Eagle Rock Reports Third Quarter Financial Results

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HOUSTON, Oct. 30, 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 September 30, 2013. Financial results with respect to third quarter 2013 included the following:

  • Reported Adjusted EBITDA of $62.8 million, an increase of approximately 12% as compared to the $55.9 million reported for the second quarter of 2013, driven by improved operating performance in both businesses.
  • Reported Distributable Cash Flow of $24.9 million, an increase of approximately 10% as compared to the $22.8 million reported for the second quarter of 2013.
  • Reported a Net Loss of $91.6 million, as compared to Net Income of $16.0 million for the second quarter of 2013, primarily due to impairments recorded in the Upstream Business in the third quarter of 2013.

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

  • Reached full operating capacity at its 60 MMcf/d cryogenic processing facility in Wheeler County, Texas, in the heart of the prolific Granite Wash play (the "Wheeler Plant"), which was initially placed into service on June 30, 2013.
  • Increased the upstream component of the borrowing base under its senior secured credit facility from $375 million to $380 million as part of the Partnership's regularly scheduled semi-annual redetermination by its commercial lenders.

Third Quarter Distribution

On October 28, 2013, the Partnership declared a cash distribution for the quarter ended September 30, 2013 of $0.15 per unit, equivalent to $0.60 per unit on an annualized basis. The distribution will be paid on a total of 158.9 million common units (including eligible restricted common units). The distribution represents a decrease from the distribution of $0.22 per common unit paid with respect to the second quarter.

Despite the improved operational and financial performance in the third quarter, the Partnership continued to generate insufficient distributable cash flow to cover the $0.22 per unit distribution level. With the expectation that the challenges that have affected the Partnership over the last several quarters are likely to continue, the Board of Directors decided to lower the distribution to a level that stabilizes and begins to improve the Partnership's leverage ratio and liquidity position.

Distribution coverage was approximately 1.05x for the third quarter of 2013, and management expects coverage to increase over the next several quarters. Management does not expect to recommend a distribution increase over the next several quarters while the Partnership redirects a portion of cash from operations towards debt repayment which should benefit the common unitholders in the form of greater equity value, and the Partnership in the form of greater liquidity and financial flexibility. All actual future distributions will be determined, declared and paid at the sole discretion of the Board of Directors.

Management and the Board of Directors continue to explore alternatives to address the Partnership's leverage position, which may include asset sales or purchases, equity financings, the separation of its upstream and midstream businesses or other alternatives.

The distribution will be paid on Thursday, November 14, 2013, to unitholders of record as of the close of business on Thursday, November 7, 2013.

Third 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 third quarter of 2013 to those of the second quarter of 2013. Please refer to the financial tables at the end of this release for further detailed information.

Midstream Business – Operating income for the Midstream Business in the third quarter of 2013 increased by approximately $5.7 million, or approximately 68%, compared to the second quarter of 2013. This increase was primarily due to improved financial results from the Texas Panhandle segment.

In the Texas Panhandle, gas gathered volumes were up approximately 12% in the third quarter of 2013 versus the second quarter as a result of increased drilling activity by producer customers. Reported equity NGL and residue volumes were down due primarily to prior period adjustments made in the second quarter which increased reported volumes in that period. Excluding these prior period adjustments, equity NGLs were higher in the third quarter due to the increased wellhead volumes, including increased wellhead volumes in the liquids-rich West Panhandle system and improved run-times in the Partnership's Gray County processing plant. The Texas Panhandle's contribution to third quarter 2013 Adjusted EBITDA was reduced by an accrual of $1.5 million recorded in the quarter related to potential adjustments to amounts recorded in prior periods.

In the Partnership's East Texas and Other Midstream segment, gas gathered volumes were down approximately 2%, with combined equity NGL and condensate volumes down approximately 17%, compared to the second quarter of 2013. The decrease in NGLs and condensate was primarily a result of lower gas gathered volumes and adjustments for positive prior period settlements for NGL's made in the second quarter of 2013 on the Partnership's Brookeland/Tyler County system. Excluding these prior period adjustments, combined equity NGLs and condensate were down 7%.

Financial results of the Texas Panhandle and East Texas and Other segments benefitted from improved NGL and condensate prices during the third quarter of 2013. Realized NGL and condensate prices in the Midstream Business were up approximately 9% and 16%, respectively, in the third quarter of 2013 relative to the second quarter of 2013. This benefit was partially offset by an approximate 11% decrease in realized natural gas prices in the quarter.

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 third quarter of 2013, including intercompany sales and intersegment cost of sales, was up approximately 8% compared to the second quarter of 2013.

Upstream Business - Operating income for Eagle Rock's Upstream Business in the third quarter of 2013, excluding the impact of impairments, increased by approximately $4.1 million, or 28%, compared to the second quarter of 2013. The increase was driven by higher production, lower operating costs, and higher realized oil, condensate and NGL prices, and was partially offset by lower realized natural gas prices. Total production volumes in the Upstream Business averaged 75.8 MMcfe/d during the quarter, an increase of 4% over the second quarter of 2013. The shut-in of a third-party processing plant for eight days during the beginning of September negatively impacted upstream volumes for the third quarter by approximately 2.1 MMcfe/d and operating income by approximately $1.8 million. The Partnership recorded an impairment of approximately $61 million in the third quarter related to its Permian properties resulting primarily from higher operating costs, higher differentials and lower reserve forecasts.

Corporate Segment – Operating loss for the Corporate Segment, excluding the impact of unrealized derivative gains and losses, was $17.6 million for the third quarter of 2013 as compared to an $11.7 million loss for the second quarter of 2013. The increased loss was attributable to a $5.4 million reduction in realized commodity derivative gains and a $1.1 million increase in general and administrative expenses for the third quarter.

Total revenue for the third quarter of 2013, including the impact of the Partnership's realized and unrealized commodity derivative gains and losses, was $301.2 million, down 6% from the $320.2 million reported for the second quarter of 2013. The decrease in revenue was primarily due to unrealized losses on commodity derivatives, and was partially offset by higher revenue from product sales and higher fee-based revenues as compared to the second quarter of 2013. The Partnership recorded an unrealized loss on commodity derivatives of $29.6 million in the third quarter 2013, as compared to an unrealized gain on commodity derivatives of $22.3 million in the second 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 14% relative to the second quarter of 2013, driven primarily by the impact of higher NGL and condensate prices and higher volumes in the Upstream Business, but partially offset by lower natural gas prices. Adjusted EBITDA was $62.8 million for the third quarter of 2013, up 12% from the second quarter of 2013, and Distributable Cash Flow was $24.9 million for the third quarter of 2013, up 10% as compared to the second quarter of 2013. The increase in Distributable Cash Flow was primarily attributable to higher Adjusted EBITDA and partially offset by higher interest expense and maintenance capital spending during the quarter.

The Partnership recorded a net loss of approximately $91.6 million for the third quarter of 2013, versus net income of $16.0 million for the second quarter of 2013. The decrease was driven primarily by unrealized commodity derivative losses and impairment charges in the third quarter of 2013, and was partially offset by higher revenues associated with the sale of natural gas, NGLs, oil, condensate, sulfur and helium during the third quarter of 2013. Net loss for the quarter excluding the impact of unrealized gains and losses and impairments was approximately $1.8 million.

Capitalization and Liquidity Update

Total debt outstanding as of September 30, 2013 was $1.2 billion, consisting of $545.1 million of senior unsecured notes (net of an unamortized debt discount of $4.9 million) and borrowings of $654.0 million under the Partnership's senior secured credit facility.

The Partnership is in compliance with its financial covenants and has no maturities under its senior secured credit facility until June 2016. As of September 30, 2013, the Partnership had approximately $128.9 million of availability under its senior secured credit facility, after taking into account outstanding borrowings and approximately $20.4 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 October 4, 2013, the Partnership announced the upstream component of the borrowing base under its senior secured credit facility was increased from $375 million to $380 million as part of the Partnership's regularly scheduled semi-annual redetermination by its commercial lenders.

The current 2013 capital budget is approximately $227 million, which includes $65 million expected to be allocated to maintenance capital expenditures and $162 million expected to be allocated to growth capital expenditures. The current 2013 capital budget includes approximately $92 million allocated to the Midstream Business and approximately $134 million allocated to the Upstream Business (with the remainder allocated to general corporate purposes). The Partnership's capital expenditures were approximately $61.0 million for the three months ended September 30, 2013, of which $18.8 million were related to maintenance capital expenditures and $42.2 million were related to growth capital expenditures.

As of September 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 July 31, 2013:

Transaction Date Product / (Type) Quantity Price ($/Bbl) Term
8/29/13 WTI Crude 14,000 $ 97.25 Cal. 2014
(Swap) Bbls/month
8/29/13 WTI Crude 12,500 $ 88.60 Cal. 2015
(Swap) Bbls/month
8/29/13 WTI Crude 38,000 $ 84.20 Cal. 2016
(Swap) Bbls/month
8/29/13 HH Natural Gas 250,000 $ 3.903 Cal. 2014
(Swap) MMBtu/month
8/29/13 HH Natural Gas 250,000 $ 4.095 Cal. 2015
(Swap) MMBtu/month
8/29/13 HH Natural Gas 340,000 $ 4.215 Cal. 2016
(Swap) MMBtu/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.

Third Quarter 2013 Conference Call Information

The Partnership will hold a conference call to discuss its third quarter 2013 financial and operating results on Thursday, October 31, 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 90146995. 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 90146995. 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 filed for the quarter ended September 30, 2013, when filed, 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 September 30, Nine Months Ended September 30, Three Months Ended June 30,
2013 2012 2013 2012 2013
REVENUE:
Natural gas, natural gas liquids, oil, condensate, sulfur and helium sales $ 306,820 $ 184,494 $ 830,412 $ 580,152 $ 269,392
Gathering, compression, processing and treating fees 21,134 13,604 62,229 35,566 20,153
Unrealized commodity derivative (losses) gains (29,591) (51,305) (35,181) 13,426 22,316
Realized commodity derivative gains 2,757 15,802 20,932 38,428 8,177
Other revenue 113 794 723 3,976 113
Total revenue 301,233 163,389 879,115 671,548 320,151
COSTS AND EXPENSES:
Cost of natural gas and natural gas liquids 213,509 110,430 579,257 338,798 185,760
Operations and maintenance 33,075 27,074 100,416 81,685 35,122
Taxes other than income 5,825 4,748 14,751 14,518 5,060
General and administrative 20,537 16,807 58,780 52,384 19,396
Impairment 61,389 55,900 63,228 122,824 1,839
Depreciation, depletion and amortization 42,641 40,395 124,035 118,043 41,157
Total costs and expenses 376,976 255,354 940,467 728,252 288,334
OPERATING (LOSS) INCOME (75,743) (91,965) (61,352) (56,704) 31,817
OTHER INCOME (EXPENSE):
Interest expense, net (17,475) (14,199) (51,168) (35,087) (16,609)
Realized interest rate derivative losses (1,693) (1,733) (5,029) (8,578) (1,685)
Unrealized interest rate derivative gains 1,234 615 4,263 4,418 1,534
Other income (expense), net 79 1 184 (44) 113
Total other expense (17,855) (15,316) (51,750) (39,291) (16,647)
(LOSS) INCOME BEFORE INCOME TAXES (93,598) (107,281) (113,102) (95,995) 15,170
INCOME TAX BENEFIT (2,033) (386) (4,055) (556) (862)
NET (LOSS) INCOME $ (91,565) $ (106,895) $ (109,047) $ (95,439) $ 16,032

TABLE TWO

Eagle Rock Energy Partners, L.P.
Consolidated Balance Sheets
($ in thousands)
(unaudited)
September 30,
2013
December 31,
2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 76 $ 25
Accounts receivable 141,796 138,732
Risk management assets 11,406 33,340
Prepayments and other current assets 6,143 9,867
Total current assets 159,421 181,964
PROPERTY, PLANT AND EQUIPMENT - Net 1,976,573 1,968,206
INTANGIBLE ASSETS - Net 106,591 111,515
DEFERRED TAX ASSET 1,997 1,656
RISK MANAGEMENT ASSETS 6,734 7,953
OTHER ASSETS 21,649 22,922
TOTAL ASSETS $ 2,272,965 $ 2,294,216
LIABILITIES AND MEMBERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 163,616 $ 160,473
Accrued liabilities 44,682 19,764
Taxes payable -- 46
Risk management liabilities 7,053 1,231
Total current liabilities 215,351 181,514
LONG-TERM DEBT 1,199,091 1,153,103
ASSET RETIREMENT OBLIGATIONS 46,939 44,814
DEFERRED TAX LIABILITY 39,480 43,000
RISK MANAGEMENT LIABILITIES 4,699 1,700
OTHER LONG TERM LIABILITIES 3,153 1,711
MEMBERS' EQUITY 764,252 868,374
TOTAL LIABILITIES AND MEMBERS' EQUITY $ 2,272,965 $ 2,294,216

TABLE THREE

Eagle Rock Energy Partners, L.P.
Segment Summary
Operating Income
($ in thousands)
(unaudited)


Three Months Ended September 30,


Nine Months Ended September 30,
Three Months
Ended
June 30,
2013 2012 2013 2012 2013
Midstream
Revenues:
Natural gas, natural gas liquids, oil and condensate sales $ 265,732 $ 147,099 $ 717,961 $ 468,355 $ 231,734
Intercompany sales - natural gas and condensate (1,900) (2,846) (5,970) (7,809) (2,275)
Gathering and treating services 21,134 13,604 62,229 35,566 20,153
Other 68 105 2,864 37
Total revenue 285,034 157,857 774,325 498,976 249,649
Cost of natural gas, natural gas liquids, oil and condensate 213,509 110,430 579,257 338,798 185,760
Intersegment cost of sales - natural gas and condensate 10,889 8,598 31,406 32,612 9,405
Operating costs and expenses:
Operations and maintenance 26,396 17,647 75,385 53,178 27,020
Impairment 35,840 101,979
Depreciation, depletion and amortization 20,160 16,488 58,178 49,735 19,087
Total operating costs and expenses 46,556 69,975 133,563 204,892 46,107
Operating income (loss) $ 14,080 $ (31,146) $ 30,099 $ (77,326) $ 8,377
Upstream
Revenue
Oil and condensate sales $ 19,782 $ 14,376 $ 47,851 $ 44,088 $ 15,756
Intersegment sales - condensate 10,323 11,431 30,829 34,226 9,220
Natural gas sales 9,155 8,324 27,691 22,474 10,355
Intersegment sales - natural gas 1,907 2,846 6,095 7,809 2,374
Natural gas liquids sales 10,786 10,979 29,658 34,060 8,596
Sulfur sales 1,365 3,716 7,251 11,175 2,951
Other 45 794 618 1,112 76
Total revenue 53,363 52,466 149,993 154,944 49,328
Operating costs and expenses:
Operations and maintenance 12,504 14,175 39,782 43,025 13,162
Impairment 61,389 20,060 63,228 20,845 1,839
Depreciation, depletion and amortization 22,061 23,484 64,446 67,070 21,456
Total operating costs and expenses 95,954 57,719 167,456 130,940 36,457
Operating (loss) income $ (42,591) $ (5,253) $ (17,463) $ 24,004 $ 12,871
Corporate and Other
Revenues:
Unrealized commodity derivative (losses) gains $ (29,591) $ (51,305) $ (35,181) $ 13,426 $ 22,316
Realized commodity derivative gains 2,757 15,802 20,932 38,428 8,177
Intersegment elimination - Sales of natural gas and condensate (10,330) (11,431) (30,954) (34,226) (9,319)
Total revenue (37,164) (46,934) (45,203) 17,628 21,174
Costs and expenses:
Intersegment elimination - Cost of natural gas and condensate (10,889) (8,598) (31,406) (32,612) (9,405)
General and administrative 20,537 16,807 58,780 52,384 19,396
Depreciation, depletion and amortization 420 423 1,411 1,238 614
Operating (loss) income $ (47,232) $ (55,566) $ (73,988) $ (3,382) $ 10,569

TABLE FOUR

Eagle Rock Energy Partners, L.P.
Midstream Segment
Operating Income
($ in thousands)
(unaudited)


Three Months Ended September 30,


Nine Months Ended September 30,
Three Months
Ended June 30,
2013 2012 2013 2012 2013
Texas Panhandle
Revenues:
Natural gas, natural gas liquids, condensate and helium sales $ 141,271 $ 60,213 $ 356,170 $ 189,230 $ 108,505
Intersegment sales - natural gas and condensate 56,799 28,025 162,457 72,514 56,523
Gathering, compression, processing and treating services 14,341 4,708 38,893 13,510 12,031
Other 68 105 2,864 37
Total revenue 212,479 92,946 557,625 278,118 177,096
Cost of natural gas, natural gas liquids, condensate and helium 163,768 67,098 431,290 189,703 135,296
Intersegment cost of sales - natural gas 61 158 -- 78
Operating costs and expenses:
Operations and maintenance 21,269 12,705 60,425 37,342 22,022
Depreciation, depletion and amortization 14,823 10,164 42,673 29,554 14,005
Total operating costs and expenses 36,092 22,869 103,098 66,896 36,027
Operating income $ 12,558 $ 2,979 $ 23,079 $ 21,519 $ 5,695
East Texas and Other Midstream
Revenues:
Natural gas, natural gas liquids and condensate sales $ 25,867 $ 26,130 $ 79,852 $ 98,398 $ 26,597
Intersegment sales - natural gas 3,948 10,020 25,191 26,471 12,705
Gathering, compression, processing and treating services 6,765 8,896 23,204 22,056 8,081
Total revenue 36,580 45,046 128,247 146,925 47,383
Cost of natural gas and natural gas liquids 26,464 33,145 96,038 111,203 36,340
Operating costs and expenses:
Operations and maintenance 5,140 4,940 14,975 15,833 5,006
Impairment 35,840 101,979 --
Depreciation, depletion and amortization 5,222 6,232 15,213 20,034 4,989
Total operating costs and expenses 10,362 47,012 30,188 137,846 9,995
Operating (loss) income $ (246) $ (35,111) $ 2,021 $ (102,124) $ 1,048
Marketing and Trading
Revenues:
Natural gas, oil and condensate sales $ 98,594 $ 60,756 $ 281,939 $ 180,727 $ 96,632
Intersegment sales - natural gas and condensate (62,647) (40,891) (193,618) (106,794) (71,503)
Gathering, compression, processing and treating services 28 132 -- 41
Total revenue 35,975 19,865 88,453 73,933 25,170
Cost of natural gas and condensate 23,277 10,187 51,929 37,892 14,124
Intersegment cost of sales - natural gas and condensate 10,828 8,598 31,248 32,612 9,327
Operating costs and expenses:
Operations and maintenance (13) 2 (15) 3 (8)
Depreciation, depletion and amortization 115 92 292 147 93
Total operating costs and expenses 102 94 277 150 85
Operating income $ 1,768 $ 986 $ 4,999 $ 3,279 $ 1,634

TABLE FIVE

Eagle Rock Energy Partners, L.P.
Midstream Operations Information
(unaudited)
Three Months Ended
September 30,
Nine Months Ended
September 30,
Three Months
Ended June 30,
2013 2012 2013 2012 2013
Gas gathering volumes - (Average Mcf/d)
Texas Panhandle 393,226 183,415 362,063 159,229 349,681
East Texas and Other Midstream 190,674 248,094 194,977 268,512 194,704
Total 583,900 431,509 557,040 427,741 544,385
NGLs - (Net equity Bbls)
Texas Panhandle 245,548 228,696 571,389 855,499 265,538
East Texas and Other Midstream 61,180 81,997 188,916 258,322 74,620
Total 306,728 310,693 760,305 1,113,821 340,158
Condensate - (Net equity Bbls)
Texas Panhandle 289,524 164,246 860,496 499,660 295,204
East Texas and Other Midstream 8,372 7,010 22,659 28,737 9,100
Total 297,896 171,256 883,155 528,397 304,304
Natural gas position - (Average MMbtu/d)
Texas Panhandle 7,985 (990) 7,881 (4,661) 9,676
East Texas and Other Midstream (51) 392 (8) 1,482 (190)
Total 7,934 (598) 7,873 (3,179) 9,486
Average realized NGL price - per Bbl
Texas Panhandle $36.31 $36.23 $35.22 $39.55 $33.44
East Texas and Other Midstream $30.08 $32.24 $29.37 $39.45 $28.10
Weighted Average $35.30 $34.89 $34.17 $39.51 $32.41
Average realized condensate price - per Bbl
Texas Panhandle $92.64 $81.08 $84.24 $86.74 $79.83
East Texas and Other Midstream $106.70 $91.57 $98.79 $100.66 $93.29
Weighted Average $93.59 $81.82 $85.08 $87.94 $80.56
Average realized natural gas price - per MMbtu
Texas Panhandle $3.34 $2.64 $3.47 $2.37 $3.76
East Texas and Other Midstream $3.53 $2.85 $3.61 $2.67 $3.93
Weighted Average $3.38 $2.71 $3.50 $2.48 $3.81

TABLE SIX

Eagle Rock Energy Partners, L.P.
Upstream Operations Information
(unaudited)
Three Months Ended
September 30,
Nine Months Ended
September 30,
Three Months
Ended June 30,
2013 2012 2013 2012 2013
Upstream
Production:
Oil and condensate (Bbl) 321,170 310,349 894,591 900,873 294,353
Gas (Mcf) 3,254,722 4,177,156 9,565,038 12,614,258 3,181,264
NGLs (Bbl) 298,031 301,644 866,055 848,047 278,158
Total Mcfe 6,969,928 7,849,113 20,128,914 23,107,778 6,616,330
Sulfur (long ton) 26,788 28,414 80,028 79,111 26,641
Realized prices, excluding derivatives:
Oil and condensate (per Bbl) $93.74 $83.16 $87.95 $86.93 $84.85
Gas (Mcf) $3.40 $2.67 $3.53 $2.40 $4.00
NGLs (Bbl) $36.19 $36.40 $34.24 $40.16 $30.90
Sulfur (long ton) $50.95 $130.77 $90.60 $141.27 $110.75
Operating statistics:
Operating costs per Mcfe (incl production taxes) (1) $1.64 $1.60 $1.80 $1.69 $1.83
Operating costs per Mcfe (excl production taxes) (1) $1.11 $1.11 $1.32 $1.18 $1.28
Operating income per Mcfe $(6.11) $(0.67) $(0.87) $1.04 $1.95
Drilling program (gross wells):
Development wells 16 6 38 25 14
Completions 16 6 37 25 14
Workovers 6 10 24 19 11
Recompletions 1 4 8 7 6
(1) Excludes post-production costs of $1,069, $3,464, $1,601 and $4,068 for the three months ended September 30, 2013 and 2012, respectively, and $1,083 for the three months ended June 30, 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 September 30, Nine Months Ended September 30, Three Months Ended June 30,
2013 2012 2013 2012 2013
Net income (loss) to Adjusted EBITDA
Net (loss) income, as reported $ (91,565) $ (106,895) $ (109,047) $ (95,439) $ 16,032
Depreciation, depletion and amortization 42,641 40,395 124,035 118,043 41,157
Impairment 61,389 55,900 63,228 122,824 1,839
Loss (gain) from risk management activities, net 27,507 36,936 15,245 (47,309) (31,476)
Total derivative settlements 1,812 13,911 16,729 29,891 7,467
Non-cash mark-to-market of Upstream product imbalances 3 229 (2) 339 (5)
Restricted units non-cash amortization expense 3,939 3,080 10,106 8,092 3,520
Income tax benefit (2,033) (386) (4,055) (556) (862)
Interest - net including realized risk management instruments and other expense 19,089 15,931 56,013 43,709 18,181
Adjusted EBITDA $ 62,782 $ 59,101 $ 172,252 $ 179,594 $ 55,853
Net income (loss) to Distributable Cash Flow
Net (loss) income, as reported $ (91,565) $ (106,895) $ (109,047) $ (95,439) $ 16,032
Depreciation, depletion and amortization expense 42,641 40,395 124,035 118,043 41,157
Impairment 61,389 55,900 63,228 122,824 1,839
Loss (gain) from risk management activities, net 27,507 36,936 15,245 (47,309) (31,476)
Total derivative settlements 1,812 13,911 16,729 29,891 7,467
Capital expenditures-maintenance related (18,751) (15,982) (46,365) (35,824) (14,900)
Non-cash mark-to-market of Upstream product imbalances 3 229 (2) 339 (5)
Restricted units non-cash amortization expense 3,939 3,080 10,106 8,092 3,520
Income tax benefit (2,033) (386) (4,055) (556) (862)
Cash income taxes (185) (749)
Distributable Cash Flow $ 24,942 $ 27,003 $ 69,874 $ 99,312 $ 22,772

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.