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EROC > SEC Filings for EROC > Form 10-K on 3-Mar-2014All Recent SEC Filings




Annual Report

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.


We are a domestically-focused, growth-oriented, publicly-traded Delaware limited partnership engaged in the following two businesses:

Upstream Business-developing and producing oil and natural gas property interests.

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

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, 2013, our Upstream Business generated an operating loss of $154.8 million compared to operating income of $12.4 million during the year ended December 31, 2012. The operating loss generated during the year ended December 31, 2013 included impairment and other charges of $214.3 million, compared to impairment and other charges of $45.3 million included in the operating income generated during year ended December 31, 2012.

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, 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, 2013, our Midstream Business generated operating income from continuing operations of $43.3 million compared to operating loss from continuing operations of $95.9 million during the year ended December 31, 2012. As discussed in "Recent Developments," on December 23, 2013, we entered into an agreement to contribute our Midstream Business to Regency Energy Partners, LP ("Regency").

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, 2013, our Corporate and Other Segment generated an operating loss of $102.0 million compared to an operating loss of $12.6 million during the year ended December 31, 2012. Results reflected net gains on our commodity derivatives of $18.5 million during the year ended December 31, 2013, compared to net gains on our commodity derivatives of $57.9 million during the year ended December 31, 2012. See "Summary of Consolidated Operating Results - Corporate and Other Segment" for a further discussion of the impact of our commodity derivatives.

Recent Developments

On December 23, 2013, we announced that we had entered into a definitive agreement to contribute our Midstream Business to Regency for total consideration of up to $1.325 billion, consisting of $200 million of newly issued Regency common units and a combination of cash and assumed debt, subject to certain closing conditions. As part of this transaction, Regency will conduct an offer to exchange our $550 million of outstanding senior unsecured notes into an equivalent amount of Regency senior unsecured notes with the same tenor, coupon and a comparable covenant package. The cash portion of the purchase price will be reduced by the amount of notes exchanged subject to a 10% adjustment factor, such that if all $550 million of bonds are exchanged, the total consideration will equal $1.27 billion ($1.325 billion less $55 million) consisting of $200 million in Regency units, $550 million of assumed debt and $520 million of cash proceeds. The transaction is subject to

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the approval of our unitholders, Hart-Scott-Rodino Antitrust Improvements Act of 1976 approval and other customary closing conditions.

As the sale of the Midstream Business is conditioned upon the approval of our unitholders, we have not classified the assets of our Midstream Business as assets-held-for-sale or the operations as discontinued.

On February 28, 2014, we announced that ourself and Regency had received a request for additional information and documents from the Federal Trade Commission in connection with the proposed contribution of our Midstream Business to Regency.


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.

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 acquired gathering 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". 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.


During the year ended December 31, 2013, we recorded impairment in our Upstream Segment of 207.1 million primarily related to certain proved properties in the Cana Shale in the Mid-Continent region and Permian region due to lower reserve forecasts. We also incurred an impairment of 7.2 million for certain leaseholds in out Mid-Continent region unproved properties that we expect to expire undrilled in 2014. During the year ended December 31, 2013, we recorded no impairment charges in our Midstream Businesses. During the year ended December 31, 2012, we recorded 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 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.

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.

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.

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Volumes (by Business)

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).

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.

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. Quantitative and Qualitative Disclosures About Market Risk.

Operating Expenses

Upstream Operating Expenses. We monitor and evaluate our Upstream Segment operating costs routinely, both on a total cost and unit cost basis. Many of the operating costs we incur are not directly related to the quantity of hydrocarbons that we produce, so we strive to maximize our production rates in order to improve our unit operating costs. The most significant portion of our Upstream Segment operating costs is associated with the operation of the Big Escambia Creek treating and processing facilities. These facilities are overseen by members of our midstream engineering and operations staff. The majority of the cost of operating these facilities is independent of their throughput. This includes items such as labor, chemicals, utilities and materials.

Midstream Operating Expenses. We monitor midstream operating expenses as a measure of the operating efficiency of our field operations. Direct labor, repair and maintenance, utilities and contract services comprise the most significant portion of our operating expenses. These expenses are largely independent of the volumes through our systems, but fluctuate depending on the activities performed during a specific period.

Adjusted EBITDA

See discussion of Adjusted EBITDA in Part II, Item 6. Selected Financial Data.

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General Trends and Outlook

We expect our business to be affected by the following key trends. This expectation is based on assumptions made by us and information currently available to us; however, our actual results may vary materially from our expectations.

Natural Gas Supply, Demand and Outlook

Since 2006, the United States has experienced significant growth in natural gas production due to drilling for gas in shale plays (such as the Haynesville and Marcellus plays), and the production of associated gas from wells drilled in liquids-rich shale and other unconventional plays (such as the Eagle Ford and Granite Wash plays). In response to greater supply, natural gas prices have stayed consistently below $5.00/mmbtu at Henry Hub since 2009, but these relatively low prices have not dampened the intensity of development of these reserves. Given this observation and the large amount of undeveloped gas reserves in these types of plays, we expect operators to continue to aggressively develop them as long as natural gas prices remain at or above an average Henry Hub price around $4.00/mmbtu.

The increase in US natural gas production has been absorbed through a reduction in natural gas imports from Canada via pipelines and from other countries as LNG, and through an increase in consumption for electricity generation. Because US electricity generation has been relatively flat over this period, almost all of the increase in natural gas-fired generation has come at the expense of coal-fired generation. Despite lower natural gas prices, other uses for natural gas (such as industrial, residential and vehicle uses) have not grown significantly, and we do not expect them to do so in the next few years. Also, it is uncertain whether natural gas can continue to gain market share from coal in the electrical power generation market. Therefore, we believe that continued increases in natural gas production due to ongoing development of domestic oil and gas shale resources will result in sustained low prices (less than $4.50/mmbtu) unless significant new sources of demand arise, such as additional fuel switching in the electrical power generation industry (perhaps due to increased regulation of emissions from coal-fired generators) or the export of natural gas to other markets in the form of LNG.

Crude Oil Supply, Demand and Outlook

Crude oil is a global commodity and the majority of the world's reserves are controlled by foreign governments and state-owned companies. Much of the world's reserves are in politically unstable regions, particularly in the Middle East and Africa, and supply disruptions (or even the threat of supply disruptions) can cause large increases in the price of crude oil. Since 2000, worldwide petroleum supply has grown at a modest pace, but not all oil producing countries have experienced increases in production. Almost all of the increase can be explained by increases in Saudi Arabia, Russia, Kazakhstan, the United States and Canada. The dramatic growth in United States production is attributable to the development of vast oil and liquids-rich shale plays that require much higher prices to remain viable than do Middle Eastern reserves. We believe that as long as WTI prices remain above $70-80/bbl, many of these plays will generate economic returns and US production growth will continue for the next several years.

The non-OECD countries currently account for almost half of worldwide petroleum consumption, and since 2000, substantially all of the increase in worldwide consumption has occurred in them. Within that group of countries, the leading consumers are China, India, Brazil and Russia, followed by Saudi Arabia, Iran and Indonesia. These seven countries account for 60% of non-OECD consumption and each of them has increased its petroleum consumption over the last decade. The most significant in terms of quantity consumed and consumption growth rate is China.

We believe that the factors that have resulted in flat or declining consumption in the OECD countries (low population growth, an aging population and increased fuel efficiency) are likely to persist, so future oil demand growth will must come from the non-OECD countries. We are optimistic that these countries will continue to increase their rates of oil consumption as their economies continue to grow and mature. The performance of the Chinese economy will continue to be an important factor in global oil demand, and we believe that if it continues to grow modestly and shifts to a more consumer-driven economy, it will provide an important source of demand growth to support oil prices.

As a result of the supply and demand trends, we believe that crude oil prices in the United States will stay in a range between $70 and $100/bbl over the next few years, but we recognize that infrastructure constraints may create short-lived periods of prices below this range.

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Natural Gas Liquids Supply, Demand and Outlook

The high levels of liquids-directed drilling in the United States has resulted in significant increases in the supply of NGLs while demand for the products has remained relatively stable. As a result, NGL prices declined significantly in 2012 and remained low in 2013. Historically, natural gas liquids prices have tended to have a high correlation to crude oil prices, especially for propane and heavier NGLs, This correlation weakened in 2012, and in 2013 was almost non-existent. We do not expect the prices of NGL's and crude oil to be well-correlated in the short term, and we are uncertain if and when the correlation will resume.

The majority of the NGLs we produce are delivered into the Conway, Kansas hub. During 2013, the difference between NGL prices at the Conway Hub and the Mont Belvieu, Texas hub were relatively modest, and actually improved in the final months of the year By the end of 2013, prices for propane, iso-butane, and normal-butane were trading at Conway at a slight premium to the Mont Belvieu prices.

Ethane comprises the largest volumetric percentage of the typical NGL barrel, and ethane prices historically have been substantially less correlated to crude oil than have the heavier NGLs. Increased supply, driven by drilling in NGL-rich plays, led to multi-year lows in ethane prices during 2012 and these low prices largely continued in 2013. Ethane demand is primarily driven by global petrochemical production, specifically by its use as a feedstock for ethylene production. Ethane's low price relative to heavier ethylene feedstocks has resulted in strong worldwide demand, and chemical manufacturers have recently announced projects to increase their ethylene production capacity using ethane. These projects have long lead-times, however, and we do not expect the demand response to offset the existing supply for several years. .

Sulfur Supply, Demand and Outlook

Much of the natural gas that we produce in the East Texas and Alabama regions within our Upstream Segment contains high, naturally-occurring concentrations of hydrogen sulfide. This is a corrosive, poisonous gas that must be removed from the natural gas stream before it can be processed for NGL extraction or sale. The process of removing the hydrogen sulfide yields a large amount of elemental sulfur, which we sell or otherwise dispose of. The process of removing hydrogen sulfide from natural gas, and similar processes for the removal of hydrogen sulfide from sour crude oils (prior to refining), are the primary sources of sulfur production in the United States and the world.

The primary use of sulfur is the production of sulfuric acid, and one of the major uses of sulfuric acid is the production of phosphoric acid. In turn, phosphoric acid is a key raw material in the manufacture of phosphate fertilizers. Therefore, one of the major factors influencing the demand for sulfur is the demand for fertilizer. The region around Tampa, Florida contains a large amount of fertilizer manufacturing facilities, and Tampa also serves as an export hub for sulfur.

As with many commodities, the developing economies are responsible for much of the global demand growth for fertilizer. Sulfur prices at Tampa in 2013 ranged from a high of $155 per long ton in the second quarter to a low of $75 per long ton in the fourth quarter. Sulfur prices were $110 per long ton in the first quarter of 2014. We expect demand to remain strong relative to supply in 2014, and, that over the next few years, the performance of the emerging economies, uncertain global economic conditions, and the start-up of significant sulfur-producing operations in the Middle East could result in supply/demand imbalances and cause significant price volatility.

Impact of Regulation of Greenhouse Gas Emissions

The operations of and use of the products produced by the natural gas and oil industry are sources of emissions of certain greenhouse gases ("GHG"), namely carbon dioxide and methane. The United States Environmental Protection Agency ("EPA"), by virtue of a 2007 Supreme Court decision, was deemed to have authority to regulate carbon dioxide and other GHG emissions under the Clean Air Act. It is possible that legislation will be proposed to amend the Clean Air Act to exclude GHG, although the probability of the enactment of such legislation is uncertain.

The EPA has already promulgated GHG regulations applicable to the natural gas and oil industry. Moreover, the current presidential administration has indicated that it may pursue additional GHG regulation through executive and administrative means in the absence of federal legislation, but the potential scope and content of such regulation are undetermined at this time. Because of the uncertainty of the nature of any potential future federal GHG regulations at this time, we are unable to forecast how future regulation of GHG emissions would negatively impact our operations. We will continue to monitor regulatory developments and to assess our ability to reasonably predict the economic impact of these developments on our business.

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The commercial risk associated with the exploration and production of fossil fuels lies in the uncertainty of regulations that may affect our customers, which could affect the demand for crude oil and natural gas. Such an impact on demand could have an adverse impact on the demand for our services, and could have an impact on our financial condition, results of operations and cash flows. On the other hand, when burned, natural gas produces less greenhouse gas emissions than other fossil fuels, such as refined petroleum products or coal. As a result, climate change legislation or GHG emissions regulations could create an increased demand for natural gas.

Critical Accounting Policies and Estimates

Conformity with GAAP requires management to make estimates and judgments that affect the amounts reported in the financial statements and notes. On an ongoing basis, we make and evaluate estimates and judgments based on management's best available knowledge of previous, current, and expected future events. We base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates, and estimates are subject to change due to modifications in the underlying conditions or assumptions. Currently, we do not foresee any reasonably likely changes to our current estimates and assumptions which would materially affect amounts reported in the financial statements and notes. Below are expanded discussions of our more significant accounting policies, estimates and judgments, i.e., those that reflect more significant estimates and assumptions used in the preparation of our financial statements. See Note 2 to our consolidated financial statements for details about additional accounting policies and estimates made by management.

Successful Efforts. We utilize the successful efforts method of accounting for our oil and natural gas properties. Leasehold costs are capitalized when incurred. Costs incurred to drill and complete development wells are capitalized. Unproved properties are assessed periodically within specific geographic areas and, if necessary, impairments are charged to expense. 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. We carry the costs of an exploratory well as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well as long as we are making sufficient progress towards assessing the reserves and the economic and operating viability of the project.

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. GAAP 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. Since our units of production depletion and amortization rate are a function of our proved reserves, we experience a higher depletion and amortization rate than we would if we claimed undeveloped or non-producing reserves. . . .

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