Eagle Rock Reports Third-Quarter 2009 Financial Results

http://www.businesswire.com/news/home/20091104006640/en

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, oil and sulfur sales $ 156,779 $ 341,700 $ 468,589 $ 1,008,891 $ 153,320
Gathering, compression, processing and treating fees 11,814 12,513 35,043 27,741 11,562
Minerals and royalty income 4,050 17,393 10,788 34,606 3,499
Unrealized commodity derivative gains (losses) (26,002 ) 255,956 (127,568 ) (33,381 ) (97,044 )
Realized commodity derivative gains (losses) 17,170 (24,105 ) 70,431 (64,388 ) 22,483
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 and NGLs 109,945 237,742 358,802 726,400 115,640
Operations and maintenance (1) 16,934 21,475 54,624 54,772 19,049
Taxes other than income 2,934 5,365 8,790 14,975 2,878
Impairment 274 - 516 - -
General and administrative 10,449 9,893 34,882 31,161 11,895
Other operating (income) expense - 3,920 (3,552 ) 10,134 (3,552 )
Depreciation, depletion and amortization 28,586 28,597 86,237 80,799 27,588
Total Costs and Expenses 169,122 306,992 540,299 918,241 173,498

OPERATING INCOME (LOSS) (5,261 ) 296,893 (81,246 ) 55,838 (78,000 )

Other Income (Expense):
Interest income 10 212 183 673 141
Other income 725 434 1,835 2,867 550
Interest expense, net (4,315 ) (7,498 ) (17,282 ) (23,576 ) (5,428 )
Unrealized interest rate derivative gains (losses) (5,308 ) (501 ) 9,745 (472 ) 11,954
Realized interest rate derivative gains (losses) (5,040 ) (2,358 ) (13,669 ) (4,903 ) (5,147 )
Other expense (267 ) (205 ) (801 ) (652 ) (267 )
Total Other Income (Expense) (14,195 ) (9,916 ) (19,989 ) (26,063 ) 1,803

INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (19,456 ) 286,977 (101,235 ) 29,775 (76,197 )

Income tax (benefit) provision 5,841 (500 ) 1,634 (1,497 ) (1,477 )

INCOME (LOSS) FROM CONTINUING OPERATIONS (25,297 ) 287,477 (102,869 ) 31,272 (74,720 )

DISCONTINUED OPERATIONS 26 594 266 1,451 (67 )

NET INCOME (LOSS) $ (25,271 ) $ 288,071 $ (102,603 ) $ 32,723 $ (74,787 )

(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 sales $ 67,468 $ 179,608 $ 196,791 $ 514,450 $ 66,373
Gathering, compression, processing, and treating services 2,795 2,671 8,209 7,664 2,601
Total revenues 70,263 182,279 205,000 522,114 68,974
Cost of natural gas and NGLs 46,540 138,428 147,894 398,828 49,407
Operating costs and expenses:
Operations and maintenance 8,206 9,190 24,407 25,653 8,056
Depreciation, depletion and amortization 11,602 10,984 33,660 32,587 10,962
Total operating costs and expenses 19,808 20,174 58,067 58,240 19,018
Operating income $ 3,915 $ 23,677 $ (961 ) $ 65,046 $ 549

East Texas/Louisiana (1)
Revenues:
Natural gas, NGLs, oil and condensate sales $ 46,253 $ 71,861 $ 134,949 $ 231,996 $ 41,245
Gathering, compression, processing, and treating services 7,367 8,908 21,951 17,056 7,375
Total revenues 53,620 80,769 156,900 249,052 48,620
Cost of natural gas and NGLs 39,665 66,007 121,907 209,937 37,233
Operating costs and expenses:
Operations and maintenance 4,727 4,194 13,887 11,511 4,608
Depreciation, depletion and amortization 4,458 2,989 13,469 8,846 4,240
Total operating costs and expenses 9,185 7,183 27,356 20,357 8,848
Operating income $ 4,770 $ 7,579 $ 7,637 $ 18,758 $ 2,539

South Texas (1)
Revenues:
Natural gas, NGLs, oil and condensate sales $ 17,324 $ 35,253 $ 73,863 $ 122,689 $ 24,751
Gathering, compression, processing, and treating services 1,348 934 4,211 3,021 1,306
Other - - 3 2 -
Total revenues 18,672 36,187 78,077 125,712 26,057
Cost of natural gas and NGLs 16,842 33,307 71,730 117,635 23,819
Operating costs and expenses:
Operations and maintenance 896 635 2,946 1,862 989
Depreciation, depletion and amortization 1,287 939 3,995 2,812 1,284
Total operating costs and expenses 2,183 1,574 6,941 4,674 2,273
Operating income (loss) from continuing operations (353 ) 1,306 (594 ) 3,403 (35 )
Discontinued Operations 26 601 266 1,436 (67 )
Operating income $ (327 ) $ 1,907 $ (328 ) $ 4,839 $ (102 )

Gulf of Mexico (1)
Revenues:
Natural gas, NGLs, oil and condensate sales $ 8,314 $ - $ 20,380 $ - $ 5,844
Gathering, compression, processing, and treating services 304 - 672 - 280
Other - - 1,616 - 1,616
Total revenues 8,618 - 22,668 - 7,740
Cost of natural gas and NGLs 6,898 - 17,271 - 5,181
Operating costs and expenses:
Operations and maintenance 310 - 1,386 - 658
Depreciation, depletion and amortization 1,480 - 4,445 - 1,477
Total operating costs and expenses 1,790 - 5,831 - 2,135
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 condensate sales $ 139,359 $ 286,722 $ 425,983 $ 869,135 $ 138,213
Gathering, compression, processing and treating services 11,814 12,513 35,043 27,741 11,562
Other - - 1,619 2 1,616
Total revenues 151,173 299,235 462,645 896,878 151,391
Cost of natural gas and NGLs 109,945 237,742 358,802 726,400 115,640
Operating costs and expenses:
Operations and maintenance 14,139 14,019 42,626 39,026 14,311
Impairment - - - - -
Depletion, depreciation and amortization 18,827 14,912 55,569 44,245 17,963
Total operating costs and expenses 32,966 28,931 98,195 83,271 32,274
Operating income (loss) from continuing operations 8,262 32,562 5,648 87,207 3,477
Discontinued Operations 26 601 266 1,436 (67 )
Operating income $ 8,288 $ 33,163 $ 5,914 $ 88,643 $ 3,410

Upstream (1)
Revenues:
Oil and condensate (2) $ 10,817 $ 22,694 $ 25,373 $ 62,153 $ 8,598
Natural gas (3) 2,221 11,168 7,081 27,725 2,965
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 maintenance 5,178 12,394 18,311 29,369 6,601
Sulfur disposal costs 348 - 1,505 - 717
Impairment - - 242 - -
Other operating income - - (3,552 ) - (3,552 )
Depreciation, depletion and amortization 7,768 11,170 25,119 29,509 7,955
Total operating costs and expenses 13,294 23,564 41,625 58,878 11,721
Operating income $ 4,176 $ 31,842 $ 1,132 $ 81,486 $ 3,448

Minerals
Revenues:
Oil and condensate $ 2,228 $ 4,390 $ 6,136 $ 12,489 $ 2,232
Natural gas 749 3,044 2,454 8,818 840
NGLs 169 413 367 1,059 69
Lease bonus, rentals and other 904 9,546 1,831 12,240 358
Total revenues 4,050 17,393 10,788 34,606 3,499
Operating costs and expenses:
Operations and maintenance 203 427 972 1,352 298
Impairment 274 - 274 - -
Depreciation, depletion and amortization 1,654 2,321 4,781 6,460 1,452
Total operating costs and expenses 2,131 2,748 6,027 7,812 1,750
Operating income $ 1,919 $ 14,645 $ 4,761 $ 26,794 $ 1,749

Corporate
Revenues:
Unrealized commodity derivative gains (losses) $ (26,002 ) $ 255,956 $ (127,568 ) $ (33,381 ) $ (97,044 )
Realized commodity derivative gains (losses) 17,170 (24,105 ) 70,431 (64,388 ) 22,483
Total revenues (8,832 ) 231,851 (57,137 ) (97,769 ) (74,561 )
General and administrative 10,449 9,893 34,882 31,161 11,895
Depreciation, depletion and amortization 337 194 768 585 218
Other operating expense - 3,920 - 10,134 -
Operating income (loss) $ (19,618 ) $ 217,844 $ (92,787 ) $ (139,649 ) $ (86,674 )

(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 Texas/Louisiana 236,561 173,728 257,957 172,434 265,740
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 Texas/Louisiana 5,830,042 6,387,873 14,672,928 17,321,951 6,166,467
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 Texas/Louisiana (31,131 ) 380,164 870,508 1,074,135 466,348
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 Texas/Louisiana 2,295 747 2,790 885 2,798
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 Texas/Louisiana $ 41.37 $ 57.54 $ 30.63 $ 56.28 $ 31.50
South Texas $ 30.71 $ 83.16 $ 28.74 $ 77.70 $ 29.68
Gulf of Mexico $ 37.70 $ - $ 31.79 $ - $ 29.57
Weighted average $ 35.63 $ 64.26 $ 29.87 $ 64.26 $ 30.22

Average realized condensate price - per Bbl
Texas Panhandle $ 65.13 $ 106.43 $ 57.79 $ 105.03 $ 59.08
East Texas/Louisiana $ 65.49 $ 125.29 $ 59.35 $ 117.16 $ 60.87
South Texas $ 58.06 $ 112.20 $ 45.02 $ 106.54 $ 55.55
Gulf of Mexico $ 65.67 $ - $ 54.50 $ - $ 48.20
Weighted average $ 65.03 $ 108.23 $ 57.57 $ 106.09 $ 59.07

Average realized natural gas price - per MMbtu
Texas Panhandle $ 2.78 $ 8.81 $ 2.98 $ 8.85 $ 2.66
East Texas/Louisiana $ 3.42 $ 9.69 $ 3.74 $ 10.37 $ 3.45
South Texas $ 3.06 $ 9.42 $ 3.66 $ 9.58 $ 3.31
Gulf of Mexico $ 3.46 $ - $ 4.64 $ - $ 3.87
Weighted average $ 3.09 $ 9.22 $ 3.42 $ 9.29 $ 3.09

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 (Bbl) 213,351 230,727 628,527 616,643 204,725
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 ton) 27,634 25,816 96,063 71,772 39,823

Realized prices, excluding derivatives: (1)
Oil and condensate (per Bbl) $ 50.78 $ 98.36 $ 40.79 $ 100.79 $ 43.20
Gas (per Mcf) $ 3.25 $ 9.05 $ 3.47 $ 9.41 $ 2.95
NGLs (per Bbl) $ 34.67 $ 67.35 $ 27.07 $ 66.58 $ 27.44
Sulfur (per Long ton) $ 505.77 $ 355.63 $ -

Operating statistics:
Operating costs per Mcfe (incl production taxes) $ 1.70 $ 3.71 $ 2.08 $ 3.32 $ 4.57
Operating costs per Mcfe (excl production taxes) $ 1.05 $ 2.94 $ 1.45 $ 2.53 $ 3.95
Operating Income per Mcfe $ 1.37 $ 9.54 $ 0.13 $ 9.21 $ (1.06 )

Drilling program (gross wells):
Development wells - 6 5 12 -
Completions - 6 4 12 -
Workovers 4 1 10 1 4
Recompletions - 3 4 7 3

Minerals
Production:
Oil and condensate (Bbl) 34,841 42,004 117,979 120,744 40,112
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 (per Bbl) $ 63.96 $ 104.62 $ 52.87 $ 103.47 $ 55.69
Gas (per Mcf) $ 2.31 $ 9.36 $ 2.76 $ 8.99 $ 2.90
NGLs (per Bbl) $ 29.44 $ 59.16 $ 23.62 $ 60.92 $ 18.83

(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 adjusted EBITDA 2009 2008 2009 2008 June 30, 2009

Net income (loss), as reported $ (25,271 ) $ 288,071 $ (102,603 ) $ 32,723 $ (74,787 )

Depreciation, depletion and amortization expense 28,586 28,597 86,237 80,799 27,588
Impairment 274 - 516 - -
Risk management interest related instruments-unrealized 5,308 501 (9,745 ) 472 (11,954 )
Risk management commodity related instruments-unrealized, including amortization of commodity derivative costs 26,002 (255,956 ) 127,568 33,381 97,044
Other operating (income) expenses (non-recurring) - 3,920 (3,552 ) 10,134 (3,552 )
Non-cash mark-to-market of Upstream product imbalances 780 - 2,609 (203 )
Restricted units non-cash amortization expense 904 1,427 5,024 4,147 1,889
Income tax provision (benefit) 5,841 (500 ) 1,634 (1,497 ) (1,477 )
Interest - net including realized risk management instruments and other expense 9,612 9,849 31,569 28,458 10,701
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 reported $ (25,271 ) $ 288,071 $ (102,603 ) $ 32,723 $ (74,787 )

Depreciation, depletion and amortization expense 28,586 28,597 86,237 80,799 27,588
Impairment 274 - 516 - -
Risk management interest related instruments-unrealized 5,308 501 (9,745 ) 472 (11,954 )
Risk management commodity related instruments-unrealized, including amortization of commodity derivative costs 26,002 (255,956 ) 127,568 33,381 97,044
Capital expenditures-maintenance related (4,392 ) (5,434 ) (12,011 ) (21,447 ) (4,836 )
Non-cash mark-to-market of Upstream product imbalances 780 - 2,609 - (203 )
Restricted units non-cash amortization expense 904 1,427 5,024 4,147 1,889
Other operating (income) expenses (non-recurring) - 3,920 (3,552 ) 10,134 (3,552 )
Income tax provision (benefit) 5,841 (500 ) 1,634 (1,497 ) (1,477 )
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 costs 10,590 2,260 33,886 6,780 11,137

Eagle Rock Energy Partners, L.P.
Jeff Wood, 281-408-1203
Senior Vice President and Chief Financial Officer

Copyright Business Wire 2009