Eagle Rock Reports Third-Quarter 2009 Financial Results
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HOUSTON--(BUSINESS WIRE)-- Eagle Rock Energy Partners, L.P. ("Eagle Rock" or the "Partnership") (NASDAQ: EROC) today announced its unaudited financial results for the three and nine months ended September 30, 2009. Notable events with respect to third-quarter 2009 included the following:
-- Adjusted EBITDA totaled $51.3 million, an increase of 15% as compared to
the $44.7 million reported in second-quarter 2009 and a decrease of 32%
as compared to the $74.9 million reported for third-quarter 2008.
-- Repaid $30.0 million of outstanding borrowings during the quarter,
reducing total debt outstanding under the revolving credit facility to
$774.4 million as of September 30, 2009.
-- Distributable Cash Flow totaled $36.6 million, an increase of 27% as
compared to the $28.8 million reported in second-quarter 2009 and a
decrease of 38% as compared to the $59.4 million reported for
third-quarter 2008.
-- Reported a net loss of $25.3 million, as compared to a net loss of $74.8
million for second-quarter 2009 and net income of $288.1 million for
third quarter 2008.
-- Announced a quarterly distribution with respect to the third quarter of
2009 of $0.025 per common and general partner unit, unchanged from the
distribution paid with respect to second-quarter 2009.
Third-quarter 2009 Adjusted EBITDA and Distributable Cash Flow excluded $10.6 million in amortization of commodity hedge costs for the period (including costs of hedge reset transactions). Including the amortization costs, third-quarter 2009 Adjusted EBITDA would have been $40.7 million and Distributable Cash Flow would have been $26.1 million.
"We are pleased to report continued improvement in our financial performance in the third quarter, driven by higher crude and natural gas liquids prices, as well as by our sustained focus on reducing operating expenses. Our Adjusted EBITDA of $51 million for the quarter was above the high end of our guidance range," said Joseph A. Mills, Chairman and Chief Executive Officer.
Mr. Mills added, "While we are encouraged by the more positive outlook on commodities as reflected in the current forward curves, we continue to feel the effects of low natural gas prices in the form of reduced drilling activity by our producer customers in our Midstream Business. Given this fact, we believe the most prudent course of action remains directing the majority of our cash flow to debt reduction and to improving our liquidity, particularly given the growth opportunities we see in our core areas. To that end, we reduced our debt balance by an additional $30 million during the quarter, bringing the total debt repaid to $63 million since we made the decision to reduce our distribution."
Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures that are defined below and reconciled to the most directly comparable GAAP financial measure of net income (loss) at the end of this release.
Third-Quarter 2009 Financial Results
Revenue for third-quarter 2009, including the impact of Eagle Rock's realized and unrealized derivative gains and losses, increased 72% to $163.9 million, compared with $95.5 million reported for second-quarter 2009 and a decrease of 73% from the $603.9 million reported for third-quarter 2008. Third-quarter 2009 revenues included a realized gain on commodity derivatives of $17.2 million, as compared to a realized gain of $22.5 million in second-quarter 2009 and a realized loss of $24.1 million in third-quarter 2008. Eagle Rock also recorded an unrealized loss on commodity derivatives of $26.0 million in third-quarter 2009, as compared to unrealized losses on commodity derivatives of $97.0 million in second-quarter 2009 and an unrealized gain of $256.0 million in third-quarter 2008. The unrealized gain (loss) on commodity derivatives is a non-cash, mark-to-market amount which includes the amortization of commodity hedging costs.
Adjusted EBITDA was $51.3 million and Distributable Cash Flow was $36.6 million for the third quarter of 2009. Third-quarter 2009 Distributable Cash Flow represents approximately 1.8 times the minimum quarterly distribution (the "MQD") of $0.3625 per common unit as established in the Eagle Rock partnership agreement, applied to only the common and general partner units and excluding subordinated units. Because the actual distribution paid for the quarter is below the MQD, the cumulative arrearage attributable to the common units will increase by $0.3375 per unit to a total of $1.0125 per unit. The Partnership is under no obligation to pay the arrearages, but all cumulative arrearages must be paid before any distributions can be made to the Partnership's subordinated units. For a more detailed discussion of the common unit arrearages, please refer to the Eagle Rock partnership agreement (filed as part of the Partnership's filings with the Securities and Exchange Commission).
Third-quarter 2009 Adjusted EBITDA and Distributable Cash Flow excluded $10.6 million in amortization of commodity hedge costs for the period (including costs of hedge reset transactions - transactions undertaken by the Partnership to increase the strike prices on commodity swaps and/or collars that settled in the period). Including the amortization costs, third-quarter 2009 Adjusted EBITDA would have been $40.7 million and Distributable Cash Flow would have been $26.1 million, representing approximately 1.3 times the MQD applied to only the common and general partner units.
Third-Quarter 2009 Operating Results by Business
Eagle Rock analyzes and manages its operations under seven distinct segments: four segments in its Midstream Business - the Texas Panhandle, East Texas/Louisiana, South Texas and Gulf of Mexico Segments - and the Upstream, Minerals and Corporate Segments. The Corporate Segment includes the Partnership's risk management (derivatives) and other corporate activities. Please refer to the financial tables at the end of this release for further detailed information.
The following discussion of Eagle Rock's operating income by business segment compares the Partnership's financial results in the third quarter of 2009 to those of the second quarter of 2009. The Partnership believes comparing these periods is more illustrative of current operating trends than comparing the current quarter to results achieved in the third quarter of 2008.
Midstream Business - Segment operating income for the Midstream Business in the third quarter of 2009 increased by $4.9 million, or 143%, compared to the second quarter of 2009. The increase was caused by higher condensate and NGL prices across all the Midstream segments, in addition to certain positive adjustments in the third quarter related to prior periods. The weighted average realized condensate and NGL prices for the third-quarter 2009 were approximately 10% and 18%, respectively, above those realized in the second-quarter 2009. These factors more than offset sequential quarter gas gathered volume declines of 4.8%. During September 2009 approximately 17.5 MMcf/d of gas was curtailed by producers in the East Texas segment due to low natural gas prices. Absent the curtailed volumes, the gathered gas volume would have declined by 3.8% during the quarter. The equity NGL and condensate volumes declined by a lesser amount of 1.6% as the decrease in gathered volumes impacted the fee based volumes to a greater extent than the processed gas volumes. The Gulf of Mexico Segment gas gathering volumes increased by approximately 33% due to the completion of repairs to damaged offshore pipelines and platforms caused by Hurricanes Ike and Gustav in late 2008.
Upstream Business - Segment operating income for Eagle Rock's Upstream Business in the third quarter of 2009 increased by $3.0 million compared to the second quarter of 2009, excluding the impact of other operating income items related to adjustments of entries booked in prior periods. The increase was caused by improved realized crude oil, natural gas and NGL prices as well as higher total net production volumes. The Partnership continued to incur sulfur disposal costs in excess of sulfur revenues related to its sulfur production at its South Alabama and East Texas producing areas. Management expects sulfur disposal costs to be an ongoing issue until sulfur demand improves.
Operating income for the Upstream Business in third-quarter 2009 was positively impacted by a reversal of $1.6 million in environmental reserves determined to no longer be necessary, as well as a credit of $0.7 million for overbilling related to a non-operated asset.
During the third quarter of 2009, the Big Escambia Creek (BEC) plant underwent unanticipated repairs and overhauls to the plant's residue gas compressors. Sales of oil, residue gas and NGLs from the BEC, Flomaton and Fanny Church fields were partially curtailed for 44 days during the quarter due to the compressors' downtime. The reduced sales during this period negatively impacted Upstream revenues by approximately $1.1 million during the quarter. Despite the downtime, total production for the third quarter of 2009 increased by 6% over the second quarter of 2009.
Minerals Business - Segment operating income from the Minerals Business in the third quarter of 2009 increased by $0.2 million compared to the second quarter of 2009. The increase was due to higher realized crude oil and NGL prices, and to higher lease bonus income. These benefits were partially offset by lower oil and gas production volumes for the quarter.
Capitalization and Liquidity Update
Total debt outstanding under the Partnership's revolving credit facility as of September 30, 2009 was approximately $774.4 million. Outstanding borrowings were reduced by $30 million during the third quarter of 2009 and by a total of $63 million over the past two quarters as a result of the decision to lower the quarterly distribution and redirect those cash flows to debt repayment.
The credit facility has aggregate commitments of approximately $971 million after adjusting for the unfunded portion of Lehman Brothers' commitment. On August 21, 2009, BBVA Compass Bank purchased certain assets and liabilities of Guaranty Bank, a wholly owned subsidiary of Guaranty Financial Group Inc. Guaranty Bank had a commitment under the Partnership's revolving credit facility of $30 million, of which approximately $25 million had been funded. BBVA Compass has assumed Guaranty Bank's commitment under the facility, resulting in no change in the aggregate commitments.
The Partnership is in compliance with its financial covenants and has no maturities under its credit facility until December 2012. Availability under the credit facility is a function of undrawn commitments and the limitations imposed by the borrowing base for the Upstream Business and traditional cash-flow based covenants for the Midstream and Minerals Businesses. The borrowing base for the Upstream Business was reaffirmed at $135 million effective October 1, 2009 as part of the Partnership's semi-annual redetermination, with no increase in fees or borrowing costs. Unused capacity available under the credit facility, based on financial covenants, was approximately $35 million as of September 30, 2009.
Management is continuing to consider alternatives to enhance the Partnership's liquidity and address concerns surrounding its ability to remain in compliance with the financial covenants under its credit facility. These alternatives include potential asset sales, which could include small, discrete midstream assets or all or certain portions of the Partnership's Upstream or Minerals Businesses, and additional adjustments to the Partnership's hedging portfolio. The Partnership's decision to enter into any asset sales will depend on numerous factors, including the potential purchase price for the assets, the extent to which the sales would be credit enhancing, the type of consideration offered and the likelihood of successfully completing the transaction.
In addition, the Partnership has received proposals from Natural Gas Partners ("NGP") and Black Stone Minerals Company which would, among other items, involve the sale of the Partnership's Minerals Business and the potential issuance of new equity. These proposals are currently being evaluated by the Conflicts Committee of the Partnership's Board. The Partnership cautions its unitholders, and others considering trading in its securities, that the proposals are not binding at this time, that neither the Board nor the Conflicts Committee has made any decision with respect to the Partnership's response to the proposals, and that there can be no assurance that any agreement will be executed or that any transaction will be approved or consummated.
Hedging Update
On July 30, 2009, Eagle Rock entered into additional natural gas hedges covering 2011 and 2012. The Partnership entered into natural gas swaps for 190,000 MMBtu per month in 2011 at $6.57 / MMBtu and 260,000 MMBtu per month in 2012 at $6.77 / MMBtu. On October 8, 2009, Eagle Rock unwound 3,000 barrels per month of an existing 60,000 barrels per month NYMEX WTI swap related to November and December of 2009 and reset the strike price on the remaining 57,000 barrels per month from $97 per barrel to $135 per barrel at a net fee of approximately $4.2 million. On October 22, 2009, the Partnership entered into (i) a costless collar for 30,000 barrels per month of WTI crude oil in 2011 with a floor of $80.00/Bbl and a cap of $92.40/Bbl, and (ii) a costless collar for 30,000 barrels per month of WTI crude oil in 2012 with a floor of $80.00/Bbl and a cap of $98.50/Bbl. On November 2, 2009, the Partnership paid approximately $5.7 million to reset the strike price from $53.55 to $95.00 on an existing 45,000 barrel per month NYMEX WTI swap relating to the first quarter of 2010.
On November 5, 2009, Eagle Rock posted an update to its Commodity Hedging Overview presentation on its website to describe the details of its latest hedge transactions and its existing hedge portfolio. The presentation can be accessed by going to www.eaglerockenergy.com, select Investor Relations, then select Presentations.
Unit Distributions
On October 28, 2009, Eagle Rock announced a third-quarter 2009 cash distribution of $0.025 per unit, or $0.10 per unit on an annualized basis, for all of its outstanding common and general partner units. Eagle Rock will not pay a distribution on the subordinated units for the third quarter of 2009. The distribution will be paid on November 13, 2009 to the general partner and all common unitholders of record on November 9, 2009.
Because Eagle Rock's 20.7 million outstanding subordinated units have not yet converted into common units, each common unit carries a cumulative arrearage equal to the sum of the amount by which each actual quarterly distribution (starting with the distribution for the first quarter of 2009) is below the MQD of $0.3625, per the provisions of Eagle Rock's partnership agreement. The third quarter 2009 Common Unit Arrearage is $0.3375 per common unit. The Cumulative Common Unit Arrearage as of the third quarter of 2009 is $1.0125 per common unit. Both Common Unit Arrearage and Cumulative Common Unit Arrearage are terms defined in Eagle Rock's partnership agreement. In general, before the Partnership can make any distributions to the subordinated units, the Cumulative Common Unit Arrearage must first be paid to common unitholders, and the distribution rate to the common unitholders must equal the MQD. However, the Partnership is not required to pay the Cumulative Common Unit Arrearage, except in certain circumstances described in the partnership agreement, and the Partnership may choose not to pay the arrearages.
"Board" and "Board of Directors" in this press release refer to the Board of Directors of the general partner of the general partner of the Partnership.
Conference Call
Eagle Rock will hold a conference call to discuss its third-quarter 2009 financial results on Thursday, November 5, 2009 at 10 a.m. Eastern Time (9 a.m. Central Time).
Interested parties may listen live over the internet or via telephone. To listen live over the internet, log on to the Partnership's web site at www.eaglerockenergy.com. To participate by telephone, the call-in number is 888-679-8033, confirmation code 12987851. Investors are advised to dial into the call at least 15 minutes prior to the call to register. Participants may use the following link to pre-register and view important information about this conference call. Pre-registering is not mandatory but is recommended as it will provide you immediate entry to the call and will facilitate the timely start of the call. Pre-registration only takes a few minutes and you may pre-register at any time, including immediately prior to and after the call start. To pre-register, please click https://www.theconferencingservice.com/prereg/key.process?key=PLFJ9NP8Y. (Due to its length, this URL may need to be copied/pasted into your internet browser's address field. Remove extra space if one exists.) An audio replay of the conference call will also be available for thirty days by dialing 888-286-8010, confirmation code 63957087. In addition, a replay of the audio webcast will be available within a few days after the call on Eagle Rock's website.
About the Partnership
The Partnership is a growth-oriented master limited partnership engaged in three businesses: a) midstream, which includes (i) gathering, compressing, treating, processing and transporting natural gas; (ii) fractionating and transporting natural gas liquids; and (iii) marketing natural gas, condensate and NGLs; b) upstream, which includes acquiring, exploiting, developing, and producing interests in oil and natural gas properties; and c) minerals, which includes acquiring and managing fee mineral and royalty interests, either through direct ownership or through investment in other partnerships in properties located in multiple producing trends across the United States. Its corporate office is located in Houston, Texas.
Contact:
Eagle Rock Energy Partners, L.P.
Jeff Wood, 281-408-1203
Senior
Vice President and Chief Financial Officer
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 as 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 our equity-based compensation program; unrealized (gains) losses on commodity and interest rate risk management related instruments; (gains) losses on discontinued operations and other (income) expense.
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 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 general partner and finance its maintenance capital expenditures. Eagle Rock further believes that Adjusted EBITDA also describes 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 describe 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 higher prices or 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: a) in our Midstream Business, capital expenditures made to replace partially or fully depreciated assets, to meet regulatory requirements, to maintain the existing operating capacity of our assets and extend their useful lives, or to connect wells to maintain existing system volumes and related cash flows; and b) in our Upstream Business, capital which is expended to maintain our production and cash flow levels in the near future.
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" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. 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, which may cause the Partnership's actual results to differ materially from those implied or expressed by the 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 SEC for the year ended December 31, 2008, and the Partnership's Forms 10-Q filed with the SEC for subsequent quarters, as well as any other public filings and press releases.
Eagle Rock Energy Partners, L.P.
Consolidated Statements of Operations
($ in thousands)
(unaudited)
Three Months Nine Months Three
Months
Ended September 30, Ended September 30, Ended
2009 2008 2009 2008 June 30,
2009
REVENUE:
Natural gas,
NGLs,
condensate, $ 156,779 $ 341,700 $ 468,589 $ 1,008,891 $ 153,320
oil and sulfur
sales
Gathering,
compression, 11,814 12,513 35,043 27,741 11,562
processing and
treating fees
Minerals and 4,050 17,393 10,788 34,606 3,499
royalty income
Unrealized
commodity (26,002 ) 255,956 (127,568 ) (33,381 ) (97,044 )
derivative
gains (losses)
Realized
commodity 17,170 (24,105 ) 70,431 (64,388 ) 22,483
derivative
gains (losses)
Other income 50 428 1,770 610 1,678
Total Revenue 163,861 603,885 459,053 974,079 95,498
COSTS AND
EXPENSES:
Cost of
natural gas 109,945 237,742 358,802 726,400 115,640
and NGLs
Operations and
maintenance 16,934 21,475 54,624 54,772 19,049
(1)
Taxes other 2,934 5,365 8,790 14,975 2,878
than income
Impairment 274 - 516 - -
General and 10,449 9,893 34,882 31,161 11,895
administrative
Other
operating - 3,920 (3,552 ) 10,134 (3,552 )
(income)
expense
Depreciation,
depletion and 28,586 28,597 86,237 80,799 27,588
amortization
Total Costs 169,122 306,992 540,299 918,241 173,498
and Expenses
OPERATING (5,261 ) 296,893 (81,246 ) 55,838 (78,000 )
INCOME (LOSS)
Other Income
(Expense):
Interest 10 212 183 673 141
income
Other income 725 434 1,835 2,867 550
Interest (4,315 ) (7,498 ) (17,282 ) (23,576 ) (5,428 )
expense, net
Unrealized
interest rate (5,308 ) (501 ) 9,745 (472 ) 11,954
derivative
gains (losses)
Realized
interest rate (5,040 ) (2,358 ) (13,669 ) (4,903 ) (5,147 )
derivative
gains (losses)
Other expense (267 ) (205 ) (801 ) (652 ) (267 )
Total Other
Income (14,195 ) (9,916 ) (19,989 ) (26,063 ) 1,803
(Expense)
INCOME (LOSS)
FROM
CONTINUING (19,456 ) 286,977 (101,235 ) 29,775 (76,197 )
OPERATIONS
BEFORE INCOME
TAXES
Income tax
(benefit) 5,841 (500 ) 1,634 (1,497 ) (1,477 )
provision
INCOME (LOSS)
FROM (25,297 ) 287,477 (102,869 ) 31,272 (74,720 )
CONTINUING
OPERATIONS
DISCONTINUED 26 594 266 1,451 (67 )
OPERATIONS
NET INCOME $ (25,271 ) $ 288,071 $ (102,603 ) $ 32,723 $ (74,787 )
(LOSS)
(1) Includes costs of $348K and $1,505K for disposal of sulfur in our Upstream Segment for the three and nine months ended September 30, 2009, respectively.
Eagle Rock Energy Partners, L.P.
Consolidated Balance Sheets
($ in thousands)
(unaudited)
September 30, December 31,
2009 2008
Assets
Current assets:
Cash and cash equivalents $ 9,168 $ 17,916
Accounts receivable 73,792 115,932
Risk management assets 26,017 76,769
Prepayments and other current assets 2,140 2,607
111,117 213,224
Property plant and equipment - net 1,313,386 1,357,609
Intangible assets - net 139,273 154,206
Deferred tax asset 1,663 -
Risk management assets 5,725 32,451
Other assets 19,678 15,571
Total assets $ 1,590,842 $ 1,773,061
Liabilities and Members' Equity
Current liabilities:
Accounts payable $ 65,666 $ 116,578
Due to affiliate 10,859 4,473
Accrued liabilities 11,364 19,565
Taxes payable 992 1,559
Risk management liabilities 34,988 13,763
123,869 155,938
Long-term debt 774,383 799,383
Asset retirement obligations 19,728 19,872
Deferred tax liability 42,051 42,349
Risk management liabilities 31,406 26,182
Other Long-term liabilities 568 1,622
Members' equity
Common unitholders 533,651 625,590
Subordinated unitholders 70,360 105,839
General partner (5,174 ) (3,714 )
598,837 727,715
Total Liabilities and Members' Equity $ 1,590,842 $ 1,773,061
Eagle Rock Energy Partners, L.P.
Midstream Segment
Operating Income
($ in thousands)
(unaudited)
Three Months Nine Months Three Months
Ended September 30, Ended September 30, Ended
2009 2008 2009 2008 June 30, 2009
Texas Panhandle
Revenues:
Natural gas, NGLs,
oil and condensate $ 67,468 $ 179,608 $ 196,791 $ 514,450 $ 66,373
sales
Gathering,
compression, 2,795 2,671 8,209 7,664 2,601
processing, and
treating services
Total revenues 70,263 182,279 205,000 522,114 68,974
Cost of natural 46,540 138,428 147,894 398,828 49,407
gas and NGLs
Operating costs
and expenses:
Operations and 8,206 9,190 24,407 25,653 8,056
maintenance
Depreciation,
depletion and 11,602 10,984 33,660 32,587 10,962
amortization
Total operating 19,808 20,174 58,067 58,240 19,018
costs and expenses
Operating income $ 3,915 $ 23,677 $ (961 ) $ 65,046 $ 549
East
Texas/Louisiana
(1)
Revenues:
Natural gas, NGLs,
oil and condensate $ 46,253 $ 71,861 $ 134,949 $ 231,996 $ 41,245
sales
Gathering,
compression, 7,367 8,908 21,951 17,056 7,375
processing, and
treating services
Total revenues 53,620 80,769 156,900 249,052 48,620
Cost of natural 39,665 66,007 121,907 209,937 37,233
gas and NGLs
Operating costs
and expenses:
Operations and 4,727 4,194 13,887 11,511 4,608
maintenance
Depreciation,
depletion and 4,458 2,989 13,469 8,846 4,240
amortization
Total operating 9,185 7,183 27,356 20,357 8,848
costs and expenses
Operating income $ 4,770 $ 7,579 $ 7,637 $ 18,758 $ 2,539
South Texas (1)
Revenues:
Natural gas, NGLs,
oil and condensate $ 17,324 $ 35,253 $ 73,863 $ 122,689 $ 24,751
sales
Gathering,
compression, 1,348 934 4,211 3,021 1,306
processing, and
treating services
Other - - 3 2 -
Total revenues 18,672 36,187 78,077 125,712 26,057
Cost of natural 16,842 33,307 71,730 117,635 23,819
gas and NGLs
Operating costs
and expenses:
Operations and 896 635 2,946 1,862 989
maintenance
Depreciation,
depletion and 1,287 939 3,995 2,812 1,284
amortization
Total operating 2,183 1,574 6,941 4,674 2,273
costs and expenses
Operating income
(loss) from (353 ) 1,306 (594 ) 3,403 (35 )
continuing
operations
Discontinued 26 601 266 1,436 (67 )
Operations
Operating income $ (327 ) $ 1,907 $ (328 ) $ 4,839 $ (102 )
Gulf of Mexico (1)
Revenues:
Natural gas, NGLs,
oil and condensate $ 8,314 $ - $ 20,380 $ - $ 5,844
sales
Gathering,
compression, 304 - 672 - 280
processing, and
treating services
Other - - 1,616 - 1,616
Total revenues 8,618 - 22,668 - 7,740
Cost of natural 6,898 - 17,271 - 5,181
gas and NGLs
Operating costs
and expenses:
Operations and 310 - 1,386 - 658
maintenance
Depreciation,
depletion and 1,480 - 4,445 - 1,477
amortization
Total operating 1,790 - 5,831 - 2,135
costs and expenses
Operating income $ (70 ) $ - $ (434 ) $ - $ 424
(1) Includes operations related to the Millennium Acquisition beginning October 1, 2008.
Eagle Rock Energy Partners, L.P.
Segment Summary
Operating Income
($ in thousands)
(unaudited)
Three Months Nine Months Three
Months
Ended September 30, Ended September 30, Ended
2009 2008 2009 2008 June 30,
2009
Midstream
Revenues:
Natural gas,
NGLs, oil and $ 139,359 $ 286,722 $ 425,983 $ 869,135 $ 138,213
condensate
sales
Gathering,
compression,
processing and 11,814 12,513 35,043 27,741 11,562
treating
services
Other - - 1,619 2 1,616
Total revenues 151,173 299,235 462,645 896,878 151,391
Cost of
natural gas 109,945 237,742 358,802 726,400 115,640
and NGLs
Operating
costs and
expenses:
Operations and 14,139 14,019 42,626 39,026 14,311
maintenance
Impairment - - - - -
Depletion,
depreciation 18,827 14,912 55,569 44,245 17,963
and
amortization
Total
operating 32,966 28,931 98,195 83,271 32,274
costs and
expenses
Operating
income (loss)
from 8,262 32,562 5,648 87,207 3,477
continuing
operations
Discontinued 26 601 266 1,436 (67 )
Operations
Operating $ 8,288 $ 33,163 $ 5,914 $ 88,643 $ 3,410
income
Upstream (1)
Revenues:
Oil and $ 10,817 $ 22,694 $ 25,373 $ 62,153 $ 8,598
condensate (2)
Natural gas 2,221 11,168 7,081 27,725 2,965
(3)
NGLs (4) 4,382 8,059 10,152 24,354 3,544
Sulfur - 13,057 - 25,524 -
Other 50 428 151 608 62
Total revenues 17,470 55,406 42,757 140,364 15,169
Operating
costs and
expenses:
Operations and 5,178 12,394 18,311 29,369 6,601
maintenance
Sulfur 348 - 1,505 - 717
disposal costs
Impairment - - 242 - -
Other
operating - - (3,552 ) - (3,552 )
income
Depreciation,
depletion and 7,768 11,170 25,119 29,509 7,955
amortization
Total
operating 13,294 23,564 41,625 58,878 11,721
costs and
expenses
Operating $ 4,176 $ 31,842 $ 1,132 $ 81,486 $ 3,448
income
Minerals
Revenues:
Oil and $ 2,228 $ 4,390 $ 6,136 $ 12,489 $ 2,232
condensate
Natural gas 749 3,044 2,454 8,818 840
NGLs 169 413 367 1,059 69
Lease bonus,
rentals and 904 9,546 1,831 12,240 358
other
Total revenues 4,050 17,393 10,788 34,606 3,499
Operating
costs and
expenses:
Operations and 203 427 972 1,352 298
maintenance
Impairment 274 - 274 - -
Depreciation,
depletion and 1,654 2,321 4,781 6,460 1,452
amortization
Total
operating 2,131 2,748 6,027 7,812 1,750
costs and
expenses
Operating $ 1,919 $ 14,645 $ 4,761 $ 26,794 $ 1,749
income
Corporate
Revenues:
Unrealized
commodity $ (26,002 ) $ 255,956 $ (127,568 ) $ (33,381 ) $ (97,044 )
derivative
gains (losses)
Realized
commodity 17,170 (24,105 ) 70,431 (64,388 ) 22,483
derivative
gains (losses)
Total revenues (8,832 ) 231,851 (57,137 ) (97,769 ) (74,561 )
General and 10,449 9,893 34,882 31,161 11,895
administrative
Depreciation,
depletion and 337 194 768 585 218
amortization
Other
operating - 3,920 - 10,134 -
expense
Operating $ (19,618 ) $ 217,844 $ (92,787 ) $ (139,649 ) $ (86,674 )
income (loss)
(1) Includes operations from the Stanolind acquisition beginning on May 1, 2008.
(2) Revenues include a change in the value of product imbalances of $0 and $(260) for the three and nine months ended September 30, 2009, respectively. No changes in the value of the product imbalances were recognized during the three and nine months ended September 30, 2008.
(3) Revenues include a change in the value of product imbalances of $(780) and $(2,377) for the three and nine months ended September 30, 2009, respectively. No changes in the value of the product imbalances were recognized during three and nine months ended September 30, 2008.
(4) Revenues include a change in the value of product imbalances of $0 and $28 for the three and nine months ended September 30, 2009, respectively. No changes in the value of the product imbalances were recognized during the three and nine months ended September 30, 2008.
Eagle Rock Energy Partners, L.P.
Midstream Operations Information
(unaudited)
Three Months Nine Months Three Months
Ended September 30, Ended September 30, Ended
2009 2008 2009 2008 June 30, 2009
Gas gathering
volumes -
(Average Mcf/d)
Texas Panhandle 134,690 159,254 140,725 154,190 143,281
East 236,561 173,728 257,957 172,434 265,740
Texas/Louisiana
South Texas 66,680 80,097 85,496 81,228 90,395
Gulf of Mexico 131,527 - 115,591 - 98,619
Total 569,458 413,079 599,769 407,852 598,035
NGLs - (Net
equity gallons)
Texas Panhandle 12,170,309 12,728,821 34,620,772 38,519,981 11,815,414
East 5,830,042 6,387,873 14,672,928 17,321,951 6,166,467
Texas/Louisiana
South Texas 252,005 - 929,452 - 452,942
Gulf of Mexico 1,376,512 - 4,280,670 - 1,192,008
Total 19,628,868 19,116,694 50,223,152 55,841,932 19,626,831
Condensate -
(Net equity
gallons)
Texas Panhandle 9,938,819 10,023,469 25,944,824 25,767,353 9,813,579
East (31,131 ) 380,164 870,508 1,074,135 466,348
Texas/Louisiana
South Texas 210,984 571,615 1,167,630 1,399,183 309,186
Gulf of Mexico - - - - -
Total 10,118,672 10,975,248 27,982,962 28,240,671 10,589,113
Natural gas
short position
- (Average
MMbtu/d)
Texas Panhandle (4,685 ) (4,150 ) (5,524 ) (5,458 ) (5,748 )
East 2,295 747 2,790 885 2,798
Texas/Louisiana
South Texas 1,784 500 928 1,500 500
Total (606 ) (2,903 ) (1,806 ) (3,073 ) (2,450 )
Average
realized NGL
price - per Bbl
Texas Panhandle $ 33.55 $ 66.36 $ 29.33 $ 67.62 $ 29.82
East $ 41.37 $ 57.54 $ 30.63 $ 56.28 $ 31.50
Texas/Louisiana
South Texas $ 30.71 $ 83.16 $ 28.74 $ 77.70 $ 29.68
Gulf of Mexico $ 37.70 $ - $ 31.79 $ - $ 29.57
Weighted $ 35.63 $ 64.26 $ 29.87 $ 64.26 $ 30.22
average
Average
realized
condensate
price - per Bbl
Texas Panhandle $ 65.13 $ 106.43 $ 57.79 $ 105.03 $ 59.08
East $ 65.49 $ 125.29 $ 59.35 $ 117.16 $ 60.87
Texas/Louisiana
South Texas $ 58.06 $ 112.20 $ 45.02 $ 106.54 $ 55.55
Gulf of Mexico $ 65.67 $ - $ 54.50 $ - $ 48.20
Weighted $ 65.03 $ 108.23 $ 57.57 $ 106.09 $ 59.07
average
Average
realized
natural gas
price - per
MMbtu
Texas Panhandle $ 2.78 $ 8.81 $ 2.98 $ 8.85 $ 2.66
East $ 3.42 $ 9.69 $ 3.74 $ 10.37 $ 3.45
Texas/Louisiana
South Texas $ 3.06 $ 9.42 $ 3.66 $ 9.58 $ 3.31
Gulf of Mexico $ 3.46 $ - $ 4.64 $ - $ 3.87
Weighted $ 3.09 $ 9.22 $ 3.42 $ 9.29 $ 3.09
average
Eagle Rock Energy Partners, L.P.
Upstream and Minerals Operations Information
(unaudited)
Three Months Nine Months Three Months
September 30, September 30, Ended
2009 2008 2009 2008 June 30, 2009
Upstream
Production:
Oil and
condensate 213,351 230,727 628,527 616,643 204,725
(Bbl)
Gas (Mcf) 991,827 1,233,951 2,792,316 2,949,241 909,928
NGLs (Bbl) 128,379 119,664 375,215 365,761 123,057
Total Mcfe 3,042,207 3,336,297 8,814,768 8,843,665 2,876,620
Sulfur (Long 27,634 25,816 96,063 71,772 39,823
ton)
Realized
prices,
excluding
derivatives:
(1)
Oil and
condensate $ 50.78 $ 98.36 $ 40.79 $ 100.79 $ 43.20
(per Bbl)
Gas (per Mcf) $ 3.25 $ 9.05 $ 3.47 $ 9.41 $ 2.95
NGLs (per $ 34.67 $ 67.35 $ 27.07 $ 66.58 $ 27.44
Bbl)
Sulfur (per $ 505.77 $ 355.63 $ -
Long ton)
Operating
statistics:
Operating
costs per
Mcfe (incl $ 1.70 $ 3.71 $ 2.08 $ 3.32 $ 4.57
production
taxes)
Operating
costs per
Mcfe (excl $ 1.05 $ 2.94 $ 1.45 $ 2.53 $ 3.95
production
taxes)
Operating
Income per $ 1.37 $ 9.54 $ 0.13 $ 9.21 $ (1.06 )
Mcfe
Drilling
program
(gross
wells):
Development - 6 5 12 -
wells
Completions - 6 4 12 -
Workovers 4 1 10 1 4
Recompletions - 3 4 7 3
Minerals
Production:
Oil and
condensate 34,841 42,004 117,979 120,744 40,112
(Bbl)
Gas (Mcf) 264,082 336,060 853,571 991,534 307,287
NGLs (Bbl) 5,739 6,981 15,110 17,381 3,660
Total Mcfe 507,562 629,970 1,652,106 1,820,288 569,919
Realized
prices,
excluding
derivatives:
Oil and
condensate $ 63.96 $ 104.62 $ 52.87 $ 103.47 $ 55.69
(per Bbl)
Gas (per Mcf) $ 2.31 $ 9.36 $ 2.76 $ 8.99 $ 2.90
NGLs (per $ 29.44 $ 59.16 $ 23.62 $ 60.92 $ 18.83
Bbl)
(1) Calculation does not include impact of product imbalances.
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 Nine Months Three
Months
Ended September 30, Ended September 30, Ended
Net income (loss) to 2009 2008 2009 2008 June 30,
adjusted EBITDA 2009
Net income (loss), as $ (25,271 ) $ 288,071 $ (102,603 ) $ 32,723 $ (74,787 )
reported
Depreciation, depletion 28,586 28,597 86,237 80,799 27,588
and amortization expense
Impairment 274 - 516 - -
Risk management interest
related 5,308 501 (9,745 ) 472 (11,954 )
instruments-unrealized
Risk management
commodity related
instruments-unrealized, 26,002 (255,956 ) 127,568 33,381 97,044
including amortization
of commodity derivative
costs
Other operating (income) - 3,920 (3,552 ) 10,134 (3,552 )
expenses (non-recurring)
Non-cash mark-to-market
of Upstream product 780 - 2,609 (203 )
imbalances
Restricted units
non-cash amortization 904 1,427 5,024 4,147 1,889
expense
Income tax provision 5,841 (500 ) 1,634 (1,497 ) (1,477 )
(benefit)
Interest - net including
realized risk management 9,612 9,849 31,569 28,458 10,701
instruments and other
expense
Other (income)/expense (725 ) (434 ) (1,835 ) (2,867 ) (550 )
Discontinued operations (26 ) (594 ) (266 ) (1,451 ) (33 )
Adjusted EBITDA $ 51,285 $ 74,881 $ 137,156 $ 184,299 $ 44,666
Net income (loss) to
distributable cash flow
Net income (loss), as $ (25,271 ) $ 288,071 $ (102,603 ) $ 32,723 $ (74,787 )
reported
Depreciation, depletion 28,586 28,597 86,237 80,799 27,588
and amortization expense
Impairment 274 - 516 - -
Risk management interest
related 5,308 501 (9,745 ) 472 (11,954 )
instruments-unrealized
Risk management
commodity related
instruments-unrealized, 26,002 (255,956 ) 127,568 33,381 97,044
including amortization
of commodity derivative
costs
Capital
expenditures-maintenance (4,392 ) (5,434 ) (12,011 ) (21,447 ) (4,836 )
related
Non-cash mark-to-market
of Upstream product 780 - 2,609 - (203 )
imbalances
Restricted units
non-cash amortization 904 1,427 5,024 4,147 1,889
expense
Other operating (income) - 3,920 (3,552 ) 10,134 (3,552 )
expenses (non-recurring)
Income tax provision 5,841 (500 ) 1,634 (1,497 ) (1,477 )
(benefit)
Other (income)/expense (725 ) (434 ) (1,835 ) (2,867 ) (550 )
Cash income taxes (635 ) (229 ) (992 ) (533 ) (280 )
Discontinued operations (26 ) (594 ) (266 ) (1,451 ) (33 )
Distributable cash flow $ 36,646 $ 59,369 $ 92,584 $ 133,861 $ 28,849
Supplemental Information
($ in thousands)
Three Months Ended Nine Months Ended
September 30, September 30,
2009 2008 2009 2008 2009
Amortization of
commodity derivative 10,590 2,260 33,886 6,780 11,137
costs
Source: Eagle Rock Energy Partners, L.P.
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