UNITED STATES
 SECURITIES AND EXCHANGE COMMISSION
 Washington, D.C. 20549
 
  FORM 10-Q
 
  x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
  For the quarterly period ended June 30, 2009
  OR
   ̈
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
  Commission File No. 001-33016
 
  EAGLE ROCK ENERGY PARTNERS, L.P.
 (Exact Name of Registrant as Specified in Its Charter)
 
 
 Delaware
68-0629883(State or Other Jurisdiction of
Incorporation or Organization)
(I.R.S. Employer
Identification Number)
  16701 Greenspoint Park Drive, Suite 200
 Houston, Texas 77060
 (Address of principal executive offices, including zip code)
  (281) 408-1200
 (Registrant’s telephone number, including area code)
 
  Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements
for the past 90 days.    Yes  x    No   ̈
  Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12
months (or for such shorter period than the registrant was required to submit and post such files).Yes   ̈    No   ̈
  Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check
one):
 
 Large accelerated filer   ̈
Accelerated filer  xNon-accelerated filer   ̈
Smaller Reporting Company   ̈(Do not check if a smaller reporting company)
  Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes   ̈    No  x
  The issuer had 55,215,112 common units outstanding as of August 3, 2009.
  
  
 EAGLE ROCK ENERGY PARTNERS, L.P.
  TABLE OF CONTENTS
  
 
 PagePART I. FINANCIAL INFORMATIONItem 1.
Financial StatementsUnaudited Condensed Consolidated Balance Sheets as of June 30, 2009 and December 31, 2008
2Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2009 and 2008
3Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2009 and 2008
4Unaudited Condensed Consolidated Statements of Members’ Equity for the six months ended June 30, 2009 and 2008
5Notes to the Unaudited Condensed Consolidated Financial Statements
6Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
25Item 3.
Quantitative and Qualitative Disclosures About Market Risk
41Item 4.
Controls and Procedures
41PART II. OTHER INFORMATIONItem 1.
Legal Proceedings
42Item 1A.
Risk Factors
42Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
43Item 3.
Defaults Upon Senior Securities
43Item 4.
Submission of Matters to a Vote of Security Holders
43Item 5.
Other Information
43Item 6.
Exhibits
43
 
  
  
  
  1
 Table of Contents
   PART 1. FINANCIAL INFORMATION
  Item 1.
Financial Statements.
 
 EAGLE ROCK ENERGY PARTNERS, L.P.
 UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
 ($ in thousands)
 
 June 30,
2009


December 31,
2008ASSETSCURRENT ASSETS:Cash and cash equivalents

$
2,062


$
17,916Accounts receivable(1)


80,796



115,932Risk management assets


49,277



76,769Prepayments and other current assets


3,909



2,607Total current assets


136,044



213,224PROPERTY, PLANT AND EQUIPMENT — Net


1,326,066



1,357,609INTANGIBLE ASSETS — Net


144,201



154,206RISK MANAGEMENT ASSETS


7,183



32,451OTHER ASSETS


19,719



15,571TOTAL

$
1,633,213


$
1,773,061LIABILITIES AND MEMBERS’ EQUITYCURRENT LIABILITIES:Accounts payable

$
67,684


$
116,578Due to affiliate


11,077



4,473Accrued liabilities


13,137



19,565Taxes payable


504



1,559Risk management liabilities


24,756



13,763Total current liabilities


117,158



155,938LONG-TERM DEBT


804,383



799,383ASSET RETIREMENT OBLIGATIONS


19,638



19,872DEFERRED TAX LIABILITY


35,175



42,349RISK MANAGEMENT LIABILITIES


35,045



26,182OTHER LONG TERM LIABILITIES


270



1,622COMMITMENTS AND CONTINGENCIES (Note 12)MEMBERS’ EQUITY:Common Unitholders(2)


549,398



625,590Subordinated Unitholders(3)


77,027



105,839General Partner(4)


(4,881
)


(3,714
)Total members’ equity


621,544



727,715TOTAL

$
1,633,213


$
1,773,061
 
 (1)
Net of allowable for bad debt of $12,127 as of June 30, 2009 and $12,080 as of December 31, 2008, of which $10,699 relates to SemGroup L.P. which filed for bankruptcy in July 2008.
 (2)
53,244,361 and 53,043,767 units were issued and outstanding as of June 30, 2009 and December 31, 2008, respectively. These amounts do not include unvested restricted common units granted under the Partnership’s long-term incentive plan of 694,813 and 905,486 as of June 30, 2009 and December 31, 2008, respectively.
 (3)
20,691,495 units were issued and outstanding as of June 30, 2009 and December 31, 2008.
 (4)
844,551 units were issued and outstanding as of June 30, 2009 and December 31, 2008.
  See notes to unaudited condensed consolidated financial statements.
  2
 Table of Contents
   EAGLE ROCK ENERGY PARTNERS, L.P.
 UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
 (In thousands, except per unit amounts)
 
 Three Month Ended
June 30,


Six Months Ended
June 30,2009


2008


2009


2008REVENUE:Natural gas, natural gas liquids, oil, condensate and sulfur sales

$
153,056


$
369,715


$
304,148


$
674,689Gathering, compression, processing and treating services


11,562



8,085



23,229



15,228Minerals and royalty income


3,499



10,255



6,738



17,213Commodity risk management losses


(74,561
)


(283,973
)


(48,305
)


(329,620
)Other revenue


1,678



122



1,720



182Total revenue


95,234



104,204



287,530



377,692COSTS AND EXPENSES:Cost of natural gas and natural gas liquids


115,476



272,055



241,295



496,129Operations and maintenance (1)


19,049



17,731



37,690



33,297Taxes other than income


2,878



5,263



5,856



9,610General and administrative


11,895



10,026



24,433



21,268Other operating (income) expenses


(3,552
)


6,214



(3,552
)


6,214Impairment


—



—



242



—Depreciation, depletion, and amortization


27,588



26,457



57,651



52,202Total costs and expenses


173,334



337,746



363,615



618,720OPERATING LOSS


(78,100
)


(233,542
)


(76,085
)


(241,028
)OTHER INCOME (EXPENSE):Interest income


141



160



173



461Other income


550



886



1,110



2,433Interest expense, net


(5,428
)


(6,974
)


(12,967
)


(16,078
)Interest rate risk management gains (losses)


6,807



11,245



6,424



(2,516
)Other expense


(267
)


(232
)


(534
)


(447
)Total other income (expense)


1,803



5,085



(5,794
)


(16,147
)LOSS FROM CONTINUING OPERATIONS
BEFORE INCOME TAXES


(76,297
)


(228,457
)


(81,879
)


(257,175
)INCOME TAX BENEFIT


(1,477
)


(886
)


(4, 207
)


(988
)LOSS FROM CONTINUING OPERATIONS


(74,820
)


(227,571
)


(77,672
)


(256,187
)DISCONTINUED OPERATIONS


33



551



340



839NET LOSS

$
(74,787
)

$
(227,020
)

$
(77,332
)

$
(255,348
)NET INCOME (LOSS) PER COMMON UNIT — BASIC AND DILUTED:Basic and diluted loss from continuing operations per unit:Common units

$
(1.00
)

$
(3.15
)

$
(1.03
)

$
(3.55
)Subordinated units

$
(1.02
)

$
(3.15
)

$
(1.08
)

$
(3.55
)General partner units

$
(1.00
)

$
(3.15
)

$
(1.03
)

$
(3.55
)Basic and diluted discontinued operations per unit:Common units

$
—


$
0.01


$
—


$
0.01Subordinated units

$
—


$
0.01


$
—


$
0.01General partner units

$
—


$
0.01


$
—


$
0.01Basic and diluted net loss per unit:Common units

$
(0.99
)

$
(3.14
)

$
(1.02
)

$
(3.54
)Subordinated units

$
(1.02
)

$
(3.14
)

$
(1.07
)

$
(3.54
)General partner units

$
(0.99
)

$
(3.14
)

$
(1.02
)

$
(3.54
)Basic and diluted weighted average units outstanding:Common units


53,147



50,762



53,093



50,731Subordinated units


20,691



20,691



20,691



20,691General partner units


845



845



845



845
 
 
 (1)
Includes costs to dispose of sulfur in our Upstream segment of $717 and $1,157 for three and six months ended June 30, 2009.
 
 See notes to unaudited condensed consolidated financial statements.
 3
 Table of Contents
   EAGLE ROCK ENERGY PARTNERS, L.P.
 UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 ($ in thousands)
 
 Six Months
Ended June 30,2009


2008CASH FLOWS FROM OPERATING ACTIVITIES:Net loss

$
(77,332
)

$
(255,348
)Adjustments to reconcile net loss to net cash provided by operating activities:Depreciation, depletion and amortization


57,651



52,202Impairment


242



—Amortization of debt issuance costs


534



436Reclassifying financing derivative settlements


(6,774
)


9,537Distribution from unconsolidated affiliates – return on investment


247



509Equity in earnings of unconsolidated affiliates


(927
)


(2,433
)Equity-based compensation expense


4,120



2,718Other operating income


(3,552
)


—Other


(3,980
)


(825
)Changes in assets and liabilities — net of acquisitions:Accounts receivable


36,217



(48,032
)Prepayments and other current assets


(1,291
)


(901
)Risk management activities


72,613



289,308Accounts payable


(45,266
)


65,571Due to affiliates


6,604



4,105Accrued liabilities


(5,173
)


6,021Other assets and liabilities


(1,654
)


(224
)Net cash provided by operating activities


32,279



122,644CASH FLOWS FROM INVESTING ACTIVITIES:Acquisitions, net of cash acquired


—



(81,289
)Additions to property, plant and equipment


(25,501
)


(33,080
)Purchase of intangible assets


(1,109
)


(1,011
)Investment in unconsolidated affiliates


(393
)


—Net cash used in investing activities


(27,003
)


(115,380
)CASH FLOWS FROM FINANCING ACTIVITIES:Repayment of revolving credit facility


(118,000
)


(50,069
)Proceeds from revolving credit facility


123,000



106,000Proceeds (payments) for derivative contracts


6,774



(9,537
)Distributions to members and affiliates


(32,904
)


(57,624
)Net cash used in financing activities


(21,130
)


(11,230
)NET CHANGE IN CASH AND CASH EQUIVALENTS


(15,854
)


(3,966
)CASH AND CASH EQUIVALENTS — Beginning of period


17,916



68,552CASH AND CASH EQUIVALENTS — End of period

$
2,062


$
64,586SUPPLEMENTAL CASH FLOW DATA:Interest paid — net of amounts capitalized

$
17,041


$
12,442Cash paid for taxes

$
1,237


$
705Investments in property, plant and equipment not paid

$
1,545


$
1,885
 
 
  See notes to unaudited condensed consolidated financial statements.
 
  4
 Table of Contents
  
 EAGLE ROCK ENERGY PARTNERS, L.P.
 UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY
 
 FOR THE SIX MONTH PERIOD ENDED JUNE 30, 2008
 ($ in thousands, except unit amounts)
 
 General
Partner


Number of
Common
Units


Common
Units


Number of
Subordinated
Units


Subordinated
Units


TotalBALANCE — December 31, 2007

$
(3,155
)


50,699,647


$
617,563



20,691,495


$
112,360


$
726,768Net loss


(2,987
)


—



(179,172
)


—



(73,189
)


(255,348
)Distributions


(669
)


—



(40,557
)


—



(16,398
)


(57,624
)Vesting of restricted units


—



124,384



—



—



—



—Distributions to affiliates


—



—



(857
)


—



—



(857
)Equity based compensation


26



—



1,909



—



783



2,718BALANCE — June 30, 2008

$
(6,785
)


50,824,031


$
398,886



20,691,495


$
23,556


$
415,657
 
 
 
 FOR THE SIX MONTH PERIOD ENDED JUNE 30, 2009
 ($ in thousands, except unit amounts)
 
 General
Partner


Number of
Common
Units


Common
Units


Number of
Subordinated
Units


Subordinated
Units


TotalBALANCE — December 31, 2008

$
(3,714
)


53,043,767


$
625,590



20,691,495


$
105,839


$
727,715Net loss


(873
)


—



(55,062
)


—



(21,397
)


(77,332
)Distributions


(337
)


—



(24,029
)


—



(8,538
)


(32,904
)Vesting of restricted units


—



217,503



—



—



—



—Units returned from escrow


—



(7,065
)


(25
)


—



—



(25
)Repurchase of common units


—



(9,844
)


(30
)


—



—



(30
)Equity based compensation


43



—



2,954



—



1,123



4,120BALANCE — June 30, 2009

$
(4,881
)


53,244,361


$
549,398



20,691,495


$
77,027


$
621,544
 
 
 
  See notes to unaudited condensed consolidated financial statements.
 
  5
 Table of Contents
  
 EAGLE ROCK ENERGY PARTNERS, L.P.
 NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
  NOTE 1. ORGANIZATION AND DESCRIPTION OF BUSINESS
  In May 2006, Eagle Rock Energy Partners, L.P. (“Eagle Rock Energy” or the “Partnership”), a Delaware limited partnership and an indirect wholly-owned subsidiary of Eagle Rock Holdings, L.P. (“Holdings”), was formed for the purpose
of completing a public offering of common units. Holdings is a portfolio company of Irving, Texas–based, private-equity-capital firm Natural Gas Partners (“NGP”). On October 24, 2006, Eagle Rock Energy Partners, L.P. completed its initial public offering of common units. In connection with the initial public offering, Eagle Rock Pipeline, L.P., which was the main operating subsidiary of Holdings, became a subsidiary of Eagle Rock Energy.
 
 Basis of Presentation and Principles of Consolidation—The accompanying financial statements include assets, liabilities and the results of operations
of the Partnership. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements presented in the Partnership’s annual report on Form 10-K for the year ended December 31, 2008. That report contains a more comprehensive summary of the Partnership’s major accounting policies. In the opinion of management, the accompanying unaudited condensed consolidated financial statements contain all appropriate adjustments, all of which
are normally recurring adjustments unless otherwise noted, considered necessary to present fairly the financial position of the Partnership and its consolidated subsidiaries and the results of operations and cash flows for the respective periods. Operating results for the three and six-month periods ended June 30, 2009 are not necessarily indicative of the results that may be expected for the year ending December 31, 2009.
 
 Description of Business— The Partnership is a growth-oriented limited partnership
engaged in the business of (i) gathering, compressing, treating, processing and transporting and selling natural gas; fractionating and transporting natural gas liquids (“NGLs”); and marketing natural gas, condensate and NGLs, which collectively the Partnership calls its “Midstream Business”; (ii) acquiring, developing and producing interests in oil and natural gas properties, which the Partnership calls its “Upstream Business”; and (iii) acquiring and managing fee mineral
and royalty interests, either through direct ownership or through investment in other partnerships in properties in multiple producing trends across the United States, which the Partnership calls its “Minerals Business.”  See Note 13 for a further description of the Partnership’s three businesses and the seven accounting segments in which it reports.
  NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
  The accompanying condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. All intercompany accounts and transactions are eliminated in the consolidated financial statements.
  The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements
and the reported amounts of revenues and expenses during the reported period. Significant estimates are required for proved oil and natural gas reserves, which can affect the carrying value of oil and natural gas properties. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets
and liabilities that are not readily apparent from other sources. Actual results could differ from those estimates and such differences could be material.
  The Partnership has provided a discussion of significant accounting policies in its annual report on Form 10-K for the year ended December 31, 2008. Certain items from that discussion are repeated or updated below as necessary to assist in understanding these financial statements.
  Oil and Natural Gas Accounting Policies
 
 The Partnership utilizes the successful efforts method of accounting for its oil and natural gas properties. Leasehold costs are capitalized when incurred. Costs incurred to drill and complete development wells, including dry holes, are capitalized. Geological and
geophysical expenses and delay rentals are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if the well is determined to be unsuccessful. The Partnership carries the costs of an exploratory well as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well as long as the Partnership is making sufficient progress towards assessing the reserves and the economic and operating viability of the project.
 
 Depletion of proved oil and natural gas properties is recorded based on units of production. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for acquisition costs using all proved reserves.
 
 Upon sale or retirement of complete fields of depreciable or depleted property, the book value thereof, less proceeds or salvage value, is charged or credited to income.
 
 Unproved properties that are individually insignificant are amortized.  Unproved properties that are individually significant are assessed for impairment on a property-by-property basis.  If considered impaired, costs are charged to expense when
such impairment is deemed to have occurred.
  Impairment of Oil and Natural Gas Properties
 
 The Partnership reviews its proved properties at the field level when management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a projection of future oil and natural
gas reserves that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, and future inflation levels. If the carrying amount of an asset exceeds the sum of the undiscounted estimated future net cash flows, the Partnership recognizes impairment expense equal to the difference between the carrying value and the fair value of the asset, which is estimated to be the expected present value of discounted future net cash flows from proved reserves utilizing
the Partnership’s estimated weighted average cost of capital. In connection with the preparation of these financial statements for the six months ended June 30, 2009, the Partnership recorded impairment charges of $0.2 million in its Upstream Segment as a result of continued decline in natural gas prices during the period.  These impairment charges related specifically to the three months ended March 31, 2009 and there is no additional impairment specifically for the three months ended June 30,
2009.  The Partnership did not incur any impairment charges related to its Upstream Segment’s oil and natural gas properties during the three and six months ended June 30, 2008.   The Partnership cannot predict the amount of additional impairment charges that may be recorded in the future.
  Other Significant Accounting Policies
  Transportation and Exchange Imbalances—In the course of transporting natural gas and natural gas liquids for others, the Partnership’s midstream business may receive for redelivery different quantities of natural gas or natural gas liquids than the quantities actually
delivered. These transactions result in transportation and exchange imbalance receivables or payables which, if not subject to cash out provisions, are recovered or repaid through the receipt or delivery of natural gas or natural gas liquids in future periods. Imbalance receivables are included in accounts receivable; imbalance payables are included in accounts payable on the unaudited condensed consolidated balance sheets and marked-to-market using current market prices in effect for the reporting period of
the outstanding imbalances. For the midstream business, as of June 30, 2009, the Partnership had imbalance receivables totaling $0.6 million and imbalance payables totaling $2.5 million, respectively. For the midstream business, as of December 31, 2008, the Partnership had imbalance receivables totaling $0.3 million and imbalance payables totaling $2.8 million, respectively. Changes in market value and the settlement of any such imbalance at a price greater than or less than the recorded imbalance results
in either an upward or downward adjustment, as appropriate, to the cost of natural gas and natural gas liquids sold.
  Derivatives—Statement of Financial Accounting Statements (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities,as
amended (“SFAS No. 133”), establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. SFAS No. 133 requires an entity to recognize all derivatives as either assets or liabilities in the statement of financial position and to measure those instruments at fair value. The Partnership uses financial instruments such as put and call options, swaps and other derivatives to mitigate
the risks to cash flows resulting from changes in commodity prices and interest rates. Because the Partnership has not designated any of these derivatives as hedges, the Partnership recognizes these financial instruments on its unaudited condensed consolidated balance sheets at the instrument’s fair value, and changes in fair value are reflected in the unaudited condensed consolidated statements of operations. The cash flows from derivatives are reported as cash flows from operating activities unless the
derivative contract is deemed to contain a financing element. Derivatives deemed to contain a financing element are reported as a financing activity in the statements of cash flows. See Note 11 for a description of the Partnership’s risk management activities.
 
 Reclassifications—Certain amounts in prior period financial statements have been reclassified to conform to the current period presentation.
The reclassification consists of an increase in revenue and operations and maintenance costs of $0.4 million from the amounts previously recognized in first quarter of fiscal 2009.  This reclassification relates to disposal costs incurred on sulfur sales which currently exceed the amount of revenue recognized for sulfur sales in fiscal 2009.  In addition, the Partnership sold its producer services business in April 2009; therefore, for the six months ended June 30, 2009, $0.3 million of revenues
minus the cost of natural gas and natural gas liquids have been reported as discontinued operations, as compared to revenues minus the cost of natural gas of $0.6 million and $0.8 million, respectively, for the three and six months ended June 30, 2008.
  Subsequent Events— The Partnership has evaluated all events subsequent to the balance sheet date of June 30, 2009 through the date of issuance, August 10, 2009.
  6
 Table of Contents
 
 NOTE 3. NEW ACCOUNTING PRONOUNCEMENTS
 
 In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (“SFAS No. 141R”),which replaces SFAS 141. SFAS 141R requires that all assets, liabilities, contingent consideration,
contingencies and in-process research and development costs of an acquired business be recorded at fair value at the acquisition date; that acquisition costs generally be expensed as incurred; that restructuring costs generally be expensed in periods subsequent to the acquisition date; and that changes in accounting for deferred tax asset valuation allowances and acquired income tax uncertainties after the measurement period impact income tax expense.  SFAS No. 141R is effective for business combinations
for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008, with the exception for the accounting for valuation allowances on deferred tax assets and acquired tax contingencies associated with acquisitions.  SFAS No. 141R amends SFAS No. 109, Accounting for Income Taxes,such that adjustments made to valuation allowances on deferred taxes and acquired tax contingencies
associated with acquisitions that closed prior to the effective date of SFAS No. 141R would also apply the provisions of SFAS No. 141R.  SFAS No. 141R was effective for the Partnership as of January 1, 2009 but the impact of the adoption on the Partnership’s consolidated financial statements will depend on the nature and the extent of business combinations occurring after January 1, 2009.
  In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements—an amendment of APB No. 51 (“SFAS No. 160”). SFAS No.160 requires that accounting and reporting for minority interests will be recharacterized
as noncontrolling interests and classified as a component of equity. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. This Statement is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008.  SFAS No. 160 was effective for the Partnership as of January 1, 2009 and did not have a material impact
on its consolidated results of operations or financial position.
  In February 2008, the FASB issued FASB Staff Position (“FSP”) No. FAS 157-2, “Effective Date of FASB Statement No. 157” (“FSP FAS 157-2”), which delays the effective date of SFAS 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value
in the financial statements on at least an annual basis, until fiscal years beginning after November 15, 2008.  Non-financial assets and liabilities that the Partnership measures at fair value on a non-recurring basis consists primarily of property, plant and equipment, intangible assets and asset retirement obligations, which are subject to fair value adjustments in certain circumstances (for example, when there is evidence of impairment).
  In March 2008, the FASB issued SFAS No. 161, Disclosures About Derivative Instruments and Hedging Activities(“SFAS No. 161”). SFAS No. 161 requires enhanced disclosures to help investors better understand the effect of an entity’s derivative instruments
and related hedging activities on its financial position, financial performance, and cash flows. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged.  SFAS No. 161 was effective for the Partnership as of January 1, 2009.  See Note 11 for the additional disclosures required under FAS No. 161 related to the Partnership’s derivative instruments.
  In March 2008 the FASB approved EITF Issue No. 07-4, Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships (“EITF 07-4”), which requires that master limited partnerships use the two-class method
of allocating earnings to calculate earnings per unit. EITF Issue No. 07-4 is effective for fiscal years and interim periods beginning after December 15, 2008.  EITF Issue No. 07-4 was effective for the Partnership as of January 1, 2009 and the impact on its earnings per unit calculation has been retrospectively applied to June 30, 2008 (see Note 16).
 
 In April 2008, the FASB issued FASB Staff Position (“FSP”) No. SFAS 142-3, Determination of the Useful Life of Intangible Assets (“FSP SFAS 142-3”).  FSP SFAS 142-3 amends the factors
that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, Goodwill and Other Intangible Assets (“SFAS 142”).  The intent of FSP SFAS 142-3 is to improve the consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No.
141R and other applicable accounting literature.  FSP SFAS 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and must be applied prospectively to intangible assets acquired after the effective date.  FSP SFAS No. 142-3 was effective for the Partnership as of January 1, 2009 but the impact of the adoption on the Partnership’s consolidated financial statements will depend on the nature and the extent of business combinations occurring after January
1, 2009.
  In June 2008, the FASB issued FSP No. EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (“FSP EITF 03-6-1”).  FSP EITF 03-6-1 affects entities
that accrue cash dividends on share-based payment awards during the awards’ service period when dividends do not need to be returned if the employees forfeit the awards.  FSP EITF 03-6-1 is effective for fiscal years beginning after December 15, 2008 and earnings-per-unit calculations would need to be adjusted retroactively.  FSP EITF 03-6-1 was effective for the Partnership as of January 1, 2009 and the impact on its earnings per unit calculation has been retrospectively applied to
June 30, 2008. (see Note 16).
 
 In December 2008, the SEC released Final Rule, Modernization of Oil and Gas Reporting to revise the existing Regulation S-K and Regulation S-X reporting requirements to align with current industry practices and technological advances. The new disclosure requirements
include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. In addition, the new disclosure requirements require a company to (a) disclose its internal control over reserves estimation and report the independence and qualification of its reserves preparer or auditor, (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserve audit
and (c) report oil and gas reserves using an average price based upon the prior 12-month period rather than period-end prices. The provisions of this final ruling will become effective for disclosures in the Partnership’s Annual Report on Form 10-K for the year ending December 31, 2009.  The adoption of the Final Rule, Modernization of Oil and Gas Reporting revision to Regulation S-K and Regulations S-X is not expected to have a material impact on the Partnership’s consolidated financial
statements.
 
 In April 2009, the FASB issued FSP FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairments “FSP FAS 115-2 and FAS 124-2”).  FSP FAS 115-2 and FAS 124-2 amend the other-than-temporary impairment guidance
for debt securities to make the guidance more operational and to improve the presentation and disclosure of other-than-temporary impairments in the financial statements. The most significant change is a revision to the amount of other-than-temporary loss of a debt security recorded in earnings. FSP FAS 115-2 and FAS 124-2 were effective for the Partnership as of June 30, 2009 and did not have a material impact on its consolidated financial statements.
 
 In April 2009, the FASB issued FSP FAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly(“FSP FAS 157-4”).  FSP
FAS 157-4 provides additional guidance for estimating fair value in accordance with FASB Statement No. 157, Fair Value Measurements, when the volume and level of activity for the asset or liability have significantly decreased.  FSP FAS 157-4 also includes guidance on identifying circumstances that indicate a transaction is not orderly and emphasizes that even if there has been a significant decrease in the volume and level of activity for the
asset or liability and regardless of the valuation technique(s) used, the objective of a fair value measurement remains the same. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction (that is, not a forced liquidation or distressed sale) between market participants at the measurement date under current market conditions.  FSP FAS 157-4 was effective for the Partnership as of June 30, 2009 and did not have a material impact on its consolidated
financial statements.
 
 In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments(“FSP FAS 107-1 and APB 28-1”). FSP FAS 107-1 and APB 28-1 amends FASB
Statement No. 107, Disclosures about Fair Value of Financial Instruments, to require disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements.  FSP FAS 107-1 and APB 28-1 also amend APB Opinion No. 28, Interim Financial Reporting, to require those disclosures in summarized financial information
at interim reporting periods. FSP FAS 107-1 and APB 28-1 were effective for the Partnership as of June 30, 2009.  See Note 10 for further discussion.
 
 In April 2009, the FASB issued FSP FAS 141(R)-1, Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies(“FSP FAS 141(R)-1”), which amended and clarified SFAS 141R with respect to contingencies.  FSP FAS 141(R)-1
provides that an acquirer shall recognize at fair value, at the acquisition date, an asset acquired or a liability assumed in a business combination that arises from a contingency if the acquisition-date fair value of that asset or liability can be determined during the measurement period.  If the acquisition-date fair value of an asset acquired or a liability assumed in a business combination that arises from a contingency cannot be determined using the measurement period, the guidance in SFAS 5 and in
FASB Interpretation No. 14, Reasonable Estimation of the Amount of a Loss, shall apply.”  FSP FAS 141(R)-1 was effective for the Partnership as of January 1, 2009 but the impact of the adoption on the Partnership’s consolidated financial statements will depend on the nature and the extent of business combinations occurring after January 1, 2009.
 
 On May 28, 2009, the FASB issued SFAS No. 165, Subsequent Events(“SFAS No. 165”), which provides guidance on the Partnership’s assessment of subsequent events. Historically, the Partnership has relied on U.S. auditing literature for guidance
on assessing and disclosing subsequent events.  SFAS No. 165 clarifies that the Partnership must evaluate, as of each reporting period, events or transactions that occur after the balance sheet date “through the date that the financial statements are issued or are available to be issued.” The Partnership must perform its assessment for both interim and annual financial reporting periods prospectively.  SFAS No. 165 was effective for the Partnership as of June 30, 2009 but the impact
of the adoption will depend on the nature and the extent of transactions that occur subsequent to our interim and annual reporting periods.
 
 On June 12, 2009, the FASB issued SFAS No. 166, Transfers of Financial Assets(SFAS No. 166), which amends the derecognition guidance in Statement 140.  SFAS No. 166 reflects the FASB’s response to issues entities have encountered when applying
Statement 140.  In addition, SFAS 166 addresses concerns expressed by the SEC, members of the United States Congress, and financial statement users about the accounting and disclosures required by Statement 140 in the wake of the subprime mortgage crisis and the deterioration in the global credit markets.  In addition, because SFAS No. 166 eliminates the exemption from consolidation for qualified special-purpose entities (“QSPEs”) a transferor will need to evaluate all existing
QSPEs to determine whether they must be consolidated.   SFAS No. 166 is effective for financial asset transfers occurring after the beginning of an entity’s first fiscal year that begins after November 15, 2009.  Early adoption of SFAS No. 166 is prohibited.   The Partnership is currently evaluating the potential impact, if any, of the adoption of SFAS No. 166 on its financial statements.
 
 7
 Table of Contents
 
 On June 12, 2009, the FASB issued SFAS No. 167, Amendments to FASB Interpretation 46(R),(“SFAS No. 167”), which amends the consolidation guidance applicable to variable interest entities (VIEs). The amendments will significantly affect the overall consolidation
analysis under FASB Interpretation 46(R) (“FIN 46(R)”).  While the FASB’s discussions leading up to the issuance of SFAS No. 167 focused extensively on structured finance entities, the amendments to the consolidation guidance affect all entities and enterprises currently within the scope of Interpretation 46(R), as well as qualifying special-purpose entities (QSPEs) that are currently excluded from the scope of FIN 46(R).  Accordingly, an enterprise will need to carefully
reconsider its previous FIN 46(R) conclusions, including (1) whether an entity is a VIE, (2) whether the enterprise is the VIE’s primary beneficiary, and (3) what type of financial statement disclosures are required.  SFAS 167 is effective as of the beginning of the first fiscal year that begins after November 15, 2009, and early adoption is prohibited.  The Partnership is currently evaluating the potential impact, if any, of the adoption of SFAS No. 167 on its financial statements.
  On June 29, 2009, the FASB issued SFAS No. 168, FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Statement No. 162(“SFAS No. 168”).  The FASB has stated that “the FASB Accounting Standards
Codification (“Codification”)” will become the source of authoritative U.S. GAAP recognized by the FASB to be applied to nongovernmental entities.  Once effective, the Codification’s content will carry the same level of authority, effectively superseding SFAS No. 162.  The U.S. GAAP hierarchy will be modified to include only two levels of GAAP: authoritative and nonauthoritative.  SFAS No. 168 is effective for financial statements issued for interim and annual
periods ended after September 15, 2009.  The Partnership does not believe that the adoption of SFAS No. 168 will have a material impact on its financial statements.
  NOTE 4. ACQUISITIONS
  2008 Acquisitions
  Update on Stanolind Acquisition.During the three months ended June 30, 2009, the Partnership finalized its purchase price allocations with respect to its acquisition of Stanolind Oil and Gas Corp. (“Stanolind”).  With respect to the Stanolind Acquisition, during
the three months ended June 30, 2009, the Partnership decreased the amount assumed for the environmental liability by $1.3 million, reduced the deferred tax liability by $2.6 million and finalized the acquired working capital balances, which resulted in a decrease to proved properties of $2.8 million and a decrease to unproved properties of $0.5 million.
  Update on Millennium Acquisition.   With respect to the South Louisiana assets acquired in the acquisition of Millennium Midstream Partners, L.P. (“MMP”), the Yscloskey and North
Terrebonne facilities were flooded with three to four feet of water as a result of the storm surges caused by Hurricanes Gustav and/or Ike in August and September 2008, respectively. The North Terrebonne facility came back on-line in November 2008 and the Yscloskey facility came back on-line in January 2009.  The Partnership received a partial payment for business interruption caused by Hurricanes Gustav and Ike of approximately $1.6 million, which was recognized as other revenue during the three and
six months ended June 30, 2009. The former owners of MMP provided the Partnership indemnity coverage for Hurricanes Gustav and Ike to the extent losses are not covered by insurance and established an escrow account of 1,818,182 common units and $0.6 million in cash available for the Partnership to recover against for this purpose and for settlement of the purchase price adjustment.  As of December 31, 2008, the escrow account held 1,777,302 common units and $0.3 million in cash.  During the
six months ended June 30, 2009, the Partnership recovered 527,064 common units, the majority of which was on account of the purchase price adjustment, and the remaining $0.3 million in cash from the escrow account.  In addition, during the three months ended June 30, 2009, the Partnership received $0.1 million representing the distribution for the fourth quarter of 2008 that was paid into escrow on 342,609 of those units, per an arrangement with the sellers that the fourth quarter 2008 distribution
on certain units cancelled as part of the purchase price adjustment should be returned to the Partnership upon cancellation.  As of June 30, 2009, the escrow account held 1,250,238 common units.
 
 NOTE 5. FIXED ASSETS AND ASSET RETIREMENT OBLIGATIONS
  Fixed assets consisted of the following:
  
 June 30,
2009


December 31,
2008($ in thousands)Land

$
1,219


$
1,211Plant


241,750



232,219Gathering and pipeline


677,355



653,016Equipment and machinery


18,856



18,672Vehicles and transportation equipment


4,160



3,958Office equipment, furniture, and fixtures


1,248



1,023Computer equipment


4,965



4,714Corporate


126



126Linefill


4,269



4,269Proved properties


515,801



515,452Unproved properties


72,516



73,622Construction in progress


20,272



39,4981,562,537



1,547,780Less: accumulated depreciation, depletion and amortization


(236,471
)


(190,171
)Net fixed assets

$
1,326,066


$
1,357,609
  Depreciation expense for the three and six months ended June 30, 2009 and 2008 was approximately $12.6 million, $27.0 million, $11.2 million and $22.0 million respectively. Depletion expense for the three and six months ended June 30, 2009 and 2008 was approximately $9.2 million, $19.1 million, $10.6 million and $20.9 million respectively.  In
connection with the preparation of these financial statements for the six months ended June 30, 2009, the Partnership recorded impairment charges related to its Upstream Segment proved property assets of $0.2 million relating specifically to the three months ended March 31, 2009.  The Partnership did not incur any impairment charges during the three months ended June 30, 2009 or during the three and six months ended June 30, 2008.
  The Partnership capitalizes interest costs on major projects during extended construction time periods. Such interest costs are allocated to property, plant and equipment and amortized over the estimated useful lives of the related assets. During the three and six months ended June 30, 2009 and 2008, the Partnership capitalized interest
costs of approximately $0.1 million, $0.1 million, $0.2 million and $0.5 million, respectively.
  Asset Retirement Obligations—The Partnership recognizes asset retirement obligations for its oil and gas working interests in accordance with FASB Statement No. 143, Accounting for Asset Retirement Obligations (“SFAS
143”). SFAS 143 applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. SFAS 143 requires that the Partnership record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. The Partnership recognizes asset retirement obligations for its midstream assets in accordance with
FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143(“FIN 47”). FIN 47 clarified that the term “conditional asset retirement obligation,” as used in SFAS No. 143, Accounting for Asset Retirement Obligations,refers to a legal obligation to perform an asset retirement activity in which
the timing and/or method of settlement are conditional upon a future event that may or may not be within the Partnership’s control. Although uncertainty about the timing and/or method of settlement may exist and may be conditional upon a future event, the obligation to perform the asset retirement activity is unconditional. Accordingly, the Partnership is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably
estimated.
  A reconciliation of our liability for asset retirement obligations is as follows (in thousands):
 
 Asset retirement obligations—December 31, 2008

$
19,872Liabilities settled


(831
)Accretion expense


597Asset retirement obligations—June 30, 2009

$
19,638
 
 8
 Table of Contents
 
 NOTE 6. INTANGIBLE ASSETS
  Intangible Assets—Intangible assets consist of rights-of-way and easements and acquired customer contracts, which the Partnership amortizes over the term of the agreement or estimated useful life. Amortization expense was approximately $5.8 million, $11.6 million, $4.7 million
and $9.3 million for the three and six months ended June 30, 2009 and 2008, respectively. Estimated aggregate amortization expense for 2009 and each of the four succeeding years is as follows: 2009—$22.9 million; 2010—$21.9 million; 2011—$11.2 million; 2012—$11.2 million; and 2013—$10.1 million. Intangible assets consisted of the following:
  
 June 30,
2009


December 31,
2008($ in thousands)Rights-of-way and easements—at cost

$
86,645


$
85,537Less: accumulated amortization


(13,119
)


(11,437
)Contracts


123,409



123,409Less: accumulated amortization


(52,734
)


(43,303
)Net intangible assets

$
144,201


$
154,206
  The amortization period for rights-of-ways and easements is 20 years. The amortization period for contracts range from 5 to 20 years, with an average life of approximately 10 years as of June 30, 2009.
  NOTE 7. LONG-TERM DEBT
  As of June 30, 2009 and December 31, 2008, the Partnership had $804.4 million and $799.4 million outstanding, respectively, under its revolving credit facility.  In April 2009, due to a regularly scheduled redetermination of the Upstream Segment’s borrowing base associated with its proved reserves, the Partnership’s
borrowing base was lowered to $135 million from $206 million as a result of declining commodity prices, including sulfur prices.  As of June 30, 2009, the Partnership was in compliance with the financial covenants under its revolving credit facility, and the unused capacity available to the Partnership under the revolving credit facility was approximately $88.0 million (excluding the commitment from Lehman Brothers), based on the financialcovenants.
  In a Form 8-K filing on July 23, 2009, Guaranty Financial Group Inc. stated that it is probable that it will not be able to continue as a going concern.  Guaranty Bank, a wholly owned subsidiary of Guaranty Financial Group Inc., has a commitment under the Partnership’s revolving credit facility of $30 million, of which
approximately $25 million has been funded.  If Guaranty Bank ceases to be a going concern, the Partnership would likely lose access to the approximate $5 million unfunded portion of Guaranty Bank’s commitment.  This unfunded commitment may increase to the extent the Partnership reduces its borrowings under the revolving credit facility, as repayments by the Partnership under the revolving credit facility would be applied proportionately among funding lenders against their respective
outstanding borrowings.  As of this filing, the Partnership has not received formal notice from Guaranty Bank or any other party as to the status of its unfunded commitment.
 
 NOTE 8. MEMBERS’ EQUITY
  At June 30, 2009, there were 53,244,361 common units (excluding unvested restricted common units), 20,691,495 subordinated units (all subordinated units owned by Holdings) and 844,551 general partner units outstanding. In addition, there were 694,813 unvested restricted common units outstanding.
 
 Subordinated units represent limited partner interests in the Partnership, and holders of subordinated units exercise the rights and privileges available to unitholders under the limited partnership agreement. Subordinated units, during the subordination period, will generally receive quarterly cash distributions only when the common units
have received a minimum quarterly distribution of $0.3625 per unit and any outstanding arrearages on the common units have been paid. Subordinated units will convert into common units on a one-for-one basis when the subordination period ends.  The subordination period will end on the first day of any quarter beginning after September 30, 2009 in respect of which, among other things, the Partnership has earned and paid at least $1.45 (the minimum quarterly distribution on an annualized basis) on
each outstanding limited partner unit and general partner unit for each of the three consecutive, non-overlapping four quarter periods immediately preceding such date and any outstanding arrearages on the common units have been paid.  Alternatively, the subordination period will end on the first business day after the Partnership earned and paid at least $0.5438 per quarter (150% of the minimum quarter distribution, or $2.175 on an annualized basis) on each outstanding limited partner unit and general
partner unit for any four consecutive quarters ending on or after September 30, 2007 and there are no outstanding arrearages on the common units.  In addition, the subordination period will end upon the removal of the Partnership’s general partner other than for cause if the units held by the Partnership’s general partner and its affiliates are not voted in favor of such removal, at which point all outstanding common unit arrearages would be extinguished.  For the three months ended
March 31, 2009 and June 30, 2009, the Partnership did not pay the full minimum quarterly distribution amount.  The second quarter Common Unit Arrearage is $0.3375 per common unit.  The Cumulative Common Unit Arrearage is expected to increase to $0.675 per common unit with the payment of the second quarter distribution on August 14, 2009.  Both Common Unit Arrearage and Cumulative Common Unit Arrearage are terms defined in Eagle Rock Energy’s partnership agreement.
 
 During the three months ended June 30, 2009, the Partnership recovered and cancelled 7,065 common units that were being held in an escrow account related to its acquisition of MacLondon Energy, L.P.
 
 On February 4, 2009, the Partnership declared its fourth quarter 2008 cash distribution to all its unitholders (i.e. common, general and subordinated) of record as of February 10, 2009. The distribution amount was $0.41 per unit, or approximately $31.6
million. The distribution was paid on February 13, 2009.
 
 On April 30, 2009, the Partnership declared its first quarter 2009 cash distribution to its common unitholders of record as of May 11, 2009.  The distribution amount was $0.025 per common unit, or approximately $1.4 million.  In addition, pursuant
to the terms of the Partnership’s partnership agreement, the Partnership’s general partner received a distribution of $0.025 per general partner unit.  The distribution was paid on May 15, 2009.
  On July 29, 2009, the Partnership declared its second quarter 2009 cash distribution of $0.025 per unit to its general partner (as to its general partner units) and its common unitholders of record as of August 10, 2009.  The distribution will be paid August 14, 2009.
  9
 Table of Contents
 
 NOTE 9. RELATED PARTY TRANSACTIONS
 
 On July 1, 2006, the Partnership entered into a month-to-month contract for the sale of natural gas with an affiliate of Natural Gas Partners, under which the Partnership sells a portion of its gas supply.  In July 2008, the company to which the Partnership
sold its natural gas was sold by the affiliate of NGP and thus ceased being a related party.  For the three and six months ended June 30, 2008, during which such counterparty was an affiliate, the Partnership recorded revenues of $8.3 million and $16.0 million respectively.
  In addition, during the three and six months ended June 30, 2009 and 2008, the Partnership incurred $1.9 million, $4.7 million, $1.7 million, and $3.0 million, respectively, in expenses with related parties, of which there was an outstanding accounts payable balance
of $0.7 million and $0.7 million, respectively, as of June 30, 2009 and December 31, 2008.
  Related to its investments in unconsolidated subsidiaries, during the three and six months ended June 30, 2009 and 2008, the Partnership recorded income of $0.4 million, $0.9 million, $0.9 million and $2.4 million, respectively, of which there was no outstanding
account receivable balances as of June 30, 2009 and December 31, 2008.
  During the three and six months ended June 30, 2009, the Partnership incurred approximately $0.5 million and $0.7 million, respectively, for services performed by Stanolind Field Services (“SFS”), which is an entity controlled by NGP.  As of
June 30, 2009, there were less than $0.1 million outstanding accounts payable balances.
 
 As of June 30, 2009 and December 31, 2008, Eagle Rock Energy G&P, LLC had $11.1 million and $4.5 million, respectively, of outstanding checks paid on behalf of the Partnership. This amount was recorded as Due to Affiliate on the Partnership’s balance sheet
in current liabilities. As the checks are drawn against Eagle Rock Energy G&P, LLC’s cash accounts, the Partnership reimburses Eagle Rock Energy G&P, LLC.
 
 The Partnership is leasing office space from Montierra Minerals & Production, L.P. (“Montierra”), which is owned by NGP and certain members of the Partnership’s senior management, including the Chief Executive Officer.  During the
three and six months ended June 30, 2009, the Partnership made rental payments of less than $0.1 million and $0.1 million, respectively.  In addition, the Partnership was reimbursed by Montierra for services performed by its employees on behalf of Montierra of less than $0.1 million for both the three and six months ended June 30, 2009.  As of June 30, 2009 and December 31, 2008, the Partnership has an outstanding receivable balance of less than $0.1 million and $0.3 million, respectively,
due from Montierra and an outstanding payable balance of $0.7 million due to Montierra.
  As of June 30, 2009 and December 31, 2008, the Partnership had an outstanding receivable balance of $1.9 million due from an affiliate of NGP.
 
 NOTE 10. FAIR VALUE OF FINANCIAL INSTRUMENTS
  Effective January 1, 2008, the Partnership adopted SFAS No. 157, which, among other things, requires enhanced disclosures about assets and liabilities carried at fair value.
  As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Partnership utilizes market data or assumptions that market participants would use in pricing the asset or liability,
including assumptions about risk inherent in the inputs to the valuation technique. SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).
  The three levels of the fair value hierarchy defined by SFAS No. 157 are as follows:
  Level 1 – Quoted prices are available in active markets for identical assets and liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide information on an ongoing basis.
  Level 2– Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies.
These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the market place throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in
the marketplace.
  Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.
  As of June 30, 2009, the Partnership has recorded its interest rate swaps and commodity derivative instruments (see Note 11), which includes crude, natural gas and natural gas liquids (“NGLs”) at fair value. The Partnership has classified the inputs to measure the fair value of its interest rate swaps, crude derivatives and
natural gas derivatives as Level 2. Because the NGL market is considered to be less liquid and thinly traded, the Partnership has classified the inputs related to its NGL derivatives as Level 3.
  10
 Table of Contents
 The following table discloses the fair value of the Partnership’s derivative instruments as of June 30, 2009.
  
 Level 1


Level 2


Level 3


Total($ in thousands)Assets:Crude derivatives

$
—


$
42,776


$
—


$
42,776Natural gas derivatives


—



10,318



—



10,318NGL derivatives


—



—



1,815



1,815Interest rate swaps


—



1,551



—



1,551Total

$
—


$
54,645


$
1,815


$
56,460Liabilities:Crude derivatives

$
—


$
(32,395
)

$
—


$
(32,395
)Natural gas derivatives


—



1,372



—



1,372NGL derivatives


—



—



(2,335
)


(2,335
)Interest rate swaps


—



(26,443
)


—



(26,443
)Total

$
—


$
(57,466
)

$
(2,335
)

$
(59,801
)
 
 As of June 30, 2009, risk management current and long-term assets in the unaudited condensed consolidated balance sheet include put premium and other derivative costs, net of amortization, of $20.7 million and $1.7 million, respectively.
 
 The following table sets forth a reconciliation primarily of changes in the fair value of the NGL derivatives classified as Level 3 in the fair value hierarchy during the three months ended June 30, 2009 and 2008 (in thousands):
 
 Three Months
Ended June 30,2009


2008Balances as of April 1

$
11,447


$
27,454Settlements


(2,468
)


—Transfers from Level 3 to Level 2


—



(4,873
)Total gains or losses (realized and unrealized)


(9,499
)


14,275Net liability balances as of June 30

$
(520
)

$
36,856
 
 The following table sets forth a reconciliation primarily of changes in the fair value of the NGL derivatives classified as Level 3 in the fair value hierarchy for the six months ended June 30, 2009 and 2008 (in thousands):
  Six Months
Ended June 30,2009


2008Balances as of January 1

$
14,016


$
36,695Settlements


(910
)


—Transfers from Level 3 to Level 2


—



(10,730
)Total gains or losses (realized and unrealized)


(13,626
)


10,891Net liability balances as of June 30

$
(520
)

$
36,856
 
 The Partnership values its Level 3 NGL derivatives using forward curves, volatility curves, volatility skew parameters, interest rate curves and model parameters.
 
 Realized and unrealized losses related to the interest rate derivatives are recorded as part of interest rate risk management gains and losses in the unaudited condensed consolidated statements of operations.  Realized and unrealized gains and losses and
the amortization of put premiums and other derivative costs related to the Partnership’s commodity derivatives are recorded as a component of revenue in the unaudited condensed consolidated statements of operations.
 
 The following table discloses the fair value of the Partnership’s assets measured at fair value on a nonrecurring basis for the six months ended June 30, 2009 (in thousands):
  
 June 30,
2009


Level 1


Level 2


Level 3


Total
LossesImpaired proved properties

$
49


$
—


$
—


$
49


$
242
 
 In connection with the preparation of these financial statements for the six months ended June 30, 2009, the Partnership wrote down proved properties with a carrying value of $0.3 million to their fair value of $0.1 million, resulting in an impairment charge of $0.2
million being included in earnings for the period.  This impairment charge related specifically to the three months ended March 31, 2009.  The Partnership calculated the fair value of the impaired proved properties using its proved reserves, estimated forward prices and an estimated weighted average cost of capital.
 
 The carrying amount of cash equivalents is believed to approximate their fair values because of the short maturities of these instruments.  The fair value of accounts receivable and accounts payable are not materially different from their carrying amounts
because of the short-term nature of these instruments.
  11
 Table of Contents
 
 NOTE 11. RISK MANAGEMENT ACTIVITIES
 
 Interest Rate Derivative Instruments
  To mitigate its interest rate risk, the Partnership entered into various interest rate swaps. These swaps convert a portion of the variable-rate interest obligations into fixed-rate interest obligations. The purpose of entering into this swap is to eliminate interest
rate variability by converting LIBOR-based variable-rate payments to fixed-rate payments through the end of 2012.  The Partnership has not designated any of its interest rate swaps as hedges and as a result is marking these derivative contracts to fair value with changes in fair values of the interest rate derivative instruments recorded as an adjustment to the mark-to-market gains (losses) on risk management transactions within other income (expense).
 
 On March 30, 2009, the Partnership amended all of its existing interest rate swaps to change the interest rate the Partnership received from three month LIBOR to one month LIBOR through January 9, 2011.  During this time period, the fixed rate to be paid
by the Partnership was reduced, on average, by 20 basis points.  After January 9, 2011, the interest rate to be received by the Partnership will change back to three month LIBOR and the fixed rate the Partnership pays will revert back to the original rate through the end of swap maturities in 2012.
  The table below summarizes the terms, notional amounts and rates to be paid and the fair values of the various interest swaps as of June 30, 2009:
 
 Roll Forward
Effective Date

Expiration
Date

Notional
Amount


Fixed
Rate(a)12/31/2008

12/31/2012

$
150,000,000



2.360% / 2.560
%09/30/2008

12/31/2012


150,000,000



4.105% / 4.295
%10/03/2008

12/31/2012


300,000,000



3.895% / 4.095
%
 
 (a)
First amount is the rate the Partnership pays through January 9, 2011 and the second amount is the interest rate the Partnership pays from January 10, 2011 through December 31, 2012.
 
 Our interest rate derivative counterparties include Wells Fargo Bank N.A. / Wachovia Bank N.A and The Royal Bank of Scotland plc.
 
 Commodity Derivative Instruments
  The prices of crude oil, natural gas and NGLs are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors which are beyond the Partnership’s control.  These risks can cause significant
changes in the Partnership’s cash flows and affect its ability to achieve its distribution objective and comply with the covenants of its revolving credit facility.  In order to manage the risks associated with the future prices of crude oil, natural gas and NGLs, the Partnership engages in non-speculative risk management activities that take the form of commodity derivative instruments.  The Partnership has determined that it is necessary to hedge a substantial portion of its expected
production in order to meaningfully reduce its future cash flow volatility.  The Partnership recognizes that hedging 100% of its future expected production is not prudent, thus it generally limits its hedging levels to 80% of expected future production.   While hedging at this level of production does not eliminate all of the volatility in the Partnership’s cash flows, it allows the Partnership to mitigate the risk of situations where a modest loss of production would put it in
an over-hedged position.  The Partnership may hedge for periods of time above the 80% of expected future production levels where it deems it prudent to reduce extreme future price volatility.  However, hedging to that level requires approval of the Board of Directors, which the Partnership has obtained for its 2009 and 2010 hedging activity.  Expected future production for its Upstream and Minerals Businesses is derived from the proved reserves, adjusted for price-dependent expenses
and revenue deductions; for the Midstream Business, expected future production is based on the expected production from wells currently flowing to the Partnership’s processing plants, plus additional volumes the Partnership expects to receive from future drilling activity by its producer customer base.  The Partnership’s expectations for its Midstream Segment volumes associated with future drilling are based on information it receives from its producer customer base and  historical
observations. The Partnership applies the appropriate contract terms to these projections to determine its expected future equity share of the commodities.
  The Partnership uses put options, costless collars and fixed-price swaps to achieve its hedging objectives, and often hedges its expected future volumes of one commodity with derivatives of the same commodity.  In some cases, however, the Partnership believes it is better to hedge future changes in the price of one commodity
with a derivative of another commodity, which it refers to as “cross-commodity” hedging.  The Partnership will often hedge the changes in future NGL prices (propane and heavier) using crude oil hedges because NGL prices have been highly correlated to crude oil prices and hedging NGLs directly is usually less attractive due to the relative illiquidity in the NGL forward market.  The Partnership will also use natural gas hedges to hedge a portion of its expected future ethane production
because forward prices for ethane are often heavily discounted from its current prices.  Also, natural gas prices provide support for ethane prices because in many processing plants ethane can be recombined with the residue gas stream and sold as natural gas.  When the Partnership uses cross-commodity hedging, it will convert the expected volumes of the underlying commodity to equivalent volumes of the hedged commodity.  In the case of NGLs hedged with crude oil derivatives, these
conversions are based on the linear regression of the prices of the two commodities observed during the previous 36 months and management’s judgment regarding future price relationships of the commodities.   In the case where ethane is hedged with natural gas derivatives, the conversion is based on the thermal content of ethane.
  The Partnership has a risk management policy which allows management to execute crude oil, natural gas and NGL hedging instruments in order to reduce exposure to substantial adverse changes in the prices of these commodities. The Partnership continually monitors
and ensures compliance with this risk management policy through senior level executives in our operations, finance and legal departments.
  The Partnership has not designated any of its commodity derivative instruments as hedges and therefore is marking these derivative contracts to fair value.  Changes in fair values of the commodity derivative instruments are recorded as an adjustment to the mark-to-market gains (losses) on risk management transactions within revenue.
 
 Our commodity derivative counterparties include BNP Paribas, Wachovia Bank N.A, Comerica Bank, Barclays Bank PLC, Bank of Nova Scotia, Sempra Energy Trading LLC (an agent of The Royal Bank of Scotland plc), Bank of America N.A., J Aron and Company (an affiliate of Goldman Sachs), BBVA Compass Bank and Credit Suisse Energy LLC (an affiliate
of Credit Suisse Group AG).
 
 On January 8, 2009, the Partnership executed a series of hedging transactions that involved the unwinding of a portion of existing “in-the-money” 2011 and 2012 WTI crude oil swaps and collars, and the unwinding of two “in-the-money” 2009 WTI
crude oil collars. With these transactions, and an additional $13.9 million of cash, the Partnership purchased a 2009 WTI crude oil swap on 60,000 barrels per month beginning January 1, 2009 at an “in-the-money” level of $97 per barrel. Both the unwound hedges and new hedges relate to expected volumes in the Partnership’s Midstream and Minerals Segments.
  12
 Table of Contents
 The following table, as of June 30, 2009, sets forth certain information regarding our commodity derivatives that will mature during the year ended December 31, 2009 (excluding transactions and volumes that settled
or were unwound during the six months ended June 30, 2009):
  Underlying

Period

Total
Notional
Volumes
(units)

Type

Floor
Strike
Price
($/unit)


Cap
Strike
Price
($/unit)Natural Gas:IF Waha

Jul-Sep 2009

60,000 mmbtu

Costless Collar

$
7.50


$
8.60IF Waha

Oct-Dec 2009

60,000 mmbtu

Costless Collar


7.50



8.90NYMEX Henry Hub

Jul-Dec 2009

100,000 mmbtu

Costless Collar


6.25



11.20NYMEX Henry Hub

Jul-Dec 2009

425,000 mmbtu

Costless Collar


7.85



9.25NYMEX Henry Hub

Jul-Dec 2009

425,000 mmbtu

Swap


8.35NYMEX Henry Hub

Jul-Dec 2009

350,000 mmbtu

Swap


6.685NYMEX Henry Hub

Jul-Dec 2009

350,000 mmbtu

Swap


6.885Crude Oil:NYMEX WTI

Jul-Dec 2009

36,000 bbls

Costless Collar


60.00



77.00NYMEX WTI

Jul-Dec 2009

60,000 bbls

Costless Collar


93.00



100.85NYMEX WTI

Jul-Dec 2009

30,000 bbls

Put


90.00NYMEX WTI

Jul-Dec 2009

42,000 bbls

Put


100.00NYMEX WTI

Jul-Dec 2009

150,000 bbls

Swap


71.25NYMEX WTI

Jul-Dec 2009

300,000 bbls

Swap


100.00NYMEX WTI

Jul-Dec 2009

300,000 bbls

Swap


97.00Natural Gas Liquids:OPIS Ethane Mt Belv non TET

Jul-Dec 2009

2,520,000 gallons

Costless Collar


0.48



0.58OPIS Ethane Mt Belv non TET

Jul-Dec 2009

2,520,000 gallons

Swap


0.53OPIS Ethane Mt Belv non TET

Jul-Dec 2009

6,300,000 gallons

Swap


0.6361OPIS IsoButane Mt Belv non TET

Jul-Dec 2009

630,000 gallons

Costless Collar


0.935



1.035OPIS IsoButane Mt Belv non TET

Jul-Dec 2009

630,000 gallons

Swap


0.985OPIS IsoButane Mt Belv non TET

Jul-Dec 2009

746,676 gallons

Swap


1.295OPIS NButane Mt Belv non TET

Jul-Dec 2009

1,386,000 gallons

Costless Collar


0.935



1.035OPIS NButane Mt Belv non TET

Jul-Dec 2009

1,386,000 gallons

Swap


0.985OPIS NButane Mt Belv non TET

Jul-Dec 2009

1,484,070 gallons

Swap


1.2775OPIS Propane Mt Belv non TET

Jul-Dec 2009

2,646,000 gallons

Costless Collar


0.765



0.815OPIS Propane Mt Belv non TET

Jul-Dec 2009

2,646,000 gallons

Swap


0.815OPIS Propane Mt Belv non TET

Jul-Dec 2009

3,780,000 gallons

Swap


1.0925OPIS Propane Mt Belv non TET

Jul-Dec 2009

1,350,846 gallons

Swap


1.0775OPIS Propane Mt Belv non TET

Jul-Dec 2009

722,610 gallons

Swap


1.0875
 
  13
 Table of Contents
 During the six months ended June 30, 2009, the Partnership entered into the following derivative transactions for the 2010 calendar year: a 125,000 MMBtu per month Henry Hub natural gas swap at $6.65 per MMBtu on January 19, 2009, a 170,000 MMBtu per month Henry Hub natural gas swap at $6.14 per MMBtu on February 17, 2009, a 45,000 barrel
per month WTI crude oil swap at $53.55 per barrel on February 17, 2009 and a 40,000 barrel per month WTI crude oil swap at $51.40 per barrel on February 19, 2009.
 
 The following table, as of June 30, 2009, sets forth certain information regarding our commodity derivatives that will mature during the year ended December 31, 2010:
 
 Underlying

Period

Total
Notional
Volumes
(units)

Type

Floor
Strike
Price
($/unit)


Cap
Strike
Price
($/unit)Natural Gas:NYMEX Henry Hub

Jan-Dec 2010

1,320,000 mmbtu

Costless Collar

$
7.70


$
9.10NYMEX Henry Hub

Jan-Dec 2010

1,500,000 mmbtu

Swap


6.65NYMEX Henry Hub

Jan-Dec 2010

2,040,000 mmbtu

Swap


6.14Crude Oil:NYMEX WTI

Jan-Dec 2010

60,000 bbls

Costless Collar


50.00



67.50NYMEX WTI

Jan-Dec 2010

60,000 bbls

Costless Collar


50.00



68.00NYMEX WTI

Jan-Dec 2010

108,000 bbls

Costless Collar


90.00



99.80NYMEX WTI

Jan-Dec 2010

180,000 bbls

Costless Collar


50.00



67.50NYMEX WTI

Jan-Dec 2010

180,000 bbls

Costless Collar


50.00



68.00NYMEX WTI

Jan-Dec 2010

60,000 bbls

Put


100.00NYMEX WTI

Jan-Dec 2010

72,000 bbls

Put


90.00NYMEX WTI

Jan-Dec 2010

120,000 bbls

Swap


78.35NYMEX WTI

Jan-Dec 2010

300,000 bbls

Swap


70.00NYMEX WTI

Jan-Dec 2010

540,000 bbls

Swap


53.55NYMEX WTI

Jan-Dec 2010

480,000 bbls

Swap


51.40Natural Gas Liquids:OPIS Ethane Mt Belv non TET

Jan-Dec 2010

4,536,000 gallons

Costless Collar


0.43



0.53OPIS Ethane Mt Belv non TET

Jan-Dec 2010

4,536,000 gallons

Swap


0.58OPIS IsoButane Mt Belv non TET

Jan-Dec 2010

2,520,000 gallons

Costless Collar


0.82



1.02OPIS IsoButane Mt Belv non TET

Jan-Dec 2010

5,544,000 gallons

Costless Collar


0.82



1.02OPIS IsoButane Mt Belv non TET

Jan-Dec 2010

5,040,000 gallons

Costless Collar


0.705



0.81OPIS IsoButane Mt Belv non TET

Jan-Dec 2010

5,040,000 gallons

Swap


0.755
 
 During the six months ended June 30, 2009, the Partnership entered into the following derivative transactions for its 2011 calendar year: a 30,000 barrel per month NYMEX WTI swap at $65.60 per barrel on March 31, 2009, a 10,000 barrel per month NYMEX WTI swap at
$65.10 per barrel on April 1, 2009, a 20,000 barrel per month NYMEX WTI swap at $75.00 per barrel on June 1, 2009, a 20,000 barrel per month NYMEX WTI swap at $80.05 per barrel on June 9, 2009 and a 60,000 MMBtu per month HENRY HUB swap at $7.085 per MMBtu on June 9, 2009.
  14
 Table of Contents
  The following table, as of June 30, 2009, sets forth certain information regarding our commodity derivatives that will mature during the year ended December 31, 2011:
 
 Underlying

Period

Total
Notional
Volumes
(units)

Type

Floor
Strike
Price
($/unit)


Cap
Strike
Price
($/unit)Natural Gas:NYMEX Henry Hub

Jan-Dec 2011

1,200,000 mmbtu

Costless Collar

$
7.50


$
8.85NYMEX Henry Hub

Jan-Dec 2011

720,000 mmbtu

Swap


7.085Crude Oil:NYMEX WTI(1)

Jan-Dec 2011

139,152 bbls

Costless Collar


75.00



85.70NYMEX WTI(2)

Jan-Dec 2011

125,256 bbls

Swap


80.00NYMEX WTI

Jan-Dec 2011

360,000 bbls

Swap


65.60NYMEX WTI

Jan-Dec 2011

120,000 bbls

Swap


65.10NYMEX WTI

Jan-Dec 2011

240,000 bbls

Swap


75.00NYMEX WTI

Jan-Dec 2011

240,000 bbls

Swap


80.05
 
 (1)
460,848 barrels of this costless collar were “unwound” as part of the January 8, 2009 hedge transactions.
 (2)
414,744 barrels of this swap were “unwound” as part of the January 8, 2009 hedge transactions.
 
 During the six months ended June 30, 2009, the Partnership entered into the following derivative transactions for its 2012 calendar year: a 20,000 barrel per month NYMEX WTI swap at $68.30 per barrel on April 1, 2009, a 20,000 barrel per month NYMEX WTI swap at $76.50
per barrel on June 1, 2009 and a 20,000 barrel per month NYMEX WTI swap at $82.02 per barrel on June 9, 2009.
  The following table, as of June 30, 2009, sets forth certain information regarding our commodity derivatives that will mature during the year ended December 31, 2012:
  
 Underlying

Period

Total
Notional
Volumes
(units)

Type

Floor
Strike
Price
($/unit)


Cap
Strike
Price
($/unit)Natural Gas:NYMEX Henry Hub

Jan-Dec 2012

1,080,000 mmbtu

Costless Collar

$
7.35


$
8.65Crude Oil:NYMEX WTI(1)

Jan-Dec 2012

135,576 bbls

Costless Collar


75.30



86.30NYMEX WTI(2)

Jan-Dec 2012

108,468 bbls

Swap


68.30NYMEX WTI

Jan-Dec 2012

240,000 bbls

Swap


80.30NYMEX WTI

Jan-Dec 2012

240,000 bbls

Swap


76.50NYMEX WTI

Jan-Dec 2012

240,000 bbls

Swap


82.02
 
 (1)
464,424 barrels of this costless collar were “unwound” as part of the January 8, 2009 hedge transactions.
 (2)
371,532 barrels of this swap were “unwound” as part of the January 8, 2009 hedge transactions.
 
 On July 30, 2009, the Partnership entered into a 190,000 MMBtu per month Henry Hub natural gas swap at $6.57 per MMBtu for the 2011 calendar year and a 260,000 MMBtu per month Henry Hub natural gas swap at $6.77 per MMBtu for the 2012 calendar year. These derivative
transactions are not reflected in the above tables.
   15
 Table of Contents
 Fair Value of Interest Rate and Commodity Derivatives
  Fair values of interest rate and commodity derivative instruments not designated as hedging instruments under SFAS No. 133 in the unaudited condensed consolidated balance sheet as of June 30, 2009 and December 31, 2008:
  Derivative Assets

Derivative LiabilitiesJune 30, 2009

December 31, 2008

June 30, 2009

December 31, 2008Balance
Sheet
Location

Fair Value

Balance
Sheet
Location

Fair Value

Balance
Sheet
Location

Fair Value

Balance
Sheet
Location

Fair Value($ in thousands)Interest rate derivatives – assets
Long-term assets

$
1,551



$
—



$
—



$
—Interest rate derivatives – liabilities



—




—

Current liabilities


(14,749
)
Current liabilities


(13,763
)Interest rate derivatives – liabilities



—




—

Long-term liabilities


(11,694
)
Long-term liabilities


(26,182
)Commodity derivatives – assets
Current assets


54,003

Current assets


77,603

Current liabilities


3,320




—Commodity derivatives – assets
Long-term assets


6,025

Long-term assets


34,088

Long-term liabilities


2,498




—Commodity derivatives – liabilities
Current assets


(4,726
)
Current assets


(834
)
Current liabilities


(13,327
)



—Commodity derivatives – liabilities
Long-term assets


(393
)
Long-term assets


(1,637
)
Long-term liabilities


(25,849
)



—Total derivatives


$
56,460



$
109,220



$
(59,801
)


$
(39,945
)
  
  The following table sets forth the location of gains and losses for derivatives not designated as hedging instruments under SFAS No. 133 within the Partnership’s Unaudited Condensed Consolidated Statement of Operations:
  Location of Gain or (Loss) Recognized in Income on Derivatives

Amount of Gain or (Loss) Recognized in Income
on DerivativesThree Month Ended
June 30,


Six Months Ended
June 30,2009


2008


2009


2008($ in thousands)Interest rate derivatives
Interest rate risk management gains (losses)

$
6,807


$
11,245


$
6,424


$
(2,516
)Commodity derivatives
Commodity risk management losses


(74,561
)


(283,973
)


(48,305
)


(329,620
)Total


$
(67,754
)

$
(272,728
)

$
(41,881
)

$
(332,136
)
 Our hedge counterparties are participants in our credit agreement, and the collateral for the outstanding borrowings under our credit agreement is used as collateral for our hedges.  We do not have rights to collateral from our counterparties, nor do we
have rights of offset against borrowings under our credit agreement.
  16
 Table of Contents
 NOTE 12. COMMITMENTS AND CONTINGENT LIABILITIES
  Litigation—The Partnership is subject to lawsuits which arise from time to time in the ordinary course of business, such as the interpretation and application of contractual terms related to the calculation of payment for liquids and natural gas proceeds.
The Partnership’s accruals were approximately $0.1 million as of June 30, 2009 and December 31, 2008 related to these matters. The Partnership has been indemnified up to a certain dollar amount for certain lawsuits that were assumed as part of prior acquisitions. If there ultimately is a finding against the Partnership in the indemnified cases, the Partnership would expect to make a claim against the indemnification up to the limits of the indemnification. The Partnership has not established any accruals
as the likelihood of these suits being successful in amounts in excess of the indemnification limits is considered remote. These matters are not expected to have a material adverse effect on our financial position, results of operations or cash flows.
  Insurance—The Partnership covers its operations and assets with insurance which management believes is consistent with that in force for other companies engaged in similar commercial operations with similar type properties.  This insurance includes: (1) commercial
general liability insurance covering liabilities to third parties for bodily injury, property damage and pollution arising out of Eagle Rock Energy operations; (2) workers’ compensation liability coverage for employees to required statutory limits; (3) automobile liability insurance covering liability to third parties for bodily injury and property damage arising out of the operation of all owned, hired and non-owned vehicles by the Partnership’s employees on company business; (4) property
insurance covering the replacement cost of all owned real and personal property, including coverage for losses due to boiler and machinery breakdown, earthquake, flood and consequent business interruption/extra expense; (5) control of well/operator’s extra expense insurance for operated and non operated wells in the Upstream Segment; and (6) corporate liability insurance including coverage for Directors and Officers and Employment Practices liabilities.  In addition, the Partnership maintains
excess liability insurance providing limits in excess of the established primary limits for commercial general liability and automobile liability insurance.
 
 All coverage’s are subject to industry accepted policy terms, conditions, limits and deductibles comparable to that obtained by other energy companies with similar operations. The cost of insurance for the energy industry continued to fluctuate over the past
year, reflecting the changing conditions in the insurance markets.
 
 Regulatory Compliance—In the ordinary course of business, the Partnership is subject to various laws and regulations. In the opinion of management, the Partnership is in material compliance with existing
laws and regulations.
  Environmental—The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex
laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, the Partnership must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and
safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on the Partnership’s
combined results of operations, financial position or cash flows. At June 30, 2009 and December 31, 2008, the Partnership had accrued approximately $6.8 million and $8.6 million, respectively, for environmental matters.
 
 The Partnership has voluntarily undertaken a self-audit of its compliance with air quality standards, including permitting in the Texas Panhandle Segment as well as a majority of its other Midstream Business locations and some of its Upstream Business locations in
Texas. This auditing has been performed pursuant to the Texas Environmental, Health and Safety Audit Privilege Act, as amended. The Partnership has completed the disclosures to the Texas Commission on Environmental Quality (“TCEQ”), and the Partnership is addressing in due course the deficiencies that it disclosed therein.  The Partnership does not foresee at this time any impediment to the timely corrective efforts identified as a result of these audits.
 
 Subsequent to December 31, 2008, the Partnership received additional Notices of Enforcement (“NOEs”) and a Notice of Violation (“NOV”) from the TCEQ related to air compliance matters.  The Partnership expects to receive additional
NOEs or NOVs from the TCEQ from time to time throughout 2009.  Though the TCEQ has the discretion to adjust penalties and settlements upwards based on a compliance history containing multiple, successive NOEs, the Partnership does not expect that the resolution of any existing NOE or any future similar NOE will vary significantly from the administrative penalties and agreed settlements experienced by it to date.
 
 Retained Revenue Interest—Certain assets in the Partnership’s Upstream Segment are subject to retained revenue interests.  These interests were established under purchase and sale agreements
that were executed by the Partnership’s predecessors in title.  The terms of these agreements entitle the owners of the retained revenue interests to a portion of the revenues received from the sale of the hydrocarbons above specified base oil and natural gas prices.  These retained revenue interests do not represent a real property interest in the hydrocarbons.  The Partnership’s reported revenues are reduced to account for the retained revenue interests on a monthly
basis.
 
 The retained revenue interests affect the Partnership’s interest at the Big Escambia Creek, Flomaton and Fanny Church fields in Escambia County, Alabama.  With respect to the Partnership’s Flomaton and Fanny Church fields, the Partnership is
currently making payments in satisfaction of the retained revenue interests.   With respect to the Partnership’s Big Escambia Creek field, these payments are expected to begin in 2010 and continue through the end of 2019.
 
 Other Commitments—The Partnership utilizes operating leases for its corporate office, certain rights-of way, facility locations and vehicles. Rental expense, including leases with no continuing commitment,
amounted to approximately, $2.2 million, $4.2 million, $1.2 million, and $2.5 million for the three and six months ended June 30, 2009 and June 30, 2008, respectively. Rental expense for leases with escalation clauses is recognized on a straight-line basis over the initial lease term.
  17
 Table of Contents
 
 NOTE 13. SEGMENTS
  Based on the Partnership’s approach to managing its assets, the Partnership believes its operations consist of four geographic segments in its Midstream Business, one upstream segment that is its Upstream Business, one minerals segment that is its Minerals Business and one functional (corporate) segment:
  (i)
Midstream—Texas Panhandle Segment:
  gathering, compressing, processing and treating natural gas and marketing of natural gas, NGLs and condensate in the Texas Panhandle;
 
 (ii)
Midstream—South Texas Segment:
  gathering, compressing, processing and treating natural gas and marketing of natural gas, NGLs and condensate in South Texas and West Texas;
  (iii)
Midstream—East Texas/Louisiana Segment:
  gathering, compressing, processing, treating and transporting natural gas and marketing of natural gas, NGLs and condensate and related NGL transportation in East Texas and Louisiana;
  (iv)
Midstream—Gulf of Mexico Segment:
  gathering and processing of natural gas and fractionating, transporting and marketing of NGLs in South Louisiana, Gulf of Mexico and inland waters of Texas;
  (v)
Upstream Segment:
  crude oil, natural gas and sulfur production from operated and non-operated wells;
  (vi)
Minerals Segment:
  fee minerals and royalties, lease bonus and rental income either through direct ownership or through investment in other partnerships; and
  (vii)
Corporate Segment:
  risk management and other corporate activities.
 
 
  18
 Table of Contents
  The Partnership’s chief operating decision-maker currently reviews its operations using these segments. The Partnership evaluates segment performance based on segment operating income or loss from continuing operations. Summarized financial information concerning the Partnership’s reportable segments is shown in the following
table:
 
 Midstream Segments
Three Months Ended June 30, 2009

Texas
Panhandle
Segment


South
Texas
Segment


East Texas /
Louisiana
Segment


Gulf of
Mexico


Total
Midstream
Segments($ in millions)Sales to external customers

$
69.0


$
25.8


$
48.6


$
7.7


$
151.1Cost of natural gas and natural gas liquids


49.4



23.7



37.2



5.2



115.5Operating costs and other expenses


8.1



0.9



4.6



0.7



14.3Depreciation, depletion, amortization and impairment


11.0



1.3



4.2



1.4



17.9Operating income (loss) from continuing operations

$
0.5


$
(0.1
)

$
2.6


$
0.4


$
3.4Capital Expenditures

$
0.7


$
0.1


$
4.8


$
—


$
5.6Segment Assets

$
532.5


$
68.5


$
250.9


$
89.1


$
941.0
 
 Three Months Ended June 30, 2009

Total
Midstream
Segments


Upstream
Segment


Minerals
Segment


Corporate
Segment


Total
Segments($ in millions)Sales to external customers

$
151.1


$
15.2


$
3.5


$
(74.6
)(a)

$
95.2Cost of natural gas and natural gas liquids


115.5



—



—



—



115.5Operating costs and other expenses


14.3



3.7



0.3



11.9



30.2Depreciation, depletion, amortization and impairment


17.9



8.0



1.5



0.2



27.6Operating income (loss) from continuing operations operations

$
3.4


$
3.5


$
1.7


$
(86.7
)

$
(78.1
)Capital Expenditures

$
5.6


$
2.0


$
—


$
0.6


$
8.2Segment Assets

$
941.0


$
379.4


$
138.6


$
174.2


$
1,633.2
 
 Midstream Segments
Three Months Ended June 30, 2008

Texas
Panhandle
Segment


South
Texas
Segment


East Texas /
Louisiana
Segment


Total
Midstream
Segments($ in millions)Sales to external customers

$
183.5


$
50.6


$
97.9


$
332.0Cost of natural gas and natural gas liquids


140.3



47.9



83.9



272.1Operating costs and other expenses


8.7



0.5



3.8



13.0Depreciation, depletion, and amortization


10.9



0.9



3.0



14.8Operating income from continuing operations

$
23.6


$
1.3


$
7.2


$
32.1Capital Expenditures

$
6.5


$
0.2


$
4.0


$
10.7Segment Assets

$
582.4


$
97.0


$
265.3


$
944.7
 
 Three Months Ended June 30, 2008

Total
Midstream
Segments


Upstream
Segment


Minerals
Segment


Corporate
Segment


Total
Segments($ in millions)Sales to external customers

$
332.0


$
45.9


$
10.3


$
(284.0
)(a)

$
104.2Cost of natural gas and natural gas liquids


272.1



—



—



—



272.1Operating costs and other expenses


13.0



9.4



0.5



16.2



39.1Depreciation, depletion, and amortization


14.8



10.0



1.5



0.2



26.5Operating income (loss) from continuing operations operations

$
32.1


$
26.5


$
8.3


$
(300.4
)

$
(233.5
)Capital Expenditures

$
10.7


$
10.3


$
—


$
0.1


$
21.1Segment Assets

$
944.7


$
588.8


$
148.2


$
83.3


$
1,765.0
 
 (a)
Represents results of the Partnership’s derivative activities.
 
  19
 Table of Contents
  
 Midstream Segments
Six Months Ended June 30, 2009

Texas
Panhandle
Segment


South
Texas
Segment


East Texas /
Louisiana
Segment


Gulf of
Mexico


Total
Midstream
Segments($ in millions)Sales to external customers

$
134.7


$
51.8


$
103.3


$
14.1


$
303.9Cost of natural gas and natural gas liquids


101.3



47.3



82.2



10.4



241.2Operating costs and other expenses


16.2



2.1



9.2



1.1



28.6Depreciation, depletion, amortization and impairment


22.1



2.7



9.0



3.0



36.8Operating income (loss) from continuing operations

$
(4.9
)

$
(0.3
)

$
2.9


$
(0.4
)

$
(2.7
)Capital Expenditures

$
3.7


$
-


$
14.1


$
0.1


$
17.9Segment Assets

$
532.5


$
68.5


$
250.9


$
89.1


$
941.0
 
 Six Months Ended June 30, 2009

Total
Midstream
Segments


Upstream
Segment


Minerals
Segment


Corporate
Segment


Total
Segments($ in millions)Sales to external customers

$
303.9


$
25.3


$
6.7


$
(48.3
)(a)

$
287.6Cost of natural gas and natural gas liquids


241.2



—



—



—



241.2Operating costs and other expenses


28.6



10.8



0.8



24.4



64.6Depreciation, depletion, amortization and impairment


36.8



17.6



3.1



0.4



57.9Operating income (loss) from continuing operations operations

$
(2.7
)

$
(3.1
)

$
2.8


$
(73.1
)

$
(76.1
)Capital Expenditures

$
17.9


$
3.6


$
—


$
1.3


$
22.8Segment Assets

$
941.0


$
379.4


$
138.6


$
172.4


$
1,633.2
 
 Midstream Segments
Six Months Ended June 30, 2008

Texas
Panhandle
Segment


South
Texas
Segment


East Texas /
Louisiana
Segment


Total
Midstream
Segments($ in millions)Sales to external customers

$
339.8


$
97.0


$
168.3


$
605.1Cost of natural gas and natural gas liquids


260.4



91.8



143.9



496.1Operating costs and other expenses


16.5



1.2



7.3



25.0Depreciation, depletion, and amortization


21.6



1.9



5.9



29.4Operating income from continuing operations

$
41.3


$
2.1


$
11.2


$
54.6Capital Expenditures

$
13.4


$
0.6


$
6.1


$
20.1Segment Assets

$
582.4


$
97.0


$
265.3


$
944.7
 
 Six Months Ended June 30, 2008

Total
Midstream
Segments


Upstream
Segment


Minerals
Segment


Corporate
Segment


Total
Segments($ in millions)Sales to external customers

$
605.1


$
85.0


$
17.2


$
(329.6
)(a)

$
377.7Cost of natural gas and natural gas liquids


496.1



—



—



—



496.1Operating costs and other expenses


25.0



17.0



0.9



27.5



70.4Depreciation, depletion, and amortization


29.4



18.3



4.1



0.4



52.2Operating income (loss) from continuing operations operations

$
54.6


$
49.7


$
12.2


$
(357.5
)

$
(241.0
)Capital Expenditures

$
20.1


$
13.2


$
—


$
0.2


$
33.5Segment Assets

$
944.7


$
588.8


$
148.2


$
83.3


$
1,765.0
 
 (a)
Represents results of the Partnership’s derivative activities.
  20
 Table of Contents
 NOTE 14. INCOME TAXES
  Provision for Income Taxes –The Partnership’s provision for income taxes relates to (i) state taxes for the Partnership and (ii) federal taxes for Eagle Rock Energy Acquisition Co., Inc. (acquiring entity of certain entities acquired in the Redman acquisition) and
Eagle Rock Energy Acquisition Co. II, Inc. (acquiring entity of certain entities acquired in the Stanolind Acquisition) and their wholly-owned corporations, Eagle Rock Upstream Development Company, Inc. (successor entity to certain entities acquired in the Redman acquisition) and Eagle Rock Upstream Development Company II, Inc. (successor entity to certain entities acquired in the Stanolind acquisition), which are subject to federal income taxes (the “C Corporations”).
  As a result of the taxable income from the underlying partnerships owned by the C Corporations described above, net operating loss carryforwards of $0.4 million, $0.4 million, $0.3 million, and $0.4 million were used during the three and six months ended June 30, 2009 and 2008, respectively, which resulted in a partial release of the valuation
allowance established for the net operating losses as of December 31, 2008.
  Effective Rate -The effective rate for six month period ended June 30, 2009 was 5.1% compared to 0.4% for the six month period ended June 30, 2008.
  Deferred Taxes -As of June 30, 2009, the net deferred tax liability was $35.2 million compared to $42.3 million as of December 31, 2008 and is primarily attributable to temporary book and tax basis differences of the entities subject to federal income taxes discussed above.  These
temporary differences result in a net deferred tax liability which will be reduced as allocation of depreciation and depletion in proportion to the assets contributed brings the book and tax basis closer together over time.  This deferred tax liability was recognized in conjunction with the purchase accounting for the Stanolind and Redman acquisitions.
  Accounting for Uncertainty in Income Taxes -In accordance with FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, the Partnership must recognize the tax effects of any uncertain tax positions it may adopt,
if the position taken by the Partnership is more likely than not sustainable.  If a tax position meets such criteria, the tax effect to be recognized by the Partnership would be the largest amount of benefit with more than a 50% chance of being realized upon settlement.This guidance was effective January 1, 2007, and the Partnership’s adoption of this guidance had and continues to have no material impact on its financial position, results
of operations or cash flows.
  Texas Franchise Tax -On May 18, 2006, the State of Texas enacted revisions to the existing state franchise tax. In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax, including previously non-taxable entities such as limited
partnerships and limited liability corporations. The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits.  The Company makes appropriate accruals for this tax during the reporting period.
   NOTE 15. EQUITY-BASED COMPENSATION
   Eagle Rock Energy G&P, LLC, the general partner of the general partner for Eagle Rock Energy Partners, L.P., has a long-term incentive plan (“LTIP”), as amended, for its employees, directors and consultants who provide services to the Partnership and its subsidiaries and affiliates.  The LTIP covers an aggregate
of 2,000,000 common units to be granted either as options, restricted units or phantom units.   As to outstanding restricted units, distributions associated with the restricted units will be distributed directly to the awardees. The Partnership has historically only issued restricted units under the LTIP.  No options or phantom units have been issued to date.
  A summary of the LTIP restricted common units’ activity for the three months ended June 30, 2009, is provided below:
 
 Number of
Restricted
Units


Weighted
Average
Fair ValueNonvested at December 31, 2008


905,486


$
17.00Granted


72,700


$
5.67Vested


(217,503
)

$
20.07Forfeitures/Cancellations


(65,870
)

$
15.41Nonvested at June 30, 2009


694,813


$
15.01
 
  21
 Table of Contents
  For the three and six months ended June 30, 2009 and 2008, non-cash compensation expense of approximately $1.9 million, $3.7 million, $1.6 million and $2.7 million, respectively, was recorded related to the granted restricted units under the LTIP.
  As of June 30, 2009, unrecognized compensation costs related to the outstanding restricted units under the LTIP totaled approximately $9.9 million. The remaining expense is to be recognized over a weighted average of 1.63 years.
  In addition to equity awards under the LTIP involving units of the Partnership, Eagle Rock Holdings, L.P. (“Holdings”), which is controlled by NGP, in the past has from time to time granted equity in Holdings to certain employees working on behalf of the Partnership, some of which are named executive officers.  During
the six month period ended June 30, 2009, Holdings granted 160,000 “Tier I” incentive interests to one Eagle Rock Energy employee.  Under the guidance of U.S. Securities and Exchange Commission Staff Accounting Bulletin Topic 1.B: “Allocation Of Expenses And Related Disclosure In Financial Statements Of Subsidiaries, Divisions Or Lesser Business Components Of Another Entity,” the Partnership recorded a portion of the value
of the incentive units as compensation expense in the Partnership’s financial statements.  This allocation is based on management’s estimation of the total value of the incentive unit grant and of the grantee’s portion of time dedicated to the Partnership.  The Partnership recorded non-cash compensation expense of $0.4 million based on management’s estimates related to the Tier I incentive unit grants made by Holdings during the six months ended June 30, 2009.  No
Tier I incentive unit grants were made by Holdings during the three months ended June 30, 2009.
  Due to the vesting of certain restricted units during the three months ended June 30, 2009, 9,844 units were cancelled by the Partnership for less than $0.1 million as consideration for the related employee tax liability paid by the Partnership.  Pursuant to the terms of the LTIP, these cancelled units are available for future
grants under the LTIP.
  NOTE 16.  EARNINGS PER UNIT
  Basic earnings per unit are computed by dividing the net income, or loss, by the weighted average number of units outstanding during a period. To determine net income, or loss, allocated to each class of ownership (common, subordinated and general partner), the Partnership first allocates net income (loss) in accordance with the amount
of distributions made for the quarter by each class, if any. The remaining net income (loss) is allocated to each class in proportion to the class’s weighted average number of units outstanding for a period, as compared to the weighted average number of units for all classes for the period.
 
 On January 1, 2009, the Partnership adopted the provisions of EITF 07-4, which provides that for master limited partnerships (“MLPs”), current period earnings be reduced by the amount of available cash that will be distributed with respect to that period for purposes of calculating earnings per unit.  Any
residual amount representing undistributed earnings is assumed to be allocated to the various ownership interests in accordance with the contractual provisions of the partnership agreement.  In addition, incentive distribution rights (“IDRs”), which represent a limited partnership ownership interest, are considered to be participating securities because they have the right to participate in earnings with common equity holders.
 
 Under the Partnership’s partnership agreement, for any quarterly period, IDRs participate in net income only to the extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in undistributed earnings or losses.  Accordingly, undistributed net income
is assumed to be allocated to the other ownership interests on a pro-rata basis.  During the three months ended June 30, 2009 and 2008, the Partnership did not declare a quarterly distribution for the IDRs.
 
 On January 1, 2009, the Partnership also adopted the provisions of FSP EITF 03-6-1, which provides that share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents meets the definition of a participating security and shall be included in the computation of earnings-per-unit pursuant
to the two-class method, as provided by SFAS No. 128, Earnings Per Share.  The restricted common units granted under the LTIP, as discussed in Note 15, contain non-forfeitable rights to the distributions declared by the Partnership.
  After applying the provisions of EITF 07-4 and FSP EITF 03-6-1, net loss per common, subordinated and general partner unit for the three and six months ended June 30, 2008 remained at $3.14 and $3.54, respectively.  Earnings per unit has not been separately disclosed for the restricted common units, as they restricted common
units are not considered a separate class of equity.
  22
 Table of Contents
 The following table presents the Partnership’s basic and diluted weighted average units outstanding for the periods indicated (in thousands):
  
 Three Months Ended
June 30,


Six Months Ended
June 30,2009


2008


2009


2008Common units


53,147



50,762



53,093



50,731Subordinated units


20,691



20,691



20,691



20,691General partner units


845



845



845



845
 
 The following table presents the Partnership’s basic and diluted loss per unit for the three months ended June 30, 2009:
 
 Total


Common Units


Restricted Common Units


Subordinated Units


General Partner
Units($ in thousands, except for per unit amounts)Loss from continuing operations

$
(74,820
)Distributions declared


1,368


$
1,331


$
16


$
—


$
21Assumed loss from continuing operations after distribution to be allocated


(76,188
)


(54,218
)


—



(21,108
)


(862
)Assumed allocation of loss from continuing operations


(74,820
)


(52,887
)


16



(21,108
)


(841
)Discontinued operations


33



23



—



9



1Assumed net loss to be allocated

$
(74,787
)

$
(52,864
)

$
16


$
(21,099
)

$
(840
)Basic and diluted loss from continuing operations per unit





$
(1.00
)





$
(1.02
)

$
(1.00
)Basic and diluted discontinued operations per unit





$
—






$
—


$
—Basic and diluted loss per unit





$
(0.99
)





$
(1.02
)

$
(0.99
)
 
 The following table presents the Partnership’s basic and diluted loss per unit for the three months ended June 30, 2008:
 
 Total


Common Units


Restricted Common Units


Subordinated Units


General Partner
Units($ in thousands, except for per unit amounts)Loss from continuing operations

$
(227,571
)Distributions declared


29,949


$
20,838


$
281


$
8,484


$
346Assumed loss from continuing operations after distribution to be allocated


(257,520
)


(180,777
)


—



(73,733
)


(3,010
)Assumed allocation of loss from continuing operations


(227,571
)


(159,939
)


281



(65,249
)


(2,664
)Discontinued operations


551



387



—



157



7Assumed net loss to be allocated

$
(227,020
)

$
(159,552
)

$
281


$
(65,092
)

$
(2,657
)Basic and diluted loss from continuing operations per unit





$
(3.15
)





$
(3.15
)

$
(3.15
)Basic and diluted discontinued operations per unit





$
0.01






$
0.01


$
0.01Basic and diluted loss per unit





$
(3.14
)





$
(3.14
)

$
(3.14
)
 
  23
 Table of Contents
 The following table presents the Partnership’s basic and diluted loss per unit for the six months ended June 30, 2009:
 
 Total


Common Units


Restricted Common Units


Subordinated Units


General Partner
Units($ in thousands, except for per unit amounts)Loss from continuing operations

$
(77,672
)Distributions declared


2,736


$
2,657


$
37


$
—


$
42Assumed loss from continuing operations after distribution to be allocated


(80,408
)


(57,204
)


—



(22,294
)


(910
)Assumed allocation of loss from continuing operations


(77,672
)


(54,547
)


37



(22,294
)


(868
)Discontinued operations


340



242



—



94



4Assumed net loss to be allocated

$
(77,332
)

$
(54,305
)

$
37


$
(22,200
)

$
(864
)Basic and diluted loss from continuing operations per unit





$
(1.03
)





$
(1.08
)

$
(1.03
)Basic and diluted discontinued operations per unit





$
—






$
—


$
—Basic and diluted loss per unit





$
(1.02
)





$
(1.07
)

$
(1.02
)
 
 The following table presents the Partnership’s basic and diluted loss per unit for the six months ended June 30, 2008:
 
 Total


Common Units


Restricted Common Units


Subordinated Units


General Partner
Units($ in thousands, except for per unit amounts)Loss from continuing operations

$
(256,187
)Distributions declared


59,026


$
41,118


$
464


$
16,760


$
684Assumed loss from continuing operations after distribution to be allocated


(315,213
)


(221,318
)


—



(90,213
)


(3,682
)Assumed allocation of loss from continuing operations


(256,187
)


(180,200
)


464



(73,453
)


(2,998
)Discontinued operations


839



589



—



241



9Assumed net loss to be allocated

$
(255,348
)

$
(179,611
)

$
464


$
(73,212
)

$
(2,989
)Basic and diluted loss from continuing operations per unit





$
(3.55
)





$
(3.55
)

$
(3.55
)Basic and diluted discontinued operations per unit





$
0.01






$
0.01


$
0.01Basic and diluted loss per unit





$
(3.54
)





$
(3.54
)

$
(3.54
)
 
 
 NOTE 17.  DISCONTINUED OPERATIONS
 
 On April 1, 2009, the Partnership sold its producer services business (which was accounted for in its South Texas Segment) by assigning and novating the contracts under this business to a third-party purchaser.  The Partnership sold the producer services business to a third-party purchaser as it was a low-margin
business that was not core to the Partnership’s operations. The Partnership received an initial payment of $0.1 million for the sale of the business.  In addition the Partnership will receive a contingency payment of up to $0.1 million in October 2009, and it will receive a monthly payment equivalent to $0.01 per MMbtu on the volume of gas that flows pursuant to the assigned contracts for the next two years.  Producer services was a business in which the Partnership would negotiate new
well connections on behalf of small producers to pipelines other than its own.  During the six months ended June 30, 2009, this business generated revenues of $26.8 million and cost of natural gas and natural gas liquids of $26.5 million.  During the three and six months ended June 30, 2008, this business generated revenues of $82.1 million and $134.1 million, respectively, and cost of natural gas and natural gas liquids of $81.5 million and $133.3 million, respectively.  For the
three and six months ended June 30, 2009, less than $0.1 million and $0.3 million, respectively, of revenues minus the cost of natural gas and natural gas liquids have been reported as discontinued operations, as compared to revenues minus the cost of natural gas of $0.6 million and $0.8 million, respectively, for the three and six months ended June 30, 2008.
 
 NOTE 18.  OTHER OPERATING (INCOME) EXPENSE
 
 Other operating (income) expense for the three and six months ended June 30, 2009, includes income of $3.6 million due to the recovery of $2.2 million of assets previously written off and the release of $1.4 million of liabilities assumed as part of the Partnership’s purchase price allocation for its acquisitions
of Escambia Asset Co., LLC and Redman Energy Holdings, L.P.  During the period, the Partnership received additional information about collectability of these assets and determined that it no longer had any obligation under these liabilities.
 
 In July 2008, SemGroup, L.P. and certain of its subsidiaries (“SemGroup”) filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code.  The Partnership historically sold portions of its condensate production from its Texas Panhandle and East Texas midstream systems to SemGroup.  As
a result of the bankruptcy the Partnership took a $6.2 million bad debt charge during the three months ended June 30, 2008, which is included in “Other Operating Expense” in the consolidated statement of operations.
 
  24
 Table of Contents
 Item 2.                      Management’s Discussion and Analysis of Financial Condition and Results of Operations.
  The following discussion and analysis of financial condition and results of operations should be read in conjunction with our unaudited condensed consolidated financial statements, and the notes thereto, appearing elsewhere in this report, as well as the Consolidated Financial Statements, Risk Factors and Management’s
Discussion and Analysis of Financial Condition and Results of Operations presented in our annual report on Form 10-K for the year ended December 31, 2008, filed with the Securities and Exchange Commission. For a description of oil and natural gas terms, see our annual report.
  Overview
 
 We are a domestically focused growth-oriented publicly traded Delaware limited partnership engaged in the following three businesses:
  •
Midstream Business—gathering, compressing, treating, processing and transporting of natural gas; fractionating and transporting of natural gas liquids (“NGLs”); and the marketing of natural gas, condensate and NGLs;
  •
Upstream Business—acquiring, developing and producing oil and natural gas property interests; and
  •
Minerals Business—acquiring and managing fee minerals and royalty interests, either through direct ownership or through investment in other partnerships.
 
 We report on our businesses in seven accounting segments.
 
 We conduct, evaluate and report on our Midstream Business within four distinct segments—the Texas Panhandle Segment, the East Texas/Louisiana Segment, the South Texas Segment and the Gulf of Mexico Segment. Our Texas Panhandle Segment consists of gathering
and processing assets in the Texas Panhandle. Our East Texas/Louisiana Segment consists of gathering and processing assets in East Texas, Central Texas and Northern Louisiana. Our South Texas Segment consists of gathering systems and related compression and processing facilities in South Texas and West Texas.   Our Gulf of Mexico Segment consists of gathering and processing assets in Southern Louisiana, the Gulf of Mexico and Galveston Bay, Texas.  During the three and six months ended
June 30, 2009, our Midstream Business generated operating income from continuing operations of $3.4 million and an operating loss from continuing operations of $2.7 million, respectively, compared to operating income from continuing operations of $32.1 million and $54.6 million during the three and six months ended June 30, 2008, respectively.
 
 We conduct, evaluate and report on our Upstream Business as one segment. Our Upstream Segment includes operated wells in Escambia County, Alabama as well as two treating facilities, one natural gas processing plant and related gathering systems that are inextricably
intertwined with ownership and operation of the wells. The Upstream Segment also includes operated and non-operated wells that are primarily located in West, East and South Texas in Ward, Crane, Pecos, Henderson, Rains, Van Zandt, Limestone, Freestone and Atascosa Counties, Texas.  During the three and six months ended June 30, 2009, our Upstream Business generated operating income of $3.4 million and an operating loss of $3.0 million, respectively, compared to operating income of $26.6 million and
$49.6 million during the three and six months ended June 30, 2008, respectively.  Of important note, the cost of disposal of sulfur exceeded the revenue generated by $0.7 million and $1.2 million during the three and six months ended June 30, 2009, respectively, compared to revenue of $7.1 million and $12.5 million generated during the three and six months ended June 30, 2008, respectively.
 
 We conduct, evaluate, and report our Minerals Business as one segment.  Our Minerals Segment consists of fee mineral, royalty and overriding royalty interests located in multiple producing trends in the United States.  A significant portion of the mineral
interests that we own are managed by a non-affiliated private partnership (the “Minerals Manager”) that controls the executive rights associated with the minerals.  During the three and six months ended June 30, 2009, our Minerals Business generated operating income of $1.7 million and $2.8 million, respectively, compared to operating income of $8.2 million and $12.1 million during the three and six months ended June 30, 2008, respectively.  Included within these numbers is lease
bonus revenue of $0.4 million and $0.9 million generated during the three and six months ended June 30, 2009, respectively, compared to $1.5 million and $2.7 million during the three and six months ended June 30, 2008, respectively.
 
 The final segment that we report on is our Corporate Segment, in which we account for our commodity derivative/hedging activity and our corporate-level general and administrative expenses.  During the three and six months ended June 30, 2009, our Corporate Segment generated an operating loss of $86.7 million
and $73.2 million, respectively, compared to an operating loss of $300.4 million and $357.5 million during the three and six months ended June 30, 2008, respectively.  Within these numbers were losses, realized and unrealized, on commodity derivatives of $74.6 million and $48.3 million during the three and six months ended June 30, 2009, respectively, compared to losses, realized and unrealized, on commodity derivatives of $284.0 million and $329.6 million during the three and six months ended June
30, 2008, respectively.
 
 We have an experienced management team dedicated to growing, operating and maximizing the profitability of our assets.  Our management team is experienced in gathering and processing natural gas, operating oil and natural gas properties and assets, and managing royalties and minerals.
 
 We are controlled by our general partner who is controlled by its general partner (collectively “general partner”), who in turn is managed by its board of directors (the “Board of Directors”).
 
 Impairment
 
 In connection with the preparation of our unaudited condensed consolidated financial statements for the three months ended March 31, 2009, we determined that we needed to record an impairment charge for certain fields within our proved properties within our Upstream
Segment.  These impairment charges were necessary due to the continued decline in natural gas prices during the period.  As a result, we incurred impairment charges of $0.2 million in our Upstream Segment.  We did not incur any impairment charges during the three months ended June 30, 2009.
 
 Pursuant to generally accepted accounting principles in the United States, our impairment analysis does not take into account the value of our commodity derivative instruments, which generally increase as the estimates of future prices decline.  Further
declines in commodity prices and other factors could result in additional impairment charges and changes to the fair value of our derivative instruments.
  Acquisitions
  Historically, we have grown through acquisitions.  Going forward, we will continue to assess acquisition opportunities, regardless of whether such opportunity is in the midstream, upstream, or minerals business, for their potential accretive value. Our ability to complete acquisitions will depend on our ability to finance the
acquisitions, either through the issuance of additional securities, debt or equity, or the incurrence of additional debt under our revolving credit facility, on terms acceptable to us.  See further discussion under “Liquidity and Capital Resources.”
  Below is a summary of our important acquisition transactions completed during the year ended December 31, 2008.
  Stanolind Acquisition -On April 30, 2008, we completed the acquisition of all of the outstanding capital stock of Stanolind Oil and Gas Corp. (“Stanolind”).  With this acquisition, we acquired crude oil and natural gas producing properties in the Permian Basin
of West Texas, primarily in Ward, Crane and Pecos Counties.
 
 Millennium Acquisition -On October 1, 2008, we completed the acquisition of 100% of the outstanding units of Millennium Midstream Partners, L.P. (“MMP”).  With the acquisition, we acquired
natural gas gathering and processing business, with assets located in East, Central and West Texas and South Louisiana.
   25
 Table of Contents
 
 Recent Transactions
 
 On April 1, 2009, we sold our producer services business (which was accounted for in our South Texas Segment) by assigning and novating the contracts under this business to a third-party purchaser.  We sold the producer services business to a third-party
purchaser as it was a low-margin business that was not core to our operations.   We received an initial payment of $0.1 million for the sale of the business.  In addition we will receive a contingency payment of up to $0.1 million in October, 2009 and we will receive a monthly payment equivalent to $0.01 per MMbtu on the volume of gas that flows pursuant to the assigned contracts for the next two years.  The producer services business was a low margin business in which we would
negotiate new well connections on behalf of small producers to pipelines other than our own.  During the six months ended June 30, 2009, this business generated revenues of $26.8 million and cost of natural gas and natural gas liquids of $26.5 million.  During the three and six months ended June 30, 2008, this business generated revenues of $82.1 million and $134.1 million, respectively, and cost of natural gas and natural gas liquids of $81.5 million and $133.3 million, respectively.  For
the three and six months ended June 30, 2009, less than $0.1 million and $0.3 million, respectively, of revenues minus the cost of natural gas and natural gas liquids have been reported as discontinued operations, as compared to revenues minus the cost of natural gas of $0.6 million and $0.8 million, respectively, for the three and six months ended June 30, 2008.
  Presentation of Financial Information
  For a description of the presentation of our financial information in this report, please see Note 1 to the unaudited condensed consolidated financial statements.
  How We Evaluate Our Operations
  Our management uses a variety of financial and operational measurements to analyze our performance. We view these measurements as important factors affecting our profitability and review these measurements on a monthly basis for consistency and trend analysis. These measures include oil, gas, NGL and sulfur volumes; margins, operating
expenses and Adjusted EBITDA (more fully described later under “Non-GAAP Financial Measures”) on a company-wide basis.
  General Trends and Outlook
  We expect our business to continue to be affected by the key trends as discussed in our Annual Report on Form 10-K for the year ended December 31, 2008 and that the recent events impacting the world’s economy and financial markets will play an important role in the performance and growth prospects of our business.  These
recent events include but are not limited to: continued turbulence in the world’s banking system and reduced availability of credit on attractive terms; precipitous drops in the value of almost all asset classes including equity, bonds, real estate, and other investment vehicles; significant volatility in commodity prices including the prices for crude oil, natural gas, NGLs, condensate, and sulfur, among others; the significant reaction to the fall in natural gas prices by our producer customers in the
Midstream Business, especially in the form of reduced drilling activity and curtailment or shutting-in of natural gas production; as well as the possibility of a prolonged period of economic recession. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about our interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.
 
 On April 29, 2009, we announced that the borrowing base under our revolving credit facility, which relates to our Upstream Business, was redetermined down to $135 million from $206 million.  This meaningful reduction in the borrowing base occurred in connection with a regularly scheduled redetermination in
accordance with our revolving credit facility and is primarily the result of the deterioration of commodity prices in the oil, natural gas and sulfur industries.  After taking into account this redetermination, we remain in compliance with the financial and other covenants in our revolving credit facility.
 
 In light of the borrowing base redetermination and the deterioration of commodity prices in the oil and natural gas industry, which has led to declines in our customers’ drilling activity and hydrocarbon throughput volumes in our gathering and processing systems, as well as reduced revenues in our Upstream
and Minerals businesses, the Board of Directors has determined it is prudent to create cash reserves for the proper conduct of our business and to remain in compliance with financial covenants under our revolving credit facility.  The cash not distributed to unitholders will be used primarily to reduce our outstanding debt under our revolving credit facility and to continue the execution of our hedge strategy to maintain future cash flows.  We anticipate continuing this strategy until our
Board of Directors determines that our leverage ratio is at an appropriate level for the proper conduct of our business. In making this determination, we anticipate that our Board of Directors will also focus on certain aspects of our business which include, but are not limited to, improvement in commodity prices in the oil and natural gas industry, and increases in our producer customers’ drilling activity and resulting throughput volumes in our gathering and processing systems.
 
 On July 29, 2009, we announced that we will pay a quarterly cash distribution of $0.025 per common and general partner unit for the quarter ended June 30, 2009, which is consistent with the distribution payment for the quarter ended March 31, 2009.  This is a reduction from the $0.41 per unit distributed
to all unitholders for the quarter ended December 31, 2008.  The distribution will be paid on August 14, 2009 to our general partner and common unit holders of record as of the close of business on August 10, 2009.
  Cautionary Note Regarding Forward-Looking Statements
 
 Certain matters discussed in this report, excluding historical information, include certain “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.
Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “continue,” “estimate,” “forecast,” “may,” “will,” or similar expressions help identify forward-looking statements. Although we believe such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that these objectives
will be reached. In addition, forward-looking statements speak only as of the date on which such statements are made.  Actual results may differ materially from any results projected, forecasted, estimated or expressed in forward-looking statements because many of the factors which determine these results are subject to uncertainties and risks, difficult to predict, and beyond management’s control. We assume no obligation to update any forward-looking statement as of any future date.  For
additional discussion of risks, uncertainties and assumptions, see our annual report on Form 10-K for the year ended December 31, 2008, filed with the Securities and Exchange Commission on March 13, 2009 as well as the risks disclosed in Part II, Item 1A below.
  26
 Table of Contents
 
 Summary of Consolidated Operating Results
 
 Below is a summary table of our consolidated operating results for the three and six months ended June 30, 2009 and June 30, 2008, respectively. Operating results for our individual operating segments are presented in tables in this Item 2.
  
 Three Month Ended
June 30,


Six Months Ended
June 30,2009


2008


2009


2008($ in thousands)REVENUE:Natural gas, natural gas liquids, oil, condensate and sulfur sales

$
153,056


$
369,715


$
304,148


$
674,689Gathering, compression, processing and treating services


11,562



8,085



23,229



15,228Minerals and royalty income


3,499



10,255



6,738



17,213Realized commodity derivative gains (losses)


22,483



(27,708
)


53,261



(40,283
)Unrealized commodity derivative losses


(97,044
)


(256,265
)


(101,566
)


(289,337
)Other revenue


1,678



122



1,720



182Total revenue


95,234



104,204



287,530



377,692COSTS AND EXPENSES:Cost of natural gas and natural gas liquids


115,476



272,055



241,295



496,129Operations and maintenance (b)


19,049



17,731



37,690



33,297Taxes other than income


2,878



5,263



5,856



9,610General and administrative


11,895



10,026



24,433



21,268Other operating (income) expenses


(3,552
)


6,214



(3,552
)


6,214Impairment


—



—



242



—Depreciation, depletion, and amortization


27,588



26,457



57,651



52,202Total costs and expenses


173,334



337,746



363,615



618,720OPERATING LOSS


(78,100
)


(233,542
)


(76,085
)


(241,028
)OTHER INCOME (EXPENSE):Interest income


141



160



173



461Other income


550



886



1,110



2,433Interest expense, net


(5,428
)


(6,974
)


(12,967
)


(16,078
)Realized interest rate derivative losses


(5,147
)


(2,444
)


(8,629
)


(2,545
)Unrealized interest rate derivative gains


11,954



13,689



15,053



29Other expense


(267
)


(232
)


(534
)


(447
)Total other income (expense)


1,803



5,085



(5,794
)


(16,147
)LOSS FROM CONTINUING OPERATIONS
BEFORE INCOME TAXES


(76,297
)


(228,457
)


(81,879
)


(257,175
)INCOME TAX BENEFIT


(1,477
)


(886
)


(4,207
)


(988
)LOSS FROM CONTINUING OPERATIONS


(74,820
)


(227,571
)


(77,672
)


(256,187
)DISCONTINUED OPERATIONS


33



551



340



839NET LOSS

$
(74,787
)

$
(227,020
)

$
(77,332
)

$
(255,348
)ADJUSTED EBITDA (a)

$
44,666


$
56,953


$
85,771


$
109,443
 
 (a)
See “Non-GAAP Financial Measures” and Reconciliation of ‘Adjusted EBITDA’ to net cash flows provided by operating activities and net loss within Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations for a definition and reconciliation to GAAP.
 (b)
Includes costs to dispose of sulfur in our Upstream segment of $717 and $1,157 for three and six months ended June 30, 2009.
  27
 Table of Contents
 Midstream Business (Four Segments)
  Texas Panhandle Segment
 Three Month Ended
June 30,


Six Months Ended
June 30,2009


2008


2009


2008($ in thousands)Revenues:Natural gas, natural gas liquids, oil, and condensate sales

$
66,373


$
180,987


$
129,323


$
334,842Gathering and treating services


2,601



2,524



5,414



4,993Total revenues


68,974



183,511



134,737



339,835Cost of natural gas and natural gas liquids


49,407



140,282



101,354



260,400Operating costs and expenses:Operations and maintenance


8,056



8,715



16,201



16,463Depreciation and amortization


10,962



10,894



22,058



21,603Total operating costs and expenses


19,018



19,609



38,259



38,066Operating income (loss)

$
549


$
23,620


$
(4,876
)

$
41,369Capital expenditures

$
766


$
6,469


$
3,709


$
13,455Realized average prices:Oil and condensate (per Bbl)

$
59.08


$
117.93


$
53.69


$
104.15Natural gas (per Mcf)

$
2.66


$
9.44


$
3.06


$
8.42NGLs (per Bbl)

$
29.82


$
74.76


$
27.26


$
68.46Production volumes:Gathering volumes (Mfc/d) (a)


143,281



149,881



143,740



152,225NGLs (net equity gallons)


11,815,414



11,857,694



22,450,463



25,791,160Condensate (net equity gallons)


9,813,579



7,793,097



16,006,005



15,743,884Natural gas short position (MMbtu/d) (a)


(5,748
)


(4,974
)


(5,943
)


(6,112
)
 
 (a)
Gathering volumes (Mcf/d) and natural gas short position (MMbtu/d) are calculated by taking the total volume and then dividing by the number of days in the respective period.
  Revenues and Cost of Natural Gas and Natural Gas Liquids.For the three and six months ended June 30, 2009, revenues minus cost of natural gas and natural gas liquids for our Texas Panhandle Segment operations totaled $19.6 million and $33.4 million, respectively, compared to
$43.2 million and $79.4 million, respectively, for the three and six months ended June 30, 2008. There were two primary contributors to this decrease: (i) lower NGL and condensate pricing, as compared to pricing in 2008, and (ii) lower NGL equity production as compared to production in 2008.  The lower NGL equity production was primarily due to approximately 5.6% lower gathered volumes in 2009 as compared to 2008 and due to operating certain plants in ethane rejection mode for much of the
first two months of 2009.  Ethane rejection operations occur when we elect to not recover the ethane component in the natural gas stream in our plants and instead choose to leave the ethane component in the residue gas stream sold at the tailgates of our plants. Ethane rejection operations result in a lower volume of equity NGLs with a correspondingly smaller natural gas short position.  We operate in this manner when the value of ethane is worth more in the gas stream than as an NGL.
  The lower gathering volumes during the three and six months ended June 30, 2009 compared to the same period in the prior year were due to natural declines in the underlying existing wells in addition to reduced drilling activity during 2009.   The dramatic fall in commodity prices experienced in the latter part of 2008 and
lasting into early 2009 has resulted in many of our producer customers significantly reducing drilling activity in the Texas Panhandle, presumably not to be resumed until commodity prices rise to levels which justify drilling.   While oil prices have recovered from the lows seen in the three months ended March 31, 2009, natural gas prices have continued to decline with an excess supply of natural gas experienced in many regions of the country.
 
 The drilling activity in the West Panhandle System is not sufficient to offset the natural declines experienced on this system. While our contract mix in the West Panhandle System provides us with a higher equity share of the production, the overall decline will
continue and we expect to recover smaller equity production in the future on the West Panhandle System.
 
 The East Panhandle System experienced strong growth in volumes and equity production due to the active Granite Wash drilling play located in Roberts, Hemphill and Wheeler Counties, Texas through much of 2008; however due to lower commodity values during the fourth
quarter of 2008 continuing through the first six months of 2009, we experienced a significant decline in drilling activity.
 
 Recent drilling by the largest operators in the Granite Wash play, utilizing horizontal drilling technologies, has resulted in initial potential (“IP”) natural gas rates of 6 MMcf per day or better.    These operators believe the economics
of the Granite Wash play will be significantly enhanced due to the fewer number of wells and lower capital required to develop the same amount of acreage versus conventional vertical drilling results.   We have extensive gathering and processing facilities in Roberts and Hemphill Counties, Texas and long term acreage dedications from several of the larger producers.   We believe the Partnership will benefit in the future due to the application of this technology in the Granite Wash
play with increased natural gas and condensate production in the East Panhandle System.
 
 The liquids content of the natural gas is lower in the East Texas Panhandle System and our contract mix provides us with a smaller share of equity production as compared to the West Panhandle System. At the current lower drilling activity in the East Panhandle System
we would be unable to offset the continued decline on the West Panhandle System of NGL and condensate equity gallons.  Our current goal is to aggressively contract for new volumes in the East Panhandle System to offset the decline in volumes and our share of equity production in the West Panhandle System.
  Operating Expenses.Operating expenses, including taxes other than income, for three and six months ended June 30, 2009 were $8.1 million and $16.2 million, respectively, compared to $8.7 million and $16.5 million, respectively, for the three and six months ended June 30, 2008. The
$0.7 million decrease in operating expenses during the three months ended June 30, 2009, as compared to the same period in 2008, was primarily due to cost reductions across the segment.  The $0.3 million decrease in operating expenses during the six months ended June 30, 2009, as compared to the same period in 2008, was primarily due to overall cost reduction across the segment offset by an increase in  environmental compliance costs of approximately $0.3 million as compared to the same period
in the prior year.
 
 Depreciation and Amortization. Depreciation and amortization expenses for three and six months ended June 30, 2009 were $11.0 million and $22.1 million, respectively, compared to $10.9 million and $21.6 million, respectively, for the three and six months ended June 30, 2008.  The
major item impacting the $0.1 million and $0.5 million increases, respectively, was depreciation expense associated with the capital expenditures placed into service during the period.
  Capital Expenditures.Capital expenditures for three and six months ended June 30, 2009 were $0.8 million and $3.7 million, respectively, compared to $6.5 million and $13.5 million, respectively, for the three and six months ended June 30, 2008. We classify capital expenditures as
either maintenance capital (which represents routine well connects and capitalized maintenance activities) or as growth capital (which represents organic growth projects). In the three and six months ended June 30, 2009, growth capital represented 31% and 73% of our capital expenditures as compared to 45% and 79%, respectively, in the three and six months ended June 30, 2008. The decrease in capital expenditures of $5.7 million and $9.8 million, respectively, was driven by reduced maintenance capital associated
with fewer new well connects due to the lower drilling activity and by less growth capital due to expenditures related to our Stinnett – Cargray plant consolidation project having occurred in the three and six months ending June 30, 2008.
  
  28
 Table of Contents
 East Texas/Louisiana Segment
 Three Month Ended
June 30,


Six Months Ended
June 30,2009(b)


2008


2009(b)


2008($ in thousands)Revenues:Natural gas, natural gas liquids, oil, and condensate sales

$
41,245


$
93,176


$
88,696


$
160,135Gathering and treating services


7,375



4,700



14,584



8,148Total revenues


48,620



97,876



103,280



168,283Cost of natural gas and natural gas liquids


37,233



83,911



82,242



143,930Operating costs and expenses:Operations and maintenance


4,608



3,837



9,160



7,317Depreciation and amortization


4,240



2,988



9,011



5,857Total operating costs and expenses


8,848



6,825



18,171



13,174Operating income (loss)

$
2,539


$
7,140


$
2,867


$
11,179Capital expenditures

$
4,820


$
4,044


$
14,077


$
6,095Realized average prices:Oil and condensate (per Bbl)

$
60.87


$
116.33


$
56.13


$
111.37Natural gas (per Mcf)

$
3.45


$
12.32


$
3.90


$
10.67NGLs (per Bbl)

$
31.50


$
58.80


$
25.38


$
55.86Production volumes:Gathering volumes (Mfc/d) (a)


265,740



179,744



268,654



171,824NGLs (net equity gallons)


6,166,467



6,283,355



8,842,886



11,234,078Condensate (net equity gallons)


466,348



341,096



901,639



693,971Natural gas short position (MMbtu/d) (a)


2,798



1,543



3,036



958
 
 (a)
Gathering volumes (Mcf/d) and natural gas long position (MMbtu/d) are calculated by taking the total volume and then dividing by the number of days in the respective period.
 (b)
Includes operations related to the Millennium Acquisition effective October 1, 2008.
  Revenues and Cost of Natural Gas and Natural Gas Liquids. For the three and six months ended June 30, 2009, revenues minus cost of natural gas and natural gas liquids for our East Texas/Louisiana Segment totaled $11.4 million and $21.0 million, respectively, compared to $14.0
million and $24.4 million, respectively, for the three and six months ended June 30, 2008.  The Millennium Acquisition positively impacted the East Texas/Louisiana Segment’s revenue minus cost of natural gas and natural gas liquids by $4.0 million and $8.4 million, respectively, during the three and six months ended June 30, 2009.  Our lower NGL equity gallons for the six months ended June 30, 2009 were primarily due to operating the facilities in ethane rejection mode during much of
the first two months of 2009. Ethane rejection mode is when we elect to not recover the ethane component in the natural gas stream in our plants and instead choose to leave the ethane component in the residue gas stream sold at the tailgates of our plants.  We operate in this manner when the value of ethane is worth more in the gas stream than as an NGL.
  We were negatively impacted by lower NGL and condensate pricing during the three and six months ended June 30, 2009 as compared to the three and six months ended June 30, 2008. We were positively impacted by 56.4% growth in gathering volume during the six months ended June 30, 2009 compared to the six months ended June 30, 2008 due to
the Millennium Acquisition while other East Texas/Louisiana Segment gathering systems realized a reduction in volumes. Excluding the Millennium Acquisition, our gathering volumes decreased by 5.6%.  The offsetting reduction in higher margin gas volumes is being replaced with lower margin, fixed fee volumes from the Millennium Acquisition.  The gas volumes from the Millennium Acquisition are primarily dry gas that does not require processing to remove NGLs prior to delivery to the interstate
pipelines in order to meet the pipelines’ gas quality tariff requirements.  The lower margin gas, though contributing to a significant increase in overall gathered volumes, has not offset the lower revenues and margins due to the lower NGL, condensate and natural gas prices during the first six months of 2009 as compared to the same time period in 2008.  During the last three months of 2008 and continuing into the first six months of 2009, we saw a significant reduction in our customer’s
drilling activity due to lower commodity values.
 
 Operating Expenses.Operating expenses for the three and six months ended June 30, 2009 were $4.6 million and $9.2 million, respectively, compared to $3.8 million and $7.3 million, respectively, for the three and six months ended June 30, 2008. The major items impacting the $0.8
million and $1.8 million increases in operating expense for the three and six months, respectively, was due to expenses associated with operating the assets acquired as part of the Millennium Acquisition.  Excluding operating expenses related to the assets acquired as part of the Millennium Acquisition, operating expenses were relatively flat for the three and six months ended June 30, 2009 as compared to the same periods in 2008.
 
 Depreciation and Amortization.Depreciation and amortization expenses for the three and six months ended June 30, 2009 were $4.2 million and $9.0 million, respectively, compared to $3.0 million and $5.9 million, respectively, for the three and six months ended June 30, 2008. The
major items impacting the $1.3 million and $3.2 million increases were (i) three and six months of depreciation and amortization of the assets acquired as part of Millennium Acquisition and (ii) depreciation expense associated with the capital expenditures placed into service.These increases were offset by an adjustment of $0.9 recorded during the three and six months ended June 30, 2009 to correct an overstatement of depreciation expense in a
prior period.
  Capital Expenditures.Capital expenditures for the three and six months ended June 30, 2009 were $4.8 million and $14.1 million, respectively, compared to $4.0 million and $6.1 million, respectively, for the three and six months ended June 30, 2008. We classify capital expenditures
as either maintenance capital (which represents routine well connects and capitalized maintenance activities) or as growth capital (which represents organic growth projects). Our increase in capital spending of $0.8 million and $8.0 million, respectively, is due primarily to the construction of gathering lines to producers in the Brookeland and Tyler County gathering systems.
  
  29
 Table of Contents
  South Texas Segment
 Three Month Ended
June 30,


Six Months Ended
June 30,2009(b)


2008


2009(b)


2008($ in thousands)Revenues:Natural gas, natural gas liquids, oil, and condensate sales

$
24,487


$
49,740


$
48,877


$
94,934Gathering and treating services


1,306



861



2,863



2,087Other


—



—



3



2Total revenues


25,793



50,601



51,743



97,023Cost of natural gas and natural gas liquids


23,655



47,862



47,326



91,799Operating costs and expenses:Operations and maintenance


989



574



2,050



1,227Depreciation and amortization


1,284



934



2,708



1,873Total operating costs and expenses


2,273



1,508



4,758



3,100Operating income (loss) from continuing operations


(135
)


1,231



(341
)


2,124Discontinued operations


33



551



340



839Operating income (loss)

$
(102
)

$
1,782


$
(1
)

$
2,963Capital expenditures

$
75


$
218


$
15


$
579Realized average prices:Oil and condensate (per Bbl)

$
55.55


$
123.16


$
40.80


$
105.12Natural gas (per Mcf)

$
3.31


$
10.88


$
3.87


$
9.67NGLs (per Bbl)

$
29.68


$
72.66


$
27.96


$
73.08Production volumes:Gathering volumes (Mfc/d) (a)


90,395



84,514



93,885



81,312NGLs (net equity gallons)


452,942



377,706



677,447



827,568Condensate (net equity gallons)


309,186



—



956,646



—Natural gas short position (MMbtu/d) (a)


500



500



500



500
 
 (a)
Gathering volumes (Mcf/d) and natural gas long position (MMbtu/d) are calculated by taking the total volume and then dividing by the number of days in the respective period.
 (b)
Includes operations related to the Millennium Acquisition effective October 1, 2008.
  Revenues and Cost of Natural Gas and Natural Gas Liquids.During the three and six months ended June 30, 2009, the South Texas Segment contributed $2.1 million and $4.4 million, respectively, in revenues minus cost of natural gas and natural gas liquids as compared to $2.7 million
and $5.2 million, respectively, for the three and six months ended June 30, 2008.  We were negatively impacted by lower NGL, natural gas and condensate pricing during the three and six months ended June 30, 2009 as compared to the same periods in 2008.   This decline was partially offset by the impact of the assets acquired as part of the Millennium Acquisition which contributed revenue minus cost of natural gas and natural gas liquids of $0.9 million and $1.7 million, respectively, during
the three and six months ended June 30, 2009.
 
 Operating Expenses.Operating expenses for the three and six months ended June 30, 2009 were $1.0 million and $2.1 million, respectively, compared to $0.6 million and $1.2 million, respectively, for the three
and six months ended June 30, 2008.  The major item impacting the $0.4 million and $0.9 million increases in operating expense, for the three and six months, respectively, was the additional expenses associated with operating the assets acquired as part of the Millennium Acquisition.
  Depreciation and Amortization.Depreciation and amortization expenses for the three and six months ended June 30, 2009 were $1.3 million and $2.7 million, respectively, compared to $0.9 million and $1.9 million, respectively, for the three and six months ended June 30, 2008.  The
major item impacting the $0.4 million and $0.8 million increases, for the three and six months, respectively, was the additional depreciation and amortization of the assets acquired as part of the Millennium Acquisition.
 
 Capital Expenditures.Capital expenditures for the three and six months ended June 30, 2009 were less than $0.1 million compared to $0.2 million and $0.6 million, respectively, for the three and six months ended June 30, 2008. We classify capital expenditures as either maintenance
capital (which represents routine well connects and capitalized maintenance activities) or as growth capital (which represents organic growth projects).
 
 Discontinued Operations.On April 1, 2009, we sold our producer services line of business and thus have classified its revenues minus cost of natural gas and natural gas liquids as discontinued operations.  During the six months ended June 30, 2009, our producer
services business generated revenues of $26.8 million and cost of natural gas and natural gas liquids of $26.5 million, as compared to revenues of $134.1 million and cost of natural gas and natural gas liquids of $133.3 million during the six months ended June 30, 2008.
 
 30
 Table of Contents
 Gulf of Mexico Segment
 Three Month Ended
June 30,


Six Months Ended
June 30,2009(b)


2008


2009(b)


2008($ in thousands)Revenues:Natural gas, natural gas liquids, oil, and condensate sales

$
5,844


$
—


$
12,066


$
—Gathering and treating services


280



—



368



—Other revenue


1,616



—



1,616



—Total revenues


7,740



—



14,050



—Cost of natural gas and natural gas liquids


5,181



—



10,373



—Operating costs and expenses:Operations and maintenance


658



—



1,076



—Depreciation and amortization


1,477



—



2,965



—Total operating costs and expenses


2,135



—



4,041



—Operating income (loss)

$
424


$
—


$
(364
)

$
—Capital expenditures

$
—


$
—


$
141


$
—Realized average prices:Oil and condensate (per Bbl)

$
48.20


$
—


$
47.79


$
—Natural gas (per Mcf)

$
3.87


$
—


$
5.11


$
—NGLs (per Bbl)

$
29.57


$
—


$
28.76


$
—Production volumes:Gathering volumes (Mfc/d) (a)


98,619



—



107,559



—NGLs (net equity gallons)


1,192,008



—



2,904,158



—
 
 (a)
Gathering volumes (Mcf/d) are calculated by taking the total volume and then dividing by the number of days in the respective period.
 (b)
Includes operations related to the Millennium Acquisition starting on October 1, 2008.
 
 Revenues and Cost of Natural Gas and Natural Gas Liquids.We entered into this segment as a result of the Millennium Acquisition, effective October 1, 2008.During
the three and six months ended June 30, 2009, the Gulf of Mexico Segment contributed $2.6 million and $3.7 million, respectively, in revenues minus cost of natural gas and natural gas liquids.  As a result of damage inflicted by Hurricanes Gustav and Ike in August 2008 and September 2008, respectively, the Yscloskey plant did not come back online until mid-January 2009 and the North Terrebonne plant did not come back online until mid-November 2008. We received a partial payment of $1.6 million, which
represents approximately 90% of our claim, for business interruption caused by Hurricanes Gustav and Ike which we recognized as other revenue during the three months ended June 30, 2009.
 
 Operating Expenses.Operating expenses for the three and six months ended June 30, 2009 were $0.7 million and $1.1 million, respectively.  We continued to incur operating expenses associated
with the Yscloskey and North Terrebonne plants while the plants were undergoing repair for the hurricane damage.  We also incurred costs for the repair of the two plants.  Such costs were recovered from the escrow account established pursuant to the Millennium Acquisition purchase and sale agreement.  As a result and pursuant to the agreement, any insurance proceeds received for repair costs will be deposited into the escrow account.  During the six months ended June 30,
2009, we received payment from the Millennium Acquisition escrow in the amount of $0.3 million in cash and began canceling common units held in escrow to satisfy additional claims.
 
 Depreciation and Amortization.Depreciation and amortization expenses for the three and six months ended June 30, 2009 were $1.5 million and $3.0 million, respectively.
 
 Capital Expenditures.Capital expenditures for the six month period ended June 30, 2009 for the Gulf of Mexico Segment were $0.1 million.
  31
 Table of Contents
 
 Upstream Business (One segment)
 Three Month Ended
June 30,


Six Months Ended
June 30,2009


2008(a)


2009


2008(a)($ in thousands)Revenues:Oil and condensate sales (b)

$
8,598


$
21,126


$
14,556


$
39,459Natural gas sales (c)


2,965



9,431



4,860



16,557Natural gas liquids sales (d)


3,544



8,155



5,770



16,295Sulfur sales


—



7,100



—



12,467Other


62



122



101



180Total revenues


15,169



45,934



25,287



84,958Operating costs and expenses:Operations and maintenance


6,601



9,386



13,133



16,975Sulfur disposal costs


717



—



1,157



—Impairment


—



—



242



—Other operating income


(3,552
)


—



(3,552
)


—Depreciation and amortization


7,955



9,914



17,351



18,339Total operating costs and expenses


11,721



19,300



28,331



35,314Operating income (loss)

$
3,448


$
26,634


$
(3,044
)

$
49,644Capital expenditures

$
1,988


$
10,261


$
3,580


$
13,184Realized average prices (e):Oil and condensate (per Bbl)

$
43.20


$
114.50


$
35.69


$
102.25Natural gas (per Mcf)

$
2.95


$
10.80


$
3.57


$
9.65NGLs (per Bbl)

$
27.44


$
68.74


$
23.26


$
66.21Sulfur (per Long ton)

$
—


$
359.97


$
—


$
271.28Production volumes:Oil and condensate (Bbl)


204,725



184,511



415,176



385,916Natural gas (Mcf)


909,686



873,093



1,800,489



1,715,290NGLs (Bbl)


123,057



118,644



246,836



246,097Total (Mcfe)


2,876,376



2,692,023



5,772,558



5,507,368Sulfur (Long ton)


39,823



19,724



68,428



45,956
 
 (a)
Includes operations from the Stanolind Acquisition effective May 1, 2008.
 (b)
Revenues include a change in the value of product imbalances of $(247) and $(260) for the three and six months ended June 30, 2009, respectively.  No changes in the value of the product imbalances were recognized during the three and six months ended June 30, 2008.
 (c)
Revenues include a change in the value of product imbalances of $284 and $(1,563) for the three and six months ended June 30, 2009, respectively.  No changes in the value of the product imbalances were recognized during three and six months ended June 30, 2008.
 (d)
Revenues include a change in the value of product imbalances of $167 and $28 for the three and six months ended June 30, 2009, respectively.  No changes in the value of the product imbalances were recognized during the three and six months ended June 30, 2008.
 (e)
Calculation does not include impact of product imbalances.
  Revenue. For the three and six months ended June 30, 2009 and 2008, the Upstream Segment contributed $15.2 million, $25.3 million, $45.9 million and $85.0 million of revenue, respectively.  The decrease in revenue was due to substantially lower realized prices for oil,
natural gas, NGLs and sulfur and the non-cash mark-to-market of product imbalances, partially offset by an additional one month and four months, respectively, of operations related to the assets acquired in the Stanolind Acquisition.  During the three and six months ending June 30, 2009, production averaged 10.0 MMcf/d and 9.9 MMcf/d, respectively, 2.2 MBO/d and 2.3 MBO/d, respectively, 1.4 MB/d of NGL’s and 1.4 MB/d of NGL’s, respectively and 437 LT/d of sulfur and 378 LT/d of sulfur, respectively.  The
period included three and six months of production from the assets acquired in the Stanolind Acquisition which averaged 857 Boe/d and 832 Boe/d, respectively.  During the three months ended June 30, 2009, the Big Escambia Creek (BEC) plant experienced reduced oil, residue gas and NGL sales due to unanticipated repairs and overhauls to the plant’s residue gas compressors.  Sales of residue gas and NGLs from BEC, Flomaton and Fanny Church fields were suspended for 16 days in June 2009 associated
with the compressors’ downtime.  The reduced production during this period negatively impacted Upstream revenues by approximately $1.5 million.
  During the three and six months ended June 30, 2009, the cost to dispose of sulfur exceeded the sales price by $0.7 million and $1.2 million, respectively, compared to revenue of $7.1 million and $12.5 million, respectively, during the three and six months ended June 30, 2008.  Historically, sulfur was viewed as a low value by-product
in the production of oil and natural gas.  Due to an increase in demand in the global fertilizer market during the first nine months of 2008, the price per long ton (before effects of net-backs) peaked at over $600 at the Tampa, Florida market in September, 2008.  Deterioration in the sulfur market during the six months ended June 30, 2009 has caused the price at the Tampa, Florida market to decline to $5 per long ton, and we are incurring costs to dispose of our sulfur at this time.   We
expect this to be an ongoing issue until the sulfur market returns to normal demand/supply equilibrium.
  Operating Expenses. Operating expenses, including severance and ad valorem taxes, totaled $6.6 million and $13.1 million, respectively, for the Upstream Segment during the three and six months ended June 30,
2009, as compared to $9.4 million and $17.0 million, respectively, for the three and six months ended June 30, 2008.  The operating expenses include six months of expenses related to the assets acquired in the Stanolind Acquisition during 2009 compared to only two months for the same period in 2008.  The decrease in operating expense can be attributed to lower well workover expense incurred during the three and six months ended June 30, 2009 as compared to the same period in the prior year
and additional expenses being incurred during the three and six months ended June 30, 2008 due to the turnaround at the BEC treating facility in April 2008.
  Depreciation, Depletion and Amortization.Depreciation, depletion and amortization expense for the three and six months ended June 30, 2009 was $8.0 million and $17.4 million, respectively, as compared to $9.9
million and $18.3 million, respectively for the three and six month periods ended June 30, 2008, respectively.  The decrease for the six months ended June 30, 2009 compared to the comparable period in 2008 is due to the decrease in our depletable base as a result of the impairment charges we incurred during the last three months of fiscal year 2008.  This decrease was partially offset by the depletion expense related to the assets added through the Stanolind Acquisition for the first six months
of 2009 compared to only two months during the same period in 2008 and the curtailed production during the six months ended June 30, 2008 due to the turnaround at the BEC treating facility in April 2008.
  Impairment.During the six months ended June 30, 2009, we incurred impairment charges related to certain fields within our Upstream Segment of $0.2 million due to the continued decline of natural
gas prices during the period.  No impairment charges were incurred during the six months ended June 30, 2008.
  Other Operating Income.Other operating income for the three and six months ended June 30, 2009, includes income of $3.6 million due to the recovery of $2.2 million of assets previously written off and the release of $1.4 million of liabilities assumed as part of our purchase
price allocation for our acquisitions of Escambia Asset Co. LLC and Redman Energy Holdings, L.P.  During the period, we received additional information about collectability of these assets and determined that we no longer had any obligation under these liabilities.
  Capital Expenditures.  The Upstream Segment’s maintenance capital expenditures for the three and six months ended June 30, 2009 and 2008 was $2.0 million, $3.6 million, $10.3 million and $13.2 million, respectively.  Growth capital expenditures during the
three and six months ended June 30, 2009 totaled less than $0.1 million and $0.9 million, respectively, and were associated with the completion of drilling projects associated with properties acquired in the Stanolind Acquisition.  We did not incur any growth capital expenditures during the three and six months ended June 30, 2008.  The maintenance capital expenditures during the three and six months ended June 30, 2009 were associated with compressor overhauls at the BEC and Flomaton treating
facilities and well completions, recompletions, workovers, equipping and leasing activities.
   32
 Table of Contents
 Minerals Business (One segment)
  Three Month Ended
June 30,


Six Months Ended
June 30,2009


2008


2009


2008($ in thousands)Revenues:Oil and condensate sales

$
2,232


$
4,732


$
3,908


$
8,099Natural gas sales


840



3,565



1,705



5,774Natural gas liquids sales


69



411



198



646Lease bonus, rentals and other


358



1,547



927



2,694Total revenues


3,499



10,255



6,738



17,213Operating costs and expenses:Operations and maintenance


298



482



769



925Depletion


1,452



1,528



3,127



4,139Total operating costs and expenses


1,750



2,010



3,896



5,064Operating income (loss)

$
1,749


$
8,245


$
2,842


$
12,149Realized average prices:Oil and condensate (per Bbl)

$
55.69


$
115.68


$
47.04


$
102.86Natural gas (per Mcf)

$
2.90


$
10.50


$
2.93


$
8.81NGLs (per Bbl)

$
18.83


$
66.13


$
21.13


$
62.12Production volumes:Oil and condensate (Bbl)


40,112



40,907



83,138



78,740Natural gas (Mcf)


307,287



339,518



589,489



655,474NGLs (Bbl)


3,660



6,215



9,371



10,400Total (Mcfe)


569,919



622,250



1,144,541



1,129,400
  Revenue.  For the three and six months ended June 30, 2009 our revenue was $3.5 million and $6.7 million, respectively, as compared to $10.3 million and $17.2 million for three and six months ended June 30, 2008, respectively.  The decrease in revenue was due
to decreases in commodity prices and lower production volumes in the three and six months ended June 30, 2009 as compared to the three and six months ended June 30, 2008.
  One of the distinctive characteristics of our large, diversified mineral position is that operators are continually conducting exploration and development drilling, recompletion, and workover operations on our interests; in our minerals segment, we refer to this
phenomenon as “regeneration.” We do not pay for these operations, but we do receive a share of the production they generate. This mode of operation has resulted in relatively constant production rates from our mineral interests in the past, and while we expect that regeneration will continue, we are uncertain if it will continue at rates sufficient to maintain or grow the segment’s production rate so long as commodity prices remain at their current levels. We have observed rapid and significant
reductions in the active drilling rig count in virtually every producing basin of the United States, except for the Haynesville (North Louisiana and East Texas) and Marcellus (Appalachian region) shale plays. The new sources of production that we expect will materialize due to regeneration will also be the source of future extensions and discoveries and positive revisions to our reserve estimates, which may effect out future depletion rates.  During the three and six months ended June 30, 2009, as a
result of regeneration we received an initial royalty payment for 62 and 135 new wells, respectively.
  Additionally, we received approximately $0.4 million and $0.9 million in bonus and delay rental payments during the three and six months ended June 30, 2009, respectively, and $1.5 million and $2.7 million in the three and six months ended June 30, 2008, respectively.
Substantially all of this was derived from our ownership in the minerals. The amount of revenue we receive from bonus and rental payments varies significantly from month to month; therefore, we do not believe a meaningful set of conclusions can be drawn by observing changes in leasing activity over small time periods. Commodity prices may affect the amount of leasing that will occur on the minerals in future periods, and it is impossible to predict the timing or amount of future bonus payments.  However,
we do expect to receive some level of bonus payments in the future.
  Operating Expenses. Operating expenses of $0.3 million and $0.8 million for the three and six months ended June 30, 2009, respectively as compared to $0.5 million and $0.9 million for the three and six months ended June 30, 2008, respectively, are predominately production and ad
valorem taxes. These taxes are levied by various state and local taxing entities.
  Depletion.  Our depletion during the three and six months ended June 30, 2009 was $1.5 million and $3.1 million, respectively, as compared to $1.5 million and $4.1 million for the three and six months
ended June 30, 2008, respectively.  The decrease in depletion expense for the six months ended June 30, 2009, as compared to the same period in the prior year, is due to lower production and an incorrect rate being used to calculate depletion causing an overstatement of depletion during the first three months in 2008.  An adjustment of $0.7 million was recorded during the three months ended June 30, 2008 to correct this overstatement.
   33
 Table of Contents
 Corporate Segment
  Three Month Ended
June 30,


Six Months Ended
June 30,2009


2008


2009


2008($ in thousands)Revenues:Unrealized commodity derivative losses

$
(97,044
)

$
(256,265
)

$
(101,566
)

$
(289,337
)Realized commodity derivative gains (losses)


22,483



(27,708
)


53,261



(40,283
)Total revenue


(74,561
)


(283,973
)


(48,305
)


(329,620
)Costs and expenses:General and administrative


11,895



10,026



24,433



21,268Other operating expenses


—



6,214



—



6,214Depreciation, depletion, and amortization


218



199



431



391Total costs and expenses


12,113



16,439



24,864



27,873Operating loss


(86,674
)


(300,412
)


(73,169
)


(357,493
)Other income (expense):Interest income


141



160



173



461Other income


550



886



1,110



2,433Interest expense, net


(5,428
)


(6,974
)


(12,967
)


(16,078
)Realized interest rate derivative losses


(5,147
)


(2,444
)


(8,629
)


(2,545
)Unrealized interest rate derivative gains


11,954



13,689



15,053



29Other expense


(267
)


(232
)


(534
)


(447
)Total other income (expense)


1,803



5,085



(5,794
)


(16,147
)Loss before taxes


(84,871
)


(295,327
)


(78,963
)


(373,640
)Income tax benefit


(1,477
)


(886
)


(4,207
)


(988
)Segment loss

$
(83,394
)

$
(294,441
)

$
(74,756
)

$
(372,652
)
  Revenues. The volatility inherent in commodity prices generates uncertainty around our cash flows. We attempt to counter this volatility by entering into certain derivative transactions to reduce our exposure to commodity price risk.
  Our Corporate Segment’s revenues, which consist solely of our commodity derivatives activity, decreased to a loss of $74.6 million and $48.3 million, respectively, for the three and six months ended June 30, 2009, from a loss of $284.0 million and $329.6 million, respectively, for the three and six months ended June 30, 2008.  As
a result of our commodity hedging activities, revenues include realized gains of $22.5 million and $53.3 million on risk management activity that was settled during the three and six months ended June 30, 2009, respectively, and unrealized mark-to-market losses of $97.0 million and $101.6 million for three and six months ended June 30, 2009, respectively, as compared to realized losses of $27.7 million and $40.3 million on risk management activity that was settled during the three and six months
ended June 30, 2008, respectively, and unrealized mark-to-market net losses of $256.3 million and $289.3 million for the three and six months ended June 30, 2008, respectively.  Included with our unrealized commodity derivative gains (losses) is the amortization of put premiums and other derivative costs of $11.1 million, $23.3 million, $2.3 million and $4.6 million during the three and six months ended June 30, 2009 and 2008, respectively.
  As the forward price curves for our hedged commodities shift in relation to the various strike prices of our commodity derivatives, the fair value of those instruments changes.  The unrealized, non-cash, mark-to-market results during the three and six months ended June 30, 2009 reflects forward curve price movements from the
beginning to the end of the three-month and six-month period for commodities underlying the derivative instruments.  The unrealized mark-to-market results for the three and six months ended June 30, 2009 and 2008 had no impact on cash activities for those periods and are excluded from our calculation of Adjusted EBITDA.
  Given the uncertainty surrounding future commodity prices, and the general inability to predict these as they relate to the caps, floors, swaps and strike prices at which we have hedged our exposure, it is difficult to predict the magnitude and impact that marking our hedges to market will have on our income from operations in future periods.
  General and Administrative Expenses. General and administrative expenses increased by $1.9 million and $3.1 million to $11.9 million and $24.4 million for the three and six months ended June 30, 2009, respectively, as compared to $10.0 million and $21.3 million for the three and
six months ended June 30, 2009, respectively. This growth in general and administrative expenses was primarily driven by increased headcount in our corporate office as a result of our 2008 acquisitions but was also impacted by our recruiting efforts in accounting, back-office, engineering, land and operations-related corporate personnel associated with being a public partnership.  Corporate-office payroll expenses increased by $1.2 million and $4.5 million for the three and six months ended June 30,
2009, respectively, as a result of the increased headcount.  Included within the increased corporate-office payroll expenses was an increase of $0.3 million and $1.4 million for the three and six months ended June 30, 2009, respectively, related to equity-based compensation, of which the six months ended June 30, 2009 includes $0.4 million related to the allocation of expense from Eagle Rock Holdings, L.P. due to its issuance of Tier I units to one of our executives.  Also included in the
six months ended June 30, 2009 was a one time charge of $0.1 million for severance payments due to a reduction in workforce.  As a result of the increase in our expenses for corporate-office headcount, contract labor and other outside professional services decreased by $0.4 million and $1.7 million during the three and six months ended June 30, 2009, respectively, as compared to the same periods in 2008.
  At the present time, we do not allocate our general and administrative expenses cost to our operational segments. The Corporate Segment bears the entire amount.
  Other Operating Expense.In July 2008, SemGroup, L.P. and certain of its subsidiaries (“SemGroup”) filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code.  We historically sold to SemGroup portions of our condensate production from our
Texas Panhandle and East Texas midstream systems.  As a result of the bankruptcy, we took a $6.2 million bad debt charge during the three and six months ended June 30, 2008, which is included in “Other Operating Expense” in the unaudited condensed consolidated statement of operations.
 
 Amounts included within other operating (income) expense are excluded from our calculation of Adjusted EBITDA.
 
 Total Other Income (Expense). Total other income (expense) includes both realized and unrealized gains and losses from our interest rate swaps. We generated income of $1.8 million and expense of $5.8 million for the three and six months ended June 30, 2009, respectively, as compared
to income of $5.1 million for the three months ended June 30, 2008 and expense of $16.1 million for the six months ended June 30, 2008.  During the three and six months ended June 30, 2009, we incurred realized losses from our interest rate swaps of $5.1 million and $8.6 million, respectively, as compared to realized losses of $2.4 million and $2.5 million during the three and six months ended June 30, 2008, respectively. We also incurred unrealized mark-to-market gains of $12.0 million and $15.1 million
during the three and six months ended June 30, 2009, respectively, as compared to unrealized mark-to-market gains of $13.7 million and less than $0.1 million during the three and six months ended June 30, 2009, respectively.  These unrealized mark-to-market gains did not have any impact on cash activities for the period, and are excluded by definition from our calculation of Adjusted EBITDA.
 
 Interest expense, net, decreased to $5.4 million and $13.0 million for the three and six months ended June 30, 2009, respectively, as compared to $7.0 million and $16.1 million during the three and six months ended June 30, 2008, respectively.  Interest expense,
net is shown before the impact of our interest rate derivatives, which convert a portion of our outstanding debt from variable-rate interest obligations to fixed-rate interest obligations.  All of our outstanding debt consists of borrowings under our revolving credit facility, which bears interest primarily based on a LIBOR rate plus the applicable margin.  The decrease in interest expense, net is due to lower LIBOR rates during the three months ended June 30, 2009 as compared to the three months ended
June 30, 2008, partially offset by higher debt balances in the 2009 period as a result of our acquisition made in 2008.
 
 Income Tax Benefit. Income tax benefit recorded during the three months ended June 30, 2009 reflects the Texas Margin Tax recorded during the current year offset by the reduction of the deferred tax liability created by the book/tax differences as a result of the acquisition of Redman
Energy Corporation in 2007 and Stanolind Oil and Gas Corp. in 2008.
  34
 Table of Contents
 
 Adjusted EBITDA
  Adjusted EBITDA, as defined under “Non-GAAP Financial Measures,” decreased by $12.3 million and $23.7 million from $57.0 million and $109.4 million for the three and six months ended June 30, 2008, respectively, to $44.7 million and $85.8 million for the three and six months ended June 30, 2009, respectively.
  As described above, for the three and six months ended June 30, 2009, revenues minus cost of natural gas and natural gas liquids for the Midstream Segment (including the Texas Panhandle, East Texas/Louisiana, South Texas and the Gulf of Mexico Segment) declined by $24.3 million
and $46.5 million as compared to the three and six months ended June 30, 2008. For the three and six months ended June 30, 2009, revenues for our Upstream and Mineral Segments declined by $37.7 million and $68.8 million, respectively, as compared to the same period in the prior year.  Our Corporate Segment’s realized commodity derivatives gain increased by $50.2 million and $93.5 million as compared to the three and six months ended June 30, 2008, respectively. This resulted in a decline of $11.8
million and $21.7 million of total incremental revenues minus cost of natural gas and natural gas liquids, adjusted to exclude the impact of unrealized commodity derivatives not included in the calculation of Adjusted EBITDA, as compared to the three and six months ended June 30, 2008.
  Operating expenses (including taxes other than income), increased by $1.2 million and $3.5 million for our Midstream Segment with respect to the three and six months ended June 30, 2009, respectively, primarily due to the addition of the Millennium Midstream acquisition properties, while operating expenses for our Upstream and Minerals
Segments decreased by $2.3 million and $3.3 million, as compared to the three and six months ended June 30, 2008, respectively.
  General and administrative expense, captured in the Corporate Segment, increased by $1.5 million and $1.8 million adjusted to exclude non-cash compensation charges related to our LTIP program and other operating expenses.
  As a result, revenues (excluding the impact of unrealized commodity derivative activity and non-cash mark-to-market of Upstream product imbalances) minus cost of natural gas and natural gas liquids decreased by $11.8 million and $21.7 million, operating expenses decreased by $1.1 million and increased by $0.2 million and general and administrative
expenses decreased by $1.5 million and $1.8 million, resulting in the decrease to Adjusted EBITDA during the three and six months ended June 30, 2009, as compared to the three and six months ended June 30, 2008.
  For a discussion of Adjusted EBITDA and reconciliation to GAAP, see “Non-GAAP Financial Measures” at the end of this item.
  Liquidity and Capital Resources
  Historically, our sources of liquidity have included cash generated from operations, equity investments by our existing owners, equity investments by other institutional investors and borrowings under our existing revolving credit facility.
  We believe that the cash generated from these sources will continue to be sufficient to meet our expected quarterly cash distributions (which we have reduced in the first two quarters of 2009 to below the minimum quarterly distribution amount described in our partnership agreement) and our requirements for short-term working capital and
long-term capital expenditures.  The actual distributions we will declare will be subject to our operating performance, prevailing market conditions (including forward oil, natural gas and sulfur commodity prices), the impact of unforeseen events and the approval of the Board of Directors of our general partner’s general partner (“general partner”) and will be done pursuant to our distribution policy.
  Our distribution policy is to distribute to our unitholders, on a quarterly basis, all of our available cash in the manner described below and as further described in our partnership agreement. Available cash generally means, for any quarter ending prior to liquidation, all cash on hand at the end of that quarter less the amount of cash
reserves that the general partner determines to establish to:
  •
provide for the proper conduct of our business, including for future capital expenditures and credit needs;
  •
comply with applicable law or any partnership debt instrument or other agreement; or
  •
provide funds for distributions to unitholders and the general partner in respect of any one or more of the next four quarters.
  In connection with making the distribution decision for the first and second quarters of 2009, the Board of Directors determined to reduce the quarterly distribution in each quarter to $0.025 per common unit, as compared to $0.41 per common and subordinated unit paid for the fourth quarter of 2008, to establish cash reserves (as against
available cash) for the proper conduct of our business and to enhance our ability to remain in compliance with financial covenants under our revolving credit facility in future periods.  The cash not distributed has been used to reduce our outstanding debt under our revolving credit facility.  Future cash not distributed will be used to reduce our outstanding debt, to continue the execution of our hedge strategy to maintain future cash flows and/or to fund growth capital expenditures.  We
anticipate that the Board of Directors will continue this strategy until such time as commodity prices impacting our business and the general economy return to levels conducive to increasing the cash distributions to be paid to our unitholders.
  Under the terms of the agreements governing our revolving credit facility, we are prohibited from declaring or paying any distribution to unitholders if a default or event of default (as defined in such agreements) exists.Our goal is to reduce outstanding indebtedness under our
revolving credit facility in order to return to a ratio of outstanding debt to Adjusted EBITDA, or “leverage ratio,” with respect to our Midstream and Minerals Businesses of approximately 3.0 to 3.5, which we believe to be appropriate in light of these more turbulent economic conditions and more in-line with historical midstream industry standards.  Absent any other adjustments or changes to our business or our expectations, to meet this goal we anticipate that we may be required to reduce
debt by as much as $200 million.  During the three months ended, June 30, 2009, we reduced our outstanding debt under the revolving credit facility by $33.0 million from $837.4 million to $804.4 million in keeping with our goal of reducing outstanding debt by $75 million to $100 million by the second quarter of 2010.  Based primarily on our current expectations of continued depressed commodity prices and decreased drilling activity, we do not expect to be able to maintain the same level of
debt reduction achieved during the second quarter of 2009 for the remaining quarters of 2009 or for 2010.  We intend to reduce outstanding debt by an additional $45 million to $65 million by the second quarter of 2010.  The actual amount and timing of further debt repayment will depend on a number of factors, including but not limited to, changes in commodity prices, our producer customers’ drilling plans, availability of external capital, and the potential consummation of asset acquisitions
or divestitures, as well as future determinations of the borrowing base under our revolving credit facility.  For a detailed description of our revolving credit facility, see the description under Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Debt Covenants included in our annual report on Form 10-K for the year ended December 31, 2008 and below under “Revolving Credit Facility and Debt Covenants.”
  In the event that we acquire additional midstream assets or natural gas or oil properties that exceed our existing capital resources, we expect that we will finance those acquisitions with a combination of expanded or new debt facilities or cash reserves established by our general partner and, if necessary, new equity issuances.  The
continued credit crisis and related turmoil in the global financial system has caused restricted access to the capital markets, particularly for non-investment grade companies like us.  If these conditions continue, we expect our level of acquisition activity to be lower going forward than that which we experienced in 2008 and 2007.
  Working Capital.Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our liabilities as they become due. As of June 30, 2009, working capital was $18.9 million as compared to $57.3 million as of December 31,
2008.
  The net decrease in working capital of $38.4 million from December 31, 2008 to June 30, 2009, resulted primarily from the following factors:
  •
cash balances and marketable securities, net of due to affiliates, decreased overall by $22.5 million and was impacted primarily by the distributions paid on February 15, 2009 with respect to the fourth quarter of 2008 financial results, the results of operations, timing of capital expenditures payments, and financing activities including our debt activities (the due to affiliate liability of $11.1 million as
of June 30, 2009 is owed to Eagle Rock Energy G&P, LLC);
  •
trade accounts receivable decreased by $35.1 million primarily from the impact of lower commodity prices on our consolidated revenue;
  •
risk management net working capital balance decreased by a net $72.6 million as a result of the changes in current portion of the mark-to-market unrealized positions, increased other derivative costs, which includes the unwinding of long-term positions to purchase current positions (see Hedging Strategy), and amortization of the put premiums and other derivative costs;
  •
accounts payable decreased by $48.9 million from December 31, 2008 primarily as a result of activities and timing of payments, including capital expenditures activities and lower commodity prices; and
  •
accrued liabilities decreased by $6.4 million primarily reflecting payment of employee benefit accruals and the timing of payment of unbilled expenditures related primarily to capital expenditures.
  35
 Table of Contents
 
 Cash Flows for the Six Months Ended June 30, 2009 Compared to the Six Months Ended June 30, 2008
  Cash Flow from Operating Activities. Decrease of $90.4 million during the six months ended June 30, 2009 as compared to the six months ended June 30, 2008 is the result of lower commodity prices across our three businesses and reduced NGL equity volumes in the Midstream
Business, changes in working capital, as discussed above, and payments made for the resetting of commodity hedges.
  Cash Flows from Investing Activities. Cash flows used for investing activities for the six months ended June 30, 2009, as compared to the six months ended June 30, 2008, decreased by $88.4 million due to acquisitions completed in 2008. The investing activities for the current
period reflect additions to property, plant and equipment expenditures of $25.5 million versus $33.1 million for the prior year period.
 
 Cash Flows from Financing Activities. Cash flows used for financing activities during the six months ended June 30, 2009, increased by $9.9 million over the six months ended June 30, 2008. Key differences between periods include net proceeds from our revolving credit facility
of $5.0 million during the six months ended June 30, 2009, as compared to net proceeds of $56.0 million from our revolving credit facility during the six months ended June 30, 2008.  Distributions to members represented a cash outflow of $32.9 million during the six months ended June 30, 2009, as compared to $57.6 million during the six months ended June 30, 2008.
 
 Hedging Strategy
 
 We use a variety of hedging instruments to accomplish our risk management objectives.  At times our hedging strategy may involve entering into hedges with strike prices above current futures prices or resetting existing hedges to higher price levels in order
to meet our cash flow requirements, stay in compliance with our credit facility covenants and continue to execute on our distribution objectives.  Hedge transactions such as these impact our liquidity in that we are required to pay the present value of the difference between the hedged price and the current futures price.  These transactions also increase our exposure to the counterparties through which we execute the hedges.  During the six months ended June 30, 2009, as part of this strategy,
we executed a series of hedging transactions that involved the unwinding of a portion of existing “in-the-money” 2011 and 2012 WTI crude oil swaps and collars, and the unwinding of two “in-the-money” 2009 WTI crude oil collars.  With these transactions, and an additional $13.9 million of cash, we purchased a 2009 WTI crude oil swap on 60,000 barrels per month beginning January 1, 2009 at $97 per barrel.
  Revolving Credit Facility and Debt Covenants
 
 On December 13, 2007, we entered into a credit agreement with Wachovia Bank, National Association, as administrative agent and swing line lender, Bank of America, N.A., as syndication agent; HSH Nordbank AG, New York Branch; the Royal Bank of Scotland, plc;
and BNP Paribas, as co-documentation agents, and the other lenders who are parties to the agreement with aggregate commitments of up to $800 million.  During the year ended December 31, 2008, we exercised $180 million of our $200 million accordion feature under the credit facility, which increased the total commitment to $980 million.  Pursuant to the credit facility, we may, at our request and subject to the terms and conditions of the credit facility, increase our commitments by an
additional $20 million to an aggregate of $1 billion.  As a result of Lehman Brothers’ bankruptcy filing, the amount of available commitments was reduced by the unfunded portion of Lehman Brothers’ commitment in an amount of approximately $9.1 million.   As of June 30, 2009, unused capacity available to us under the new credit agreement, based on outstanding debt and compliance with financial covenants as of that date, was approximately $88.0 million.  The credit
agreement is scheduled to mature on December 13, 2012.
 
 Given the current state of the banking industry worldwide, we are pleased with the degree of diversification within our lender group. After the upsizing of our credit facility as described above, our credit facility now includes the participation of 20 financial
institutions. As of today, all of our banks’ commitments, with the exception of Lehman Brothers’ commitment and potentially Guaranty Bank (see discussion below), remain in place and have funded in response to our borrowing notices.  A Lehman Brothers subsidiary has an approximately 2.6% participation in the Partnership’s credit facility.
 
 In a Form 8-K filing on July 23, 2009, Guaranty Financial Group Inc. stated that it is probable that it will not be able to continue as a going concern.  Guaranty Bank, a wholly owned subsidiary of Guaranty Financial Group Inc., has a commitment under our revolving credit facility of $30 million, of which approximately $25 million
has been funded.  If Guaranty Bank ceases to be a going concern, we would likely lose access to the approximate $5 million unfunded portion of Guaranty Bank’s commitment.  This unfunded commitment may increase to the extent we reduce our borrowings under the revolving credit facility, as repayments by the Partnership under the revolving credit facility would be applied proportionately among funding lenders against their respective outstanding borrowings.  As of this filing,
we have not received formal notice from Guaranty Bank or any other party as to the status of its unfunded commitment.
 
 Our credit facility accommodates, through the use of a borrowing base for our Upstream Business and traditional cash-flow based covenants for our Midstream and Minerals Businesses, the allocation of indebtedness to either our Upstream Business (to be measured against
the borrowing base) or to our Midstream and Minerals Businesses (to be measured against the cash-flow based covenant).  At June 30, 2009, we were in compliance with our covenants under the credit facility. Our interest coverage ratio, as defined in the credit agreement (i.e., Consolidated EBITDA divided by Consolidated Interest Expense), was 5.5 as compared to a minimum interest coverage covenant of 2.5, and our leverage ratio, as defined in the credit agreement (i.e., Total Funded Indebtedness divided
by Adjusted Consolidated EBITDA), was 4.4 as compared to a maximum leverage ratio of 5.0.  Primarily as a result of lower expected future commodity prices, our borrowing base was re-determined in April 2009 to $135 million (which resulted in a higher allocation of indebtedness to our Midstream and Minerals Businesses).  The reduction in borrowing base was a contributing factor to the decrease in our quarterly distribution (as discussed above).  It also contributed to our taking steps
to reduce our leverage.  At this time, we believe that we will remain in covenant compliance for the remainder of 2009.
  Capital Requirements
  We anticipate that we will have sufficient liquidity and access to capital to continue to maintain and commercially exploit our Midstream Business (all four segments), Upstream Segment, and Mineral Segment assets consistent with our current operations.  Additionally, as an operator of midstream and upstream assets, our capital
requirements have increased to maintain those assets, hold production and throughput constant and to replace reserves. We anticipate that we will meet these requirements through cash generated from operations.  We believe, however, that substantial growth would require access to external capital sources.   At this time, we cannot provide assurances that we will be able to obtain the necessary capital under terms acceptable to us.
  Our 2009 capital budget anticipates that we will spend approximately $40.0 million in total for the year on our existing assets.  Our 2009 capital budget anticipated that we would spend approximately $21.2 million in the six months ended June 30, 2009 on our existing assets. We actually spent approximately $22.8 million in total
during that period as a result of accelerating high return-on-investment projects.
  The energy business can be capital intensive, requiring significant investment for the acquisition or development of new facilities. We categorize our capital expenditures as either:
  •
growth capital expenditures, which are made to acquire additional assets to increase our business, to expand and upgrade existing systems and facilities or to construct or acquire similar systems or facilities in our Midstream Business (and our Upstream Business with respect to the Big Escambia Plant and other Alabama plants and facilities), or grow our production in our Upstream Business; or
  •
maintenance capital expenditures, which are 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 in our Midstream Business (and in our Upstream Business with respect to the Big Escambia Plant and other Alabama plants
and facilities); in our Upstream Business, maintenance capital also includes capital which is expended to maintain our production and cash flow levels in the near future.
  Since our inception in 2002, we have made substantial growth capital expenditures. We anticipate that when economic conditions allow us, we will continue to make growth capital expenditures and acquisitions; however we anticipate that our expenditures and acquisitions in 2009 and 2010 will not return to the levels maintained by us prior
to 2009. We continually review opportunities for both organic growth projects and acquisitions which will enhance our financial performance.  De-levering our business by reducing our debt and enhancing our liquidity and access to new capital such that we once again have the ability to develop and maintain sources of funds to meet our capital requirements are critical to our ability to meet our growth objectives over the long-term.
 
 We historically have financed our maintenance capital expenditures (including well-connect costs) with internally generated cash flow and our growth capital expenditures ultimately with draws from our credit facility (although such expenditures were often funded out of internally generated cash flow as an interim step).  We anticipate
funding our limited growth capital expenditures, for the foreseeable future, out of cash flow generated from operations, and, to the extent necessary, with draws from our credit facility.
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 Off-Balance Sheet Obligations
  We have no off-balance sheet transactions or obligations.
  Recent Accounting Pronouncements
  In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (“SFAS No. 141R”), which replaces SFAS 141. SFAS 141R requires that all assets, liabilities, contingent consideration, contingencies and in-process research and development costs
of an acquired business be recorded at fair value at the acquisition date; that acquisition costs generally be expensed as incurred; that restructuring costs generally be expensed in periods subsequent to the acquisition date; and that changes in accounting for deferred tax asset valuation allowances and acquired income tax uncertainties after the measurement period impact income tax expense.  SFAS No. 141R is effective for business combinations for which the acquisition date is on or after the beginning
of the first annual reporting period beginning on or after December 15, 2008, with the exception for the accounting for valuation allowances on deferred tax assets and acquired tax contingencies associated with acquisitions.  SFAS No. 141R amends SFAS No. 109, Accounting for Income Taxes,such that adjustments made to valuation allowances on deferred taxes and acquired tax contingencies associated with acquisitions that closed prior to the effective
date of SFAS No. 141R would also apply the provisions of SFAS No. 141R.  SFAS No. 141R was effective for us as of January 1, 2009 but the impact of the adoption on our consolidated financial statements will depend on the nature and the extent of business combinations occurring after January 1, 2009.
  In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements—an amendment of APB No. 51 (“SFAS No. 160”). SFAS No.160 requires that accounting and reporting for minority interests will be recharacterized
as noncontrolling interests and classified as a component of equity. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. This Statement is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008.  SFAS No. 160 was effective for us as of January 1, 2009 and did not have a material impact on our consolidated
results of operations or financial position.
  In February 2008, the FASB issued FASB Staff Position (“FSP”) No. FAS 157-2, “Effective Date of FASB Statement No. 157” (“FSP FAS 157-2”), which delays the effective date of SFAS 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value
in the financial statements on at least an annual basis, until fiscal years beginning after November 15, 2008.  Non-financial assets and liabilities that the Partnership measures at fair value on a non-recurring basis consists primarily of property, plant and equipment, intangible assets and asset retirement obligations, which are subject to fair value adjustments in certain circumstances (for example, when there is evidence of impairment).
  In March 2008, the FASB issued SFAS No. 161, Disclosures About Derivative Instruments and Hedging Activities(“SFAS No. 161”). SFAS No. 161 requires enhanced disclosures to help investors better understand the effect of an entity’s derivative instruments
and related hedging activities on its financial position, financial performance, and cash flows. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged.  SFAS No. 161 was effective for us as of January 1, 2009.  See Note 11 for the additional disclosures required under FAS No. 161 related to our derivative instruments.
  In March 2008 the FASB approved EITF Issue No. 07-4, Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships (“EITF 07-4”), which requires that master limited partnerships use the two-class method
of allocating earnings to calculate earnings per unit. EITF Issue No. 07-4 is effective for fiscal years and interim periods beginning after December 15, 2008.  EITF Issue No. 07-4 was effective for us as of January 1, 2009 and the impact on our earnings per unit calculation has been retrospectively applied to June 30, 2008 (see Note to our unaudited condensed consolidated financial statements).
 
 In April 2008, the FASB issued FASB Staff Position (“FSP”) No. SFAS 142-3, Determination of the Useful Life of Intangible Assets (“FSP SFAS 142-3”).  FSP SFAS 142-3 amends the factors
that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, Goodwill and Other Intangible Assets (“SFAS 142”).  The intent of FSP SFAS 142-3 is to improve the consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No.
141R and other applicable accounting literature.  FSP SFAS 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and must be applied prospectively to intangible assets acquired after the effective date.  FSP SFAS No. 142-3 was effective for us as of January 1, 2009 but the impact of the adoption on our consolidated financial statements will depend on the nature and the extent of business combinations occurring after January 1, 2009.
 
 In June 2008, the FASB issued FSP No. EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (“FSP EITF 03-6-1”).  FSP EITF
03-6-1 affects entities that accrue cash dividends on share-based payment awards during the awards’ service period when dividends do not need to be returned if the employees forfeit the awards.  FSP EITF 03-6-1 is effective for fiscal years beginning after December 15, 2008 and earnings-per-unit calculations would need to be adjusted retroactively.  FSP EITF 03-6-1 was effective for us as of January 1, 2009 and the impact on its earnings per unit calculation has been retrospectively
applied to June 30, 2008 (see Note 16 to our unaudited condensed consolidated financial statements).
 
 In December 2008, the SEC released Final Rule, Modernization of Oil and Gas Reporting to revise the existing Regulation S-K and Regulation S-X reporting requirements to align with current industry practices and technological advances. The new disclosure requirements
include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. In addition, the new disclosure requirements require a company to (a) disclose its internal control over reserves estimation and report the independence and qualification of its reserves preparer or auditor, (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserve audit
and (c) report oil and gas reserves using an average price based upon the prior 12-month period rather than period-end prices. The provisions of this final ruling will become effective for disclosures in our Annual Report on Form 10-K for the year ending December 31, 2009.  The adoption of the Final Rule, Modernization of Oil and Gas Reporting revision to Regulation S-K and Regulation S-X is not expected to have a material impact on the Partnership’s consolidated financial statements.
 
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 Table of Contents
 
 In April 2009, the FASB issued FSP FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairments “FSP FAS 115-2 and FAS 124-2”).  FSP FAS 115-2 and FAS 124-2 amends the other-than-temporary impairment guidance
for debt securities to make the guidance more operational and to improve the presentation and disclosure of other-than-temporary impairments in the financial statements. The most significant change is a revision to the amount of other-than-temporary loss of a debt security recorded in earnings. FSP FAS 115-2 and FAS 124-2 were effective for us as of June 30, 2009 and did not have a material impact on our consolidated financial statements.
 
 In April 2009, the FASB issued FSP FAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly(“FSP FAS 157-4”).  FSP
FAS 157-4 provides additional guidance for estimating fair value in accordance with FASB Statement No. 157, Fair Value Measurements, when the volume and level of activity for the asset or liability have significantly decreased.  FSP FAS 157-4 also includes guidance on identifying circumstances that indicate a transaction is not orderly and emphasizes that even if there has been a significant decrease in the volume and level of activity for the
asset or liability and regardless of the valuation technique(s) used, the objective of a fair value measurement remains the same. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction (that is, not a forced liquidation or distressed sale) between market participants at the measurement date under current market conditions.  FSP FAS 157-4 was effective for us as of June 30, 2009 and did not have a material impact on our consolidated financial
statements.
 
 In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments(“FSP FAS 107-1 and APB 28-1”). FSP FAS 107-1 and APB 28-1 amends FASB
Statement No. 107, Disclosures about Fair Value of Financial Instruments, to require disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements.  FSP FAS 107-1 and APB 28-1 also amends APB Opinion No. 28, Interim Financial Reporting, to require those disclosures in summarized financial information
at interim reporting periods. FSP FAS 107-1 and APB 28-1 were effective for us as of June 30, 2009.  See Notes to our unaudited condensed consolidated financial statements for further discussion.
 
 In April 2009, the FASB issued FSP FAS 141(R)-1, Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies(“FSP FAS 141(R)-1”), which amended and clarified SFAS 141R with respect to contingencies.  FSP FAS 141(R)-1
provides that an acquirer shall recognize at fair value, at the acquisition date, an asset acquired or a liability assumed in a business combination that arises from a contingency if the acquisition-date fair value of that asset or liability can be determined during the measurement period.  If the acquisition-date fair value of an asset acquired or a liability assumed in a business combination that arises from a contingency cannot be determined using the measurement period, the guidance in SFAS 5 and in
FASB Interpretation No. 14, Reasonable Estimation of the Amount of a Loss, shall apply.”  FSP FAS 141(R)-1 was effective for us as of January 1, 2009 but the impact of the adoption on our consolidated financial statements will depend on the nature and the extent of business combinations occurring after January 1, 2009.
 
 On May 28, 2009, the FASB issued SFAS No. 165, Subsequent Events(“SFAS No. 165”), which provides guidance on the Partnership’s assessment of subsequent events. Historically, the Partnership has relied on U.S. auditing literature for guidance
on assessing and disclosing subsequent events.  SFAS No. 165 clarifies that the Partnership must evaluate, as of each reporting period, events or transactions that occur after the balance sheet date “through the date that the financial statements are issued or are available to be issued.” The Partnership must perform its assessment for both interim and annual financial reporting periods prospectively.  SFAS No. 165 was effective for us as of June 30, 2009 but the impact of the
adoption will depend on the nature and the extent of transactions that occur subsequent to our interim and annual reporting periods.
 
 On June 12, 2009, the FASB issued SFAS No. 166, Transfers of Financial Assets(SFAS No. 166), which amends the derecognition guidance in Statement 140.  SFAS No. 166 reflects the FASB’s response to issues entities have encountered when applying
Statement 140.  In addition, SFAS 166 addresses concerns expressed by the SEC, members of the United States Congress, and financial statement users about the accounting and disclosures required by Statement 140 in the wake of the subprime mortgage crisis and the deterioration in the global credit markets.  In addition, because SFAS No. 166 eliminates the exemption from consolidation for qualified special-purpose entities (“QSPEs”) a transferor will need to evaluate all existing
QSPEs to determine whether they must be consolidated.   SFAS No. 166 is effective for financial asset transfers occurring after the beginning of an entity’s first fiscal year that begins after November 15, 2009.  Early adoption of SFAS No. 166 is prohibited.   We are currently evaluating the potential impact, if any, of the adoption of SFAS No. 166 on our financial statements.
 
 On June 12, 2009, the FASB issued SFAS No. 167, Amendments to FASB Interpretation 46(R),(“SFAS No. 167”), which amends the consolidation guidance applicable to variable interest entities (VIEs). The amendments will significantly affect the overall
consolidation analysis under FASB Interpretation 46(R) (“FIN 46(R)”).  While the FASB’s discussions leading up to the issuance of SFAS No. 167 focused extensively on structured finance entities, the amendments to the consolidation guidance affect all entities and enterprises currently within the scope of Interpretation 46(R), as well as qualifying special-purpose entities (QSPEs) that are currently excluded from the scope of FIN 46(R).  Accordingly, an enterprise will need
to carefully reconsider its previous FIN 46(R) conclusions, including (1) whether an entity is a VIE, (2) whether the enterprise is the VIE’s primary beneficiary, and (3) what type of financial statement disclosures are required.  SFAS 167 is effective as of the beginning of the first fiscal year that begins after November 15, 2009, and early adoption is prohibited.  We are currently evaluating the potential impact, if any, of the adoption of SFAS No. 167 on our financial statements.
 
 On June 29, 2009, the FASB issued SFAS No. 168, FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Statement No. 162(“SFAS No. 168”).  The FASB has stated that
“the FASB Accounting Standards Codification (“Codification”)” will become the source of authoritative U.S. GAAP recognized by the FASB to be applied to nongovernmental entities.  Once effective, the Codification’s content will carry the same level of authority, effectively superseding SFAS No. 162.  The U.S. GAAP hierarchy will be modified to include only two levels of GAAP: authoritative and nonauthoritative.  SFAS No. 168 is effective for financial
statements issued for interim and annual periods ended after September 15, 2009.  We do not believe that the adoption of SFAS No. 168 will have a material impact on our financial statements.
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 Table of Contents
 Non-GAAP Financial Measures
  We include in this filing the following non-GAAP financial measure, Adjusted EBITDA. We provide reconciliations of this non-GAAP financial measure to its most directly comparable financial measures as calculated and presented in accordance with GAAP.
  We define 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. We use Adjusted EBITDA as a measure of our core profitability to assess the financial performance of our assets.  Adjusted EBITDA is used as a supplemental financial measure by external users of our financial statements such as investors,
commercial banks and research analysts. For example, our lenders under our revolving credit facility use a variant of our Adjusted EBITDA in a compliance covenant designed to measure the viability of us and our ability to perform under the terms of the revolving credit facility; we, therefore, use Adjusted EBITDA to measure our compliance with our revolving credit facility.  We believe that investors benefit from having access to the same financial measures that our management uses in evaluating performance.  Adjusted
EBITDA is useful in determining our 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 our executed derivative instruments and is independent of our assets’ performance or cash flow generating ability, we believe Adjusted EBITDA reflects more accurately our ability to generate cash sufficient to pay interest costs, support our level of indebtedness, make cash distributions
to our unitholders and general partner and finance our maintenance capital expenditures. We further believe that Adjusted EBITDA describes more accurately the underlying performance of our operating assets by isolating the performance of our 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 our financial statements
a more accurate picture of our current assets’ cash generation ability, independently from that of assets which are no longer a part of our operations. Our 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 us. For example, we include in Adjusted EBITDA the actual settlement revenue created from our commodity hedges by virtue of transactions undertaken by us to reset
commodity hedges to higher prices or purchase puts or other similar floors despite the fact that we exclude from Adjusted EBITDA any charge for amortization of the cost of such commodity hedge reset transactions or puts.  For a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP (accounting principles generally accepted in the United States) see the table below.
  Adjusted EBITDA should not be considered an alternative to net income (loss), operating income (loss), cash flows from operating activities or any other GAAP measure of liquidity or financial performance.
 
 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 determined under GAAP, as well as Adjusted EBITDA, to evaluate our liquidity.
  39
 Table of Contents
 Reconciliations of “Adjusted EBITDA” to net cash flows provided by operation activities and net loss
  
 Three Month Ended
June 30,


Six Months Ended
June 30,2009


2008


2009


2008Net cash flows provided by operating activities

$
36,896


$
89,499


$
32,279


$
122,644Add (deduct):Depreciation, depletion, amortization and impairment


(27,588
)


(26,457
)


(57,893
)


(52,202
)Amortization of debt issuance costs


(267
)


(219
)


(534
)


(436
)Risk management portfolio value changes


(85,090
)


(242,576
)


(72,613
)


(289,308
)Net realized (loss) gain on derivatives


2,457



(7,259
)


6,774



(9,537
)Other


3,364



(111
)


4,092



31Accounts receivables and other current assets


(10,351
)


18,719



(34,926
)


48,933Accounts payable, due to affiliates and accrued liabilities


2,731



(58,006
)


43,835



(75,697
)Other assets and liabilities


3,061



(610
)


1,654



224Net loss


(74,787
)


(227,020
)


(77,332
)


(255,348
)Add (deduct):Interest (income) expense, net


10,701



9,490



21,957



18,609Depreciation, depletion and amortization


27,588



26,457



57,893



52,202Income tax benefit


(1,477
)


(886
)


(4,207
)


(988
)EBITDA


(37,975
)


(191,959
)


(1,689
)


(185,525
)Add (deduct):Unrealized risk management losses


85,090



242,576



86,513



289,308Equity-based compensation expense


1,889



1,559



4,120



2,718Non-cash mark-to-market of Upstream imbalances


(203
)


—



1,829



—Other income


(550
)


(886
)


(1,110
)


(2,433
)Discontinued operations


(33
)


(551
)


(340
)


(839
)Other operating expenses


(3,552
)


6,214



(3,552
)


6,214ADJUSTED EBITDA

$
44,666


$
56,953


$
85,771


$
109,443
  
  40
 Table of Contents
  Item 3.                      Quantitative and Qualitative Disclosures About Market Risk.
  Risk and Accounting Policies
  We are exposed to market risks associated with adverse changes in commodity prices, interest rates and counterparty credit. We may use financial instruments such as put and call options, swaps and other derivatives to mitigate the effects of the identified risks. Adverse effects on our cash flow from changes in crude oil, natural gas,
NGL product prices or interest rates could adversely impact our ability to make distributions to our unitholders, meet debt service obligations, fund required capital expenditures and other similar requirements. Our management has established a comprehensive review of our market risks and has developed risk management policies and procedures to monitor and manage these market risks. Our general partner is responsible for the overall approval of market risk management policies, delegation of transaction authority
levels, and for the establishment of a Risk Management Committee. The Risk Management Committee is composed of officers (including, on an ex officio basis, our chief executive officer) who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee is responsible for the overall management of commodity price risk, interest rate risk and credit risk, including monitoring exposure limits.
  Commodity Price Risk
  We are exposed to the impact of market fluctuations in the prices of crude oil, natural gas, NGLs, sulfur and other commodities as a result of our gathering, processing, producing and marketing activities, which produce a naturally long position in crude oil, NGLs, sulfur and natural gas. Both our profitability and our cash flow are affected
by volatility in prevailing prices for these commodities. These prices are impacted by changes in the supply and demand for these commodities, as well as market uncertainty and other factors beyond our control. Historically, changes in the prices of NGLs, such as natural gasoline, have generally correlated with changes in the price of crude oil but those correlations may change in the future.
  We frequently use financial derivatives to reduce our exposure to commodity price risk. We have implemented a risk management policy which allows management to execute crude oil, natural gas liquids and natural gas hedging instruments, which may include swaps, collars, options and other derivatives, in order to reduce exposure to substantial
adverse changes in the prices of these commodities. These hedges are only intended to mitigate the risk associated with our natural physical position.  To date we have been unable to identify financial derivatives to reduce our exposure to sulfur price risk.
  We have not designated our derivative contracts as accounting hedges under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. As a result, we mark our derivatives to fair value with the resulting change in fair value included in our statement of operations.  For
the three months ended June 30, 2009, the Partnership recorded a loss on risk management instruments of $74.6 million representing a fair value (unrealized) loss of $85.9 million, amortization of put premiums and other derivative costs of $11.1 million and net (realized) settlement gain of $22.5 million.  For the six months ended June 30, 2009, the Partnership recorded a loss on risk management instruments of $48.3 million representing a fair value (unrealized) loss of $78.3 million, amortization of
put premiums and other derivative costs of $23.3 million and net (realized) settlement gains of $53.3 million.  As of June 30, 2009, the fair value asset of these commodity contracts, including put premiums and other derivative costs, totaled approximately $21.6 million.
  We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant.
  Interest Rate Risk
  We are exposed to variable interest rate risk as a result of borrowings under our existing credit agreement. To mitigate its interest rate risk, the Partnership has entered into various interest rate swaps. These swaps convert the variable-rate term loan into a fixed-rate obligation. The purpose of entering into this swap is to eliminate
interest rate variability by converting LIBOR-based variable-rate payments to fixed-rate payments through the end of 2010. Amounts received or paid under these swaps were recorded as reductions or increases in interest expense.
  We have not designated our contracts as accounting hedges under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. As a result, we mark our derivatives to market with the resulting
change in fair value included in our statement of operations.  For the three months ended June 30, 2009, the Partnership recorded a fair value (unrealized) gain of $12.0 million and a realized loss of $5.1 million.  For the six months ended June 30, 2009, the Partnership recorded a fair value (unrealized) gain of $15.1 million and a realized loss of $8.6 million.  As of June 30, 2009, the fair value liability of these interest rate contracts totaled approximately $24.9 million.
 
 Credit Risk
  Our principal natural gas sales customers are large gas marketing companies that, in turn, typically sell to large end users such as local distribution companies and electrical utilities. With respect to the sale of our NGLs and condensates, our principal customers
are large natural gas liquids purchasers, fractionators and marketers, and large condensate aggregators that then typically sell to large multi-national petrochemical and refining companies. We also sell a small amount of propane to medium sized, local distributors.
 
 This concentration of credit risk may affect our overall credit risk in that these customers may be similarly affected by changes in the natural gas, natural gas liquids, petrochemical and other segments of the energy industry, the economy in general, the regulatory environment and other factors.  Our credit risk monitoring is
not an absolute protection against credit loss.  Our credit risk monitoring is intended to mitigate our exposure to significant credit risk.
 
 Our derivative counterparties, both commodity and interest rate, include BNP Paribas, Wells Fargo Bank N.A., Wachovia Bank N.A, Bank of Nova Scotia, Comerica Bank, Barclays Bank PLC, The Royal Bank of Scotland plc and its agent Sempra Energy Trading LLC, Bank of America N.A., J Aron and Company (an affiliate of Goldman Sachs) BBVA Compass
Bank and Credit Suisse Energy LLC (an affiliate of Credit Suisse Group AG).
  Item 4.
Controls and Procedures.
  Evaluation of Disclosure Controls and Procedures
 
 Based on the evaluation of our disclosure controls and procedures (as defined in the Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) required by Exchange Act Rules 13a-15(b) or 15d-15(b), our principal executive officer and principal financial
officer have concluded that as of the end of the period covered by this report, our disclosure controls and procedures were effective to ensure that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated
and communicated to our management, including the principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.
 
 Changes in Internal Control Over Financial Reporting
  There were no changes in our internal control over financial reporting that occurred during the Partnership’s most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
   41
 Table of Contents
   PART II. OTHER INFORMATION
  Item 1.
Legal Proceedings.
  Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we are and may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. However, we are not currently a party to any material litigation. We maintain insurance policies
with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent. We cannot, however, assure you that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.
  We have voluntarily undertaken a self-audit of our compliance with air quality standards, including permitting in the Texas Panhandle Segment as well as a majority of our other Midstream Business locations and some of our Upstream Business locations in Texas. This auditing has been performed pursuant to the Texas Environmental, Health
and Safety Audit Privilege Act, as amended. We have completed the disclosures to the Texas Commission on Environmental Quality (“TCEQ”), and we are addressing in due course the deficiencies that we disclosed therein.  We do not foresee at this time any impediment to the timely corrective efforts identified as a result of these audits.
  Subsequent to December 31, 2008, we received additional Notices of Enforcement (“NOEs”) and a Notice of Violation (“NOV”) from the TCEQ related to air compliance matters.  We expect to receive additional NOEs or NOVs from the TCEQ from time to time throughout 2009.  Though the TCEQ has the discretion
to adjust penalties and settlements upwards based on a compliance history containing multiple, successive NOEs, we do not expect that the resolution of any existing NOE or any future similar NOE will vary significantly from the administrative penalties and agreed settlements experienced by us to date.
  
  Item 1A.                      Risk Factors.
  Set forth below is a material update to the risk factors discussed in our annual report on Form 10-K for the year ended December 31, 2008.
  Regulation of greenhouse gas emissions could adversely affect our revenues and costs of operation.
 
 On April 17, 2009, the U.S. Environmental Protection Agency (“EPA”) released a proposed finding that greenhouse gas (“GHG”) emissions cause or contribute to air pollution that endangers public health and welfare within the meaning of Section 202(a) of the Clean Air Act.  EPA’s proposed
rule is in response to the U.S. Supreme Court’s 2007 decision in Massachusetts et al v. EPA, which held that the EPA can avoid taking action to regulate GHG emissions only if it determines that greenhouse gases do not contribute to climate change or if it provides some reasonable explanation as to why it cannot or will not exercise its discretion to determine whether they do. The proposed endangerment finding does not include proposed regulations
of GHG emissions. The public comment period on the proposed rule ended June 23, 2009. EPA has not taken final action.
 
 On June 26, 2009, the U.S. House of Representatives passed The American Clean Energy and Security Act of 2009, also known as the Waxman-Markey Bill.   The legislation would, among other things, establish a cap-and-trade program to regulate emissions of greenhouse gases.  It would also preempt regulation
of GHG emissions under state cap-and-trade programs and certain provisions of the Clean Air Act.  President Obama has expressed his support for House passage of the Waxman-Markey Bill.  The U.S. Senate is working on its own legislation to control GHG emissions.  If the Senate adopts different GHG legislation, the Senate legislation would need to be reconciled with the Waxman-Markey Bill and both chambers would be required to approve identical legislation before it could become law.
 
 The EPA’s proposed endangerment finding and the House passage of the Waxman-Markey Bill increase the likelihood that the U.S. will implement a federal program to regulate GHG emissions.  Many significant uncertainties remain, however, about the timing, nature, and effect of any such action.  Although
it is not possible at this time to predict whether or when new laws or regulations may be adopted to regulate GHG emissions, such actions would likely require us to incur increased operating costs, and could have an adverse effect on demand for the oil and natural gas we produce and distribute.
  In addition, we disclosed in our Form 8-K filed with the Securities and Exchange Commission on April 29, 2009 additional risks relating to the ownership of common units of the Partnership.  We disclosed these additional risks in light of the distribution reduction we announced on April 29, 2009, for our distribution to be paid
on May 15, 2009 with respect to the first quarter of 2009.  These additional risks are as follows:
   We may not be able to pay the minimum quarterly distribution and any arrearages on the common units.
 
 Based on current market conditions and the outlook for commodity prices, we recently announced that quarterly distributions on our common units are being reduced below the minimum quarterly distribution as defined in our partnership agreement.  As described in the partnership agreement, during the subordination period, our common
units carry arrearage rights. Although the common unitholders have arrearage rights, the unitholders are not entitled to receive these arrearages, which may never be paid.  We can give no assurances that the minimum quarterly distribution and any arrearages will ever be paid on the common units.  However, we must first pay all arrearages in addition to current minimum quarterly distributions before distributions can be made to holders of our subordinated units and our incentive distribution
rights, and we generally must first pay all arrearages before conversion of our subordinated units can occur.
  Limited partners may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
  Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, limited partners will be required to pay any federal income taxes and, in some cases, state and local income
taxes on their share of our taxable income even if no cash distributions were received from us.  Our taxable income for a taxable year may include income without a corresponding receipt of cash by us, such as accrual of future income, original issue discount or cancellation of indebtedness income.  We may not pay cash distributions equal to a limited partner’s share of our taxable income or even equal to the actual tax liability that result from that income.
  Except as disclosed above, the risks previously disclosed in our annual report on Form 10-K for the year ended December 31, 2008 have not changed in any material respect.
  42
 Table of Contents
  Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds.
  We did not sell our equity securities in unregistered transactions during the period covered by this report.
  The following table sets forth certain information with respect to repurchases of common units during the three months ended June 30, 2009:
 
 Period

Total Number of
Units
Purchased(1)


Average Price
Paid per Unit


Total Number of
Units Purchased as
Part of
Publicly Announced
Plans or Programs


Maximum Number (or
Approximate Dollar
Value) of Units
that May yet Be
Purchased Under the
Plans or ProgramsApril 1 – April 30


—



—



—



—May 1 – May 31


9,844


$
3.01



—



—June 1 – June 30


—



—



—



—
 
 (1)  All of the units were surrendered by employees to pay tax withholding in connection with the vesting of restricted common units awarded on May 15, 2007 and 2008. As a result, we are deeming the surrenders to be “repurchases.” These repurchases were not part of a publicly announced program to repurchase our common units, nor do we have a publicly announced program to repurchase our common
units.
   Item 3.
Defaults Upon Senior Securities.
  None.
  Item 4.
Submission of Matters to a Vote of Security Holders.
  None.
  Item 5.
Other Information.
  None.
  Item 6.
Exhibits.
 
 31.1
Certification by Joseph A. Mills pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.31.2
Certification by Jeffrey P. Wood pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.32.1
Certification by Joseph A. Mills pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 1350.32.2
Certification by Jeffrey P. Wood pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 1350.
 
 
  43
 Table of Contents
  SIGNATURES
  Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 Date: August 10, 2009
EAGLE ROCK ENERGY PARTNERS, L.P.By:
EAGLE ROCK ENERGY GP, L.P., its general partnerBy:
EAGLE ROCK ENERGY G&P, LLC, its general partnerBy:
/s/ Jeffrey P. WoodJeffrey P. WoodSenior Vice President,Chief Financial Officer and Treasurer of Eagle RockEnergy G&P, LLC, General Partner of Eagle RockEnergy GP, L.P., General Partner of Eagle RockEnergy Partners, L.P.
 
 
 
 
 
 
 
 
 
 
 
 
 
  44
 Table of Contents
  
 EAGLE ROCK ENERGY PARTNERS, L.P.
 
 EXHIBIT INDEX
 
 
 31.1
Certification by Joseph A. Mills pursuant to Section 302 of the Sarbanes-Oxley Act of 200231.2
Certification by Jeffrey P. Wood pursuant to Section 302 of the Sarbanes-Oxley Act of 200232.1
Certification by Joseph A. Mills pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 135032.2
Certification by Jeffrey P. Wood pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and 18 U.S.C. Section 1350