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Eagle Rock Reports Fourth Quarter and Year End 2012 Financial Results

HOUSTON, Feb. 25, 2013 (GLOBE NEWSWIRE) -- Eagle Rock Energy Partners, L.P. ("Eagle Rock" or the "Partnership") (Nasdaq:EROC) today announced its unaudited financial results for the full year 2012 and three months ended December 31, 2012. Financial highlights with respect to fourth quarter 2012 included the following:

  • Reported Adjusted EBITDA of $66.2 million, an increase of approximately 12% as compared to the $59.1 million reported for the third quarter of 2012.
  • Reported Distributable Cash Flow of $29.5 million, an increase of approximately 9% as compared to the $27.0 million reported for the third quarter of 2012.
  • Announced a quarterly distribution with respect to the fourth quarter of 2012 of $0.22 per common unit, equal to the third quarter 2012 distribution and a 5% increase from the distribution paid for the fourth quarter of 2011.
  • Reported a Net Loss of $55.2 million, driven almost entirely by impairments and unrealized mark-to-market losses on commodity hedges, both of which are non-cash charges to earnings.

Other notable financial and operational activities of the Partnership during the fourth quarter of 2012 included the following:

  • Closed on the acquisition of BP's Texas Panhandle midstream assets (the "Panhandle Acquisition") on October 1, 2012, and, following the negotiated transition services period, assumed control of operations, marketing and commercial activities on January 1, 2013.
  • Completed the first phase of the emissions reduction project at the Big Escambia Creek (BEC) processing facility in Southern Alabama on December 17, 2012, resulting in increased sulfur recovery and reductions in SO2 emissions to levels well below the current permitted levels.
  • Increased commitments from the lending group under its existing senior secured credit facility from $675 million to $820 million.

For the full year 2012, Eagle Rock generated $245.8 million of Adjusted EBITDA, an increase of 18% from the $208.2 million reported for the full year 2011, despite lower year-over-year natural gas and natural gas liquids (NGL) prices. The increase in 2012 was primarily due to a full year contribution from its Mid-Continent Upstream assets, which were acquired on May 3, 2011, and a quarter of a year contribution from the Panhandle Acquisition.

"The fourth quarter marked the end of another very active year for Eagle Rock," said Joseph A. Mills, Eagle Rock's Chairman and Chief Executive Officer. "During 2012, we significantly expanded our Midstream position in the Texas Panhandle through our Panhandle Acquisition and execution of a 20-year fixed-fee gathering and processing agreement with BP. In addition, we announced a substantial new area dedication by Anadarko Petroleum Corporation in Western Louisiana and successfully developed a portion of our attractive upstream drilling inventory in the SCOOP area of western Oklahoma."

Mills further commented, "As we look forward to 2013, we continue to be excited about growing our gathering footprint around our newly-acquired assets in the Texas Panhandle as well as realizing the full resource potential of our Mid-Continent Upstream portfolio."

Update Regarding the Panhandle Acquisition

Eagle Rock closed the Panhandle Acquisition on October 1, 2012, and assumed control of operations, marketing and commercial activities as scheduled on January 1, 2013. In conjunction with assuming control, the Partnership hired 78 former BP employees, comprising essentially all of the personnel who worked on the asset under BP, and integrated these personnel into Eagle Rock's existing organizational structure, including in a number of key leadership roles. The integration of the newly-acquired Panhandle assets with the Partnership's existing Panhandle assets, including procuring right-of-way and making various interconnects, is on schedule.

Update Regarding Construction of the Wheeler Cryogenic Processing Plant

Construction of the Wheeler 60 MMcf/d cryogenic processing plant (the "Wheeler Plant"), located in Wheeler County, and associated gathering and compression infrastructure, is expected to be completed in the second quarter of 2013 at a cost of approximately $63 million, of which $40.2 million had been spent through December 31, 2012. Upon completion of the Wheeler Plant, the Partnership will have over 540 MMcf/d of high-efficiency processing capacity in the Texas Panhandle to serve continued drilling activity in the Granite Wash and surrounding geological plays.

Year-End Proved Reserves

Eagle Rock estimates its proved reserves at year-end 2012 totaled 58.3 MMBOE, down approximately 6% from year-end 2011. Reserves were lower primarily due to the sale of its non-core position in the Barnett Shale in December 2012, and to negative revisions to its gas reserves as a result of lower natural gas prices, which combined were greater than the increases to reserves related to extensions and discoveries and positive well performance. Due to lower natural gas prices throughout 2012, the Partnership reduced its proved reserves by approximately 7.0 MMBOE which represents approximately 11% of its 2011 year-end total proved reserves. Total production for 2012 was 5.05 MMBOE, or 13.8 Mboe/d, an increase of 25% from total production in 2011. The Partnership replaced 174% of its 2012 production through its drilling activity at a unit development cost of $22.08 / Boe. Approximately 76% of the Partnership's total proved reserves as of December 31, 2012 were classified as proved developed.

Update on Upstream Drilling Activity

During 2012, the Partnership participated in the drilling and completion of 33 total wells, of which 11 were proved undeveloped locations and 12 were operated by the Partnership. Drilling activity was concentrated in the Mid-Continent region, primarily in the Cana and Cana Southeast Shale plays and Golden Trend Field of western Oklahoma. In addition, during 2012, the Partnership participated in recompletion and workover projects on 32 wells, of which 31 were operated by the Partnership.

Fourth Quarter 2012 Financial and Operating Results

The Midstream Business's financial results are reported in the following segments: (i) Texas Panhandle, (ii) East Texas and Other Midstream, which consolidates Eagle Rock's former East Texas/Louisiana, South Texas and Gulf of Mexico segments, and (iii) Marketing and Trading, which is a new reporting segment. The Partnership's Upstream segment and functional (Corporate) segments remained unchanged from what had been previously reported.

The following discussion of Eagle Rock's operating income by business segment compares the Partnership's financial results in the fourth quarter of 2012 to those of the third quarter of 2012. The Partnership believes comparing these periods is more illustrative of current operating trends than comparing the current quarter to results achieved in the fourth quarter of 2011. Please refer to the financial tables at the end of this release for further detailed information.

Midstream Business – Operating income from continuing operations, excluding the impact of impairments, for the Midstream Business in the fourth quarter of 2012 increased by approximately $6.5 million, or 138%, compared to the third quarter of 2012, despite lower average realized prices for NGLs and condensate. This increase was attributable to the additional volumes and associated cash flows from the Panhandle Acquisition, which closed on October 1, 2012 and contributed approximately $6.8 million of EBITDA to the Partnership in the fourth quarter of 2012, and to improved run-times and recoveries at certain of the Partnership's processing plants.

In the Texas Panhandle, gathered volumes were up 103%, with combined equity NGL and condensate volumes up approximately 83%, compared to the third quarter of 2012. Gathering, NGL and condensate volumes were higher as compared to the third quarter 2012 due primarily to the additional volumes from the Panhandle Acquisition.

In the Partnership's East Texas and Other Midstream segment, gathered volumes were down 12.3%, with equity NGL and condensate volumes up approximately 1%, compared to the third quarter of 2012. The decrease in gathered volumes was due to natural declines in the production of existing wells and loss of production in the Gulf of Mexico due to Hurricane Isaac. Partially offsetting the declines, gathered volumes in the Partnership's systems which service the liquids-rich Austin Chalk play in East Texas increased approximately 2% as compared to the third quarter of 2012, which also led to the slight increase in combined NGL and condensate equity volumes relative to the third quarter of 2012.

As previously disclosed, the Yscloskey Plant in Louisiana, in which Eagle Rock has a non-operated ownership interest, suffered significant damage from Hurricane Isaac in August 2012. The Yscloskey Plant has been shut down since that time and is expected to remain shut down for an indefinite period of time. Gathering volumes associated with the Yscloskey Plant for the first six months of 2012 averaged approximately 52 MMcf/d. The Yscloskey Plant contributed approximately $0.5 million of EBITDA to the Partnership for the first six months of 2012.

The Marketing and Trading segment includes the financial results of the Partnership's crude oil and condensate marketing, and natural gas marketing and trading subsidiaries. Eagle Rock's crude oil and condensate marketing subsidiary was created in 2010 to develop and implement marketing uplift strategies surrounding crude and condensate in Alabama and in the Texas Panhandle. Eagle Rock's natural gas marketing and trading subsidiary was created in 2011 to capitalize on physical and financial natural gas marketing and trading opportunities that extend from the Partnership's upstream and midstream assets. Operating income for the Marketing and Trading segment in the fourth quarter of 2012, including intercompany sales and intersegment cost of sales, increased by approximately $0.5 million compared to the third quarter of 2012.

Upstream Business - Operating income for Eagle Rock's Upstream Business in the fourth quarter of 2012, excluding the impact of impairments, decreased by approximately $2.0 million, or 13%, compared to the third quarter of 2012. The decrease was primarily due to lower production during the quarter associated with the Partnership's scheduled turnaround at its BEC facility; lower crude oil, NGLs and sulfur prices; and the sale of its non-core Barnett assets (for $15 million) on December 20, 2012. Production volumes in the Upstream Business averaged 77.9 MMcfe/d during the quarter, a decrease of approximately 10% from the third quarter of 2012. The Partnership estimates the scheduled turnaround negatively impacted its EBITDA during the quarter by approximately $6.0 million and its average production for the quarter by 4.2 MMcfe/d.

The Partnership, through its subsidiaries, has successfully completed the first phase of the emissions reduction project at its BEC processing facility in Southern Alabama. The project was initiated in December of 2011 to comply with the required step-down in SO2 emissions under the existing environmental permit. 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 has resulted in increased sulfur recovery and reductions in SO2 emissions to levels well below the current permitted levels. The next phase of the project involves potential upgrades to the existing sulfur recovery unit to further improve sulfur recoveries and further reduce SO2 emissions. In the first of these planned upgrades, Eagle Rock expects to replace the incinerator portion of the sulfur recovery unit in 2014 at a cost of $15 million. The final upgrades will be completed in 2016. Eagle Rock expects to recognize operational cost savings and improve the overall reliability of the BEC facility in addition to recovering more of the marketable elemental sulfur from the well stream as a result of the emissions project.

Corporate Segment – Operating loss for the Corporate segment, excluding the impact of unrealized derivative gains and losses, was $2.3 million for the fourth quarter of 2012 as compared to a $4.3 million loss for the third quarter of 2012. The lower loss was attributable to a decrease in intercompany eliminations due to lower inventory balances at the end of the fourth quarter, partially offset by a $2.9 million reduction in realized commodity derivative gains and an approximate $800,000 increase in General and Administrative expenses for the fourth quarter.

Total revenue for the fourth quarter of 2012, including the impact of Eagle Rock's realized and unrealized commodity derivative gains and losses, was $312.4 million, up 91% compared with the $163.4 million reported for the third quarter of 2012. The increase in revenue was primarily due to the Panhandle Acquisition, which closed on October 1, 2012, and to lower unrealized losses on commodity derivatives compared to the third quarter of 2012. Eagle Rock recorded an unrealized loss on commodity derivatives of $6.9 million in the fourth quarter 2012, as compared to an unrealized loss on commodity derivatives of $51.3 million in the third quarter 2012. Unrealized gain (loss) on commodity derivatives is a non-cash, mark-to-market amount.

Revenues associated with the sale of crude oil, natural gas, NGLs, condensate and sulfur were up 54% relative to the third quarter of 2012, driven primarily by increased volumes from the Panhandle Acquisition and higher average realized natural gas prices. Adjusted EBITDA was $66.2 million, up 12% from the third quarter of 2012, and Distributable Cash Flow was $29.5 million for the fourth quarter of 2012, up 9% as compared to the third quarter of 2012. The increase in Distributable Cash Flow was primarily attributable to higher Adjusted EBITDA, partially offset by higher interest expense following the senior notes issuance in July 2012 and by higher maintenance capital spending. The Partnership recorded $18.6 million of maintenance capital in the fourth quarter of 2012, an increase of $2.6 million as compared to the third quarter of 2012. Of the fourth quarter 2012 maintenance capital, $6.2 million was related to the scheduled Alabama facility upgrades discussed above.

The Partnership recorded a net loss of approximately $55.2 million for the fourth quarter of 2012, versus a net loss of $106.9 million for the third quarter of 2012. The net loss was driven primarily by impairment charges of $54.2 million taken during the quarter. Net income for the quarter excluding the impact of impairments and unrealized gains and losses was approximately $4.8 million. The Partnership incurred impairment charges in its Upstream Business related to its proved properties in East Texas and the Permian Basin due to reduced cash flow resulting from lower natural gas prices and relatively high operating costs associated with gas compression. In addition, the Partnership recorded a loss on the sale of its non-core Barnett Shale properties, which closed on December 20, 2012. The Partnership also incurred impairment charges in its Midstream Business related to its Central Gathering System in East Texas, and to reduced drilling activity in the Gulf of Mexico impacting the Partnership's North Terrebonne processing plant, in which Eagle Rock has a non-operated ownership interest.

Fourth Quarter Distribution

On January 28, 2013, the Partnership declared a cash distribution on common units (including restricted common units) of $0.22 per unit for the quarter ended December 31, 2012, equivalent to $0.88 per unit on an annualized basis. This distribution is equal to the distribution paid for the third quarter 2012 and represents a 5% increase from the distribution paid for the fourth quarter of 2011. As declared, the distribution was paid on Thursday, February 14, 2013, on units and to unitholders of record as of the close of business on Thursday, February 7, 2013.

Full Year 2012 Financial and Operating Results

Total revenue for 2012, including the impact of Eagle Rock's realized and unrealized derivative gains and losses, was $984.0 million, down 7% compared with $1.1 billion reported for 2011. The largest contributor to the decrease in total revenue was the lower average realized NGL and natural gas prices. Revenues associated with the sale of crude oil, natural gas, NGLs, condensate and sulfur were down 12% relative to those in 2011. Total revenue in 2012 included a realized gain on commodity derivatives of $51.3 million, as compared to a realized loss of $20.4 million in 2011. The Partnership recorded an unrealized gain on commodity derivatives of $6.6 million in 2012, as compared to an unrealized gain on commodity derivatives of $52.9 million in 2011.

Adjusted EBITDA was $245.8 million and Distributable Cash Flow was $129.0 million in 2012 as compared to $208.2 million and $119.3 million, respectively, in 2011. The Partnership recorded a net loss of approximately $150.6 million for the full year of 2012, versus net income of $73.1 million for the full year of 2011. The net loss in 2012 was driven primarily by impairment charges of $177.0 million taken during the year. Net income for the year excluding the impact of impairments and unrealized gains or losses was approximately $14.3 million.

With regard to the Partnership's Midstream Business operations, gas gathering volumes were down 1%, and combined NGL and condensate volumes were up 5% for the year, as compared to those in 2011. The impact of the increased NGL and condensate volumes were offset by lower average realized prices for NGLs, which were down 29%, as compared to NGL prices in 2011.

With regard to the Partnership's Upstream Business operations, total production was up 25% as compared to production in 2011, primarily due to a full year of production from the Partnership's Mid-Continent assets, which were acquired on May 3, 2011.

Capitalization and Liquidity Update

Total debt outstanding as of December 31, 2012 was $1.15 billion, consisting of $544.6 million of senior unsecured notes (net of an unamortized debt discount of $5.4 million) and borrowings of $608.5 million under the Partnership's senior secured credit facility. Total debt increased during the fourth quarter of 2012, primarily due to borrowings to fund the Panhandle Acquisition, the construction of the Wheeler Plant and the Partnership's Upstream drilling program.

On December 28, 2012, the Partnership received increased commitments from its lending group under its senior secured credit facility. Total commitments increased from $675 million to $820 million, supported by the Partnership's existing lenders and by the addition of Whitney Bank to the lending group. Concurrent with the increase in commitments, the Partnership and lending group amended the senior secured 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." Total Leverage Ratio, Senior Secured Leverage Ratio, and other Investments are each defined in the senior secured credit agreement.

The Partnership is in compliance with its financial covenants and has no maturities under its senior secured credit facility until June 2016. Availability under the Partnership's senior secured credit facility is subject to a borrowing base comprised of two components: the upstream component and the midstream component. As of December 31, 2012, the Partnership had approximately $192.5 million of availability under its senior secured credit facility, based on its outstanding commitments, after taking into account $608.5 million of outstanding borrowings and approximately $19.1 million of outstanding letters of credit.

The current capital budget for 2013 is approximately $208 million, which includes $88 million allocated to the Midstream Business and $118 million allocated to the Upstream Business (with the remainder allocated to general corporate purposes). Approximately $70 million of the total capital budgeted is expected to be classified as maintenance capital.

As of December 31, 2012, the Partnership had 147.3 million common units outstanding, including unvested restricted common units issued under its Long-Term Incentive Plan.

Hedging Update

The Partnership entered into the following commodity hedges since its last hedging update on October 31, 2012:

Transaction Date Product / (Type) Quantity Price ($/Bbl) Term
1/10/13 WTI Crude 40,000 $90.15 Cal. 2015
(Swap) Bbls/month
2/22/13 HH Natural 200,000 $4.1575 Cal. 2014 - 2016
Gas (Swap) MMBtu/month

Details of the recent hedging transactions are included in the updated Commodity Hedging Overview presentation Eagle Rock posted today, to its website. The latest presentation can be accessed by going to www.eaglerockenergy.com: select Investor Relations, then select Presentations.

Fourth Quarter and Full-Year 2012 Conference Call Information

Eagle Rock will hold a conference call to discuss its fourth quarter and full year 2012 financial and operating results on Tuesday, February 26, 2013 at 2:00 p.m. Eastern Time (1:00 p.m. Central Time).

Interested parties may listen to the earnings conference call live over the Internet or via telephone. To listen live over the Internet, participants are advised to log on to the Partnership's website at www.eaglerockenergy.com and select the "Events & Presentations" sub-tab under the "Investor Relations" tab. To participate by telephone, the call in number is 877-293-5457, conference ID 93704871. Participants are advised to dial into the call at least 15 minutes prior to the call. An audio replay of the conference call will also be available for thirty days by dialing 855-859-2056, conference ID 93704871. In addition, a replay of the audio webcast will be available by accessing the Partnership's website after the call is concluded.

About the Partnership

The Partnership is a growth-oriented master limited partnership engaged in two businesses: a) midstream, which includes (i) gathering, compressing, treating, processing and transporting natural gas; (ii) fractionating and transporting natural gas liquids (NGLs); (iii) crude oil and condensate logistics and marketing; and (iv) natural gas marketing and trading; and b) upstream, which includes exploiting, developing, and producing hydrocarbons in oil and natural gas properties.

Contacts:
Eagle Rock Energy Partners, L.P.
Jeff Wood, 281-408-1203
Senior Vice President and Chief Financial Officer
Adam Altsuler, 281-408-1350
Director, Corporate Finance and Investor Relations

Use of Non-GAAP Financial Measures

This news release and the accompanying schedules include the non-generally accepted accounting principles, or non-GAAP, financial measures of Adjusted EBITDA and Distributable Cash Flow. The accompanying non-GAAP financial measures schedules (after the financial schedules) provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measures calculated and presented in accordance with accounting principles generally accepted in the United States, or GAAP. Non-GAAP financial measures should not be considered alternatives to GAAP measures such as net income (loss), operating income (loss), cash flows from operating activities or any other GAAP measure of liquidity or financial performance.

Eagle Rock defines 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 the Partnership's 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.

Eagle Rock uses Adjusted EBITDA as a measure of its core profitability to assess the financial performance of its assets. Adjusted EBITDA also is used as a supplemental financial measure by external users of Eagle Rock's financial statements such as investors, commercial banks and research analysts. For example, the Partnership's lenders under its revolving credit facility use a variant of its Adjusted EBITDA in a compliance covenant designed to measure the viability of Eagle Rock and its ability to perform under the terms of the revolving credit facility; Eagle Rock, therefore, uses Adjusted EBITDA to measure its compliance with its revolving credit facility. Eagle Rock believes that investors benefit from having access to the same financial measures that its management uses in evaluating performance. Adjusted EBITDA is useful in determining Eagle Rock's 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 the Partnership's executed derivative instruments and is independent of its assets' performance or cash flow generating ability, Eagle Rock believes Adjusted EBITDA reflects more accurately the Partnership's ability to generate cash sufficient to pay interest costs, support its level of indebtedness, make cash distributions to its unitholders and finance its maintenance capital expenditures. Eagle Rock further believes that Adjusted EBITDA also portrays more accurately the underlying performance of its operating assets by isolating the performance of its operating assets from the impact of an unrealized, non-cash measure designed to portray the fluctuating inherent value of a financial asset. Similarly, by excluding the impact of non-recurring discontinued operations, Adjusted EBITDA provides users of the Partnership's financial statements a more accurate picture of its current assets' cash generation ability, independently from that of assets which are no longer a part of its operations.

Eagle Rock's 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 Eagle Rock. For example, the Partnership includes in Adjusted EBITDA the actual settlement revenue created from its commodity hedges by virtue of transactions undertaken by it to reset commodity hedges to prices higher than those reflected in the forward curve at the time of the transaction or to purchase puts or other similar floors despite the fact that the Partnership excludes from Adjusted EBITDA any charge for amortization of the cost of such commodity hedge reset transactions or puts. Eagle Rock has reconciled Adjusted EBITDA to the GAAP financial measure of net income (loss) at the end of this release.

Distributable Cash Flow is defined as Adjusted EBITDA minus: (i) maintenance capital expenditures; (ii) cash interest expense; (iii) cash income taxes; and (iv) the addition of losses or subtraction of gains relating to other miscellaneous non-cash amounts affecting net income (loss) for the period. Maintenance capital expenditures represent capital expenditures made to replace partially or fully depreciated assets; to meet regulatory requirements; to maintain the existing operating capacity of the Partnership's gathering, processing and treating assets or to maintain the Partnership's natural gas, NGL, crude or sulfur production.

Distributable Cash Flow is a significant performance metric used by senior management to compare cash flows generated by the Partnership (excluding growth capital expenditures and prior to the establishment of any retained cash reserves by the Board of Directors) to the cash distributions expected to be paid to unitholders. Using this metric, management can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. This financial measure also is important to investors as an indicator of whether the Partnership is generating cash flow at a level that can sustain or support an increase in quarterly distribution rates. Actual distributions are set by the Board of Directors.

The GAAP measure most directly comparable to Distributable Cash Flow is net income (loss). Eagle Rock's Distributable Cash Flow definition may not be comparable to Distributable Cash Flow or similarly titled measures of other entities, as other entities may not calculate Distributable Cash Flow (and Adjusted EBITDA, on which it builds) in the same manner as Eagle Rock. See the example given above for Adjusted EBITDA related to amortization of costs of commodity hedges, including costs of hedge reset transactions. Eagle Rock has reconciled Distributable Cash Flow to the GAAP financial measure of net income/(loss) at the end of this release.

This news release may include "forward-looking statements." All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Partnership expects, believes or anticipates will or may occur in the future are forward-looking statements and speak only as of the date on which such statement is made. These statements are based on certain assumptions made by the Partnership based on its experience and perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate under the circumstances. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Partnership. These include, but are not limited to, risks related to volatility of commodity prices; market demand for crude oil, natural gas and natural gas liquids; the effectiveness of the Partnership's hedging activities; the Partnership's ability to retain key customers; the Partnership's ability to continue to obtain new sources of crude oil and natural gas supply; the availability of local, intrastate and interstate transportation systems and other facilities to transport crude oil, natural gas and natural gas liquids; competition in the oil and gas industry; the Partnership's ability to obtain credit and access the capital markets; general economic conditions; and the effects of government regulations and policies. Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, the Partnership's actual results and plans could differ materially from those implied or expressed by any forward-looking statements. The Partnership assumes no obligation to update any forward-looking statement as of any future date. For a detailed list of the Partnership's risk factors, please consult the Partnership's Form 10-K, filed with the Securities and Exchange Commission ("SEC") for the year ended December 31, 2011 and the Partnership's Forms 10-Q filed with the SEC for subsequent quarters, as well as any other public filings, including, when filed, the Partnership's Form 10-K for the year ended December 31, 2012, and press releases.

Eagle Rock Energy Partners, L.P.
Consolidated Statement of Operations
($ in thousands)
(unaudited)


Three Months Ended


Twelve Months Ended
Three
Months
Ended
December 31, December 31, September 30,
2012 2011 2012 2011 2012
REVENUE:
Natural gas, natural gas liquids, oil, condensate and sulfur sales $ 284,732 $ 245,461 $ 864,884 $ 977,952 $ 184,494
Gathering, compression, processing and treating fees 21,265 10,654 56,831 47,770 13,604
Unrealized commodity derivative (losses) gains (6,864) (33,288) 6,562 52,876 (51,305)
Realized commodity derivative losses 12,904 (2,408) 51,332 (20,366) 15,802
Other revenue 374 270 4,350 1,676 794
Total revenue 312,411 220,689 983,959 1,059,908 163,389
COSTS AND EXPENSES:
Cost of natural gas and natural gas liquids 193,921 146,898 532,719 633,184 110,430
Operations and maintenance 38,143 26,725 119,828 93,048 27,074
Taxes other than income 4,914 6,087 19,432 19,148 4,748
General and administrative 17,610 14,145 69,994 57,891 16,807
Other operating income -- -- -- (2,893) --
Impairment 54,179 1,534 177,003 16,288 55,900
Depreciation, depletion and amortization 43,002 41,297 161,045 131,611 40,395
Total costs and expenses 351,769 236,686 1,080,021 948,277 255,354
OPERATING (LOSS) INCOME (39,358) (15,997) (96,062) 111,631 (91,965)
OTHER INCOME (EXPENSE):
Interest expense, net (16,391) (10,043) (51,478) (29,622) (14,199)
Realized interest rate derivative losses (1,649) (3,622) (10,227) (16,996) (1,733)
Unrealized interest rate derivative (losses) gains 1,082 3,404 5,500 5,595 615
Other (expense) income 6 (17) (38) (184) 1
Total other income (expense) (16,952) (10,278) (56,243) (41,207) (15,316)
(LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (56,310) (26,275) (152,305) 70,424 (107,281)
INCOME TAX BENEFIT (1,147) (622) (1,703) (2,432) (386)
(LOSS) INCOME FROM CONTINUING OPERATIONS (55,163) (25,653) (150,602) 72,856 (106,895)
DISCONTINUED OPERATIONS, NET OF TAX -- 66 -- 276 --
NET (LOSS) INCOME $ (55,163) $ (25,587) $ (150,602) $ 73,132 $ (106,895)
Eagle Rock Energy Partners, L.P.
Consolidated Balance Sheets
($ in thousands)
(unaudited)
December 31,
2012
December 31,
2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 25 $ 877
Accounts receivable 138,732 97,832
Risk management assets 33,340 13,080
Prepayments and other current assets 9,867 13,739
Total current assets 181,964 125,528
PROPERTY, PLANT AND EQUIPMENT - Net 1,968,206 1,763,674
INTANGIBLE ASSETS - Net 111,515 109,702
DEFERRED TAX ASSET 1,656 1,432
RISK MANAGEMENT ASSETS 7,953 24,290
OTHER ASSETS 22,922 21,062
TOTAL ASSETS $ 2,294,216 $ 2,045,688
LIABILITIES AND MEMBERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 160,473 $ 145,985
Accrued liabilities 19,764 12,734
Taxes payable 46 487
Risk management liabilities 1,231 11,649
Total current liabilities 181,514 170,855
LONG-TERM DEBT 1,153,103 779,453
ASSET RETIREMENT OBLIGATIONS 44,814 33,303
DEFERRED TAX LIABILITY 43,000 45,216
RISK MANAGEMENT LIABILITIES 1,700 6,893
OTHER LONG TERM LIABILITIES 1,711 2,621
MEMBERS' EQUITY 868,374 1,007,347
TOTAL LIABILITIES AND MEMBERS' EQUITY $ 2,294,216 $ 2,045,688
Eagle Rock Energy Partners, L.P.
Segment Summary
Operating Income
($ in thousands)
(unaudited)


Three Months Ended


Year Ended
Three
Months
Ended
December 31, December 31, September 30,
2012 2011 2012 2011 2012
Midstream
Revenues:
Natural gas, natural gas liquids, oil and condensate sales $ 248,153 $ 198,582 $ 716,508 $ 823,521 $ 147,099
Intercompany sales - natural gas (2,325) (4,084) (10,134) (5,487) (2,846)
Gathering and treating services 21,265 10,654 56,831 47,770 13,604
Other revenue -- -- 2,864 -- --
Total revenue 267,093 205,152 766,069 865,804 157,857
Cost of natural gas, natural gas liquids, oil and condensate (1) 194,004 146,898 532,802 633,184 110,430
Intersegment elimination - Cost of natural gas, oil and condensate 11,705 11,565 44,317 41,382 8,598
Operating costs and expenses:
Operations and maintenance 29,470 16,458 82,648 64,539 17,647
Impairment 29,735 -- 131,714 4,560 35,840
Depreciation, depletion and amortization 20,760 16,413 70,495 64,663 16,488
Total operating costs and expenses 79,965 32,871 284,857 133,762 69,975
Operating income from continuing operations (18,581) 13,818 (95,907) 57,476 (31,146)
Discontinued Operations (2) -- 66 -- (128) --
Operating income (loss) $ (18,581) $ 13,884 $ (95,907) $ 57,348 $ (31,146)
Upstream
Revenue
Oil and condensate sales $ 14,332 $ 17,775 $ 58,420 $ 51,574 $ 14,376
Intersegment sales - condensate 8,778 12,741 43,004 42,716 11,431
Natural gas sales 9,631 9,854 32,105 42,551 8,324
Intersegment sales - natural gas 2,530 4,084 10,339 5,487 2,846
Natural gas liquids sales 9,771 14,278 43,831 42,553 10,979
Sulfur sales 2,845 4,972 14,020 17,753 3,716
Other 374 270 1,486 1,676 794
Total revenue 48,261 63,974 203,205 204,310 52,466
Operating costs and expenses:
Operations and maintenance (2) (3) 13,709 16,354 56,734 47,723 14,175
Impairment 24,444 1,534 45,289 11,728 20,060
Depreciation, depletion and amortization 21,707 24,485 88,777 65,531 23,484
Total operating costs and expenses 59,860 42,373 190,800 124,982 57,719
Operating income $ (11,599) $ 21,601 $ 12,405 $ 79,328 $ (5,253)
Corporate and Other
Revenues:
Unrealized commodity derivative (losses) gains $ (6,864) $ (33,288) $ 6,562 $ 52,876 $ (51,305)
Realized commodity derivative losses 12,904 (2,408) 51,332 (20,366) 15,802
Intersegment elimination - Sales of natural gas, oil and condensate (8,983) (12,741) (43,209) (42,716) (11,431)
Total revenue (2,943) (48,437) 14,685 (10,206) (46,934)
Costs and expenses:
Intersegment elimination - Cost of natural gas, oil and condensate (11,788) (11,565) (44,400) (41,382) (8,598)
General and administrative 17,610 14,145 69,994 57,891 16,807
Intersegment elimination - Operations and maintenance (122) -- (122) (66) --
Other operating Income -- -- -- (2,893) --
Depreciation, depletion and amortization 535 399 1,773 1,417 423
Operating (loss) income $ (9,178) $ (51,416) $ (12,560) $ (25,173) $ (55,566)
(1) Includes natural gas sales of $83 from the Upstream Segment to the Panhandle Segment for the year ended December 31, 2012.
(2) Includes natural gas sales of $66 from the East Texas and Other Midstream Texas Segment to the Upstream Segment for the year ended December 31, 2011.
(3) Includes natural gas sales of $122 from the Marketing and Trading Segment to the Upstream Segment for the year ended December 31, 2012.
Eagle Rock Energy Partners, L.P.
Midstream Segment
Operating Income
($ in thousands)
(unaudited)


Three Months Ended


Year Ended
Three
Months
Ended
December 31, December 31, September 30,
2012 2011 2012 2011 2012
Texas Panhandle
Revenues:
Natural gas, natural gas liquids, oil and condensate sales $ 145,065 $ 74,104 $ 334,295 $ 378,917 $ 60,213
Intersegment sales - natural gas 33,245 33,990 105,759 60,237 28,025
Gathering, compression, processing and treating services 12,233 4,169 25,743 17,074 4,708
Other revenue -- -- 2,864 -- --
Total revenue 190,543 112,263 468,661 456,228 92,946
Cost of natural gas, natural gas liquids, oil and condensate (1) 143,172 80,263 332,875 327,775 67,098
Operating costs and expenses:
Operations and maintenance 23,542 10,315 60,884 41,749 12,705
Impairment -- -- -- 4,560 --
Depreciation, depletion and amortization 14,897 9,652 44,451 37,034 10,164
Total operating costs and expenses 38,439 19,967 105,335 83,343 22,869
Operating income $ 8,932 $ 12,033 $ 30,451 $ 45,110 $ 2,979
East Texas and Other Midstream
Revenues:
Natural gas, natural gas liquids, oil and condensate sales $ 27,114 $ 49,888 $ 125,512 $ 243,673 $ 26,130
Intercompany Sales 12,628 12,324 39,099 16,654 10,020
Gathering, compression, processing and treating services 8,961 6,477 31,017 30,688 8,896
Total revenue 48,703 68,689 195,628 291,015 45,046
Cost of natural gas and natural gas liquids 36,290 55,440 147,493 231,642 33,145
Operating costs and expenses:
Operations and maintenance 5,929 6,145 21,762 22,790 4,940
Impairment 29,735 -- 131,714 -- 35,840
Depreciation, depletion and amortization 5,737 6,761 25,771 27,629 6,232
Total operating costs and expenses 41,401 12,906 179,247 50,419 47,012
Operating income (loss) from continuing operations (28,988) 343 (131,112) 8,954 (35,111)
Discontinued Operations (2) -- 66 -- (128) --
Operating income (loss) $ (28,988) $ 409 $ (131,112) $ 8,826 $ (35,111)
Marketing and Trading
Revenues:
Natural gas, natural gas liquids, oil and condensate sales $ 75,974 $ 74,590 $ 256,701 $ 200,931 $ 60,756
Intercompany Sales (48,198) (50,398) (154,992) (82,378) (40,891)
Gathering, compression, processing and treating services 71 8 71 8 --
Total revenue 27,847 24,200 101,780 118,561 19,865
Cost of natural gas and natural gas liquids 14,542 11,195 52,434 73,767 10,187
Intersegment Cost of Sales 11,705 11,565 44,317 41,382 8,598
Operating costs and expenses:
Operations and maintenance (1) (2) 2 -- 2
Depreciation, depletion and amortization 126 -- 273 -- 92
Total operating costs and expenses 125 (2) 275 -- 94
Operating income $ 1,475 $ 1,442 $ 4,754 $ 3,412 $ 986
(1) Includes natural gas sales of $83 from the Upstream Segment to the Panhandle Segment for the year ended December 31, 2012.
(2) Includes natural gas sales of $66 from the East Texas and Other Midstream Texas Segment to the Upstream Segment for the year ended December 31, 2011.
Eagle Rock Energy Partners, L.P.
Midstream Operations Information
(unaudited)


Three Months Ended


Year Ended
Three
Months
Ended
December 31, December 31, September 30,
2012 2011 2012 2011 2012
Gas gathering volumes - (Average Mcf/d)
Texas Panhandle 372,124 158,419 212,617 155,122 183,415
East Texas and Other Midstream 217,496 286,920 255,752 319,892 248,094
Total 589,620 445,339 468,369 475,014 431,509
NGLs - (Net equity Bbls)
Texas Panhandle 415,103 271,252 1,270,601 880,348 228,696
East Texas and Other Midstream 80,315 105,793 338,636 451,048 81,997
Total 495,418 377,045 1,609,237 1,331,396 310,693
Condensate - (Net equity Bbls)
Texas Panhandle 302,168 238,172 801,828 962,982 164,246
East Texas and Other Midstream 9,613 10,816 38,350 46,242 7,010
Total 311,781 248,988 840,178 1,009,224 171,256
Natural gas short position - (Average MMbtu/d)
Texas Panhandle 16,114 (5,932) 547 (5,622) (990)
East Texas and Other Midstream 1,676 1,765 1,530 1,913 392
Total 17,790 (4,167) 2,077 (3,709) (598)
Average realized NGL price - per Bbl
Texas Panhandle $ 31.39 $ 46.25 $ 36.00 $ 52.67 $ 36.23
East Texas and Other Midstream $ 32.04 $ 46.03 $ 37.83 $ 49.72 $ 32.24
Weighted Average $ 31.51 $ 46.16 $ 36.56 $ 51.42 $ 34.89
Average realized condensate price - per Bbl
Texas Panhandle $ 74.32 $ 75.04 $ 82.64 $ 80.41 $ 81.08
East Texas and Other Midstream $ 87.20 $ 98.08 $ 96.91 $ 95.08 $ 91.57
Total $ 75.20 $ 76.52 $ 83.78 $ 81.56 $ 81.82
Average realized natural gas price - per MMbtu
Texas Panhandle $ 3.23 $ 3.24 $ 2.63 $ 3.74 $ 2.64
East Texas and Other Midstream $ 3.37 $ 3.42 $ 2.85 $ 4.15 $ 2.85
Total $ 3.26 $ 3.31 $ 2.79 $ 3.91 $ 2.71
Eagle Rock Energy Partners, L.P.
Upstream Operations Information
(unaudited)


Three Months Ended


Year Ended
Three
Months
Ended
December 31, December 31, September 30,
2012 2011 2012 2011 2012
Upstream
Production:
Oil and condensate (Bbl) 283,326 345,428 1,184,200 1,117,778 310,349
Gas (Mcf) 3,828,320 4,363,298 16,442,579 12,636,473 4,177,156
NGLs (Bbl) 272,476 272,136 1,120,522 805,359 301,644
Total Mcfe 7,163,132 8,068,682 30,270,911 24,175,295 7,849,114
Sulfur (long ton) 22,892 26,862 102,002 98,372 28,414
Realized prices, excluding derivatives:
Oil and condensate (per Bbl) $ 81.57 $ 88.34 $ 85.65 $ 84.36 $ 83.16
Gas (Mcf) $ 3.18 $ 3.19 $ 2.58 $ 3.69 $ 2.67
NGLs (Bbl) $ 35.86 $ 52.47 $ 39.12 $ 54.58 $ 36.40
Sulfur (long ton) $ 124.30 $ 185.08 $ 137.46 $ 180.46 $ 130.77
Operating statistics:
Operating costs per Mcfe (incl production taxes) (1) $ 1.72 $ 1.86 $ 1.69 $ 1.88 $ 1.60
Operating costs per Mcfe (excl production taxes) (1) $ 1.22 $ 1.25 $ 1.19 $ 1.24 $ 1.11
Operating income per Mcfe $ 1.02 $ 3.39 $ 1.03 $ 3.52 $ (0.67)
Drilling program (gross wells):
Development wells 8 10 33 42 6
Completions 8 10 33 42 6
Workovers 2 1 21 14 10
Recompletions 4 1 11 9 4
(1) Excludes post-production costs of $1,410 and $5,478 for the three months and year ended December 31, 2012, respectively, $1,359 and $2,390 for the three months and year ended December 31, 2011, respectively, and $1,601 for the three months ended September 30, 2012.

Non-GAAP Financial Measures

The following tables present a reconciliation of the non-GAAP financial measures of Adjusted EBITDA and Distributable Cash Flow to the GAAP financial measure of net income for each of the periods indicated (in thousands).

Eagle Rock Energy Partners, L.P.
GAAP to Non-GAAP Reconciliations
($ in thousands)
(unaudited)

Three Months Ended

Year Ended
Three Months Ended
December 31, December 31, September 30,
2012 2011 2012 2011 2012
Net (loss) income to Adjusted EBITDA
Net (loss) income, as reported $ (55,163) $ (25,587) $ (150,602) $ 73,132 $ (106,895)
Depreciation, depletion and amortization 43,002 41,297 161,045 131,611 40,395
Impairment 54,179 1,534 177,003 16,288 55,900
Risk management interest related instruments - unrealized (1,082) (3,404) (5,500) (5,595) (615)
Risk management commodity related instruments - unrealized, including amortization of commodity derivative costs 6,864 33,288 (6,562) (52,876) 51,305
Other Operating Income -- -- -- (2,893) --
Non-cash mark-to-market of Upstream product imbalances (21) 197 317 74 229
Unrealized gains from other derivative activity (235) (234) 192 (772) 157
Restricted units non-cash amortization expense 1,790 1,704 9,882 5,145 3,080
Income tax (benefit) provision (1,147) (622) (1,703) (2,432) (386)
Interest - net including realized risk management instruments and other expense 18,040 13,665 61,705 46,618 15,932
Other income (6) 17 38 184 (1)
Discontinued operations -- (66) -- (276) --
Adjusted EBITDA $ 66,221 $ 61,789 $ 245,815 $ 208,208 $ 59,101
Net (loss) income to Distributable Cash Flow
Net (loss) income, as reported $ (55,163) $ (25,587) $ (150,602) $ 73,132 $ (106,895)
Depreciation, depletion and amortization expense 43,002 41,297 161,045 131,611 40,395
Impairment 54,179 1,534 177,003 16,288 55,900
Risk management interest related instruments-unrealized (1,082) (3,404) (5,500) (5,595) (615)
Risk management commodity related instruments - unrealized, including amortization of commodity derivative costs 6,629 33,054 (6,370) (53,648) 51,462
Capital expenditures-maintenance related (18,593) (12,426) (54,417) (40,855) (15,982)
Non-cash mark-to-market of Upstream product imbalances (21) 197 317 74 229
Restricted units non-cash amortization expense 1,790 1,704 9,882 5,145 3,080
Other Operating Income -- -- -- (2,893) --
Income tax (benefit) provision (1,147) (622) (1,703) (2,432) (386)
Other income (6) -- 38 -- --
Cash income taxes (75) (489) (737) (1,291) (185)
Discontinued operations -- (66) -- (276) --
Distributable Cash Flow $ 29,513 $ 35,192 $ 128,956 $ 119,260 $ 27,003

Source:Eagle Rock Energy Partners, L.P.

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Price
 
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