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Eagle Rock Reports Second Quarter Financial Results

HOUSTON, July 31, 2013 (GLOBE NEWSWIRE) -- Eagle Rock Energy Partners, L.P. ("Eagle Rock" or the "Partnership") (Nasdaq:EROC) today announced its unaudited financial results for the three months ended June 30, 2013. Financial results with respect to second quarter 2013 included the following:

  • Reported Adjusted EBITDA of $55.9 million, an increase of approximately 4% as compared to the $53.6 million reported for the first quarter of 2013.
  • Reported Distributable Cash Flow of $22.8 million, an increase of approximately 3% as compared to the $22.2 million reported for the first quarter of 2013.
  • Announced a quarterly distribution with respect to the second quarter of 2013 of $0.22 per common unit, equal to the first quarter 2013 distribution.
  • Reported Net Income of $16.0 million, as compared to a Net Loss of $33.5 million for the first quarter of 2013.

Other notable financial and operational activities that occurred during the second quarter of 2013 included the following:

  • Startup of its 60 MMcf/d cryogenic processing facility in Wheeler County, Texas, in the heart of the prolific Granite Wash play (the "Wheeler Plant").
  • Execution of a new, fee-based gas gathering and processing agreement with Monarch Natural Gas, LLC ("Monarch"), under which Monarch has dedicated to the Partnership all of its gathered natural gas volume from wells within an area encompassing more than 150,000 gross acres, located in Hemphill, Lipscomb and Ochiltree counties, Texas.
  • Amendment of its existing senior secured credit facility to allow for a temporary step-up in the Total Leverage Ratio and the Senior Secured Leverage Ratio through the third quarter of 2014.

"Second quarter results were below our expectations due primarily to the weak NGL price environment and lower than anticipated volume growth in both businesses," said Joseph A. Mills, Eagle Rock's Chairman and Chief Executive Officer. "However, we are seeing positive results from drilling activity on our new acreage dedications in the Midstream Business, synergies associated with our BP acquisition and recent drilling activity in the Upstream Business."

"In addition, we appreciate the continued support of our lender group who recently approved an amendment to our senior secured credit facility which substantially enhances our financial flexibility so we may continue to pursue organic growth opportunities," stated Mills.

Second Quarter 2013 Financial and Operating Results

The Partnership's financial results are reported in the following segments: (a) the Midstream Business -- Texas Panhandle; (b) the Midstream Business -- East Texas and Other Midstream; (c) the Midstream Business -- Marketing and Trading; (d) the Upstream Business; and (e) the Corporate Segment.

The following discussion of the Partnership's operating income by business segment compares the Partnership's financial results in the second quarter of 2013 to those of the first quarter of 2013. Please refer to the financial tables at the end of this release for further detailed information.

Midstream Business – Operating income from continuing operations for the Midstream Business in the second quarter of 2013 increased by approximately $0.7 million, or approximately 10%, compared to the first quarter of 2013. This increase was due to higher natural gas, NGL, and condensate volumes and higher average realized prices for natural gas. These factors were partially offset by lower average realized prices for NGLs and condensate.

In the Texas Panhandle, gathered volumes were up 2%, with combined equity NGL and condensate volumes up approximately 65%, as compared to the first quarter of 2013, on a reported basis. However, this increase was primarily due to negative adjustments and updates to estimates impacting reported equity NGL and condensate volumes in the first quarter of 2013 related to the Partnership's acquisition of BP's Sunray and Hemphill processing plants and associated 2,500 mile gathering system. Excluding the impact of these adjustments, combined equity NGL and condensate volumes for the second quarter of 2013 were down approximately 7%, as compared to the first quarter of 2013. This decrease was primarily due to the rejection of ethane for the entire second quarter of 2013 versus the rejection of ethane during a portion of the first quarter. Eagle Rock's decision to reject ethane is an economic decision based on the Partnership's contract portfolio and the price spread between ethane and natural gas.

In the Partnership's East Texas and Other Midstream segment, gathered volumes were down 3%, with equity NGL and condensate volumes up approximately 43%, compared to the first quarter of 2013, on a reported basis. This increase was due to higher gathering volumes around the Partnership's systems servicing the liquids-rich Woodbine formation in East Texas and to adjustments in measured volumes in the second quarter of 2013. Excluding the impact of these adjustments, combined equity NGL and condensate volumes for the second quarter of 2013 were up approximately 15%, as compared to the first quarter of 2013.

The Marketing and Trading segment includes the financial results of the Partnership's crude oil and condensate marketing, and natural gas marketing and trading operations. Operating income for the Marketing and Trading segment in the second quarter of 2013, including intercompany sales and intersegment cost of sales, was up approximately 2% compared to the first quarter of 2013.

Upstream Business - Operating income for Eagle Rock's Upstream Business in the second quarter of 2013, excluding the impact of impairments, increased by approximately $2.5 million, or 20%, compared to the first quarter of 2013. The increase was driven by higher oil production, lower workover expense, and higher realized natural gas prices, and was partially offset by lower NGL production and lower realized NGL prices. Total production volumes in the Upstream Business averaged 72.7 MMcfe/d during the quarter. This production rate is unchanged from the first quarter of 2013, but lower than anticipated primarily due to an additional shutdown of the Flomaton plant facility, ongoing higher than expected fuel usage at the Big Escambia Creek (BEC) facility, and certain unsuccessful recompletions.

During the quarter, Eagle Rock brought online five new operated wells in the Partnership's Golden Trend field and the South Central Oklahoma Oil Province ("SCOOP") acreage in Oklahoma. Three of these wells are located in Grady County, Oklahoma and were drilled and completed late in the second quarter. Production from these new wells is contributing to the Upstream Business' current estimated July production of 77 MMcfe/d. One of these new wells is the Partnership's third operated horizontal Woodford shale well in the SCOOP play, the Riddle 14-32H well, in which the Partnership has a 60% working interest. The well was drilled and completed at a total cost of approximately $8.2 million and began flowing to sales on June 27, 2013. During July the well has averaged 3.6 MMcf/d and 230 bopd.

Corporate Segment – Operating loss for the Corporate Segment, excluding the impact of unrealized derivative gains and losses, was $11.7 million for the second quarter of 2013 as compared to a $9.4 million loss for the first quarter of 2013. The increased loss was attributable to a $1.8 million reduction in realized commodity derivative gains and a $0.5 million increase in general and administrative expenses for the second quarter, partially offset by a decrease in intercompany eliminations.

Total revenue for the second quarter of 2013, including the impact of the Partnership's realized and unrealized commodity derivative gains and losses, was $320.2 million, up 24.2% compared with the $257.7 million reported for the first quarter of 2013. The increase in revenue was primarily due to higher unrealized gains on commodity derivatives and higher revenue from sales of natural gas, NGLs, oil, condensate, sulfur and helium compared to the first quarter of 2013. The Partnership recorded an unrealized gain on commodity derivatives of $22.3 million in the second quarter 2013, as compared to an unrealized loss on commodity derivatives of $27.9 million in the first quarter 2013. Unrealized gain (loss) on commodity derivatives is a non-cash, mark-to-market amount.

Revenues associated with the sale of natural gas, NGLs, oil, condensate, sulfur and helium were up 6% relative to the first quarter of 2013, driven primarily by the impact of higher natural gas prices and higher volumes in the Midstream Business, but partially offset by lower NGL and condensate prices. Adjusted EBITDA was $55.9 million for the second quarter of 2013, up 4% from the first quarter of 2013, and Distributable Cash Flow was $22.8 million for the second quarter of 2013, up 3% as compared to the first quarter of 2013. The increase in Distributable Cash Flow was primarily attributable to higher Adjusted EBITDA and slightly lower interest expense, partially offset by higher maintenance capital spending during the quarter. The Partnership recorded approximately $14.9 million of maintenance capital in the second quarter of 2013, an increase of $2.2 million as compared to the first quarter of 2013. Of the second quarter 2013 maintenance capital, approximately $0.8 million was related to the previously-disclosed, scheduled upgrades to the Partnership's Big Escambia Creek facility located in Southern Alabama to enhance SO2 emissions reductions, as compared to approximately $0.5 million recorded in the first quarter of 2013.

The Partnership recorded net income of approximately $16.0 million for the second quarter of 2013, versus a net loss of $33.5 million for the first quarter of 2013. The increase was driven primarily by higher unrealized commodity derivative gains in the second quarter of 2013 and higher revenues associated with the sale of natural gas, NGLs, oil, condensate, sulfur and helium during the second quarter of 2013. Net loss for the quarter excluding the impact of unrealized gains and losses and impairments was approximately $6.0 million. The Partnership incurred a $1.8 million impairment charge in its Upstream Business in the second quarter of 2013 related to certain proved properties primarily in the Permian region due to reduced cash flows resulting from lower commodity prices and continued high operating costs.

Second Quarter Distribution

On July 23, 2013, the Partnership declared a cash distribution for the quarter ended June 30, 2013 of $0.22 per unit, equivalent to $0.88 per unit on an annualized basis. The distribution will be paid on a total of 159.0 million common and eligible restricted units. The second quarter 2013 distribution is equal to the distribution paid for the first quarter 2013. Distribution coverage, calculated as distributable cash flow per unit divided by distributions per unit, was approximately 0.65 times for the second quarter, which is roughly consistent with distribution coverage in the first quarter of 2013. The distribution will be paid on Wednesday, August 14, 2013, to unitholders of record as of the close of business on Wednesday, August 7, 2013.

Capitalization and Liquidity Update

Total debt outstanding as of June 30, 2013 was $1.16 billion, consisting of $544.9 million of senior unsecured notes (net of an unamortized debt discount of $5.1 million) and borrowings of $613.0 million under the Partnership's senior secured credit facility.

On July 23, 2013, the Partnership and its lenders amended the senior secured credit facility to allow for a temporary step-up in the Total Leverage Ratio and the Senior Secured Leverage Ratio, as defined therein, through the third quarter of 2014 and the third quarter of 2013, respectively. The amendment also extends the period of time the Partnership is subject to the Senior Secured Leverage Ratio from September 30, 2013 to September 30, 2014. The amendment is effective as of June 30, 2013, and adjusts the Total Leverage Ratio and Senior Secured Leverage Ratio covenants as follows:

Total Leverage Ratio Senior Secured Leverage Ratio
Amended Previous Amended Previous
2Q13 5.50x 4.75x 3.15x 2.85x
3Q13 5.50x 4.75x 3.15x 2.85x
4Q13 5.50x 4.50x 3.15x NA
1Q14 5.25x 4.50x 3.10x NA
2Q14 5.00x 4.50x 3.05x NA
3Q14 4.75x 4.50x 2.95x NA
Thereafter 4.50x 4.50x NA NA

The Partnership is in compliance with its financial covenants and has no maturities under its senior secured credit facility until June 2016. As of June 30, 2013, the Partnership had approximately $164.4 million of availability under its senior secured credit facility, after taking into account $613.0 million of outstanding borrowings and approximately $25.3 million of outstanding letters of credit. 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. On April 17, 2013, the Partnership announced the upstream component of the borrowing base under its senior secured credit facility was decreased from $400 million to $375 million as part of the Partnership's regularly scheduled semi-annual redetermination by its commercial lenders.

The current 2013 capital budget is approximately $208 million, which includes $60 million expected to be allocated to maintenance capital expenditures and $148 million expected to be allocated to growth capital expenditures. The current 2013 capital budget includes approximately $90 million allocated to the Midstream Business and approximately $115 million allocated to the Upstream Business (with the remainder allocated to general corporate purposes). The Partnership's capital expenditures were approximately $67.4 million for the three months ended June 30, 2013, of which $14.9 million were related to maintenance capital expenditures and $52.5 million were related to growth capital expenditures.

As of June 30, 2013, the Partnership had 159.6 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 most recent hedging update on March 28, 2013:

Transaction Date Product / (Type) Quantity Price ($/Bbl) Term
6/13/2013 WTI Crude 20,000 $87.30 Cal. 2015
(Swap) Bbls/month
6/13/2013 WTI Crude 20,000 $87.28 Cal. 2015
(Swap) Bbls/month
6/13/2013 WTI Crude 20,000 $84.40 Cal. 2016
(Swap) Bbls/month
6/14/2013 WTI Crude 20,000 $84.55 Cal. 2016
(Swap) Bbls/month

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

Second Quarter 2013 Conference Call Information

The Partnership will hold a conference call to discuss its second quarter 2013 financial and operating results on Thursday, August 1, 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 web site 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 21592571. 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 21592571. 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.

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. Eagle Rock has reconciled Adjusted EBITDA to the GAAP financial measure of net income (loss) at the end of this release.

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.

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. For purposes of the foregoing, maintenance capital expenditures are intended to 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. In particular, with respect to maintenance capital expenditures intended to maintain the Partnership's natural gas, NGL, crude or sulfur production, the Partnership estimates these amounts based on current projections and expectations, and the Partnership does not undertake to adjust any historical amounts based on the actual impact of such expenditures on production. As a result, the included amount of maintenance capital expenditures could fail to maintain production if actual performance does not meet projections and expectations.

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. 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 or declines (including sustained declines) in 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, 2012 and the Partnership's Forms 10-Q filed with the SEC for subsequent quarters, including the Partnership's Form 10-Q to be filed for the quarter ended June 30, 2013, as well as any other public filings, and press releases.

Eagle Rock Energy Partners, L.P.
Consolidated Statement of Operations
($ in thousands)
(unaudited)
Three Months Ended Six Months Ended Three Months
June 30, June 30, Ended March
2013 2012 2013 2012 31, 2013
REVENUE:
Natural gas, natural gas liquids, oil, condensate, sulfur and helium sales $ 269,392 $ 172,945 $ 523,592 $ 395,658 $ 254,200
Gathering, compression, processing and treating fees 20,153 10,451 41,095 21,962 20,942
Unrealized commodity derivative gains (losses) 22,316 79,502 (5,590) 64,731 (27,906)
Realized commodity derivative gains 8,177 16,463 18,175 22,626 9,998
Other revenue 113 3,043 610 3,182 497
Total revenue 320,151 282,404 577,882 508,159 257,731
COSTS AND EXPENSES:
Cost of natural gas and natural gas liquids 185,760 97,914 365,748 228,368 179,988
Operations and maintenance 35,122 27,562 67,341 54,611 32,219
Taxes other than income 5,060 4,620 8,926 9,770 3,866
General and administrative 19,396 18,736 38,243 35,577 18,847
Impairment 1,839 21,402 1,839 66,924
Depreciation, depletion and amortization 41,157 38,354 81,394 77,648 40,237
Total costs and expenses 288,334 208,588 563,491 472,898 275,157
OPERATING INCOME (LOSS) 31,817 73,816 14,391 35,261 (17,426)
OTHER INCOME (EXPENSE):
Interest expense, net (16,609) (10,647) (33,693) (20,888) (17,084)
Realized interest rate derivative losses (1,685) (3,470) (3,336) (6,845) (1,651)
Unrealized interest rate derivative gains 1,534 2,007 3,029 3,803 1,495
Other income (expense) 113 4 105 (45) (8)
Total other expense (16,647) (12,106) (33,895) (23,975) (17,248)
INCOME (LOSS) BEFORE INCOME TAXES 15,170 61,710 (19,504) 11,286 (34,674)
INCOME TAX BENEFIT (862) (79) (2,022) (170) (1,160)
NET INCOME (LOSS) $ 16,032 $ 61,789 $ (17,482) $ 11,456 $ (33,514)
Eagle Rock Energy Partners, L.P.
Consolidated Balance Sheets
($ in thousands)
(unaudited)
June 30, 2013 December 31, 2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 95 $ 25
Accounts receivable 150,257 138,732
Risk management assets 24,202 33,340
Prepayments and other current assets 9,070 9,867
Total current assets 183,624 181,964
PROPERTY, PLANT AND EQUIPMENT - Net 2,021,705 1,968,206
INTANGIBLE ASSETS - Net 108,289 111,515
DEFERRED TAX ASSET 1,646 1,656
RISK MANAGEMENT ASSETS 17,003 7,953
OTHER ASSETS 20,675 22,922
TOTAL ASSETS $ 2,352,942 $ 2,294,216
LIABILITIES AND MEMBERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 183,464 $ 160,473
Accrued liabilities 27,278 19,764
Taxes payable 46
Risk management liabilities 2,032 1,231
Total current liabilities 212,774 181,514
LONG-TERM DEBT 1,157,923 1,153,103
ASSET RETIREMENT OBLIGATIONS 47,436 44,814
DEFERRED TAX LIABILITY 41,092 43,000
RISK MANAGEMENT LIABILITIES 3,466 1,700
OTHER LONG TERM LIABILITIES 3,102 1,711
MEMBERS' EQUITY 887,149 868,374
TOTAL LIABILITIES AND MEMBERS' EQUITY $ 2,352,942 $ 2,294,216
Eagle Rock Energy Partners, L.P.
Segment Summary
Operating Income
($ in thousands)
(unaudited)
Three Months Ended Six Months Ended Three Months
June 30, June 30, Ended March
2013 2012 2013 2012 31, 2013
Midstream
Revenues:
Natural gas, natural gas liquids, oil and condensate sales $ 231,734 $ 140,324 $ 452,229 $ 321,256 $ 220,495
Intercompany sales - natural gas and condensate (2,275) (2,113) (4,070) (4,963) (1,795)
Gathering and treating services 20,153 10,451 41,095 21,962 20,942
Other revenue 37 2,864 37 2,864
Total revenue 249,649 151,526 489,291 341,119 239,642
Cost of natural gas, natural gas liquids, oil and condensate 185,760 97,914 365,748 228,368 179,988
Intersegment cost of sales - natural gas and condensate 9,405 10,383 20,517 24,014 11,112
Operating costs and expenses:
Operations and maintenance 27,020 18,164 48,989 35,531 21,969
Impairment 20,617 66,139
Depreciation, depletion and amortization 19,087 16,565 38,018 33,247 18,931
Total operating costs and expenses 46,107 55,346 87,007 134,917 40,900
Operating income (loss) $ 8,377 $ (12,117) $ 16,019 $ (46,180) $ 7,642
Upstream
Revenue
Oil and condensate sales $ 15,756 $ 12,247 $ 28,069 $ 29,712 $ 12,313
Intersegment sales - condensate 9,220 10,306 20,506 22,795 11,286
Natural gas sales 10,355 6,832 18,536 14,150 8,181
Intersegment sales - natural gas 2,374 2,113 4,188 4,963 1,814
Natural gas liquids sales 8,596 10,340 18,872 23,081 10,276
Sulfur sales 2,951 3,202 5,886 7,459 2,935
Other 76 179 573 318 497
Total revenue 49,328 45,219 96,630 102,478 47,302
Operating costs and expenses:
Operations and maintenance 13,162 14,018 27,278 28,850 14,116
Impairment 1,839 785 1,839 785
Depreciation, depletion and amortization 21,456 21,366 42,385 43,586 20,929
Total operating costs and expenses 36,457 36,169 71,502 73,221 35,045
Operating income $ 12,871 $ 9,050 $ 25,128 $ 29,257 $ 12,257
Corporate and Other
Revenues:
Unrealized commodity derivative gains (losses) $ 22,316 $ 79,502 $ (5,590) $ 64,731 $ (27,906)
Realized commodity derivative gains 8,177 16,463 18,175 22,626 9,998
Intersegment elimination - Sales of natural gas and condensate (9,319) (10,306) (20,624) (22,795) (11,305)
Total revenue 21,174 85,659 (8,039) 64,562 (29,213)
Costs and expenses:
Intersegment elimination - Cost of natural gas and condensate (9,405) (10,383) (20,57) (24,014) (11,112)
General and administrative 19,396 18,736 38,243 35,577 18,847
Depreciation, depletion and amortization 614 423 991 815 377
Operating income (loss) $ 10,569 $ 76,883 $ (26,756) $ 52,184 $ (37,325)
Eagle Rock Energy Partners, L.P.
Midstream Segment
Operating Income
($ in thousands)
(unaudited)
Three Months Ended Six Months Ended Three Months
June 30, June 30, Ended March
2013 2012 2013 2012 31, 2013
Texas Panhandle
Revenues:
Natural gas, natural gas liquids, condensate and helium sales $ 108,505 $ 55,937 $ 214,899 $ 129,017 $ 106,394
Intersegment sales - natural gas and condensate 56,523 19,043 105,658 44,489 49,135
Gathering, compression, processing and treating services 12,031 3,852 24,552 8,802 12,521
Other revenue 37 2,864 37 2,864
Total revenue 177,096 81,696 345,146 185,172 168,050
Cost of natural gas, natural gas liquids, condensate and helium 135,296 51,117 267,522 122,605 132,226
Intersegment cost of sales - natural gas 78 97 19
Operating costs and expenses:
Operations and maintenance 22,022 12,399 39,156 24,637 17,134
Depreciation, depletion and amortization 14,005 9,873 27,850 19,390 13,845
Total operating costs and expenses 36,027 22,272 67,006 44,027 30,979
Operating income $ 5,695 $ 8,307 $ 10,521 $ 18,540 $ 4,826
East Texas and Other Midstream
Revenues:
Natural gas, natural gas liquids, and condensate sales $ 26,597 $ 30,998 $ 53,985 $ 72,268 $ 27,388
Intersegment sales - natural gas 12,705 6,928 21,243 16,451 8,538
Gathering, compression, processing and treating services 8,081 6,599 16,439 13,160 8,358
Total revenue 47,383 44,525 91,667 101,879 44,284
Cost of natural gas and natural gas liquids 36,340 32,550 69,574 78,058 33,234
Operating costs and expenses:
Operations and maintenance 5,006 5,764 9,835 10,893 4,829
Impairment 20,617 66,139
Depreciation, depletion and amortization 4,989 6,667 9,991 13,802 5,002
Total operating costs and expenses 9,995 33,048 19,826 90,834 9,831
Operating income (loss) $ 1,048 $ (21,073) $ 2,267 $ (67,013) $ 1,219
Marketing and Trading
Revenues:
Natural gas, oil and condensate sales $ 96,632 $ 53,389 $ 183,345 $ 119,971 $ 86,713
Intersegment sales - natural gas and condensate (71,503) (28,084) (130,971) (65,903) (59,468)
Gathering, compression, processing and treating services 41 104 63
Total revenue 25,170 25,305 52,478 54,068 27,308
Cost of natural gas and condensate 14,124 14,247 28,652 27,705 14,528
Intersegment cost of sales - natural gas and condensate 9,327 10,383 20,420 24,014 11,093
Operating costs and expenses:
Operations and maintenance (8) 1 (2) 1 6
Depreciation, depletion and amortization 93 25 177 55 84
Total operating costs and expenses 85 26 175 56 90
Operating income $ 1,634 $ 649 $ 3,231 $ 2,293 $ 1,597
Eagle Rock Energy Partners, L.P.
Midstream Operations Information
(unaudited)
Three Months Ended Six Months Ended Three Months
June 30, June 30, Ended March
2013 2012 2013 2012 31, 2013
Gas gathering volumes - (Average Mcf/d)
Texas Panhandle 349,681 133,590 346,224 146,749 342,346
East Texas and Other Midstream 194,704 265,472 197,164 278,961 200,700
Total 544,385 399,062 543,388 425,710 543,046
NGLs - (Net equity Bbls)
Texas Panhandle 265,538 297,688 325,800 626,802 64,551
East Texas and Other Midstream 74,620 84,981 127,605 176,325 53,204
Total 340,158 382,669 453,405 803,127 117,755
Condensate - (Net equity Bbls)
Texas Panhandle 295,204 163,320 570,874 335,414 275,692
East Texas and Other Midstream 9,100 10,403 14,299 21,727 5,226
Total 304,304 173,723 585,173 357,141 280,918
Natural gas position - (Average MMbtu/d)
Texas Panhandle 9,676 (5,629) 6,559 (6,546) 3,379
East Texas and Other Midstream (190) 3,952 14 2,031 344
Total 9,486 (1,677) 6,573 (4,515) 3,723
Average realized NGL price - per Bbl
Texas Panhandle $33.44 $38.30 $34.56 $42.40 $35.53
East Texas and Other Midstream $28.10 $39.72 $29.01 $42.53 $29.98
Weighted Average $32.41 $38.85 $33.52 $42.45 $34.51
Average realized condensate price - per Bbl
Texas Panhandle $79.83 $82.29 $80.08 $89.28 $80.34
East Texas and Other Midstream $93.29 $103.71 $93.75 $103.68 $94.25
Weighted Average $80.56 $83.90 $80.80 $90.61 $81.06
Average realized natural gas price - per MMbtu
Texas Panhandle $3.76 $1.93 $3.53 $2.19 $3.27
East Texas and Other Midstream $3.93 $2.22 $3.63 $2.59 $3.36
Weighted Average $3.81 $2.04 $3.56 $2.35 $3.29
Eagle Rock Energy Partners, L.P.
Upstream Operations Information
(unaudited)
Three Months Ended Six Months Ended Three Months
June 30, June 30, Ended March
2013 2012 2013 2012 31, 2013
Upstream
Production:
Oil and condensate (Bbl) 294,353 266,580 573,421 590,524 279,069
Gas (Mcf) 3,181,264 4,341,298 6,310,316 8,437,103 3,129,052
NGLs (Bbl) 278,158 267,673 568,024 546,404 289,866
Total Mcfe 6,616,330 7,546,811 13,158,986 15,258,666 6,542,662
Sulfur (long ton) 26,641 21,705 53,240 50,697 26,598
Realized prices, excluding derivatives:
Oil and condensate (per Bbl) $84.85 $84.60 $84.71 $88.92 $84.56
Gas (Mcf) $4.00 $2.06 $3.60 $2.27 $3.19
NGLs (Bbl) $30.90 $38.63 $33.22 $42.24 $35.45
Sulfur (long ton) $110.75 $147.55 $110.54 $147.15 $110.34
Operating statistics:
Operating costs per Mcfe (incl production taxes) (1) $1.83 $1.68 $1.89 $1.73 $1.96
Operating costs per Mcfe (excl production taxes) (1) $1.28 $1.18 $1.44 $1.21 $1.59
Operating income per Mcfe $1.95 $1.20 $1.91 $1.92 $1.87
Drilling program (gross wells):
Development wells 14 9 22 19 8
Completions 14 9 21 19 7
Workovers 11 4 18 9 7
Recompletions 6 1 7 3 1
(1) Excludes post-production costs of $1,083, $2,394, $1,319 and $2,467 for the three months ended June30, 2013 and 2012, respectively, and $1,311 for the three months ended March 31, 2013.

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 Six Months Ended Three Months
June 30, June 30, Ended March
2013 2012 2013 2012 31, 2013
Net income (loss) to Adjusted EBITDA
Net income (loss), as reported $ 16,032 $ 61,789 $ (17,482) $ 11,456 $ (33,514)
Depreciation, depletion and amortization 41,157 38,354 81,394 77,648 40,237
Impairment 1,839 21,402 1,839 66,924
Risk management interest related instruments - unrealized (1,534) (2,007) (3,029) (3,803) (1,495)
Risk management commodity related instruments - unrealized (22,475) (79,029) 5,684 (64,461) 28,159
Non-cash mark-to-market of Upstream product imbalances (5) 307 (5) 109
Restricted units non-cash amortization expense 3,520 2,818 6,167 5,012 2,647
Income tax benefit (862) (79) (2,022) (170) (1,160)
Interest - net including realized risk management instruments and other expense 18,181 14,113 36,924 27,778 18,743
Adjusted EBITDA $ 55,853 $ 57,668 $ 109,470 $ 120,493 $ 53,617
Net income (loss) to Distributable Cash Flow
Net income (loss), as reported $ 16,032 $ 61,789 $ (17,482) $ 11,456 $ (33,514)
Depreciation, depletion and amortization expense 41,157 38,354 81,394 77,648 40,237
Impairment 1,839 21,402 1,839 66,924
Risk management interest related instruments-unrealized (1,534) (2,007) (3,029) (3,803) (1,495)
Risk management commodity related instruments - unrealized (22,475) (79,029) 5,684 (64,461) 28,159
Capital expenditures-maintenance related (14,900) (11,816) (27,614) (19,842) (12,714)
Non-cash mark-to-market of Upstream product imbalances (5) 307 (5) 109
Restricted units non-cash amortization expense 3,520 2,818 6,167 5,012 2,647
Income tax benefit (862) (79) (2,022) (170) (1,160)
Cash income taxes (189) (564)
Distributable Cash Flow $ 22,772 $ 31,550 $ 44,932 $ 72,309 $ 22,160

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

Source:Eagle Rock Energy Partners, L.P.