eagle Rock Energy G&P, LLC and Unitholders of Eagle Rock Energy Partners, L.P.
Houston, Texas
We have audited, before the effects of the adjustments to retrospectively apply the change to the consolidated financial statement disclosures for a change in the composition of reportable segments discussed in Note 14 to the consolidated financial statements, the consolidated statements of operations, members' equity, and cash flows of Eagle Rock Energy Partners, L.P. and subsidiaries (the “Partnership”) for the year ended December 31, 2010 (the 2010 consolidated financial statements before the effects of the adjustments, discussed in Note 14 to the consolidated financial statements are not presented herein). These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such 2010 consolidated financial statements, before the effects of the adjustments to retrospectively apply the change to the consolidated financial statement disclosures for a change in the composition of reportable segments discussed in Note 14 to the consolidated financial statements, present fairly, in all material respects, the results of the Partnership's operations and its cash flows for the year ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.
We were not engaged to audit, review, or apply any procedures to the adjustments to retrospectively apply the change to the consolidated financial statement disclosures for a change in the composition of reportable segments discussed in Note 14 to the consolidated financial statements and, accordingly, we do not express an opinion or any other form of assurance about whether such retrospective adjustments are appropriate and have been properly applied. Those retrospective adjustments were audited by other auditors.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
November 14, 2011
F- 3
EAGLE ROCK ENERGY PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2012 AND 2011
($ in thousands)
________________________
(a)
Net of allowance for bad debt of $972 as of December 31, 2012 and $1,347 as of December 31, 2011.
(b)
144,675,751 and 127,606,229 common units were issued and outstanding as of December 31, 2012 and December 31, 2011, respectively. These amounts do not include unvested restricted common units granted under the Partnership's long-term incentive plan of 2,608,035 and 2,560,110 as of December 31, 2012 and December 31, 2011, respectively.
See accompanying notes to consolidated financial statements.
F- 4
EAGLE ROCK ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
($ in thousands)
See accompanying notes to consolidated financial statements.
F- 5
EAGLE ROCK ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS (continued)
FOR THE YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
See accompanying notes to consolidated financial statements.
F- 6
EAGLE ROCK ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
(in thousands, except unit amounts)
See accompanying notes to consolidated financial statements.
F- 7
EAGLE ROCK ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2012, 2011, AND 2010
($ in thousands)
See accompanying notes to consolidated financial statements.
F- 8
EAGLE ROCK ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2012, 2011 AND 2010
NOTE 1. ORGANIZATION AND DESCRIPTION OF BUSINESS
Description of Business-Eagle Rock Energy Partners, L.P. ("Eagle Rock Energy" or the "Partnership") is a growth-oriented limited partnership engaged in (i) the business of gathering, compressing, treating, processing, transporting, marketing and trading natural gas; fractionating, transporting and marketing natural gas liquids ("NGLs"); and crude oil and condensate logistics and marketing (the “Midstream Business”); and (ii) the business of developing and producing interests in oil and natural gas properties (the “Upstream Business”). The Partnership's midstream assets are strategically located in four productive, mature natural gas producing regions; the Texas Panhandle, East Texas/Louisiana, South Texas and the Gulf of Mexico, and its natural gas pipelines gather natural gas from designated points near producing wells and transport these volumes to third-party pipelines, the Partnership's gas processing plants, utilities and industrial consumers. Natural gas transported to the Partnership's gas processing plants, either in the Partnership's pipelines or third party pipelines, is treated to remove contaminants and conditioned or processed into marketable natural gas and NGLs. The Partnership reports its Midstream Business results through three segments: the Texas Panhandle Segment, the East Texas and Other Midstream Segment and the Marketing and Trading Segment. The Partnership's upstream assets are characterized by long-lived, high-working interest properties with extensive production histories and development opportunities. Its upstream assets are located primarily in South Alabama (where it also operates the associated gathering and processing assets), Texas, Oklahoma and Arkansas. The Partnership reports its Upstream Business through one segment.
The general partner of Eagle Rock Energy is Eagle Rock Energy GP, L.P, and the general partner of Eagle Rock Energy GP, L.P. is Eagle Rock Energy G&P, LLC, both of which became wholly-owned subsidiaries of the Partnership on July 30, 2010, as further discussed in Notes 9 and 10. The transaction with Eagle Rock Energy GP, L.P. was accounted for by the Partnership as a recapitalization. The acquisition of Eagle Rock Energy G&P, LLC was accounted for as an acquisition of entities under common control, which requires the Partnership to present its financial statements as if the two entities had always been combined, similar to the pooling of interests method.
NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation and Principles of Consolidation-The accompanying audited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). Eagle Rock Energy is the owner of non-operating undivided interests in certain gas processing plants and gas gathering systems. Eagle Rock Energy owns these interests as tenants-in-common with the majority owner-operator of the facilities. Accordingly, Eagle Rock Energy includes its pro-rata share of assets, liabilities, revenues and expenses related to these assets in its financial statements. All intercompany accounts and transactions are eliminated in the consolidated financial statements.
Use of Estimates-The preparation of 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 financial statements and the reported amounts of revenues and expenses during the reported period. Significant estimates are required for proved oil and natural gas reserves, which can affect the carrying value of oil and natural gas properties. The Partnership evaluates its estimates and assumptions on a regular basis. The Partnership bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from those estimates and such differences could be material.
Cash and Cash Equivalents-Cash and cash equivalents include certificates of deposit and other highly liquid investments with maturities of three months or less at the time of purchase.
Concentration and Credit Risk-Concentration and credit risk for the Partnership principally consists of cash and cash equivalents and accounts receivable.
The Partnership places its cash and cash equivalents with high-quality institutions and in money market funds. The Partnership derives its revenue from customers primarily in the natural gas industry. Industry concentrations have the potential to impact the Partnership's overall exposure to credit risk, either positively or negatively, in that the Partnership's customers could be affected by similar changes in economic, industry or other conditions. However, the Partnership believes the risk posed by this industry concentration is offset by the creditworthiness of the Partnership's customer base. The Partnership's portfolio of accounts receivable is comprised primarily of mid-size to large domestic corporate entities.
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The following is the activity within the Partnership's allowance for doubtful accounts during the years ended December 31, 2012, 2011 and 2010.
During the year ended December 31, 2011, the write off charged to the allowance related to the payment the Partnership received related to the sale of its 503(b)(9) claims related to SemGroup, L.P. ("SemGroup"). This amount relates to the non-503(b)(9) claims and the portion of the receivables sold in August 2009 (see Note 20 for further discussion).
Certain Other Concentrations-The Partnership relies on natural gas producers for its Midstream Business's natural gas and natural gas liquid supply, with the top two producers (by segment) accounting for 33% of its natural gas supply in the Texas Panhandle Segment and 27% of its natural gas supply in the East Texas and Other Midstream Segment for the year ended December 31, 2012. While there are numerous natural gas and natural gas liquid producers, and some of these producers are subject to long-term contracts, the Partnership may be unable to negotiate extensions or replacements of these contracts on favorable terms, if at all. If the Partnership were to lose all or even a portion of the natural gas volumes supplied by these producers and was unable to acquire comparable volumes, the Partnership's results of operations and financial position could be materially adversely affected. These percentages are calculated based on natural gas volumes gathered during the year ended December 31, 2012. For the year ended December 31, 2012, ONEOK, Inc. and Chevron Corporation, the Partnership's largest customers, represented 20% and 13%, respectively, of its total sales revenue (including realized and unrealized gains on commodity derivatives).
Inventory-Inventory is stated at the lower of cost or market, with cost being determined using the average cost method. At December 31, 2012 and December 31, 2011, the Partnership had $0.8 million and $1.4 million, respectively, of crude oil finished goods inventory which is recorded as part of Other Current Assets within the audited consolidated balance sheet.
Property, Plant and Equipment-Property, plant and equipment consists primarily of gas gathering systems, gas processing plants, NGL pipelines, conditioning and treating facilities and other related facilities, and oil and natural gas properties, which are carried at cost less accumulated depreciation, depletion and amortization. The Partnership charges repairs and maintenance against income when incurred and capitalizes renewals and betterments, which extend the useful life or expand the capacity of the assets. The Partnership capitalizes interest costs on major projects during extended construction time periods. Such interest costs are allocated to property, plant and equipment and amortized over the estimated useful lives of the related assets. The Partnership calculates depreciation on the straight-line method over estimated useful lives of the Partnership's newly developed or acquired assets. The weighted average useful lives are as follows:
Oil and Natural Gas Properties-The Partnership utilizes the successful efforts method of accounting for its oil and natural gas properties. Leasehold costs are capitalized when incurred. Costs incurred to drill and complete development wells are capitalized. Geological and geophysical expenses and delay rentals are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if the well is determined to be unsuccessful. The Partnership carries the costs of an exploratory well as an asset if the well is found to have a sufficient quantity of reserves to justify its capitalization as a producing well as long as the Partnership is making sufficient progress towards assessing the reserves and the economic and operating viability of the project.
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Depletion of producing oil and natural gas properties is recorded based on units of production. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for acquisition costs using all proved reserves. Authoritative guidance requires that acquisition costs of proved properties be amortized on the basis of all proved reserves (developed and undeveloped), and that capitalized development costs (wells and related equipment and facilities) be amortized on the basis of proved developed reserves.
Upon sale or retirement of complete fields of depreciable or depleted property, the book value thereof, less proceeds or salvage value, is charged or credited to income.
Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience, drilling plans and average lease-term lives. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a units of production basis. Unproved properties (both individually significant and insignificant) are assessed periodically within specific geographic areas and, if necessary, impairments are charged to expense.
Other Assets- As of December 31, 2012, other assets primarily consist of costs associated with debt issuance costs, net of amortization, of $19.5 million; business deposits to various providers and state or regulatory agencies of $2.2 million; and investment in unconsolidated affiliates of $0.9 million. As of December 31, 2011, other assets primarily consist of costs associated with debt issuance costs, net of amortization, of $15.1 million; business deposits to various providers and state or regulatory agencies of $4.9 million; and investment in unconsolidated affiliates of $1.0 million.
Impairment of Long-Lived Assets-Management evaluates whether the carrying value of non-oil and natural gas long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the assets. Management considers various factors when determining if these assets should be evaluated for impairment, including, but not limited to:
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significant adverse changes in legal factors or in the business climate;
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a current-period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast which demonstrates continuing losses associated with the use of a long-lived asset;
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an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;
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significant adverse changes in the extent or manner in which an asset is used or in its physical condition;
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a significant change in the market value of an asset; or
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a current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.
For its oil and natural gas long-lived assets, the Partnership reviews its proved properties at the field level when management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a negative revision or unfavorable projection of future oil and natural gas reserves and/or forward prices that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, and future inflation levels.
If the carrying value is not recoverable on an undiscounted basis, the impairment loss is measured as the excess of the asset's carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management's intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets.
See Note 5 for further discussion on impairment charges.
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Revenue Recognition-Eagle Rock Energy's primary types of sales and service activities reported as operating revenue include:
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sales of natural gas, NGLs, crude oil, condensate and sulfur;
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natural gas gathering, processing and transportation, from which Eagle Rock Energy generates revenues primarily through the compression, gathering, treating, processing and transportation of natural gas; and
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NGL transportation from which the Partnership generates revenues from transportation fees.
Revenues associated with sales of natural gas, NGLs, crude oil, condensate and sulfur are recognized when title passes to the customer, which is when the risk of ownership passes to the customer and physical delivery occurs. Revenues associated with transportation and processing fees are recognized in the period when the services are provided.
For gathering and processing services, the Partnership either receives fees or commodities from natural gas producers under various types of contracts including percentage-of-proceeds, fixed recovery and percent-of-index arrangements. The Partnership also recognizes fee-based service revenues for services such as transportation, compression and processing.
The Partnership's Upstream Segment recognizes natural gas revenues based on the amount of natural gas sold to purchasers. The volumes of natural gas sold may differ from the volumes to which the Partnership is entitled based on its interests in the properties. Differences between volumes sold and volumes based on entitlements create natural gas imbalances. Imbalances are reflected as adjustments to reported natural gas reserves and future cash flows. For the Upstream Segment, as of December 31, 2012, the Partnership had long-term imbalance payables of $0.6 million. For the Upstream Segment, as of December 31, 2011, the Partnership had imbalance receivables of $0.3 million, and it had a long-term payables balance $1.6 million.
Transportation and Exchange Imbalances-In the course of transporting natural gas and NGLs for others, the Partnership may receive for redelivery different quantities of natural gas or NGLs than the quantities actually delivered. These transactions result in transportation and exchange imbalance receivables or payables which are recovered or repaid through the receipt or delivery of natural gas or NGLs in future periods, if not subject to cash out provisions. Imbalance receivables are included in accounts receivable and imbalance payables are included in accounts payable on the consolidated balance sheets and marked-to-market using current market prices in effect for the reporting period of the outstanding imbalances. For the Midstream Business, as of December 31, 2012, the Partnership had imbalance receivables totaling $0.2 million and imbalance payables totaling $2.1 million. For the Midstream Business, as of December 31, 2011, the Partnership had imbalance receivables totaling $0.6 million and imbalance payables totaling $0.5 million. Changes in market value and the settlement of any such imbalance at a price greater than or less than the recorded imbalance results in either an upward or downward adjustment, as appropriate, to the cost of natural gas sold.
Environmental Expenditures-Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures which relate to an existing condition caused by past operations and do not generate current or future revenue are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated.
Income Taxes-Provision for income taxes is primarily applicable to the Partnership's state tax obligations under the Revised Texas Franchise Tax (the “Revised Texas Franchise Tax”) and certain federal and state tax obligations of Eagle Rock Energy Acquisition Co., Inc., Eagle Rock Acquisition Co. II, Inc., Eagle Rock Upstream Development Company, Inc. and Eagle Rock Upstream Development Company II, Inc., all of which are consolidated subsidiaries. Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities of the tax paying entities for financial reporting and tax purposes.
In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax. In May 2006, the State of Texas expanded its pre-existing franchise tax to include limited partnerships, limited liability companies, corporations and limited liability partnerships. As a result of the change in tax law, the Partnership's tax status in the State of Texas changed from non-taxable to taxable effective with the 2007 tax year.
Since the Partnership is structured as a pass-through entity, it is not subject to federal income taxes. As a result, its partners are individually responsible for paying federal and certain income taxes on their share of the Partnership's taxable
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income. Since the Partnership does not have access to information regarding each partner's tax basis, it cannot readily determine the total difference in the basis of the Partnership's net assets for financial and tax reporting purposes.
Derivatives-Authoritative guidance establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It requires an entity to recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The guidance provides that normal purchase and sale contracts, when appropriately designated, are not subject to the guidance. Normal purchases and sales are contracts which provide for the purchase or sale of something, other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business. The Partnership's forward natural gas and crude oil purchase and sales contracts are designated as normal purchases and normal sales, with the exception of certain contracts with our natural gas trading and marketing business. The Partnership uses financial instruments such as swaps, collars and other derivatives to mitigate the risks to cash flows resulting from changes in commodity prices and interest rates. The Partnership recognizes these financial instruments on its consolidated balance sheet at the instrument's fair value with changes in fair value reflected in the consolidated statement of operations, as the Partnership has not designated any of these derivative instruments as hedges. The cash flows from derivatives are reported as cash flows from operating activities unless the derivative contract is deemed to contain a financing element. Derivatives deemed to contain a financing element are reported as a financing activity in the statement of cash flows. See Note 11 for a description of the Partnership's risk management activities.
Other Reclassifications-Certain prior period financial statement balances have been reclassified to conform to the current year presentation. These reclassifications had no material effect on the recorded net income and are not significant.
NOTE 3. NEW ACCOUNTING PRONOUNCEMENTS
In December 2011, the FASB issued new guidance related to disclosure requirements about the nature of an entity's rights of set-off and related arrangements associated with its financial instruments and derivative instruments. The new disclosures are designed to make financial statements that are prepared under U.S. GAAP more comparable to those prepared under IFRS. To better facilitate comparison between financial statements prepared under U.S. GAAP and IFRS, the new disclosures will give financial statement users information about both gross and net exposures. The disclosure requirements are effective for annual reporting periods beginning on or after January 1, 2013, and interim periods therein, with retrospective application required. The Partnership is currently evaluating the impact, if any, of the adoption of this guidance on its consolidated financial statements and related disclosures.
NOTE 4. ACQUISITIONS
Acquisition of Midstream Assets in the Texas Panhandle
On October 1, 2012, the Partnership completed the acquisition of two of BP America Production Company's ("BP") gas processing facilities, and the associated gathering systems, that are located in the Texas Panhandle (the "newly-acquired Panhandle System"). The aggregate purchase price of the newly-acquired Panhandle System was $230.6 million, which the Partnership funded from borrowings under its revolving credit facility. The results of the operations of the newly-acquired Panhandle System have been included in the consolidated financial statements since the acquisition date. The Partnership incurred $0.5 million of acquisition related expenses, which are included within general and administrative expenses for the year ended December 31, 2012.
This acquisition was accounted for under the acquisition method of accounting. Accordingly, the Partnership conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisitions were expensed as incurred. The initial accounting for the business combinations is not complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates.
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The following presents the preliminary purchase price allocation for the newly-acquired Panhandle System assets, based on preliminary estimates of fair value (in thousands):
The fair value measurements of assets acquired and liabilites assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value of oil and natural gas properties and asset retirement obligation were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of property, plant and equipment include estimates of: (i) replacement costs; (ii) useful and remaining lives; (iii) physical deterioration; and (iv) functional and technical obsolescence. These inputs require significant judgments and estimates by the Partnership's management at the time of the valuation and are the most sensitive and subject to change.
Pro forma data for the years ended December 31, 2012 and 2011 has been deemed to be impracticable as BP did not separately manage its gathering and processing facilities with the activities of the acquired assets being integrated (financially and operationally) within its exploration and production segment. The amounts of newly-acquired Panhandle System's revenue and net income included within the Partnership's audited consolidated statement of operations for the year ended December 31, 2012 are as follows.
Acquisition of CC Energy II L.L.C.
On May 3, 2011, the Partnership completed the acquisition (the "Mid-Continent Acquisition") of all of the outstanding membership interests of CC Energy II L.L.C (together with its subsidiaries, "Crow Creek Energy"), a portfolio company of Natural Gas Partners, VIII, L.P. ("NGP VIII"). Crow Creek Energy has oil and natural gas properties located in multiple basins across Oklahoma, north Texas and Arkansas (the "Mid-Continent" properties) and provides the Partnership with an extensive inventory of low-risk development prospects in established plays such as the Golden Trend field and developing plays such as the Cana Shale. The aggregate purchase price has been calculated as follows (in thousands, except unit and per unit amounts):
The number of common units of the Partnership issued was determined based on the value of the equity issued to the sellers of $301.9 million divided by $10.50, the ceiling price of the agreed upon range in the contribution agreement between the Partnership and Crow Creek Energy. The cash portion of the acquisition consideration and the repayment of Crow Creek Energy’s outstanding debt were funded through borrowings under the Partnership’s revolving credit facility. In addition, the Partnership incurred $2.3 million of acquisition related expenses, which are included within general and administrative expenses for the year ended December 31, 2011.
This acquisition was accounted for under the acquisition method of accounting. Accordingly, the Partnership conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at
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their estimated acquisition date fair values, while transaction and integration costs associated with the acquisitions were expensed as incurred.
The following presents the purchase price allocation for the Crow Creek Energy assets, based on estimates of fair value (in thousands):
The fair value measurements of assets acquired and liabilites assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value of oil and natural gas properties and asset retirement obligation were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimate of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; (iv) estimated future cash flows; and (v) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Partnership's management at the time of the valuation and are the most sensitive and subject to change.
The amounts of Crow Creek Energy's revenue and net income included within the Partnership's audited consolidated statement of operations for the year ended December 31, 2011, and the pro forma revenue and net income of the combined entity had the acquisition date been January 1, 2010, are as follows:
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NOTE 5. PROPERTY PLANT AND EQUIPMENT
Fixed assets consisted of the following:
The following table sets forth the total depreciation, depletion, capitalized interest costs and impairment expense by type of asset within the Partnership's audited consolidated statements of operations:
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(a)
During the year ended December 31, 2012, the Partnership incurred impairment charges in its Upstream Business related to its proved properties in the Barnett Shale, East Texas and Permian regions that experienced reduced cash flows resulting from lower natural gas prices and continuing high operating costs associated with gas compression. During the year ended December 31, 2011, the Partnership incurred impairment charges in its Upstream Business related to certain proved properties in the Jourdanton Field in South Texas, which included plans for five future drilling locations that the Partnership has determined not to pursue due to the current natural gas price environment.
(b)
During the year ended December 31, 2012, the Partnership incurred impairment charges in its Upstream Business related to certain unproved property leaseholds expected to expire undrilled in 2013. During the year ended December 31, 2011, the Partnership incurred impairment charges related to certain drilling locations in its unproved properties which the Partnership no longer intends to develop based on the performance of offsetting wells. During the year ended December 31, 2010, the Partnership incurred impairment charges related to unproved properties related to certain fields in its unproved properties which we determined are not technologically feasible to develop.
(c)
During the year ended December 31, 2012, the Partnership incurred impairment charges in its Midstream Business related to certain plants and pipelines in its East Texas and Other Midstream Segment due to (i) reduced throughput volumes as its producer customers curtailed their drilling activity in response to the continued depressed natural gas price environment (ii) the loss of significant gathering contracts on its Panola and other systems and (iii) the substantial damage incurred at the Yscloskey processing plant as a result of Hurricane Isaac in August 2012. The value of assets for both the Panola system and the Yscloskey plant have been fully written down. During the year ended December 31, 2011, the Partnership recorded an impairment charge in its Texas Panhandle Segment to fully write-down its idle Turkey Creek plant. In 2010, the Partnership recorded
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impairment charges related to its Midstream Business due to the notification during the second quarter 2010 that a significant gathering contract in the South Texas region within its East Texas and Other Midstream Segment was terminated.
NOTE 6. ASSET RETIREMENT OBLIGATIONS
The Partnership recognizes asset retirement obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. The Partnership records the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. For its producing oil and natural gas properties, the Partnership makes estimates of property abandonment costs that, in some cases, will not be incurred until a substantial number of years in the future. Such cost estimates could be subject to significant revisions in subsequent years due to changes in regulatory requirements, technological advances and other factors that may be difficult to predict. The Partnership recognizes asset retirement obligations for its midstream assets in accordance with the term “conditional asset retirement obligation,” which refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional upon a future event that may or may not be within the Partnership's control. Although uncertainty about the timing and/or method of settlement may exist and may be conditional upon a future event, the obligation to perform the asset retirement activity is unconditional. Accordingly, the Partnership is required to recognize a liability for the fair value of a conditional asset retirement obligation upon initial recognition if the fair value of the liability can be reasonably estimated. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that covert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of (i) remediation costs, (ii) remaining lives, (iii) future inflation factors and (iv) a credit-adjusted risk free interest rate.
A reconciliation of the Partnership's liability for asset retirement obligations is as follows:
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(a) As of December 31, 2012, $3.9 million were included within accrued liabilities in the Consolidated Balance Sheets.
NOTE 7. INTANGIBLE ASSETS
Intangible assets consist of rights-of-way and easements and acquired customer contracts, which the Partnership amortizes over the term of the agreement or estimated useful life. The amortization period for the Partnership's rights-of-way and easements is 20 years. The amortization period for contracts ranges from 5 to 20 years. Intangible assets consisted of the following:
The following table sets forth the total amortization and impairment expense by type of intangible assets within the Partnership's audited consolidated statements of operations:
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(a)
During the year ended December 31, 2012, the Partnership incurred impairment charges in its Midstream Business related to certain rights-of-way and contracts in its East Texas and Other Midstream Segment due to (i) reduced throughput volumes as its producer customers curtailed their drilling activities due to the continued decline in natural gas prices during the first three months of 2012 and (ii) the termination of significant gathering contracts on its Panola system during the year ended December 31, 2012. The value of the contracts and rights-of-way related to the Panola system have been fully written down.
(b)
During the year ended December 31, 2010, the Partnership incurred impairment charges due to the notification during the second quarter 2010 that a significant gathering contract in the South Texas region within its East Texas and Other Midstream Segment was terminated.
Estimated future amortization expense related to the intangible assets at December 31, 2012, is as follows (in thousands):
NOTE 8. LONG-TERM DEBT
Long-term debt consisted of the following:
Revolving Credit Facility
On June 22, 2011, the Partnership entered into an Amended and Restated Credit Agreement, as amended on December 28, 2012 (the “Credit Agreement”) with Wells Fargo Bank, National Association, as administrative and documentation agent and swingline lender, Bank of America, N.A. and The Royal Bank of Scotland plc, as co-syndication agents, and the other lenders who are parties to the Credit Agreement. The Credit Agreement amended and restated the Partnership’s prior $880 million Credit Agreement (the “Prior Credit Agreement”). Upon the effectiveness of the Credit Agreement, all commitments of the lenders party to the Prior Credit Agreement were terminated and all loans and other indebtedness of the Partnership under the Prior Credit Agreement were renewed and extended, inclusive of new lender commitments, on the terms and conditions of the Credit Agreement. The Credit Agreement matures on June 22, 2016.
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The initial borrowings under the Credit Agreement were used to repay in full the borrowings under the Prior Credit Agreement and to pay fees and expenses incurred in connection with the Credit Agreement. Also, in connection with the Credit Agreement, the Partnership incurred debt issuance costs of $9.8 million and recorded a charge of $0.4 million to write off a portion of the unamortized debt issuance costs related to the Prior Credit Agreement. As of December 31, 2012, the Partnership had unamortized debt issuance costs of $7.4 million.
On December 28, 2012, the Partnership received increased commitments from its lending group under the Credit Agreement. Aggregate commitments increased from $675 million to $820 million. The Partnership has the option to request further increases in commitments, subject to the terms and conditions of the Credit Agreement, up to an aggregate total amount of $1.2 billion. Availability under the credit facility is subject to a borrowing base comprised of two components: the upstream component and the midstream component. The upstream component of the borrowing base is determined semi-annually as an amount equal to the loan value of the proved oil and gas reserves of the Partnership and its subsidiaries as determined by the lenders party to the Credit Agreement. The midstream component of the borrowing base is determined quarterly as an amount equal to the lesser of (i) 55% of the total borrowing base (subject to increase for certain periods following certain material acquisitions up to 60% of the total borrowing base) and (ii) 3.75 times Consolidated EBITDA (as defined in the Credit Agreement) attributable to the midstream assets of the Partnership and its subsidiaries for the trailing four fiscal quarters. Pro forma adjustments to each component of the borrowing base, and thus total availability under the credit facility, are made upon the occurrence of certain events including material acquisitions and dispositions. Availability under the Credit Agreement is based on the lower of the current borrowing base and the total commitments. As of December 31, 2012, the Partnership had approximately $192.5 million of availability under the credit facility. The Partnership currently pays a 0.45% commitment fee (based on the Partnership's borrowing base utilization percentage) per year on the difference between total commitments and the amount drawn under the credit facility.
Concurrent with the increase in commitments on December 28, 2012, the Partnership and its lending group agreed to amend the Credit Agreement to: (i) allow for a temporary step-up in the Total Leverage Ratio from 4.50x to 4.75x through the third quarter of 2013; (ii) institute a new Senior Secured Leverage Ratio of 2.85x through the third quarter of 2013; and (iii) increase the amount of permitted "other Investments" as defined in the Credit Agreement.
The Credit Agreement includes a sub-limit for the issuance of standby letters of credit for a total of $150.0 million. As of December 31, 2012, the Partnership had $19.1 million of outstanding letters of credit.
At the Partnership's election, interest will accrue on the credit facility at either LIBOR plus a margin ranging from 1.75% to 2.75% (currently 2.25% per annum based on the Partnership's borrowing base utilization percentage) or the base rate plus a margin ranging from 0.75% to 1.75% (currently 1.25% per annum based on the Partnership's borrowing base utilization percentage). The applicable margin is determined based on the utilization of the then existing borrowing base. The borrowings under the Credit Agreement may be prepaid, without any premium or penalty, at any time. The base rate is generally the highest of the federal funds rate plus 0.5%, the prime rate as announced from time to time by the Administrative Agent, or daily LIBOR for a term of one month plus 1.0%. As of December 31, 2012, the weighted average interest rate (excluding the impact of interest rate swaps) on the Partnership's outstanding debt under its revolving credit facility was 2.47%.
The obligations under the Credit Agreement are secured by first priority liens on substantially all of the Partnership’s (and its material subsidiaries') material assets, including a pledge of all of the equity interests of each of the Partnership’s material subsidiaries.
The Credit Agreement requires the Partnership and certain of its subsidiaries to make certain representations and warranties that are customary for credit facilities of this type. The Credit Agreement also contains affirmative and negative covenants that are customary for credit facilities of this type, including compliance with financial covenants. The financial covenants prohibit the Partnership from:
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Permitting, as of any fiscal quarter-end, the ratio of Consolidated EBITDA (as defined in the Credit Agreement) for the four fiscal quarter period ending with such fiscal quarter to Consolidated Interest Expense (as defined in the Credit Agreement) for such four fiscal quarter period (the "Interest Coverage Ratio") to be no less than 2.50 to 1.00. The Interest Coverage Ratio was 4.0 to 1.0 as of December 31, 2012;
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Permitting, as of any fiscal quarter-end, the ratio of Total Funded Indebtedness (as defined in the Credit Agreement) to Consolidated EBITDA for the four fiscal quarter period ending with such fiscal quarter (the “Total Leverage Ratio”) to be no greater than (i) 4.75 to 1.00 for the fiscal quarters ending December 31, 2012, March 31, 2013, June 30, 2013, or
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September 30, 2013 and (ii) 4.50 to 1.00 for any fiscal quarter ending on any other date. The Total Leverage Ratio was 4.4 to 1.00 as of December 31, 2012;
•
Permitting, as of the fiscal quarter-end for the fiscal quarters ending December 31, 2012, March 31, 2013, June 30, 2013, and September 30, 2013, the ratio of Senior Secured Debt (as defined in the Credit Agreement) to Consolidated EBITDA for the four fiscal quarter period ending with such fiscal quarter (the “Senior Secured Leverage Ratio”) to be no greater than 2.85 to 1.00. The Senior Secured Leverage Ratio was 2.3 to 1.00 as of December 31, 2012; and
•
Permitting the ratio of the Partnership’s consolidated current assets (including availability under the Credit Agreement up to the Loan Limit (as defined within the Credit Agreement), but excluding non-cash assets under the accounting guidance for derivatives) to consolidated current liabilities (excluding non-cash obligations under the accounting guidance for derivatives and current maturities under the Credit Agreement) (the “Current Ratio”) to be no less than 1.00 to 1.00. The Current Ratio was 2.0 to 1.0 as of December 31, 2012.
As of December 31, 2012, the Partnership was in compliance with the financial covenants under the Credit Agreement.
Senior Notes
On May 27, 2011, the Partnership, along with its subsidiary, Eagle Rock Energy Finance Corp. ("Finance Corp"), as co-issuer and certain subsidiary guarantors, issued $300.0 million of senior unsecured notes (the "Senior Notes"), that bear a coupon of 8.375%, through a private placement. The Senior Notes will mature on June 1, 2019, and interest is payable on each June 1 and December 1, commencing December 1, 2011. After the original discount of $2.2 million and excluding related offering expenses, the Partnership received net proceeds of approximately $297.8 million, which were used to repay borrowings outstanding under the Prior Credit Agreement.
On July 13, 2012, the Partnership, along with its subsidiary, Finance Corp, as co-issuer and certain subsidiary guarantors, completed the sale of an additional $250.0 million of 8.375% senior unsecured notes due 2019 through a private placement exempt from the registration requirements of the Securities Act of 1933. After the original issue discount of $3.7 million and excluding related offering expenses, the Partnership received net proceeds of approximately $246.3 million, which were used to repay borrowings outstanding under its revolving credit facility. This issuance supplemented the Partnership's prior $300.0 million of Senior Notes issued in May 2011, all of which are treated as a single series. As of December 31, 2012, the Partnership had unamortized debt issuance costs of $12.0 million and an unamortized debt discount of $5.4 million, which is recorded as an offset to the principal amount of the Senior Notes.
The Senior Notes are general unsecured senior obligations and rank equally in right of payment with all of the Partnership's existing and future senior indebtedness and rank senior in right of payment to any of the Partnership's future subordinated indebtedness. The Senior Notes are effectively junior in right of payment to all of the Partnership's existing and future secured indebtedness and other obligations, including borrowings outstanding under the Partnership's Credit Agreement, to the extent of the value of the assets securing such indebtedness and other obligations. The Senior Notes are jointly and severally guaranteed on a senior unsecured basis by the Partnership's existing and future subsidiaries, who are referred to as the "subsidiary guarantors," that guarantee the Partnership's credit facility or other indebtedness.
The indenture governing the Senior Notes, among other things, restricts the Partnership's ability and the ability of the Partnership's restricted subsidiaries to: (i) incur, assume or guarantee additional indebtedness or issue redeemable stock; (ii) pay dividends on stock, repurchase stock or redeem subordinated debt; (iii) make certain investments; (iv) enter into certain transactions with affiliates; (v) create liens on their assets; (vi) sell or otherwise dispose of certain assets, including capital stock of subsidiaries; (vii) restrict dividends, loans or other asset transfers from the Partnership's restricted subsidiaries; (viii) enter into new lines of business; and (ix) consolidate with or merge with or into, or sell all or substantially all of their properties (taken as a whole) to another person.
The Partnership has the option to redeem all or a portion of the Senior Notes at any time on or after June 1, 2015 at the redemption prices specified in the indenture plus accrued and unpaid interest. The Partnership may also redeem the Senior Notes, in whole or in part, at a "make-whole" redemption price specified in the indenture, plus accrued and unpaid interest, at any time prior to June 1, 2015. In addition, the Partnership may redeem up to 35% of the Senior Notes prior to June 1, 2014
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under certain circumstances with the net cash proceeds from certain equity offerings at 108.375% of the principal amount of the notes redeemed.
Scheduled maturities of long-term debt as of December 31, 2012, were as follows:
NOTE 9. MEMBERS’ EQUITY
At December 31, 2012, there were 144,675,751 common units outstanding. In addition, there were 2,608,035 unvested restricted common units outstanding.
As a result of the approval of certain of the Recapitalization and Related Transactions, as further discussed in Note 10, on May 24, 2010, the Partnership's general partner and Eagle Rock Holdings, L.P. ("Holdings") contributed to the Partnership all 20,691,495 of the outstanding subordinated units and all of the outstanding incentive distribution rights in the Partnership. In connection with the contribution of the subordinated units and incentive distribution rights, the Partnership (i) issued 4,825,211 common units to Holdings as payment of the transaction fee contemplated by the Recapitalization and Relation Transactions and (ii) adopted and entered into a Second Amended and Restated Agreement of Limited Partnership.
Pursuant to the Partnership's Second Amended and Restated Agreement of Limited Partnership, among other things: (i) the subordinated units and incentive distribution rights were cancelled; (ii) the concepts of a subordination period and a minimum quarterly distribution (and, as a result, the concept of arrearages on the common units) were eliminated; and (iii) provisions were included that provide the Partnership an option to acquire its general partner and its general partner entities, which were acquired on July 30, 2010, as further discussed below.
On June 1, 2010, the Partnership launched its rights offering to the holders of its common and general partner units as of close of business on May 27, 2010, the record date. Each Right entitled the holder (including holders of Rights acquired during the subscription period) to purchase (i) one common unit and (ii) one warrant to purchase one additional common unit at $6.00 on certain specified days beginning on August 15, 2010 and ending on May 15, 2012. The rights offering expired on June 30, 2010, and the Partnership issued 21,557,164 common units and 21,557,164 warrants on or about July 8, 2010 for gross proceeds of $53.9 million. During the years ended December 31, 2012, 2011 and 2010, 5,300,588, 14,957,540 and 891,919 warrants, respectively, were exercised for an equivalent number of newly issued common units. The final exercise date for the warrants was May 15, 2012, and on that date the remaining unexercised warrants expired. As of December 31, 2011, 5,707,705 warrants were outstanding.
On July 27, 2010, the Partnership gave notice to Holdings of its intention to exercise the GP Acquisition Option (as defined in Note 10). The transaction closed on July 30, 2010, and the Partnership issued 1,000,000 common units to Holdings to acquire the Partnership's general partner entities. As a result, the Partnership's 844,551 outstanding general partner units were cancelled. In connection with the completion of the GP Acquisition Option, the Partnership's board of directors (the "Board") was expanded to include two additional independent directors who were appointed by the Conflicts Committee on July 30, 2010.
On May 31, 2012, the Partnership announced a program through which it may issue common units, from time to time, with an aggregate market value of up to $100 million. The Partnership is under no obligation to issue equity under the program. As of December 31, 2012, 834,327 units had been issued under this program for net proceeds of approximately $7.3 million.
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On August 17, 2012, the Partnership closed an underwritten public offering of 10,120,000 common units, which included the full exercise of the underwriters' option to purchase additional common units to cover over-allotments, for net proceeds of approximately $84.3 million.
The Partnership has declared a cash distribution for each quarter since its initial public offering. The table below summarizes these distributions for the last three years.
_____________________________
+
The distribution per unit represents distributions made only on common units, including restricted common units issued under our Long Term Incentive Plan. Since July 30, 2010, the only other class of equity we have outstanding is a non-economic general partner interest.
*
The distribution per unit represents distributions made only on common units (including restricted common units issued under our Long Term Incentive Plan) and general partner units.
**
The "Record Date" set forth in the table above means the close of business on each of the listed Record Dates.
NOTE 10. RELATED PARTY TRANSACTIONS
The following table summarizes transactions between the Partnership and affiliated entities:
In connection with the closing of the acquisition of certain fee minerals, royalties, overriding royalties and non-operated working interest properties from Montierra Minerals & Production, L.P. ("Montierra") and NGP-VII Co-Investment Opportunities, L.P. ("Co-Invest") on April 30, 2007, the Partnership entered into registration rights agreements with Montierra and Co-Invest. In the registration rights agreements, the Partnership agreed, for the benefit of Montierra and Co-Invest, to register the common units it holds, the common units issuable upon conversion of the subordinated units that it holds and any common units or other equity securities issuable in exchange for the common units and subordinated units it holds. The registration rights agreement is still in effect and the Partnership is in compliance with all obligations of the agreement.
On May 3, 2011, the Partnership completed the Mid-Continent Acquisition. Due to Crow Creek Energy being a portfolio company of NGP VIII and NGP's ownership interest in the Partnership and Board of Directors representation, the Board of Directors of the general partner of the Partnership's general partner, authorized its Conflicts Committee to review, evaluate, and, if determined appropriate, approve the Mid-Continent Acquisition, due to the potential conflict of interest among the Partnership, the NGP and the Partnership's public unitholders. The Conflicts Committee, consisting of independent directors of the Partnership, determined that the Mid-Continent Acquisition was fair and reasonable to the Partnership and its
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public unitholders and recommended to the Board of Directors that the transaction be approved and authorized. In determining the consideration for the acquisition of Crow Creek Energy, the Conflicts Committee, with the assistance of a third-party, considered the valuation of the properties involved in the transaction, the valuation of the units to be offered as consideration in the transaction and the cash flows of Crow Creek Energy.
In connection with the closing of the Mid-Continent Acquisition, the Partnership entered into a registration rights agreement ("Registration Rights Agreement") with NGP VIII. The Registration Rights Agreement grants NGP VIII and certain of its affiliates registration rights with respect to the common units acquired pursuant to the Partnership's acquisition of Crow Creek Energy and their outstanding warrants to purchase common units that were previously acquired by NGP VIII and certain of its affiliates in connection with the Partnership's previously completed recapitalization transaction. Pursuant to the Registration Rights Agreement, NGP VIII and certain of its affiliates have the ability to demand that the Partnership register for resale their common units acquired pursuant to the acquisition of Crow Creek Energy and their existing warrants to purchase common units. This registration may be an underwritten offering at the discretion of NGP VIII and certain of its affiliates. NGP VIII and certain of its affiliates may demand up to four such registrations, subject to an increase to up to seven if the registration rights are amended. Additionally, the Registration Rights Agreement provides that NGP VIII and certain of its affiliates have piggyback registration rights in certain circumstances, which would require inclusion of their common units and warrants on registration statements that the Partnership files, subject to certain customer exceptions. There are no limits on the number of times NGP VIII and certain of its affiliates can exercise these piggyback registration rights.
Recapitalization and Related Transactions
In 2010, the Partnership completed a series of transactions (the "Recapitalization and Related Transactions") which simplified its capital structure and provided the Partnership with added financial liquidity. This series of transactions included:
•
the contribution, and resulting cancellation, of the Partnership's incentive distribution rights and subordinated units held by Holdings, which occurred on May 24, 2010 (see Note 9);
•
the sale of all of the Partnership's fee mineral and royalty interests, as well as the Partnership's equity investment in Ivory Working Interests, L.P., (collectively "the Minerals Business") to Black Stone Minerals Company, L.P. The sale was completed on May 24, 2010 (See Note 19);
•
a rights offering, which was launched on June 1, 2010 and expired on June 30, 2010 (See Note 9);
•
an option to capture the value of the controlling interest in the Partnership through (a) acquiring the Partnership's general partner entities from Holdings and immediately thereafter eliminating the Partnership's outstanding general partner units owned by Holdings and (b) reconstituting the Board to allow the Partnership's common unitholders not affiliated with NGP to elect the majority of our directors (the "GP Acquisition Option"). On July 30, 2010, the Partnership completed the GP Acquisition Option, and the Board was expanded to include two additional independent directors who were appointed by the conflicts committee on July 30, 2010 (See Note 9).
NOTE 11. RISK MANAGEMENT ACTIVITIES
Interest Rate Swap Derivative Instruments
To mitigate its interest rate risk, the Partnership enters into various interest rate swaps. These swaps convert the variable-rate term loan into a fixed-rate obligation. The purpose of entering into these swaps is to eliminate interest rate variability by converting LIBOR-based variable-rate payments to fixed-rate payments. Amounts received or paid under these swaps were recorded as reductions or increases in interest expense.
The following table sets forth certain information regarding the Partnership's various interest rate swaps as of December 31, 2012:
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During July 2012, in conjunction with the Partnership's issuance of $250.0 million of Senior Notes (see Note 8), which increased its fixed interest rate exposure, the Partnership terminated $200.0 million notional amount of existing fixed rate interest rate swaps at a cost of $3.9 million.
Commodity Derivative Instruments - Corporate
The prices of crude oil, natural gas and NGLs are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors which are beyond the Partnership's control. These risks can cause significant changes in the Partnership's cash flows and affect its ability to achieve its distribution objectives and comply with the covenants of its revolving credit facility. In order to manage the risks associated with changes in the future prices of crude oil, natural gas and NGLs on its forecasted equity production, the Partnership engages in risk management activities that take the form of commodity derivative instruments. The Partnership has determined that it is necessary to hedge a substantial portion of its expected production in order to meaningfully reduce its future cash flow volatility. The Partnership generally limits its hedging levels to less than its total expected future production. While hedging at this level of production does not eliminate all of the volatility in the Partnership's cash flows, it allows the Partnership to mitigate the risk of situations where a modest loss of production would not put it in an over-hedged position. At times, the Partnership's strategy may involve entering into hedges with strike prices above current future prices or resetting existing hedges to higher price levels in order to meet its cash flow objectives or to stay in compliance with the covenants under its revolving credit facility. In addition, the Partnership may also terminate or unwind hedges or portions of hedges when the expected future volumes do not support the level of hedges. Expected future production for its Upstream Business is derived from the proved reserves, adjusted for price-dependent expenses and revenue deductions. For the Midstream Business, expected future production is based on the expected production from wells currently flowing to the Partnership's processing plants, plus additional volumes the Partnership expects to receive from future drilling activity by its producer customer base. The Partnership's expectations for its Midstream Business volumes associated with future drilling are based on information it receives from its producer customer base and historical observations. The Partnership applies the appropriate contract terms to these projections to determine its expected future equity share of the commodities.
The Partnership uses fixed-price swaps, costless collars and put options to achieve its hedging objectives and often hedges its expected future volumes of one commodity with derivatives of the same commodity. In some cases, however, the Partnership believes it is better to hedge future changes in the price of one commodity with a derivative of another commodity, which it refers to as “proxy” hedging. The Partnership will often hedge the changes in future NGL prices using crude oil hedges because NGL prices have been highly correlated to crude oil prices and hedging NGLs directly is usually less attractive due to the relative illiquidity in the NGL forward market. The Partnership may use natural gas hedges to hedge a portion of its expected future ethane production because forward prices for ethane are often heavily discounted from its current prices. Also, natural gas prices provide support for ethane prices because in many processing plants ethane can be recombined with the residue gas stream and sold as natural gas. When the Partnership uses "proxy" hedging, it converts the expected volumes of the underlying commodity to equivalent volumes of the hedged commodity. In the case of NGLs hedged with crude oil derivatives, these conversions are based on the historical relationship of the prices of the two commodities and management's judgment regarding future price relationships of the commodities. In the case where ethane is hedged with natural gas derivatives, the conversion is based on the thermal content of ethane.
For accounting purposes, the Partnership has not designated any of its commodity derivative instruments as hedges; instead it marks these derivative contracts to fair value (see Note 12). Changes in fair values of the commodity derivative instruments are recorded as an adjustment to the mark-to-market gains (losses) on risk management transactions within revenue.
By using derivative instruments to economically hedge exposure to changes in commodity prices, the Partnership exposes itself to counterparty credit risk. Historically, the Partnership's corporate derivative counterparties have all been participants or affiliates of participants within its revolving credit facility (see Note 8), which is secured by substantially all of the assets of the Partnership. Therefore, the Partnership is not currently required to post any collateral, nor does it require collateral from its counterparties.
The Partnership's commodity derivative counterparties as of December 31, 2012, not including counterparties of its marketing and trading business, included BNP Paribas, Wells Fargo Bank, National Association, Comerica Bank, Bank of Nova Scotia, The Royal Bank of Scotland plc, Bank of America N.A., J Aron and Company (an affiliate of Goldman Sachs),
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ING Capital Markets LLC, BBVA Compass Bank, Royal Bank of Canada, Regions Financial Corporation and CITIBANK, N.A.
The following tables set forth certain information regarding the Partnership's commodity derivatives. Within each table, some trades of the same commodities with the same tenors have been aggregated and shown as weighted averages.
Commodity derivatives, as of December 31, 2012, that will mature during the years ended December 31, 2013, 2014 and 2015:
_______________________
(a)
Volumes of natural gas are measured in MMbtu, volumes of crude oil are measured in barrels, and volumes of natural gas liquids are measured in gallons.
(b)
Amounts represent the weighted average price. The weighted average prices are in $/MMbtu for natural gas, $/barrel for crude oil and $/gallon for natural gas liquids.
During July 2012, the Partnership enhanced its commodity derivative portfolio by paying $2.8 million to adjust the strike price from $68.30 to $92.00 (the forward market price at the date of the transaction) per barrel on an existing WTI crude oil swap of 20,000 barrels per month for the last six months of 2012.
Commodity Derivative Instruments - Marketing & Trading
The Partnership conducts natural gas marketing and trading activities. The Partnership engages in activities intended to capitalize on favorable price differentials between various receipt and delivery locations. The Partnership's activities are governed by its risk policy.
As part of its natural gas marketing and trading activities, the Partnership enters into both financial derivatives and physical contracts. These financial derivatives, primarily basis swaps, are transacted: (i) to economically hedge subscribed capacity exposed to market rate fluctuations and (ii) to mitigate the price risk related to other purchase and sales of natural gas. By entering into a basis swap, one pricing index is exchanged for another, effectively locking in the margin between the natural gas purchase and sale by removing index spread risk on the combined physical and financial transaction.
A commodity-related derivative contract may be designated as a "normal" purchase or sale if the commodity is to be physically received or delivered for use or sale in the normal course of business. If designated as "normal" the derivative contract is accounted for under the accrual method of accounting (not marked-to-market) with no balance sheet or income statement recognition of the contract until settlement. Commodity-related contracts that do not qualify for the normal designation are accounted for as derivatives and are marked-to-market each period.
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Through the Partnership's natural gas marketing activity, the Partnership will have credit exposure to additional counterparties. The Partnership minimizes the credit risk associated with natural gas marketing by limiting its exposure to any single counterparty and monitoring the creditworthiness of its counterparties on an ongoing basis. In addition, the Partnership's natural gas purchase and sale contracts, for certain counterparties, are subject to counterparty netting agreements governing settlement under such natural gas purchase and sales contracts.
Marketing and Trading commodity derivative instruments, as of December 31, 2012, that will mature during the years ended December 31, 2012 and 2013:
Changes in the fair value of these financial and physical contracts are recorded as adjustments to natural gas sales.
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Fair Value of Interest Rate and Commodity Derivatives
Fair values of interest rate and commodity derivative instruments not designated as hedging instruments in the consolidated balance sheet as of December 31, 2012 and December 31, 2011:
The following table sets forth the location of gains and losses for derivatives not designated as hedging instruments within the Partnership's audited consolidated statement of operations (in thousands):
NOTE 12. FAIR VALUE OF FINANCIAL INSTRUMENTS
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Partnership utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk inherent in the inputs to the valuation technique. The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).
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The three levels of the fair value hierarchy are as follows:
Level 1 - Quoted prices are available in active markets for identical assets and liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide information on an ongoing basis.
Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the market place throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Level 3 - Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value.
As of December 31, 2012, the Partnership has recorded its interest rate swaps and commodity derivative instruments (see Note 11), which includes crude oil, natural gas and NGLs, at fair value. The Partnership reviews the classification of the inputs at the end of each period and has classified the inputs to measure the fair value of its interest rate swaps, crude oil derivatives and natural gas derivatives as Level 2. In prior periods, the Partnership has classified the inputs to measure its NGL derivatives as Level 3 as the NGL market was considered to be less liquid and thinly traded. As of September 30, 2011, the Partnership concluded that the inputs for its NGL derivatives were considered to be more observable due to the NGL market being more liquid through the term of our contracts and has classified these inputs as Level 2. The following table discloses the fair value of the Partnership's derivative instruments as of December 31, 2012 and 2011:
____________________________
(a)
Represents counterparty netting under agreement governing such derivative contracts.
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____________________________
(a)
Represents counterparty netting under agreement governing such derivative contracts.
The following table sets forth a reconciliation of changes in the fair value of the Level 3 NGL derivatives during the years ended December 31, 2012, 2011 and 2010 (in thousands):
The Partnership values its Level 3 NGL derivatives using forward curves, interest rate curves, and volatility parameters, when applicable. In addition, the impact of counterparty credit risk is factored into the value of derivative assets, and the Partnership's credit risk is factored into the value of derivative liabilities.
The Partnership recognized losses of $5.7 million in the year ended December 31, 2010, that are attributable to the change in unrealized gains or losses related to those Level 3 assets and liabilities still held at December 31, 2010, which are included in the commodity risk management (losses) gains.
Realized and unrealized losses related to the interest rate derivatives are recorded as part of interest rate risk management gains and losses in the audited consolidated statements of operations. Realized and unrealized gains and losses and premium amortization related to the Partnership's commodity derivatives are recorded as a component of revenue in the audited consolidated statements of operations.
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Fair Value of Assets and Liabilities Measured on a Non-recurring Basis
The following table discloses the fair value of the Partnership's assets measured at fair value on a nonrecurring basis for the year ended December 31, 2012:
The Partnership calculated the fair value of the impaired assets using discounted cash flow analysis to determine the excess of the asset's carrying value over its fair value. Significant inputs to the valuation of fair value of the proved properties included estimates of (i) reserves, (ii) future operating and development costs (ii) forward commodity prices and (iii) a discount rate reflective of the Partnership's cost of capital. Significant inputs to the valuation of fair value of plant, pipeline and intangible assets include estimates of (i) future cash flows, including revenue, expenses and capital expenditures, (ii) timing of cash flows, (iii) forward commodity prices, adjusted for location differentials and (iv) a discount rate reflective of the Partnership's cost of capital. For the other assets impaired by the partnership during the year ended December 31, 2012, the assets were fully written down and are thus not included in the table above. See Notes 5 and 7 for a further discussion of the impairment charges.
The carrying amount of cash equivalents is believed to approximate their fair values because of the short maturities of these instruments. The fair value of accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments.
As of December 31, 2012, the outstanding debt associated with the Credit Agreement bore interest at a floating rate; as such, the Partnership believes that the carrying value of this debt approximates its fair value. The outstanding debt associated with the Senior Notes bears interest at a fixed rate; based on the market price of the Senior Notes as of December 31, 2012, the Partnership estimates that the fair value of the Senior Notes is $561.0 million compared to a carrying value of $544.6 million. Fair value of the senior notes was estimated based on prices quoted from third-party financial institutions, which are characteristic of Level 2 fair value measurement inputs.
NOTE 13. COMMITMENTS AND CONTINGENT LIABILITIES
Litigation-The Partnership is subject to lawsuits which arise from time to time in the ordinary course of business, such as the interpretation and application of contractual terms related to the calculation of payment for liquids and natural gas proceeds. The Partnership had no accruals as of December 31, 2012 and 2011 related to legal matters, and current lawsuits are not expected to have a material adverse effect on our financial position, results of operations or cash flows. The Partnership has been indemnified up to a certain dollar amount for two lawsuits. If there ultimately is a finding against the Partnership in these two indemnified cases, the Partnership would expect to make a claim against the indemnification up to limits of the indemnification.
Insurance-The Partnership covers its operations and assets with insurance which management believes is consistent with that in force for other companies engaged in similar commercial operations with similar type properties. This insurance includes: (1) commercial general liability insurance covering liabilities to third parties for bodily injury, property damage and pollution arising out of Eagle Rock Energy operations; (2) workers’ compensation liability coverage for employees to required statutory limits; (3) automobile liability insurance covering liability to third parties for bodily injury and property damage arising out of the operation of all owned, hired and non-owned vehicles by its employees on company business; (4) property insurance covering the replacement cost of all owned real and personal property, including coverage for losses due to boiler and machinery breakdown, earthquake, flood and consequent business interruption/extra expense; (5) control of well/operator's extra expense insurance for operated and non-operated wells in the Upstream Segment; and (6) corporate liability insurance including coverage for Directors and Officers and Employment Practices liabilities. In addition, the Partnership maintains
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excess liability insurance providing limits in excess of the established primary limits for commercial general liability and automobile liability insurance.
All coverages are subject to industry accepted policy terms, conditions, limits and deductibles comparable to that obtained by other energy companies with similar operations. The cost of insurance for the energy industry continued to fluctuate over the past year, reflecting the changing conditions in the insurance markets.
Environmental-The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, the Partnership must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on the Partnership's combined results of operations, financial position or cash flows. At December 31, 2012 and 2011, the Partnership had accrued approximately $2.8 million and $3.2 million, respectively, for environmental matters.
In July 2012, the Alabama Department of Environmental Management (“ADEM”) notified one of the Partnership's subsidiaries that ADEM had made a determination that alleged violations warrant enforcement action and determined that the alleged violations are appropriate for resolution by Consent Order and proposed the terms of a to-be-mutually agreed-upon Consent Order (“Proposed Consent Order”). Such notification and the Proposed Consent Order are the result of findings made by ADEM relating to the Partnership's subsidiary's Flomaton/Fanny Church Oil and Gas Production and Treating Facility. The Proposed Consent Order primarily related to allegations of emissions in excess of those allowed by the production rate. Prior to receiving the Proposed Consent Order, the Partnership self-reported its emission rates and worked with ADEM to complete a series of quality improvement plans to address the causes of the alleged violations. On November 20, 2012, the Partnership executed a revised consent order that became effective on January 11, 2013. The order provides for a civil penalty of $80,000, which was paid on January 31, 2013.
Retained Revenue Interest-Certain assets of the Partnership's Upstream Segment are subject to retained revenue interests. These interests were established under purchase and sale agreements that were executed by the Partnership's predecessors in title. The terms of these agreements entitle the owners of the retained revenue interests to a portion of the revenues received from the sale of the hydrocarbons above specified base oil and natural gas prices. These retained revenue interests do not represent a real property interest in the hydrocarbons. The Partnership's reported revenues are reduced to account for the retained revenue interests on a monthly basis.
The retained revenue interests affect the Partnership's interest at the Big Escambia Creek, Flomaton and Fanny Church fields in Escambia County, Alabama. With respect to the Partnership's Flomaton and Fanny Church fields, these retained revenue interests are in effect for any calendar year in which the Partnership surpasses certain average net production rates. The Partnership did not surpass such rates in 2012 and does not anticipate doing so in 2013. With respect to the Partnership's Big Escambia Creek field, the retained revenue interest commenced in 2010 and continues through the end of 2019.
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Other Commitments-The Partnership utilizes assets under operating leases for its corporate office, certain rights-of-way and facilities locations, vehicles and in several areas of its operations. Rental expense, including leases with no continuing commitment, amounted to approximately $8.9 million, $7.8 million and $7.8 million for the years ended December 31, 2012, 2011 and 2010, respectively. Rental expense for leases with escalation clauses is recognized on a straight-line basis over the initial lease term. At December 31, 2012, commitments under long-term non-cancelable operating leases for the next five years are as follows (in thousands):
NOTE 14. SEGMENTS
During the fourth quarter of 2011, the Partnership's chief operating decision-maker (“CODM”) decided that due to the relative size of the East Texas/Louisiana, South Texas and Gulf of Mexico segments, these three reporting segments would be collapsed into a single reporting segment and that a new Marketing and Trading reporting segment would be created. The Midstream Business's financial results are now reported in the following segments: (i) Texas Panhandle, which no longer includes the results of the Partnership's Marketing and Trading operations, (ii) East Texas and Other Midstream, which consolidates the Partnership's former East Texas/Louisiana, South Texas and Gulf of Mexico segments, and (iii) Marketing and Trading, which is a new reporting segment. Operating results for the reportable segments have been recast for the years ending December 31, 2010 and 2009 to reflect these changes. The Partnership's Upstream Segment and functional (Corporate) Segment remained unchanged from what has been previously reported.
Based on the Partnership’s approach to managing its assets, the Partnership believes its operations consist of three segments in its Midstream Business, one Upstream Segment and one Corporate segment:
(i) Midstream-Texas Panhandle Segment:
gathering, compressing, treating, processing and transporting natural gas; fractionating, transporting and marketing NGLs;
(ii) Midstream-East Texas and Other Midstream Segment:
gathering, compressing, processing and treating natural gas and marketing of natural gas, NGLs and condensate in South Texas, East Texas, Louisiana, Gulf of Mexico and inland waters of Texas;
(iii) Midstream-Marketing and Trading Segment:
crude oil and condensate logistics and marketing in the Texas Panhandle and Alabama; and natural gas marketing and trading;
(iv) Upstream Segment:
crude oil, condensate, natural gas, NGLs and sulfur production from operated and non-operated wells; and
(v) Corporate and Other Segment:
risk management, intersegment eliminations and other corporate activities such as general and administrative expenses.
The Partnership's CODM currently reviews its operations using these segments. The CODM evaluates segment performance based on segment operating income or loss from continuing operations. Summarized financial information concerning the Partnership's reportable segments is shown in the following tables:
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______________________________
(a)
Represents results of the Partnership's commodity risk management activity.
(b)
Includes elimination of intersegment transactions.
(c)
Sales to external customers in the Texas Panhandle Segment for the year ended December 31, 2012, includes $2.9 million of business interruption insurance recovery related to damage sustained by the Partnership's Cargray processing facility due to severe winter weather in 2011, which is recognized as part of Other Revenue in the consolidated statements of operations.
(d)
Sales to external customers for the years ended December 31, 2011 and 2010 includes $2.0 million and $3.0 million, respectively, of business interruption insurance recovery related to the shutdown of the Eustace plant in 2010 in the Upstream Segment, which is recognized as part of Other revenue in the consolidated statement of operations.
(e)
Includes costs to dispose of sulfur in the Upstream Segment of $0.7 million for the year ended December 31, 2010.
NOTE 15. EMPLOYEE BENEFIT PLAN
The Partnership offers a defined contribution benefit plan to its employees. For the three years ended December 31, 2012, the plan provided for a dollar for dollar matching contribution by the Partnership of up to 4% of an employee's contribution and 50% of additional contributions up to an additional 2%. Additionally, the Partnership may, at its sole discretion and election, contribute up to 6% of a participating employee's base salary annually, subject to vesting requirements. Expenses under the plan for the years ended December 31, 2012, 2011 and 2010 were approximately $1.8 million, $1.0 million and $1.0 million, respectively.
NOTE 16. INCOME TAXES
The Partnership's provision for income taxes relates to (i) state taxes for the Partnership and (ii) federal taxes for Eagle Rock Energy Acquisition Co., Inc, (acquiring entity of Redman Energy Holdings, L.P. and Redman Energy Holdings II, L.P. and certain assets owned by NGP Income Co-Investment Opportunities Fund II, L.P. (collectively the "Redman Acquisition") in 2007) and Eagle Rock Energy Acquisition Co. II, Inc. (acquiring entity of certain entities acquired in the Stanolind Acquisition in 2008) and their wholly owned corporations, Eagle Rock Upstream Development Company, Inc., (successor entity of certain entities acquired in the Redman acquisition) and Eagle Rock Upstream Development Company II, Inc. (successor entity of certain entities acquired in the Stanolind acquisition), which are subject to federal income taxes (the “C Corporations”). In addition, the Partnership has become a taxable entity in the state of Texas. On May 18, 2006, the State of Texas enacted House Bill 3 which revised the pre-existing state franchise tax. In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax, including previously non-taxable entities such as limited partnerships and limited liability partnerships. The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits. Although the bill states that the Revised Texas Franchise Tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses.
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The Partnership's federal and state income tax provision is summarized below (in thousands):
The effective rates for the years ended December 31, 2012, 2011 and 2010 are shown in the table below. For 2011, the effective tax rate is attributable to the state and federal taxes being applied to their book income. In 2012 and 2010, the federal and state based income taxes were applied against book losses which resulted in effective tax rates of 1.1% and 10.3%, respectively. A reconciliation of the provision for income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows (in thousands):
Significant components of deferred tax liabilities and deferred tax assets as of December 31, 2012 and 2011 are as follows (in thousands):
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The largest single component of the Partnership's deferred tax liabilities is related to federal income taxes of the C Corporations described above, where the book/tax differences were created by the Redman and Stanolind Acquisitions. These book/tax temporary differences will be reduced as allocation of built-in gain in proportion to the assets contributed brings the book and tax basis closer together over time. This net deferred tax liability was recognized in conjunction with the purchase accounting adjustments for long term assets.
Due to the enactment of the Revised Texas Franchise Tax, the Partnership recorded a net deferred tax liability related to the book/tax differences in property, plant and equipment and unrealized hedging transactions.
In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. At December 31, 2012, based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Partnership will realize the benefits of these deductible differences. The amount of deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced. The AMT credit carryforward presented above does not have an expiration date.
The Partnership adopted authoritative guidance related to accounting for uncertainty in income taxes on January 1, 2007. The Partnership has taken a position which is deemed to be “more likely than not” to be upheld upon review, if any, with respect to the deductibility of certain costs for the purpose of its franchise tax liability on a state franchise return. The Partnership has recorded a provision for the portion of this tax liability equal to the probability of recognition. In addition, the Partnership has accrued interest and penalties associated with these liabilities and has recorded these amounts within its state deferred income tax expense. The amount stated below relates to the tax returns filed for 2012, 2011 and 2010, which are still open under current statute.
A reconciliation of the beginning and ending amount of the unrecognized tax benefits (liabilities) is as follows (in thousands):
NOTE 17. EQUITY-BASED COMPENSATION
Eagle Rock Energy G&P, LLC, the general partner of the general partner of the Partnership, has a long-term incentive plan, as amended (“LTIP”), for its employees, directors and consultants who provide services to the Partnership and its subsidiaries and affiliates. The LTIP provides for the issuance of an aggregate of up to 7,000,000 common units, to be granted either as options, restricted units or phantom units. Distributions declared and paid on outstanding restricted units are paid directly to the holders of the restricted units. No options or phantom units have been issued to date.
The restricted units granted are valued at the market price as of the date issued. The weighted average fair value of the units granted during the years ended December 31, 2012, 2011 and 2010 was $9.50, $10.13 and $6.60, respectively. The awards generally vest over three years on the basis of one third of the award each year. The Partnership recognizes compensation expense on a straight-line basis over the requisite service period for the restricted unit grants. During the restriction period, distributions associated with the granted awards will be distributed to the awardees.
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A summary of the restricted common units’ activity for the year ended December 31, 2012 is provided below:
For the years ended December 31, 2012, 2011 and 2010, non-cash compensation expense of approximately $9.9 million, $5.1 million and $5.4 million, respectively, was recorded related to the granted restricted units as general and administrative expense on the consolidated statements of operations.
As of December 31, 2012, unrecognized compensation costs related to the outstanding restricted units under the LTIP totaled approximately $18.7 million. The remaining expense is to be recognized over a weighted average of 2.0 years.
In connection with the vesting of certain restricted units during the years ended December 31, 2012, 2011 and 2010, 286,716, 137,985 and 181,292, respectively, of the newly-vested common units were cancelled by the Partnership in satisfaction of $2.5 million, $1.4 million and $1.2 million, respectively, of minimum employee tax liability paid by the Partnership. Pursuant to the terms of the LTIP, these cancelled units are available for future grants under the LTIP.
In addition to equity awards under the LTIP, Eagle Rock Holdings, L.P. (“Holdings”), which is controlled by NGP, granted, from time to time, equity in Holdings to certain employees working on behalf of the Partnership, some of which are named executive officers. During the year ended December 31, 2010, Holdings granted 40,000, “Tier I” incentive interests to certain Eagle Rock Energy employees. The Partnership recorded a portion of the value of the incentive units as compensation expense in the Partnership's Consolidated Statements of Operations. This allocation is based on management's estimation of the total value of the incentive unit grant and of the grantees' portion of time dedicated to the Partnership. The Partnership recorded non-cash compensation expense of $0.1 million based on management's estimates related to the Tier I incentive unit grants made by Holdings during the year ended December 31, 2010.
NOTE 18. EARNINGS PER UNIT
Basic earnings per unit is computed by dividing the net income (loss) by the weighted average number of units outstanding during a period. To determine net income (loss) allocated to each class of ownership (common, subordinated and general partner), the Partnership first allocates net income (loss) in accordance with the amount of distributions made for the quarter by each class, if any. The remaining net income (loss) is allocated to each class in proportion to the class weighted average number of units outstanding for a period, as compared to the weighted average number of units for all classes for the period.
As of December 31, 2012, 2011 and 2010, the Partnership had unvested restricted common units outstanding, which are considered dilutive securities. These units will be considered in the diluted weighted average common unit outstanding number in periods of net income. In periods of net losses, these units are excluded from the diluted weighted average common unit outstanding number.
Any warrants outstanding during the period are considered to be dilutive securities. These outstanding warrants will be considered in the diluted weighted average common units outstanding number in periods of net income, except if the exercise price of the outstanding warrants is greater than the average market price of the common units for such periods. In periods of net losses, the outstanding warrants are excluded from the diluted weighted average common units outstanding.
Under the Partnership's original partnership agreement, which was amended and restated on May 24, 2010 in connection with approval of the recapitalization and related transactions, for any quarterly period, incentive distribution rights (“IDRs”) participated in net income only to the extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in undistributed earnings or losses. Accordingly, undistributed net income is assumed to be allocated to the other ownership interests on a pro-rata basis. During the years ended December 31, 2010 and 2009, the
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Partnership did not declare a quarterly distribution for the IDRs. On May 24, 2010, the Partnership's general partner contributed all of the outstanding IDRs to the Partnership, and they were eliminated.
In addition, all of the subordinated units and general partner units were contributed to the Partnership and cancelled on May 24, 2010 and July 30, 2010, respectively.
The following table presents the Partnership's calculation of basic and diluted units outstanding for the periods indicated:
The restricted common units granted under the LTIP, as discussed in Note 17, contain non-forfeitable rights to the distributions declared by the Partnership and therefore meet the definition of participating securities. Participating securities are required to be included in the computation of earnings per unit pursuant to the two-class method. For the year ended December 31, 2011, the Partnership determined that it is more dilutive to apply the two-class method versus the treasury stock method in calculating dilutive earnings per unit. Thus, the unvested restricted common units are included in the computation of the diluted weighted average common unit outstanding calculation, but the denominator in the computation of diluted earnings per common unit only includes the basic weighted average common units outstanding and weighted average warrants outstanding.
The following table presents the Partnership's basic income per unit for the year ended December 31, 2012:
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The following table presents the Partnership's basic and diluted income per unit for the year ended December 31, 2011:
The following table presents the Partnership's basic and diluted income per unit for the year ended December 31, 2010:
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NOTE 19. DIVESTITURE RELATED ACTIVITIES
The following table represents activity from divestiture related activities for the years ended December 31, 2012, 2011 and 2010:
_____________________________
(a)
On December 20, 2012, the Partnership sold its Barnett Shale properties (which was accounted for in its Upstream Segment). In 2012, the Partnership incurred a loss from sale which is included within impairment expense in the Consolidated Statement of Operations.
(b)
On May 20, 2011, the Partnership sold its Wildhorse Gathering System (which was accounted for in its East Texas and Other Midstream Segment). In 2010, the Partnership incurred impairment charges related to the assets which is included in the loss from operations.
(c)
On May 24, 2010, the Partnership completed the sale of its Minerals Business. Cash proceeds from the sale exclude the cash retained by the Partnership from net revenues received from the Minerals Business after the effective date. During the year ended December 31, 2011, the Partnership received payments related to pre-effective date operations and recorded this amount as part of discontinued operations for the period.
(d)
On April 1, 2009, the Partnership sold its producer services business (which was accounted for in its East Texas and Other Midstream Segment). As part of the sale, the Partnership received a monthly payment equivalent to $0.01 per MMbtu on the volume of gas that flowed pursuant to the assigned contracts through March 31, 2011 which is included in discontinued operations for the respective periods.
(e)
Amounts are included in total discontinued operations, net of tax.
(f)
Proved and unproved properties are included in "Property, Plant and Equipment, net" and Asset retirement obligation is included in "Asset Retirement Obligation" in the Consolidated Balance Sheets.
NOTE 20. OTHER OPERATING INCOME
In July 2008, SemGroup, L.P. and certain of its subsidiaries (“SemGroup”) filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. The Partnership historically sold portions of its condensate production from its Texas Panhandle and East Texas midstream systems to SemGroup. In August 2009, the Partnership sold $3.9 million of its outstanding receivables from SemGroup, which represented its 20-day administrative claims under 503(b)(9) of the United States Bankruptcy Code, for which it received a payment of $3.0 million. Due to certain repurchase obligations under the assignment agreement, the Partnership recorded the payment as a current liability within accounts payable as of December 31, 2010 and maintained the balance as a liability until it was clear that the repurchase obligations can no longer be triggered. Due to the expiration of the repurchase obligations during the year ended December 31, 2011, the Partnership released its reserve for these receivables and recorded other operating income of $2.9 million related to these reserves.
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NOTE 21. SUBSIDIARY GUARANTORS
The Partnership has issued registered debt securities guaranteed by its subsidiaries. As of December 31, 2012, all guarantors were wholly-owned or available to be pledged and such guarantees were joint and several and full and unconditional. Although the guarantees of our subsidiary guarantors are considered full and unconditional, the guarantees are subject to certain customary release provisions. Such guarantees will be released in the following circumstances:
•
in connection with any sale or other disposition of all or substantially all of the properties or assets of that guarantor (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) an issuer or a restricted subsidiary of us;
•
in connection with any sale or other disposition of capital stock of that guarantor to a person that is not (either before or after giving effect to such transaction) an issuer or a restricted subsidiary of us, such that, the guarantor ceases to be a restricted subsidiary of us as a result of the sale or other disposition;
•
if we designate any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the applicable provisions of the indenture;
•
upon legal defeasance or satisfaction and discharge of the indenture;
•
upon the liquidation or dissolution of such guarantor provided no default or event of default has occurred that is continuing;
•
at such time as such guarantor ceases to guarantee any other indebtedness of either of the issuers or any guarantor; or
•
upon such guarantor consolidating with, merging into or transferring all of its properties or assets to us or another guarantor, and as a result of, or in connection with, such transaction such guarantor dissolving or otherwise ceasing to exist.
In accordance with Rule 3-10 of Regulation S-X, the Partnership has prepared Condensed Consolidating Financial Statements as supplemental information. The following condensed consolidating balance sheets at December 31, 2012 and December 31, 2011, condensed consolidating statements of operations for the years ended December 31, 2012, 2011 and 2010, and condensed consolidating statements of cash flows for the years ended December 31, 2012, 2011 and 2010, present financial information for Eagle Rock Energy as the Parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the co-issuer and the subsidiary guarantors, which are all 100% owned by the Parent, on a stand-alone basis, and the consolidation and elimination entries necessary to arrive at the information for the Partnership on a consolidated basis. The subsidiary guarantors are not restricted from making distributions to the Partnership.
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Condensed Consolidating Balance Sheet
December 31, 2012
Condensed Consolidating Balance Sheet
December 31, 2011
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Condensed Consolidating Statement of Operations
For the Year Ended December 31, 2012
Condensed Consolidating Statement of Operations
For the Year Ended December 31, 2011
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Condensed Consolidating Statement of Operations
For the Year Ended December 31, 2010
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Condensed Consolidating Statement of Cash Flows
For the Year Ended December 31, 2012
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Condensed Consolidating Statement of Cash Flows
For the Year Ended December 31, 2011
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Condensed Consolidating Statement of Cash Flows
For the Year Ended December 31, 2010
NOTE 22. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
Oil and Natural Gas Reserves
Users of this information should be aware that the process of estimating quantities of proved oil and natural gas reserves is very complex, and requires significant subjective decisions in the evaluation of the available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and changing operating and market conditions. As a result, revisions to reserve estimates may occur from time to time. Although reasonable effort is made to ensure the reported reserve estimates are accurate, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.
There are numerous uncertainties inherent in estimating the quantities of proved reserves, the future rates of production and the timing of development expenditures. Reserves data represent estimates only and should not be construed as being exact. Moreover, the Standardized Measure of Oil and Gas (“SMOG”) should not be construed as the current market value of the proved oil and natural gas reserves or as the costs that would be incurred to obtain equivalent reserves. A market
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value determination would include many additional factors including (a) anticipated future changes in natural gas and crude oil prices, production and development costs, (b) an allowance for return on investment, (c) the value of additional reserves, not considered proved at present, which may be recovered as a result of further exploration and development activities, and (d) other business risks.
Recent Developments
On May 24, 2010, the Partnership sold its Minerals Business (see Note 19). Financial information, including reserve amounts and changes, related to the Minerals Business have been retrospectively adjusted to be reflected as assets and liabilities held-for-sale and discontinued operations.
Proved Reserves Summary
The following table illustrates the Partnership's estimated net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by Cawley, Gillespie and Associates. Oil and natural gas liquids prices applied for 2012 are based on an average of the prior twelve months first-of-month spot prices of West Texas Intermediate ($94.71 per barrel) and are adjusted for quality, transportation fees, and regional price differentials. Likewise, natural gas prices applied for 2012 are based on an average of the prior twelve months first-of-month spot prices of Henry Hub natural gas ($2.76 per MMBtu) and are adjusted for energy content, transportation fees, and regional price differentials. All prices are held constant in accordance with SEC guidelines. All of the Partnership's reserves are located in the United States.
As shown in the following reconciliation table, the Partnership recognized significant negative revisions to its estimates of proved natural gas reserves in 2012. These negative revisions were almost entirely due to the application of a lower natural gas price in the preparation of the reserves estimates as of December 31, 2012 as compared to the price used as of December 31, 2011, in accordance with SEC guidelines. Under the lower price assumption, many wells (developed and undeveloped) reach their economic limit sooner and reserves are truncated from the end of their life, and some undeveloped locations are not considered to be commercial. In both cases, the expected future production from these wells has been reclassified as "proved contingent resources," and all or some portion is expected to return to proved reserves if higher prices were used in future proved reserves estimates.
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Proved Reserves Summary - Equity Method Entities
As part of the sale of the Minerals Business in 2010, the Partnership sold its limited partner interest in Ivory Working Interests, L.P. ("IWI"), which it had accounted for under the equity method. IWI is managed by Black Stone and is not required to make public disclosures about its proved reserves and the agreements that governed the Partnership's rights as limited partners in IWI do not require Black Stone to provide us with detailed reserve data of the type that would be sufficient to make all of the disclosures that the SEC now requires with respect to proved reserves of equity method entities. As a result, the Partnership lacks the data needed to prepare the Supplemental Oil and Gas Disclosures for its equity interests.
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Capitalized Costs Relating to Oil and Natural Gas Producing Activities
The following table illustrates the total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization at December 31, 2012, 2011 and 2010:
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities
Costs incurred in property acquisition, exploration and development activities were as follows for the years ended December 31, 2012, 2011 and 2010:
No costs were incurred associated with the Minerals Business which is classified as Discontinued Operations on the Consolidated Statements of Operations .
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
The following information has been developed utilizing authoritative guidance procedures and is based on oil and natural gas reserves estimated by the Partnership's independent reserves engineer. It can be used for some comparisons, but should not be the only method used to evaluate the Partnership or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flow be viewed as representative of the current value of the Partnership.
The Partnership believes that the following factors should be taken into account when reviewing the following information:
•
future costs and selling prices will probably differ from those required to be used in these calculations;
•
due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations; and
•
a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues.
Under the Standardized Measure, future cash inflows were estimated by applying year-end oil and natural gas prices to the estimated future production of year-end proved reserves. Estimates of future income taxes were computed using current
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statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows were reduced to present value amounts by applying a 10% discount factor.
A significant portion of the revenues associated with the Partnership's hydrocarbon reserves in Alabama and East Texas are from the sale of sulfur that is derived from the hydrogen sulfide that is removed from the natural gas stream. Although sulfur is not a hydrocarbon, it is intimately associated with the hydrocarbon stream, and must be removed to render the natural gas saleable. The Partnership's rationale for inclusion of these revenues is that the sulfur is produced with the natural gas, and that the cost of removing the sulfur is included in the operating costs of the properties. No reserve volumes have been booked for sulfur, but the inclusion of the sulfur revenues in the cash flows related to the reserves does have a very small positive impact on the hydrocarbon reserves estimates by lowering the properties' economic limit; our independent reserves engineer has concurred with this approach. Also, the Partnership has included the expected impact of the retained revenue interests as a revenue reduction.
The recent changes to the disclosure rules relating to proved reserves require the inclusion of the Partnership's share of the reserves associated with entities that it reports under the equity method. As discussed above, the Partnership sold these interests as part of the sale of its Minerals Business. As the Partnership did not have the right and has been unable to gather the data needed to include these reserves in its Standardized Measure calculations, the tables below reflect only the reserves for the Partnership's consolidated entities.
The Standardized Measure is as follows as of December 31, 2012, 2011 and 2010:
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Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
The following is a summary of the changes in the Standardized Measure of discounted future net cash flows for the Partnership's proved oil and natural gas reserves for the years ended December 31, 2012, 2011 and 2010:
Results of Operations
The following are the results of operations for the Partnership's oil and natural gas producing activities for the years ended December 31, 2012, 2011 and 2010:
* * * *
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Index to Exhibits
*
Filed herewith
**
Management contract or compensatory plan or arrangement required to be filed as an exhibit hereto.
***
Furnished herewith
†
Portions of this exhibit have been omitted pursuant to a request for confidential treatment.