Eagle Rock Energy Partners L P (EROC) 10-K/A 2006 FY Annual report (amended)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

þ     ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2006

OR

o     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	(I.R.S. Employer
Incorporation or Organization)	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)

14950 Heathrow Forest Parkway, Suite 111
Houston, Texas 77032
(Former name, former address and former fiscal year, if changed since last report)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Common Units of Limited Partner Interests	NASDAQ Stock Market LLC

Securities registered pursuant to Section 12(g) of the Act:None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes   o       No   þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.
Yes   o       No   þ

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   þ       No   o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer   o       Accelerated Filer   o       Non-accelerated Filer   þ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes   o       No   þ

     As of March 29, 2007, the aggregate market value of the registrant’s common units held by non-affiliates of the registrant was $381,052,602 based on the closing sale price as reported on NASDAQ Global Market.

The issuer had 20,691,495 common units and 21,536,046 subordinated and general partner units outstanding as of March 30, 2007.

DOCUMENTS INCORPORATED BY REFERENCE.

NONE.

TABLE OF CONTENTS

	Page
Item 8. Financial Statements and Supplementary Data		1
Item 15. Exhibits and Financial Statement Schedules		1
Consent of Deloitte & Touche LLP
Certification Pursuant to Section 302
Certification Pursuant to Section 302
Certification Pursuant to Section 906
Certification Pursuant to Section 906

 i 

We are providing this Amendment to Form 10-K to include the financial statements of ONEOK Texas Field Services, L.P., our predecessor, within Item 8. Financial Statements and Supplementary Data. Such financial statements have previously been filed in Partnership’s initial Form S-1.

PART II

Item 8. Financial Statements and Supplementary Data.

     Our consolidated financial statements, together with the independent registered public accounting firm’s report of Deloitte & Touche LLP (“Deloitte & Touche”), begin on page F-1 of this Annual Report.

PART IV

Item 15. Exhibits and Financial Statement Schedules.

(a)(1) Financial Statements:

     The following financial statements and the Report of Independent Registered Public Accounting Firm are filed as a part of this report on the pages indicated:

(a)(2) Financial Statement Schedules:

           None.

(a)(3) Exhibits:

     The following documents are included as exhibits to this report:

Exhibit Number	Description
3.1	Certificate of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
3.2	Amended and Restated Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P. (included as Appendix A to the Prospectus and including specimen unit certificate for the common units) (incorporated by reference to Exhibit 3.2 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
3.3	Certificate of Limited Partnership of Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 3.3 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
3.4	Limited Partnership Agreement of Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 3.4 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
3.5	Certificate of Formation of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 3.5 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
3.6	Amended and Restated Limited Liability Company Agreement of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 3.6 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
4.1	Registration Rights Agreement dated March 27, 2006, among Eagle Rock Pipeline, L.P. and the Purchasers listed thereto (incorporated by reference to Exhibit 4.1 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
4.2	Tag Along Agreement dated March 27, 2006, among Eagle Rock Pipeline, L.P., Eagle Rock Pipeline GP, LLC, Eagle Rock Holdings, L.P., and the Purchasers listed thereto. (incorporated by reference to Exhibit 4.2 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
4.3	Form of Registration Rights Agreement between Eagle Rock Energy Partners, L.P. and Eagle Rock Holdings, L.P. (incorporated by reference to Exhibit 4.3 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
4.4	Form of Common Unit Certificate (included as Exhibit A to the Amended and Restated Partnership Agreement of Eagle Rock Energy Partners, L.P., which is included as Appendix A to the Prospectus) (incorporated by reference to Exhibit 3.2 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.1	Amended and Restated Credit and Guaranty Agreement (incorporated by reference to Exhibit 3.1 of the registrant’s registration statement on Form S-1 (File No. 333-134750))

1

Exhibit Number	Description
10.2	Form of Omnibus Agreement (incorporated by reference to Exhibit 3.1 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.3**	Form of Eagle Rock Energy Partners, L.P. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.4	Sale, Contribution and Exchange Agreement by and among the general and limited partners of Midstream Gas Services, L.P., Eagle Rock Energy Services, L.P. and Eagle Rock Pipeline, L.P. (incorporated by reference to Exhibit 10.4 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.5†	Natural Gas Liquids Exchange Agreement by and between ONEOK Hydrocarbon, L.P. and ONEOK Texas Field Services, L.P. (incorporated by reference to Exhibit 10.5 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.6†	Gas Sales and Purchase Agreement between MC Panhandle, Inc. (Chesapeake Energy Marketing Inc.) and MidCon Gas Services Corp. (Eagle Rock Field Services, L.P.) (incorporated by reference to Exhibit 10.6 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.7†	Brookeland Gas Facilities Gas Gathering and Processing Agreement between Union Pacific Resources Company (Anadarko E&P Company LP) and Sonat Exploration Company (Eagle Rock Field Services, L.P.) (incorporated by reference to Exhibit 10.7 of the registrant’s registration statement on Form S-1 (File No. 333-134750))

2

Exhibit Number	Description
10.8†	Minimum Volume Agreement between ONEOK Texas Field Services L.P. and Peak Operating of Texas, LLC (incorporated by reference to Exhibit 10.8 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.9†	Gas Purchase Agreement between ONEOK Texas Field Services L.P. and Peak Operating of Texas, LLC (incorporated by reference to Exhibit 10.9 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.10†	Gas Purchase Contract between Warren Petroleum Company (Eagle Rock Field Services, L.P.) and Wallace Oil & Gas, Inc. (Cimarex Energy Co.) (incorporated by reference to Exhibit 10.10 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.11	Form of Contribution, Conveyance and Assumption Agreement (incorporated by reference to Exhibit 10.11 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.12**	Employment Agreement dated August 2, 2006 between Eagle Rock Energy G&P, LLC and Richard W. FitzGerald (incorporated by reference to Exhibit 10.12 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.13	Base Contract for Sale and Purchase of Natural Gas between Eagle Rock Field Services, L.P. and Odyssey Energy Services, LLC (incorporated by reference to Exhibit 10.13 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
14.1	Code of Ethics posted on the Company’s website atwww.eaglerockenergy.com.
21.1	List of Subsidiaries of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 21.1 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
23.1*	Consent of Deloitte & Touche LLP
24.1*	Powers of Attorney (included on page 5 of the 10-K/A)
31.1*	Certification of Periodic Financial Reports by Joseph A. Mills. in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002
31.2*	Certification of Periodic Financial Reports by Alfredo Garcia in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002
32.1*	Certification of Periodic Financial Reports by Joseph A. Mills in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002
32.2*	Certification of Periodic Financial Reports by Alfredo Garcia in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002

*	Filed herewith
**	Management contract or compensatory plan or arrangement required to be filed as an exhibit hereto.
†	Portions of this exhibit have been omitted pursuant to a request for confidential treatment.

3

SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report on its behalf by the undersigned, thereunto duly authorized, on July 26, 2007.

EAGLE ROCK ENERGY PARTNERS, L.P.
By:	Eagle Rock Energy GP, L.P., its general partner
By:	Eagle Rock Energy G&P, LLC, its general partner
By:	/s/ Joseph A. Mills
Name: Joseph A. Mills
Title: Chairman and Chief Executive Officer
EAGLE ROCK ENERGY PARTNERS, L.P.
By: Eagle Rock Energy GP, L.P., its general partner
By: Eagle Rock Energy G&P, LLC, its general partner
By:	/s/ Alfredo Garcia
Name: Alfredo Garcia
Title: Acting Chief Financial Officer

4

POWERS OF ATTORNEY

     KNOW ALL MEN BY THESE PRESENTS, that each of the undersigned directors and/or officers of EAGLE ROCK ENERGY G&P, LLC (the “Company”), a Delaware limited liability company, acting in its capacity as general partner of Eagle Rock Energy Partners, L.P., a Delaware limited partnership (the “Partnership”), does hereby appoint JOSEPH A. MILLS and ALFREDO GARCIA, his true and lawful attorneys-in-fact and agents to do any and all acts and things, and execute any and all instruments which, with the advice and consent of Counsel, said attorneys-in-fact and agents may deem necessary or advisable to enable the Company and Partnership to comply with the Securities Act of 1934, as amended, and any rules, regulations, and requirements thereof, to sign his name as a director and/or officer of the Company to the Form 10-K Report for Eagle Rock Energy Partners, L.P., each for the year ended December 31, 2006, and to any instrument or document filed as a part of, or in accordance with, each said Form 10-K or amendment thereto; and the undersigned do hereby ratify and confirm all that said attorneys-in-fact and agents shall do or cause to be done by virtue hereof.

     IN WITNESS WHEREOF, the undersigned have subscribed these presents this 26th day of July, 2007.

Signature	Title	Date
/s/Joseph A. MillsJoseph A. Mills	Chairman and Chief Executive Officer (Principal Executive Officer)	July 26, 2007
/s/Alfredo GarciaAlfredo Garcia	Senior Vice President, Corporate Development and Acting Chief Financial Officer (Principal Accounting Officer)	July 26, 2007
/s/Kenneth A. HershKenneth A. Hersh	Director	July 26, 2007
/s/William J. QuinnWilliam J. Quinn	Director	July 26, 2007
/s/John A. WeinzierlJohn A. Weinzierl	Director	July 26, 2007
/s/Philip B. SmithPhilip B. Smith	Director	July 26, 2007
/s/William K. WhiteWilliam K. White	Director	July 26, 2007

*	/s/Alfredo Garcia
	Attorney-in-Fact

5

CONSOLIDATED FINANCIAL STATEMENTS
OF EAGLE ROCK ENERGY PARTNERS, L.P.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets as of December 31, 2006 and 2005		F-3
Consolidated Statements of Operations for the years ended December 2006, 2005 and 2004		F-4
Consolidated Statements of Cash Flows for the years ended December 31, 2006, 2005 and 2004		F-5
Consolidated Statements of Members’ Equity for the years ended 2006, 2005 and 2004		F-7
Notes to Consolidated Financial Statements
Note 1. Organization and Description of Business		F-8
Note 2. Summary of Significant Accounting Policies		F-8
Note 3. New Accounting Pronouncements		F-11
Note 4. Acquisitions		F-12
Note 5. Fixed Assets and Asset Retirement Obligations		F-14
Note 6. Long-term Debt		F-14
Note 7. Members’ Equity		F-16
Note 8. Related Party Transactions		F-17
Note 9. Fair Value of Financial Instruments		F-17
Note 10. Risk Management Activities		F-18
Note 11. Commitments and Contingent Liabilities		F-19
Note 12. Segments		F-20
Note 13. Discontinued Operations		F-21
Note 14. Employee Benefit Plans		F-21
Note 15. Income Taxes		F-21
Note 16. Equity-Based Compensation		F-21
Note 17. Earnings Per Unit		F-22
Note 18. Subsequent Events		F-23
ONEOK Texas Field Services, L.P.:
Report of Independent Registered Public Accounting Firm		F-24
Balance Sheets as of December 31, 2004 and November 30, 2005		F-25
Statements of Operations for the Years Ended December 31, 2003 and 2004 and for the Eleven-Month Period Ended November 30, 2005		F-26
Statements of Partnership Capital for the Years Ended December 31, 2003 and 2004 and for the Eleven-Month Period Ended November 30, 2005		F-27
Statements of Cash Flows for the Years Ended December 31, 2003 and 2004 and for the Eleven-Month Period Ended November 30, 2005		F-28
Notes to Financial Statements		F-29

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Eagle Rock Energy G&P, LLC and Unitholders of
Eagle Rock Energy Partners, L.P.
Houston, Texas

     We have audited the consolidated balance sheets of Eagle Rock Energy Partners, L.P. and subsidiaries (formerly Eagle Rock Pipeline, L.P.) (the “Partnership”) and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of operations, members’ equity, and cash flows for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

     We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe our audits provide a reasonable basis for our opinion.

     In our opinion, such financial statements present fairly, in all material respects, the consolidated financial position of Eagle Rock Energy Partners, L.P. and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP
Houston, Texas
April 2, 2007

F - 2

EAGLE ROCK ENERGY PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2006 and 2005

	December 31,			December 31,
	2006			2005
	($ in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	10,581		$	19,372
Accounts receivable		43,567			43,557
Risk management assets		13,837			21,830
Prepayments and other current assets		2,679			1,277
Total current assets		70,664			86,036
PROPERTY, PLANT AND EQUIPMENT — Net		554,063			441,588
INTANGIBLE ASSETS — Net		130,001			115,000
RISK MANAGEMENT ASSETS		17,373			44,023
OTHER ASSETS		7,800			14,012
TOTAL	$	779,901		$	700,659
LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	49,558		$	43,401
Distributions payable-affiliate		—			5,000
Accrued liabilities		7,996			2,324
Risk management liabilities		1,005			2,260
Current maturities of long-term debt		—			3,866
Total current liabilities		58,559			56,851
LONG-TERM DEBT		405,731			404,600
ASSET RETIREMENT OBLIGATIONS		1,819			679
DEFERRED TAX LIABILITY		1,229			—
RISK MANAGEMENT LIABILITIES		20,576			30,433
COMMITMENTS AND CONTINGENCIES MEMBERS’ EQUITY:
Common Unitholders (1)		116,283			208,013
Subordinated Unitholders (2)		176,248			—
General Partner		(544	)		83
Total members’ equity		291,987			208,096
TOTAL	$	779,901		$	700,659

(1)	20,691,495 and 24,150,739 units were issued and outstanding for 2006 and 2005, respectively.
(2)	20,691,495 and 0 units were issued and outstanding for 2006 and 2005, respectively.

See notes to consolidated financial statements.

F - 3

EAGLE ROCK ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

	Years Ended December 31,
($ in thousands, except per unit amounts)	2006			2005			2004
REVENUE:
Natural gas liquids sales	$	234,354		$	29,192		$	8,797
Natural gas sales		195,146			26,463			968
Condensate		57,411			4,266			72
Gathering, compression, and processing fees		14,862			6,247			799
(Loss) gain on risk management instruments		(24,004	)		7,308			—
Other		621			214			—
Total revenue		478,390			73,690			10,636
COSTS AND EXPENSES:
Cost of natural gas and natural gas liquids		377,580			55,272			8,811
Operations and maintenance		32,905			2,955			34
General and administrative		13,161			4,765			2,406
Advisory termination fee		6,000			—			—
Depreciation and amortization		43,220			4,088			619
Total costs and expenses		472,866			67,080			11,870
OPERATING INCOME (LOSS)		5,524			6,610			(1,234	)
OTHER INCOME (EXPENSE):
Interest and other income		996			171			24
Interest and other expense		(28,604	)		(4,031	)		—
Total other (expense) income		(27,608	)		(3,860	)		24
INCOME TAX PROVISION		1,230			—			—
(LOSS) INCOME FROM CONTINUING OPERATIONS		(23,314	)		2,750			(1,210	)
INCOME FROM DISCONTINUED OPERATIONS		—			—			22,192
NET (LOSS) INCOME	$	(23,314	)	$	2,750		$	20,982
NET (LOSS) INCOME PER COMMON UNIT — BASIC AND DILUTED:
(Loss) income from continuing operations
Common units	$	(1.26	)	$	0.11		$	(0.05	)
Subordinated units		(0.43	)		—			—
General partner units		(0.80	)		4.06			(0.05	)
Income from discontinued operations
Common units	$	—		$	—		$	0.87
General partner units		—			—			—
Net (loss) income
Common units	$	(1.26	)	$	0.11		$	0.92
Subordinated units		(0.43	)		—			—
General partner units		(0.80	)		4.06			—
Basic and Diluted (units in thousands)
Common units		12,123			24,151			24,151
Subordinated units		17,873			—			—
General partner units		557			20			—

See notes to consolidated financial statements.

F - 4

EAGLE ROCK ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

	Years Ended December 31,
($ in thousands)	2006			2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income	$	(23,314	)	$	2,750		$	20,982
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization		43,220			4,088			1,174
Amortization of debt issuance costs		1,114			76			—
Net realized gain on derivative contracts		(978	)		—			—
Gain on sale of assets		—			—			(19,465	)
Advisory termination fee		6,000			—			—
Equity-based compensation		142			—			—
Other		1,424			5			—
Changes in assets and liabilities — net of acquisitions:
Accounts receivable		(10	)		(42,821	)		688
Prepayments and other current assets		(1,422	)		(358	)		214
Risk management activities		23,531			(5,709	)		—
Accounts and distributions payable		3,105			40,094			167
Accrued liabilities		5,672			103			2
Other assets		(3,492	)		104			111
Other current liabilities		—			—			(221	)
Net cash provided by (used in) operating activities		54,992			(1,667	)		3,652
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment		(38,416	)		(4,157	)		(20,491	)
Sale of fixed assets		—			—			37,409
Acquisitions, net		(101,182	)		(530,951	)		—
Escrow cash		7,643			(7,643	)		—
Purchase of intangible assets		(2,918	)		(750	)		—
Net cash (used in) provided by investing activities		(134,873	)		(543,501	)		16,918
CASH FLOWS FROM FINANCING ACTIVITIES:
(Repayment of) proceeds from long-term debt		(4,635	)		400,000			(14,000	)
Proceeds from revolver		12,500			7,600			—
Repayment of revolver		(10,600	)		—			—
Payment of debt issuance costs		(2,939	)		(6,535	)		—
Payment for derivative contracts		—			(27,452	)		—
Proceeds from derivative contracts		978			—			—
Unit issuance costs for IPO		(3,723	)		—			—
Net cash in flow from IPO, including overallotment		248,067			—			—
Distributions of IPO proceeds to pre-IPO members		(245,067	)		—			—
Contribution by members		98,540			192,369			45
Distributions to members and affiliates		(22,033	)		(9,679	)		—
Net cash provided by (used in) financing activities		71,088			556,304			(13,955	)
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(8,791	)		11,136			6,615
CASH AND CASH EQUIVALENTS — Beginning of period		19,372			8,235			1,620
CASH AND CASH EQUIVALENTS — End of period	$	10,581		$	19,372		$	8,235

F - 5

	Years Ended December 31,
($ in thousands)	2006		2005		2004
Interest paid — net of amounts capitalized	$	30,657	$	—	$	317
Investments in property, plant and equipment not paid	$	6,573	$	1,190	$	—
Distributions payable to member	$	—	$	5,000	$	—
Prepayment financed by note payable	$	—	$	866	$	—
Issuance of common units for MGS acquisition	$	20,280	$	—	$	—

See notes to consolidated financial statements.

F - 6

EAGLE ROCK ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2006, 2005 and 2004
($ in thousands, except Unit amounts)

															Eagle Rock
				Number of						Number of					Pipeline, L.P.
	General			Common			Common			Subordinated		Subordinated			Predecessor
	Partner			Units			Units			Units		Units			Equity			Total
BALANCE — January 1, 2004	$	—			24,150,731	(1)	$	—			—	$	—		$	6,628		$	6,628
Net income		—			—			—			—		—			20,982			20,982
Capital contributions		—			—			—			—		—			45			45
BALANCE — December 31, 2004		—			24,150,731	(1)		—			—		—			27,655			27,655
Net income		83			—			4,067			—		—			(1,400	)		2,750
Capital contributions		—			—			142,688			—		—			49,681			192,369
Distributions		—			—			—			—		—			(14,679	)		(14,679	)
Conversion of predecessor equity to common units		—			—			61,258			—		—			(61,258	)		—
BALANCE —December 31, 2005		83			24,150,731	(1)		208,013			—		—			—			208,096
Net loss		(448	)		—			(15,229	)		—		(7,637	)		—			(23,314	)
Distributions		(287	)		—			(4,160	)		—		(12,587	)		—			(17,033	)
Conversion of common units to subordinated units		—			(20,691,495	)		(193,481	)		20,691,495		193,481			—			—
Issuance of common units — March 2006		—			3,922,930	(2)		98,540			—		—			—			98,540
Issuance of common units in MGS acquisition		—			809,329	(2)		20,280			—		—			—			20,280
IPO and overallotment		4,883			12,500,000			37,144			—		206,039			—			248,067
Distribution of IPO proceeds		(4,824	)		—			(35,860	)		—		(204,382	)		—			(245,067	)
IPO offering costs		(74	)		—			(1,593	)		—		(2,056	)		—			(3,723	)
Advisory fee termination		120			—			2,567			—		3,313			—			6,000
Restricted units expense		3			—			61			—		78			—			142
BALANCE — December 31, 2006	$	(544	)		20,691,495		$	116,283			20,691,495	$	176,248		$	—		$	291,987

(1)	Represents adjusted common units for presentation purposes. Based upon units on formation in March 2006, adjusted for IPO unit rate conversion.
(2)	Units issued adjusted for IPO conversion.

See notes to consolidated financial statements.

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EAGLE ROCK ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2006, 2005 and 2004

NOTE 1. ORGANIZATION AND DESCRIPTION OF BUSINESS

     Eagle Rock Pipeline, L.P., a Texas limited partnership, is an indirect wholly-owned subsidiary of Eagle Rock Holdings, L.P. (“Holdings”). Holdings is a portfolio company of Irving, Texas based private equity capital firm, Natural Gas Partners. Eagle Rock Pipeline, L.P. was formed on November 14, 2005 for the purpose of owning a limited partnership interest in Eagle Rock Midstream Resources, L.P.

     In May 2006, Eagle Rock Energy Partners, L.P., a Delaware limited partnership, an indirect wholly-owned subsidiary of Holdings, was formed for the purpose of completing a public offering of common units. On October 24, 2006, it offered and sold 12,500,000 common units in its initial public offering, or IPO, at a price of $19.00 per unit. Net proceeds from the sale of the units, $222.1 million after underwriting costs, were used for reimbursement of capital expenditures for investors prior to the initial public offering, replenish working capital, and distribution arrearage payment. In connection with the initial public offering, Eagle Rock Pipeline, L.P. was merged with and into a newly formed subsidiary of Eagle Rock Energy Partners, L.P. (“Eagle Rock Energy” or the “Partnership”).

     Basis of Presentation and Principles of Consolidation— The accompanying financial statements include assets, liabilities and the results of operations of Eagle Rock Energy from October 24, 2006, and the results of operations of Eagle Rock Pipeline, L.P. and its predecessor entities for the periods prior to October 24, 2006. The reorganization of these entities was accounted for as a reorganization of entities under common control. The general partner of Eagle Rock Energy and Eagle Rock Midstream Resources, L.P. is Eagle Rock Energy GP, L.P., a wholly-owned subsidiary of Holdings. Eagle Rock Pipeline, L.P., Eagle Rock Midstream Resources L.P. and their subsidiaries and, effective October 24, 2006, Eagle Rock Energy Partners, L.P. are collectively referred to as “Eagle Rock Energy” or the “Partnership.”

     Eagle Rock Energy, through its wholly-owned subsidiaries and partnerships, provides midstream energy services, including gathering, transportation, treating, processing and conditioning services in the Texas Panhandle region. The Partnership’s natural gas pipelines collect natural gas from designated points near producing wells and transports these volumes to third-party pipelines, the Partnership’s gas processing plants, utilities and industrial consumers. Natural gas shipped to the Partnership’s gas processing plants, either on the Partnership’s pipelines or third-party pipelines, is treated to remove contaminants, conditioned or processed into mixed natural gas liquids, or NGLs. The Partnership conducts it operation within two geographic areas of Texas. The Partnership’s Texas Panhandle assets consist of assets acquired from ONEOK, Inc. on December 1, 2005 (see Note 4), and include gathering and processing assets (the “Texas Panhandle Systems”). The Partnership’s southeast Texas and Louisiana assets include a non-operated 25% undivided interest in a processing plant as well as a non-operated 20% undivided interest in a connected gathering system. In December 2005, the Partnership began operations of a newly constructed pipeline in east Texas that connects to the non-operated system (collectively, the “Texas and Louisiana System”). This pipeline was completed on February 28, 2006. On March 31, 2006, the Partnership’s southeast Texas and Louisiana System completed the acquisition of 100% interest in the Brookeland and Masters Creek processing plants in east Texas from Duke Energy Field Services. (see Note 4) On June 2, 2006, the Partnership’s Texas Panhandle Systems completed the acquisition of 100% of Midstream Gas Services, L.P. (see Note 4)

NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

     The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States. Eagle Rock Energy is the owner of a non-operating undivided interest in a gas processing plant and a gas gathering system. Eagle Rock Energy owns these interests as tenants in common with the majority owner-operator of the facilities. Accordingly, Eagle Rock Energy includes its pro-rata share of assets, liabilities, revenues and expenses related to these assets in its financial statements. All significant intercompany accounts and transactions are eliminated in the consolidated financial statements.

     Use of Estimates— The preparation of the financial statements in conformity with accounting policies generally accepted in the United States of America requires management to make estimates and assumptions which affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities that exist at the date of the financial statements. Although management believes the estimates are appropriate, actual results can differ from those estimates.

     Cash and Cash Equivalents— Cash and cash equivalents include certificates of deposit or other highly liquid investments

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with maturities of three months or less at the time of purchase.

     Concentration and Credit Risk— Concentration and credit risk for the Partnership principally consists of cash and cash equivalents and accounts receivable.

     The Partnership places its cash and cash equivalents with high-quality institutions and in money market funds. The Partnership derives its revenue from customers primarily in the natural gas industry. On June 1, 2006, the Partnership increased the parties to which it was selling liquids and natural gas from two to eleven. These industry concentrations have the potential to impact the Partnership’s overall exposure to credit risk, either positively or negatively, in that the Partnership’s customers could be affected by similar changes in economic, industry or other conditions. However, the Partnership believes the credit risk posed by this industry concentration is offset by the creditworthiness of the Partnership’s customer base. The Partnership’s portfolio of accounts receivable is comprised primarily of mid-size to large domestic corporate entities.

     Certain Other Concentrations— The Partnership relies on natural gas producer customers for its natural gas and natural gas liquid supply, with two producers accounting for 29.2% of its natural gas supply in its Texas Panhandle Systems and 55.9% of its natural gas supply in the Texas and Louisiana System for the year ended December 31, 2006. Those suppliers accounted for 28.1% of the natural gas supply for the year ended December 31, 2005. While there are numerous natural gas and natural gas liquid producers and some of these producer customers are subject to long-term contracts, the Partnership may be unable to negotiate extensions or replacements of these contracts, on favorable terms, if at all. If the Partnership were to lose all or even a portion of the natural gas volumes supplied by these producers and was unable to acquire comparable volumes, the Partnership’s results of operations and financial position could be materially adversely affected.

     Property, Plant, and Equipment— Property, plant, and equipment consists primarily of gas gathering systems, gas processing plants, NGL pipelines, conditioning and treating facilities and other related facilities, which are carried at cost less accumulated depreciation. The Partnership charges repairs and maintenance against income when incurred and capitalizes renewals and betterments, which extend the useful life or expand the capacity of the assets. The Partnership calculates depreciation on the straight-line method principally over 20-year estimated useful lives of the Partnership’s newly developed or acquired assets, with usually no residual value. The weighted average useful lives are as follows:

Pipelines and equipment	20 years
Gas processing and equipment	20 years
Office furniture and equipment	5 years

     The Partnership capitalizes interest on major projects during extended construction time periods. Such interest is allocated to property, plant and equipment and amortized over the estimated useful lives of the related assets. During the year ended December 31, 2006, the Partnership capitalized interest of $0.4 million. The Partnership capitalized interest of $10,300 related to the construction of a pipeline in 2005.

     The costs of maintenance and repairs, which are not significant improvements, are expensed when incurred. Expenditures to extend the useful lives of the assets or enhance its productivity or efficiency from its original design are capitalized over the expected benefit or useful period.

     Impairment of Long-Lived Assets— Management evaluates whether the carrying value of long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the asset. Management considers various factors when determining if these assets should be evaluated for impairment, including but not limited to:

• significant adverse change in legal factors or in the business climate;

• a current-period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast which demonstrates continuing losses associated with the use of a long-lived asset;

• an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;

• significant adverse changes in the extent or manner in which an asset is used or in its physical condition;

• a significant change in the market value of an asset; or

• a current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.

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     If the carrying value is not recoverable on an undiscounted basis, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets.

     Intangible Assets— Intangible assets consist of right-of-ways and easements and acquired customer contracts, which the Partnership amortizes over the term of the agreement or estimated useful life. Amortization expense was approximately $15.8 million for the year ended December 31, 2006, and approximately $1.2 million for the year ended December 31, 2005. There was no amortization expense for any period prior to December 1, 2005. Estimated aggregate amortization expense for each of the five succeeding years is as follows: 2007 — $16.4 million; 2008 — $16.4 million; 2009 — $16.4 million; 2010 — $16.4 million; and 2011 — $7.7 million. Intangible assets consisted of the following:

	December 31,			December 31,
($ in thousands)	2006			2005
Rights-of-way and easements — at cost	$	66,801		$	57,714
Less: accumulated amortization		(7,407	)		(237	)
Contracts		80,210			58,499
Less: accumulated amortization		(9,603	)		(975	)
Net Intangible assets	$	130,001		$	115,000

     The amortization period for our rights-of-way and easements are 20 years and contracts are 5 years, respectively, and overall, approximately 12 years average in total as of December 31, 2005. The amortization period for our rights-of-way and easements was 20 years and contracts range from 5 to 15 years, respectively, and overall, approximately 13 years average in total as of December 31, 2006.

     Other Assets— Other assets primarily consist of costs associated with debt issuance ($7.8 million at December 31, 2006), net of amortization. Amortization of debt issuance costs is calculated using the straight-line method over the maturity of the associated debt (or the expiration of the contract).

     Transportation and Exchange Imbalances— In the course of transporting natural gas and natural gas liquids for others, the Partnership 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 are recovered or repaid through the receipt or delivery of natural gas or natural gas liquids in future periods, if not subject to cash out provisions. Imbalance receivables are included in accounts receivable and imbalance payables are included in accounts payable on the consolidated balance sheets and marked-to-market using current market prices in effect for the reporting period of the outstanding imbalances. As of December 31, 2006 and 2005, the Partnership had imbalance receivables totaling $0.3 million and $0.2 million, respectively, and imbalance payables totaling $1.9 million and $0.8 million, respectively. As of December 31, 2005, the Partnership had imbalance receivables totaling $0.2 million and imbalance payables totaling $0.8 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 sold.

     Revenue Recognition— Eagle Rock Energy’s primary types of sales and service activities reported as operating revenue include:

• sales of natural gas, NGLs and condensate;

• natural gas gathering, processing and transportation, from which Eagle Rock Energy generates revenues primarily through the compression, gathering, treating, processing and transportation of natural gas; and

• NGL transportation from which we generate revenues from transportation fees.

     Revenues associated with sales of natural gas, NGLs and condensate are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery occurs. Revenues associated with transportation and processing fees are recognized when the service is provided.

     For gathering and processing services, Eagle Rock Energy either receives fees or commodities from natural gas producers

F - 10

depending on the type of contract. Commodities received are in turn sold and recognized as revenue in accordance with the criteria outlined above. Under the percentage-of-proceeds contract type, Eagle Rock Energy is paid for its services by keeping a percentage of the NGLs produced and a percentage of the residue gas resulting from processing the natural gas. Under the keep-whole contract type, Eagle Rock Energy purchases wellhead natural gas and sells processed natural gas and NGLs to third parties.

     Transportation, compression and processing-related revenue are recognized in the period when the service is provided and include the Partnership’s fee-based service revenue for services such as transportation, compression and processing.

     Environmental Expenditures— Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures which relate to an existing condition caused by past operations and do not generate current or future revenue are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. The Partnership has recorded environmental liabilities of $0.3 million as of December 31, 2006 and 2005.

     Income Taxes— No provision for federal income taxes related to the operation of Eagle Rock Energy is included in the accompanying consolidated financial statements as such income is taxable directly to the partners holding interests in the Partnership. The State of Texas enacted a margin tax in May 2006 which requires the Partnership to pay beginning in 2008, based on 2007 results. The method of calculation for this margin tax is similar to an income tax, requiring the Partnership to recognize currently the impact of this new tax on the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. Approximately $1.2 million deferred state tax liability has been recorded at December 31, 2006. (see Note 15)

     Derivatives— Statement of Financial Accounting Standards (“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 measure those instruments at fair value. SFAS No. 133 provides that normal purchase and normal sale contracts, when appropriately designated, are not subject to the statement. Normal purchases and normal sales are contracts which provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business. The Partnership’s forward natural gas purchase and sales contracts are designated as normal purchases and sales. Substantially all forward contracts fall within a one-month to five-year term; however, the Partnership does have certain contracts which extend through the life of the dedicated production. The Partnership uses financial instruments such as puts, swaps and other derivatives to mitigate the risks to cash flows resulting from changes in commodity prices and interest rates. The Partnership recognizes these financial instruments on its consolidated balance sheet at the instrument’s fair value with changes in fair value reflected in the statement of operations, as the Partnership has not designated any of these derivative instruments as hedges. 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 statement of cash flows. See Note 10 for a description of the Partnership’s risk management activities.

NOTE 3. NEW ACCOUNTING PRONOUNCEMENTS

     In May 2005, the Financial Accounting Standards Board, or the FASB, issued SFAS No. 154,Accounting Changes and Error Corrections.This statement establishes new standards on the accounting for and reporting of changes in accounting principles and error corrections. This statement requires retrospective application to the financial statements of prior periods for all such changes, unless it is impracticable to do so. The Partnership adopted this statement beginning January 1, 2006. The adoption of this statement had no impact and is not expected to have a material effect on our financial position or results of operations on future financial statements.

     In February 2006, the FASB issued SFAS No. 155,Accounting for Certain Hybrid Financial Instruments, an amendment of FASB Statements No. 133 and No. 140 (SFAS No. 155). SFAS No. 155 amends SFAS No. 133, which required a derivative embedded in a host contract which does not meet the definition of a derivative be accounted for separately under certain conditions. SFAS No. 155 amends SFAS No. 133 to narrow the scope of such exception to strips which represent rights to receive only a portion of the contractual interest cash flows or of the contractual principal cash flows of a specific debt instrument. In addition, SFAS No. 155 amends SFAS No. 140,Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,which permitted a qualifying special-purpose entity to hold only a passive derivative financial instrument pertaining to beneficial interests issued or sold to parties other than the transferor. SFAS No. 155 amends SFAS No. 140 to allow a qualifying special purpose entity to hold a derivative instrument pertaining to beneficial interests that itself is a derivative financial instrument. SFAS No. 155 is effective for all financial instruments acquired or issued (or subject

F - 11

to a re-measurement event) following the start of an entity’s first fiscal year beginning after September 15, 2006. The Partnership will adopt SFAS No. 155 on January 1, 2007, and does not expect this standard to have a material impact, if any, on our consolidated financial statements.

     In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements.This statement defines fair value, establishes a framework for measuring fair value, and expands disclosure about fair value measurements. The statement is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company is currently evaluating the effect the adoption of this statement will have, if any, on its consolidated results of operations and financial position.

     In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities(SFAS NO. 159), which permits entities to choose to measure many financial instruments and certain other items at fair value. SFAS No. 159 is effective for us as of January 1, 2008 and will have no impact on amounts presented for periods prior to the effective date. We cannot currently estimate the impact of SFAS No. 159 on our consolidated results of operations, cash flows or financial position and have not yet determined whether or not we will choose to measure items subject to SFAS No. 159 at fair value.

     A significant portion of the Partnership’s sale and purchase arrangements are accounted for on a gross basis in the statements of operations as natural gas sales and costs of natural gas, respectively. These transactions are contractual arrangements which establish the terms of the purchase of natural gas at a specified location and the sale of natural gas at a different location at the same or at another specified date. These arrangements are detailed either jointly, in a single contract or separately, in individual contracts which are entered into concurrently or in contemplation of one another with a single or multiple counterparties. Both transactions require physical delivery of the natural gas and the risk and reward of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk and counterparty nonperformance risk. In accordance with the provision of Emerging Issues Task Force Issue No. 04-13,Accounting for Purchases and Sales of Inventory with the Same Counterparty(“EITF 04-13”), the Partnership reflects the amounts of revenues and purchases for these transactions as a net amount in its consolidated statements of operations beginning with April 2006. For the year ended December 31, 2006, the Partnership did not enter into any purchase and sale agreements with the same counterparty. As a result, the adoption of EITF 04-13 had no effect on the results of operations for the year ended December 31, 2006.

     In October 2005, the FASB issued Staff Position FAS 13-1 concerning the accounting for rental expenses associated with operating leases for land or buildings which are incurred during a construction period. We considered how this might apply to our payment for rights-of-way associated with the construction of pipelines, and we do not anticipate any changes to our accounting practices or impacts on our results of operations or financial condition in light of this recently issued Staff Position.

     In July 2006, the FASB issued FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109(FIN 48), which clarifies the accounting and disclosure for uncertainty in tax positions, as defined. FIN 48 seeks to reduce the diversity in practice associated with certain aspects of the recognition and measurement related to accounting for income taxes. This interpretation is effective for fiscal years beginning after December 15, 2006. We do not expect that the adoption of FIN 48 will have a material impact on our results of operations or financial position.

NOTE 4. ACQUISITIONS

     On December 1, 2005, the Partnership completed its acquisition of ONEOK Field Services Texas (“ONEOK Texas”) for $531.1 million (the “Panhandle Acquisition”) to expand the Partnership’s asset base and to obtain critical mass. ONEOK Texas provides natural gas midstream services in the Texas Panhandle and its assets primarily consist of gathering pipelines and processing plants. The results of operations have been included in the statement of operations since the date of acquisition. The Partnership financed the Panhandle Acquisition and related transactions and costs with proceeds from the following:

     Borrowings of approximately $393.5 million of the $400.0 million initially borrowed under the new Credit Facility discussed in Note 6;

     Net proceeds received from Holdings from a $133.0 million private placement of equity to Natural Gas Partners.

     With the assistance of a third-party valuation firm, management has prepared an assessment of the fair value of the property, plant and equipment and intangible assets of the Panhandle Acquisition as of December 1, 2005. The purchase price allocation was finalized during the fourth quarter 2006. The purchase price has been allocated as presented below.

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($ in thousands)
Accounts receivable and other current assets	$	673
Property, plant, and equipment		420,551
Intangibles		115,265
Accounts payable		(2,047	)
Other current liabilities		(1,931	)
Asset retirement obligations		(1,405	)
	$	531,106

     All liabilities assumed were at their fair values. The fair value of intangibles is estimated to be $115.5 million. There were no identified intangibles which were determined to have indefinite lives.

     On March 31, 2006, the Partnership’s southeast Texas and Louisiana System completed the acquisition of an 80% interest in the Brookeland gathering and processing facility, a 76.3% interest in the Masters Creek gathering system and 100% of the Jasper NGL line for $75.7 million to solidify the Partnership’s southeast Texas and Louisiana operations and to integrate with the segments existing operations. The Partnership commenced recording these results of operations on April 1, 2006. On April 7, 2006, the remaining interests were acquired for $20.2 million and the results of operations have been recorded effective as of April 1, 2006, as results of operations for the period April 1, 2006 to April 7, 2006, were not material. Included in other assets at December 31, 2005 is $7.6 million of escrow cash on deposit for the acquisition of these assets. This escrow cash was released on March 31, 2006. The purchase price was allocated on a preliminary basis to property, plant and equipment and intangibles in the amounts of $88.8 million and $7.9 million, respectively, based on their respective fair value as determined by management with the assistance of a third-party valuation specialist. In addition to long-term assets, the Partnership assumed certain accrued liabilities. The purchase price has been allocated as presented below.

($ in thousands)
Property, plant, and equipment	$	88,858
Intangibles		7,992
Other current liabilities		(750	)
Asset retirement obligations		291
	$	95,809

     On June 2, 2006, the Partnership purchased Midstream Gas Services, L.P. (“MGS”) for $4.7 million in cash and 809,174 (1,125,416 pre-IPO conversion) common units to integrate with the Texas Panhandle Systems’ existing operations. The Partnership will issue up to 798,113 common units, converted at the time of the initial public offering (1-for-0.719), to Natural Gas Partners VII, L.P., the primary equity owner of MGS, as a contingent earn-out payment if MGS achieves certain financial objectives for the year ending December 31, 2007. The Partnership commenced recording the results of operations on June 2, 2006.

     The following pro forma information for the year ended December 31, 2006 and 2005, assumes the Brookeland gathering and processing facility, the Masters Creek gathering system, the Jasper NGL line and the MGS interests (only for 2006) had been acquired on January 1, 2006 and 2005, respectively (uanaudited):

($ in thousands)	2006			2005
Pro forma earnings data:
Revenues	$	492,507		$	508,904
Costs and expenses		(489,723	)		(478,066	)
Operating (loss) income		2,784			30,838
Other income (expense), net		(27,786	)		(31,078	)
Income tax provision		(1,230	)		—
Loss from continuing operations	$	(26,232	)	$	(240	)

     In July 2004, the Partnership acquired a 25% undivided interest in a processing plant as well as a 20% undivided interest in a connected gathering system for $19.9 million. The results of operations have been recorded on a pro-rata consolidation basis and have been included in the statement of operations since the date of acquisition.

F - 13

NOTE 5. FIXED ASSETS AND ASSET RETIREMENT OBLIGATIONS

     Fixed assets consisted of the following:

	December 31,
($ in thousands)	2006			2005
Land	$	853		$	327
Plant		81,485			63,718
Gathering and pipeline		433,779			345,296
Equipment and machinery		37,185			24,386
Vehicles and transportation equipment		2,740			1,970
Office equipment, furniture, and fixtures		511			133
Computer equipment and software		4,623			508
Corporate		126			126
Linefill		3,923			3,674
Construction in progress		19,677			4,888
		584,902			445,025
Less: accumulated depreciation		(30,839	)		(3,438	)
Net fixed assets	$	554,063		$	441,588

     Depreciation expense for the years ended December 31, 2006 and 2005 were $27.4 million and $2.9 million, respectively.

     Asset Retirement Obligations— On December 31, 2005, we adopted 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 our 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, we are 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. The adoption of FIN 47 had no impact on the Partnership’s consolidated financial statements.

     A reconciliation of our liability for asset retirement obligations is as follows:

($ in thousands)
Asset retirement obligations — January 1, 2005	$	—
Addition, primarily Panhandle acquisitions		674
Accretion expense		5
Asset retirement obligations — December 31, 2005		679
Additions for Brookeland and MGS acquisitions		297
Purchase price allocation adjustment on Panhandle assets		698
Additional liability on newly built assets		17
Accretion expense		128
Asset retirement obligations — December 31, 2006	$	1,819

     Asset retirement obligations prior to January 1, 2005 were not significant.

NOTE 6. LONG-TERM DEBT

     Long-term debt consists of:

	December 31,		December 31,
($ in thousands)	2006		2005
Revolver	$	106,481	$	7,600
Term loan		299,250		400,000
Other		—		866
Total debt		405,731		408,466
Less: current portion		—		3,866
Total long-term debt	$	405,731	$	404,600

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     On August 31, 2006, the Partnership amended and restated its existing credit agreement (the “Amended and Restated Credit Agreement”). The Amended and Restated Credit Agreement is a $500.0 million credit agreement with a syndicate of commercial and investment banks and institutional lenders, with Goldman Sachs Credit Partners L.P., as the administrative agent. The Amended and Restated Credit Agreement provides for $300.0 million aggregate principal amount of Series B Term Loans (the “Term Loan”) and up to $200.0 million aggregate principal amount of Revolving Commitments (the “Revolver”). A $750,000 principal payment was made toward the Term Loan in October 2006, reducing the Term Loan aggregate principal amount to $299.3 million. The Amended and Restated Credit Agreement includes a sub limit for the issuance of standby letters of credit for the aggregate unused amount of the Revolver. At December 31, 2006, the Partnership had $2.5 million of outstanding letters of credit. In addition, the loan agreement allows the Partnership to expand its credit facility by an additional $100.0 million if the Partnership meets certain financial conditions.

     In connection with the Amended and Restated Credit Agreement, the Partnership incurred debt issuance costs of $2.4 million to the Consolidated Statement of Operations during the year ended December 31, 2006, of which approximately $0.4 million was expensed directly, with the remaining portion to be amortized over the remaining term of the agreement.

     Prior to the initial public offering, the principal amount due under the Term Loan was to be repaid in consecutive quarterly installments on the four quarterly scheduled interest payment dates applicable to the Term Loan, commencing September 30, 2006, in an amount equal to one-quarter percent (0.25%) of the original principal amount outstanding with the remaining outstanding principal amount due on the Term Loan maturity date. With the consummation of the Partnership’s initial public offering on October 27, 2006, quarterly installments under the Term Loan ceased with the balance due on the Term Loan maturity date, August 31, 2011. The Revolver matures on the revolving commitment termination date, August 31, 2011.

     In certain instances defined in the Amended and Restated Credit Agreement, the Term Loan is subject to mandatory repayments and the Revolver is subject to a commitment reduction for cumulative asset sales exceeding $15.0 million; insurance/condemnation proceeds; the issuance of equity securities; and the issuance of debt.

     The Amended and Restated Credit Agreement contains various covenants which limit the Partnership’s ability to grant certain liens; make certain loans and investments; make certain capital expenditures outside the Partnership’s current lines of business or certain related lines of business; make distributions other than from available cash; merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of the Partnership’s assets. Additionally, the Amended and Restated Credit Agreement limits the Partnership’s ability to incur additional indebtedness with certain exceptions and purchase money indebtedness and indebtedness related to capital or synthetic leases not to exceed $7.5 million.

     The Amended and Restated Credit Agreement also contains covenants, which, among other things, require the Partnership, on a consolidated basis, to maintain specified ratios or conditions as follows:

• Adjusted EBITDA (as defined) to interest expense of not less than 2.0 to 1.0 through December 31, 2006, and 2.50 to 1.0 thereafter; and

• Total consolidated funded debt to Adjusted EBITDA (as defined) of not more than 6.0 to 1.0 through December 31, 2006, and 5.0 to 1.0 thereafter and 5.25 to 1.0 for the three quarters following a material acquisition;

     Based upon the senior debt to Adjusted EBITDA ratio calculated as of December 31, 2006 (utilizing the September and December 2006 quarters Consolidated Adjusted EBITDA as defined under the Credit Agreement annualized for an annual Adjusted EBITDA amount for the ratio), the Partnership has approximately $80.0 million of unused capacity under the Amended and Restated Credit Agreement Revolver with $24.0 million available capacity at year end.

     At the Partnership’s election, the Term Loan and the Revolver bear interest on the unpaid principal amount either at a base rate plus the applicable margin (defined as 1.25% per annum, reducing to 1.00% when consolidated funded debt to Adjusted EBITDA (as defined) is less than 3.5 to 1); or at the Adjusted Eurodollar Rate plus the applicable margin (defined as 2.25% per annum, reducing to 2.00% when consolidated funded debt to Adjusted EBITDA (as defined) is less than 3.5 to 1). At August 31, 2006, the Partnership elected the Eurodollar Rate plus the applicable margin (defined as 2.25%) for a cumulative rate of 7.65%. The applicable margin increased by 0.50% per annum on January 31, 2007, under the Amended and Restated Credit Agreement as the Partnership elected not to obtain a rating by S&P and Moody’s.

     Base rate interest loans are paid the last day of each March, June, September and December. Eurodollar Rate Loans are paid the last day of each interest period, representing one-, two-, three- or six-, nine- or twelve-months, as selected by the Partnership. Interest on the Term Loan is paid approximately each December 31, March 31, June 30 and September 30 of each year, commencing on September 30, 2006. The Partnership pays a commitment fee equal to (1) the average of the daily

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difference between (a) the revolver commitments and (b) the sum of the aggregate principal amount of all outstanding revolver loans plus the aggregate principal amount of all outstanding swing loans times (2) 0.50% per annum; provided, the commitment fee percentage increased by 0.25% per annum on January 31, 2007, as the Partnership elected not to obtain a rating by S&P and Moody’s. The Partnership also pays a letter of credit fee equal to (1) the applicable margin for revolving loans which are Eurodollar Rate loans times (2) the average aggregate daily maximum amount available to be drawn under all such Letters of Credit (regardless of whether any conditions for drawing could then be met and determined as of the close of business on any date of determination). Additionally, the Partnership pays a fronting fee equal to 0.125%, per annum, times the average aggregate daily maximum amount available to be drawn under all letters of credit.

     The obligations under the Amended and Restated Credit Agreement are secured by first priority liens on substantially all of the Partnership’s assets, including a pledge of all of the capital stock of each of its subsidiaries.

     Prior to entering into the Amended and Restated Credit Agreement, the Partnership operated under a $475.0 million credit agreement (the “Credit Agreement”) with a syndicate of commercial banks, including Goldman Sachs Credit Partners L.P., as the administrative agent. The Credit Agreement was entered into on December 1, 2005. The Credit Agreement provided for $400.0 million aggregate principal amount of Series A Term Loans (the “Original Term Loan”) and up to $75.0 million ($100.0 million effective June 2, 2006) aggregate principal amount of Revolving Commitments (the “Original Revolver”). The Credit Agreement included a sub limit for the issuance of standby letters of credit for the lesser of $55.0 million or the aggregate unused amount of the Original Revolver. At December 31, 2005, the Partnership had $400.0 million outstanding under the Original Term Loan, $7.6 million outstanding under the Original Revolver and $0.1 million of outstanding letters of credit.

     Scheduled maturities of long-term debt as of December 31, 2006, were as follows:

	Principal
($ in thousands)	Amount
2007	$	0
2008		0
2009		0
2010		0
2011		405,731
	$	405,731

     The Partnership was in compliance with the financial covenants under the Amended and Restated Credit Agreement as of December 31, 2006. If an event of default existed under the Amended and Restated Credit Agreement, the lenders would be able to accelerate the maturity of the Amended and Restated Credit Agreement and exercise other rights and remedies.

NOTE 7. MEMBERS’ EQUITY

     At December 31, 2005, the Partnership had common units outstanding representing 98.01% of limited partnership interest and 1.99% of general partner interests, all of which were controlled by Holdings. On March 27, 2006, the Partnership sold 5,455,050 common units in a private placement for $98.3 million and converted the 98.01% limited partnership interest into 33,582,918 subordinated units. In June 2006, the Partnership issued 1,125,416 common units in connection with the MGS acquisition. At the initial public offering, the pre-IPO common units outstanding were converted into publicly-traded common units using a factor of approximately 0.7191. Additionally, Holdings contributed $0.2 million in cash during 2006. For the initial public offering, the Partnership issued 12.5 million common units. The overallotment option was exercised by the underwriters in November 2006 with 1,463,785 common units being issued from common units acquired by the Partnership from Holdings and selected private investors. The exercise of the overallotment did not result in additional shares being issued by the Partnership. At December 31, 2006, there were 20,691,496 common units and 20,691,496 subordinated units (all subordinated units owned by Holdings) outstanding. In addition, there were 122,450 restricted unvested common units outstanding.

     Additionally, during the fourth quarter of 2006, Holdings paid $6.0 million to terminate the advisory fee arrangement with Natural Gas Partners. The expense was recorded on the Partnership’s financial results of operations with the offset to members’ equity (see Note 8).

     Subordinated units represent limited liability interests in the Partnership, and holders of subordinated units exercise the rights and privileges available to unitholders under the limited liability company 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. Subordinated units will convert into common units on a one-for-one basis when the

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subordination period ends. Pursuant to the Partnership’s agreement of limited partnership, the subordination period will extend to the earliest date following March 31, 2009 for which there does not exist any cumulative common unit arrearage.

     On August 15, 2006, the Partnership declared and paid a distribution of $1.9 million to its common unit holders. As of September 30, 2006, the Partnership was in arrears on its subordinated units and general partner units in the amount of $10.7 million and $0.3 million, respectively for the second quarter of 2006. The arrearages were declared and paid at the time of the initial public offering. The IPO net cash received was $222.1 million, including $3.0 million for initial public offering transaction costs reimbursement to the Partnership. Distributions of $219.1 million were made in the fourth quarter for capital expenditure and working capital reimbursements and distribution arrearages. On November 14, 2006, the Partnership distributed $14.4 million from its third quarter 2006 results. This distribution was made to the unitholders on record as of September 30, 2006. In November, the Partnership received net cash of $26.0 million for the exercise of the overallotment by the underwriters. This amount was used to buy common units from Holdings and certain Pre-IPO investors.

     On January 26, 2006, the Partnership declared its 2006 fourth quarter distribution to its common unitholders of record as of February 7, 2007. The distribution amount per common unit was $0.3625 which was adjusted to $0.2679 per unit for the partial quarter the units were outstanding due to the initial public offering date. The distribution was made on February 15, 2007. No distributions were declared on the general partner or subordinated units.

NOTE 8. RELATED PARTY TRANSACTIONS

     Holdings had a management advisory arrangement with Natural Gas Partners requiring a quarterly fee payment. The agreement was modified on December 1, 2005, to increase the management fee to $0.5 million annually, with an escalation to $1.0 million annually, upon the completion of the initial public offering by the Partnership. The fee paid under the advisory arrangement has been expensed by the Partnership. For years ended 2006 and 2005, the Partnership expensed the $0.4 million and $0.1 million for the management advisory arrangement. At the time of the initial public offering, Holdings terminated the agreement with a $6.0 million payment to Natural Gas Partners. The termination fee was recorded as an expense of the Partnership during the fourth quarter of 2006, with the offset as a capital contribution.

     During the fourth quarter of 2005, the Partnership declared and accrued a $5.0 million distribution. This distribution was included in the balance sheet at December 31, 2005, in distribution payable-affiliate. In addition, for 2006, the Partnership paid a $215.2 million distribution to Holdings, for initial public offering related activities and earning distributions. A portion of this amount was distributed to Holdings from the Partnership’s distributions to its general partner. Holdings owns and controls the general partner of the partnership while Holdings is controlled by Natural Gas Partners with minority ownership by certain management personnel and board members of the Partnership’s general partner.

     As discussed in Note 4, on June 2, 2006, the Partnership acquired Midstream Gas Services, L.P., which was a portfolio company of Natural Gas Partners in its Natural Gas Partners Vll, L.P. As part of the consideration for the acquisition, Natural Gas Partners received pre-initial public offering common units in the Partnership which were converted at the time of the initial public offering. During 2006, the Partnership made distributions of $3.7 million to Natural Gas Partners for these units for the initial public offering, overallotment and other distribution activities.

     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’s Texas Panhandle Systems has the option to sell a portion of its gas supply. The Partnership has received a Letter of Credit related to this agreement. The Partnership recorded $19.4 million of revenues in 2006 from the agreement, of which there was a receivable of $2.7 million outstanding at December 31, 2006.

     In the fourth quarter of 2006, the Partnership entered into an Omnibus Agreement with Eagle Rock Energy G&P, LLC, Holdings and the Partnership’s general partner which requires the Partnership to reimburse Eagle Rock Energy G&P, LLC for the payment of certain expenses incurred on the Partnership’s behalf, including payroll, benefits, insurance and other operating expenses, and provides certain indemnification obligations.

     The Partnership does not directly employ any persons to manage or operate our business. Those functions are provided by our general partner. We reimburse the general partner for all direct and indirect costs of these services.

NOTE 9. FAIR VALUE OF FINANCIAL 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.

     The carrying amount of cash equivalents is believed to approximate their fair values because of the short maturities of

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these instruments. As of December 31, 2006, the debt associated with the Credit Agreement bore interest at floating rates. As such, carrying amounts of this debt instruments approximates fair value.

NOTE 10. RISK MANAGEMENT ACTIVITIES

     The Credit Agreement required the Partnership to enter into interest rate risk management activities. In December 2005, the Partnership 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 for a period of five years from January 1, 2006 to January 1, 2011. Amounts received or paid under these swaps were recorded as reductions or increases in interest expense. The table below summarizes the terms, amounts received or paid and the fair values of the various interest swaps:

								($ in thousands)
								Fair Value
Roll Forward	Expiration		Notional		Fixed			December 31,
Effective Date	Date		Amount		Rate			2006
01/03/2006		01/03/2011	$	100,000,000		4.9500	%	$	(319	)
01/03/2006		01/03/2011		100,000,000		4.9625			(267	)
01/03/2006		01/03/2011		50,000,000		4.8800			(295	)
01/03/2006		01/03/2011		50,000,000		4.8800			(295	)

     For the year ended December 31, 2006, the Partnership recorded a fair value gain within interest expense of $2.8 million (unrealized) and a $0.5 million realized gain. As of December 31, 2006, the fair value liability of these contracts totaled $1.2 million.

     The prices of natural gas and NGLs are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors which are beyond the Partnership’s control. In order to manage the risks associated with natural gas and NGLs, the Partnership engages in risk management activities that take the form of commodity derivative instruments. Currently these activities are governed by the general partner, which today typically prohibits speculative transactions and limits the type, maturity and notional amounts of derivative transactions. We will be implementing a Risk Management Policy which will allow management to execute crude oil, natural gas liquids and natural gas hedging instruments in order to reduce exposure to substantial adverse changes in the prices of these commodities. We intend to monitor and ensure compliance with this Risk Management Policy through senior level executives in our operations, finance and legal departments.

     In October and December 2005, the Partnership entered into the following:

• Over-the-counter NGL puts, costless collar and swap transactions for the sale of Mont Belvieu gas liquids with a combined notional amount of 530,000 Bbls per month for a term from January 2006 through December 2010;

• Condensate puts and costless collar transactions for the sale of West Texas Intermediate crude oil with a combined notional amount of 250,000 Bbls per month for a term from January 2006 through December 2010; and

• Natural gas calls for the sale of Henry Hub natural gas with a notional amount of 200,000 MMBtu per month for a term from January 2006 through December 2007.

     During 2006, the Partnership entered into the following additional risk management activities:

• Costless collar transactions for West Texas Intermediate crude oil with a combined notional amount of 50,000 Bbls per month for a term of October through December 2006; and, 60,000 Bbls per month for a term of January 2007 through December 2007.

• Fixed swap agreements to hedge WTS-WTI basis differential in amount of 20,000 Bbls per month for a term of October-December 2006; and, 20,000 Bbls per month for a term of January through December 2007.

• Natural gas fixed swap agreements to hedge short natural gas positions with a combined notional amount of 100,000 MMBtu per month for the term of August 2006 through September 2006.

     The counterparties used for these transactions have investment grade ratings. The NGL and condensate derivatives are intended to hedge the risk of weakening NGL and condensate prices with offsetting increases in the value of the puts based on

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the correlation between NGL prices and crude oil prices. The natural gas derivatives are included to hedge the risk of increasing natural gas prices with the offsetting value of the natural gas calls.

     Eagle Rock Energy has not designated these derivative instruments as hedges and as a result is marking these derivative contracts to market with changes in fair values recorded as an adjustment to the mark-to-market gains /losses on risk management transactions within revenue. For the year ended December 31, 2005, the Partnership recorded a fair value gain of $7.3 million related to these contracts. As of December 31, 2005, the fair value of these contracts totaled $34.8 million. For the year ended December 31, 2006, the Partnership recorded a loss on risk management instruments of $24.0 million, representing a fair value (unrealized) loss of $7.1 million, amortization of put premiums of $19.2 million and net (realized) settlements gain to the Partnership of $2.3 million. As of December 31, 2006, the fair value of these contracts, including the put premiums, totaled $8.4 million.

NOTE 11. COMMITMENTS AND CONTINGENT LIABILITIES

     Litigation— The Partnership is subject to several lawsuits, primarily related to the payments of liquids and gas proceeds in accordance with contractual terms. The Partnership has accruals of $1.5 million as of December 31, 2006 and $1.63 million, as of December 31, 2005, related to these matters. In addition, the Partnership is also subject to other lawsuits related to the payment of liquid and gas proceeds in accordance with contractual terms for which the Partnership has been indemnified up to a certain dollar amount. For the indemnified lawsuits, the Partnership has not established any accruals as the likelihood of these suits being successful against them is considered remote. If there ultimately is a finding against the Partnership in the indemnified cases, the Partnership could make a claim against the indemnification up to limits of the indemnification. These matters are not expected to have a material adverse effect on our financial position, results of operations or cash flows.

     Insurance— Eagle Rock Energy carries insurance coverage which includes the assets and operations, which management believes is consistent with companies engaged in similar commercial operations with similar type properties. These insurance coverages includes (1) commercial general public liability insurance for liabilities arising to third parties for bodily injury and property damage resulting from Eagle Rock Energy field operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage, (4) property insurance covering the replacement value of all real and personal property damage, including damages arising from boiler and machinery breakdowns, earthquake, flood damage and business interruption/extra expense, and (5) corporate liability policies including Directors and Officers coverage and Employment Practice liability coverage. All coverages are subject to certain deductibles, terms, and conditions common for companies with similar types of operation.

     Eagle Rock Energy also maintains excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Limits, terms, conditions and deductibles are comparable to those carried by other energy companies of similar size. The cost of general insurance coverages continued to fluctuate over the past year reflecting the changing conditions of 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, compliance with existing laws and regulations will not materially affect the financial position of the Partnership.

     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 December 31, 2006 and 2005, the Partnership had accrued $0.3 million for environmental matters.

     Other Commitments and Contingencies— The Partnership utilizes assets under operating leases for its corporate office, certain rights-of way and facilities locations, vehicles and in several areas of its operation. Rental expense, including leases with no continuing commitment, amounted to $0.2 million, $0.2 million, and $37,000 for the years ended December 31, 2006, 2005 and 2004, respectively. Rental expense for leases with escalation clauses is recognized on a straight-line basis over the

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initial lease term. At December 31, 2006, commitments under long-term non-cancelable operating leases for the next five years and thereafter are payable as follows: 2007 — $0.7 million; 2008 — $0.7 million; 2009 — $0.7 million; 2010 — $0.3 million; 2011 — $0.3 million; and thereafter — $2.0 million.

NOTE 12. SEGMENTS

     Based on the Partnership’s approach to managing its assets, the Partnership believes its operations consist of two geographic segments and one functional (corporate) segment: (i) gathering, processing, transportation and marketing of natural gas in the Texas Panhandle Systems, (ii) gathering, natural gas processing and related NGL transportation in the Texas and Louisiana System, and (iii) risk management and other corporate activities. The Partnership’s chief operating decision-maker currently reviews its operations using these segments. The Partnership evaluates segment performance based on segment margin before depreciation and amortization. Transactions between reportable segments are conducted on a basis believed to be at market values. Prior to the December 1, 2005, acquisition of the Panhandle Acquisition, the Partnership had only one segment.

     Summarized financial information concerning the Partnership’s reportable segments is shown in the following table:

			Southeast
($ in millions)			Texas and
Year Ended December 31, 2006	Panhandle		Louisiana		Corporate			Total
Sales to external customers	$	422.1	$	79.4	$	(23.1	)(a)	$	478.4
Interest expense and other financing costs		—		—		28.6			28.6
Depreciation and amortization		36.3		5.9		1.0			43.2
Segment profit (loss)(b)		104.5		19.4		(23.1	)		100.8
Capital expenditures		12.2		20.7		5.5			38.4
Segment assets		573.6		148.9		57.4			779.9

			Southeast
($ in millions)			Texas and
Year Ended December 31, 2005	Panhandle		Louisiana		Corporate			Total
Sales to external customers	$	43.0	$	23.4	$	7.3	(a)	$	73.7
Interest expense and other financing costs		—		—		4.0			4.0
Depreciation and amortization		2.9		1.0		0.1			4.1
Segment profit (b)		7.8		3.3		7.3			18.4
Capital expenditures		—		4.1		0.1			4.2
Segment assets		525.4		82.0		93.3			700.7

			Southeast
($ in millions)			Texas and
Year Ended December 31, 2004	Panhandle		Louisiana		Corporate		Total
Sales to external customers	$	—	$	10.6	$	—	$	10.6
Interest expense and other financing costs		—		—		—		—
Depreciation and amortization		—		0.6		—		0.6
Segment profit (b)		—		1.8		—		1.8
Capital expenditures		—		20.5		—		20.5
Segment assets		—		19.7		8.3		28.0

(a)	Represents results of our derivatives activity.
(b)	Segment profit (loss) is defined as sales to external customers minus cost of natural gas and natural gas liquids and other cost of sales. Sales to external customers for the corporate column include the impact of the risk management activities.

     The following table reconciles segment profit (loss) to income from continuing operations:

	Year Ended			Year Ended			Year Ended
	December 31,			December 31,			December 31,
($ in millions)	2006			2005			2004
Segment profit	$	100.8		$	18.4		$	1.8
Operations and maintenance		(32.9	)		(2.9	)		—
General and administrative		(13.2	)		(4.8	)		(2.4	)

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	Year Ended			Year Ended			Year Ended
	December 31,			December 31,			December 31,
($ in millions)	2006			2005			2004
Advisory termination fee		(6.0	)		—			—
Depreciation and amortization		(43.2	)		(4.1	)		(0.6	)
Interest expense, net		(27.6	)		(3.9	)		—
Provision for income taxes		(1.2	)		—			—
(Loss) income from continuing operations	$	(23.3	)	$	2.7		$	(1.2	)

NOTE 13. DISCONTINUED OPERATIONS

     On July 1, 2004, the Partnership closed on the sale of its Dry Trail assets for $37.4 million. The Dry Trail assets consisted of a CO₂ tertiary recovery plant near Hough, Oklahoma. The Dry Trail assets had revenues of $5.1 million in 2004, and generated income of $2.7 million, which is net of interest expense allocated to these operations of $0.3 million in 2004. All interest incurred during the period the Partnership owned the Dry Trail assets was allocated to discontinued operations as the debt was specifically related to those assets and was paid off with proceeds from the sale. The Partnership realized a gain of $19.5 million in 2004 on the sale.

NOTE 14. EMPLOYEE BENEFIT PLAN

     In 2004, the Partnership began providing a defined contribution benefit plan to its employees who have been with the Partnership longer than six months. The plan provides for a dollar for dollar matching contribution by the Partnership of up to 3% of an employee’s contribution and 50% of additional contributions up to an additional 2%. Additionally, the Partnership contributes 6% of a participating employee’s base salary annually, contributed at 3% twice a year. Expenses under the plan for the years ended December 31, 2006, 2005 and 2004 were approximately $0.3 million, $37,000 and $65,000, respectively.

NOTE 15. INCOME TAXES

     In May 2006, the State of Texas enacted a margin tax which will become effective in 2008. This margin tax will require the Partnership to determine a tax of 1.0% on our “margin,” as defined in the law, beginning in 2008 based on our 2007 results. The margin to which the tax rate will be applied generally will be calculated as our revenues for federal income tax purposes less the cost of the products sold for federal income tax purposes, in the State of Texas. Under the provisions of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes”, the Partnership is required to record the effects on deferred taxes for a change in tax rates or tax law in the period which includes the enactment date.

     Under FAS 109, taxes based on income like the Texas margin tax are accounted for using the liability method under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at the end of the period. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.

     Temporary differences related to the Partnership’s property will affect the Texas margin tax, and we have recorded a deferred tax liability in the amount of $1.2 million as of December 31, 2006.

NOTE 16. EQUITY-BASED COMPENSATION

     On October 24, 2006, the general partner for Eagle Rock Energy Partners, L.P., approved a long-term incentive plan (LTIP for its employees, directors and consultants who provide services to the Partnership covering an aggregate of 1,000,000 common unit options, restricted units and phantom units. With the consummation of the initial public offering on October 24, 2006, 124,450 restricted common units were issued to the employees and directors of the General Partner who provide services to the Partnership. The awards generally vest on the basis of one third of the award each year. During the restriction period, distribution associated with the granted awards will be held by the Partnership and will be distributed to the awardees upon the restriction lapsing. No options or phantom units have been issued to date.

     A summary of the restricted common units activity for the year ended December 31, 2006, is provided below:

	Number of			Weighted Average
	Restricted			Grant - Date Fair
	Units			Value
Outstanding at beginning of period		—		$	0
Granted		124,250			18.75
Vested		—
Forfeitures		(1,800	)		18.75
Outstanding at end of period		122,450		$	18.75

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     For the fourth quarter of 2006, compensation expense of $0.1 million was recorded related to the granted restricted units.

     As of December 31, 2006, unrecognized compensation costs related to the outstanding restricted units under our LTIP totaled $2.2 million. The granted restricted units were valued at the market price of the initial public offering less a discount for the delayed in their cash distributions during the unvested period. The remaining expense is to be recognized over a weighted average of 2.75 years.

NOTE 17. EARNINGS PER UNIT

     Basic earnings per unit is 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), we first allocated net income, or loss, by the amount of distributions made for the quarter by each class, if any. The remaining net income, or loss, after the deduction for the related quarter distribution was allocated to each class in proportion to the class’ weighted average number of units outstanding for a period, as compared to the weighted average number of units for all classes for the period. To determine the weighted average number of units outstanding for a period, we converted units existing during 2006, prior to the initial public offering, at the initial public offering conversion rate (1-for-0.7139), resulting in equivalent units for all periods. For 2005 and 2004 unit determinations, we used the initial public offering converted common and general partner units at the beginning of 2006 as the adjusted weighted average units for these earlier periods. General partner units were outstanding for this calculation as of December 1, 2005, which is the timing of the Texas Panhandle acquisition and an organization formation. There were no previous stated units during these periods. Net income for 2005 and 2004 was allocated to the common and general partner based upon the adjusted weighted average units determined above for each class.

     We issued restricted, unvested common units at the time of the initial public offering, October 24, 2006. These units will be considered in the diluted common unit weighted average number in periods of net income. In periods of net losses, such as the fourth quarter and total year 2006, the units are excluded from the diluted earnings per unit calculation due to their antidilutive effect.

     At December 31, 2006, we had 20,691,495 common units, 20,691,495 subordinated units and 844,551 general partner units outstanding. In addition, we had 122,450 restricted unvested common units granted and outstanding.

     The following table presents our calculation of basic earnings per unit for the periods indicated:

	For the Year Ended December 31,
($ in thousands)	2006			2005		2004
Net (loss) income:	$	(23,314	)	$	2,750	$	20,982
Net (loss) income allocated:
Common units		(15,229	)		2,667		20,982
Subordinated units		(7,637	)		—		—
General partner units		(448	)		83		—
Weighted average unit outstanding during period:
Common units		12,123			24,151		24,151
Subordinated units		17,873			—		—
General partner units		557			20		—
Earnings Per Unit — continuing operations:
Common units	$	(1.26	)	$	0.11	$	(0.05	)
Subordinated units	$	(0.43	)	$	—	$	—
General partner units	$	(0.80	)	$	4.06	$	(0.05	)

F - 22

NOTE 18. SUBSEQUENT EVENTS

     On February 7, 2007, the Partnership declared a $0.3625 distribution per common unit for the fourth quarter of 2006, prorated to $0.2679 per common unit for the timing of the initial public offering on October 24, 2006. The distribution to the common unitholders was paid on February 15, 2007. No distribution was made to the subordinated unitholders or general partner for the quarter.

     On April 2, 2007, the Partnership announced it has signed a definitive agreement to acquire Laser Midstream Energy, L.P. (“Laser”) and certain of its subsidiaries for an aggregate purchase price of $136.8 million, $110.0 million in cash and 1,407,895 common units, in a privately negotiated transaction. The assets subject to this transaction include gathering systems and related compression and processing facilities in South Texas, East Texas and North Louisiana. The acquisition is subject to customary closing conditions and is expected to close in late April.

     In addition, Eagle Rock has signed a definitive agreement to acquire certain fee minerals, royalties and working interest properties from Montierra Minerals & Production, L.P. (a Natural Gas Partners VII, L.P. portfolio company) and NGP-VII Income Co-Investment Opportunities, L.P. (a Natural Gas Partners affiliate). For a combined negotiated value of $127.6 million for the assets contributed to Eagle Rock, Montierra and such co-investment fund (together “Montierra”) will receive as consideration a total of 6,400,000 newly-issued common units and $6.0 million in cash. The assets conveyed in this transaction include minerals acres, and interests in wells with net proved producing reserves of approximately 4.6 billion cubic feet of gas (unaudited) and 2.5 million barrels of oil (unaudited).

     The Partnership also announced on April 2, 2007, it had entered into a unit purchase agreement to sell in a private placement 7,005,495 common units to third-party investors, for total cash proceeds of $127.5 million. The Partnership also has agreed to file a registration statement with the SEC registering for resale the common units within 90 days after the closing. The proceeds from this equity private placement will fully fund the cash portion of the purchase price of the Laser acquisition. The Partnership anticipates that the private placement will close simultaneously with the Laser acquisition.

     In addition, the Partnership has received commitments to upsize its revolver facility under its existing Amended and Restated Credit Facility by $100 million. The increase of the revolver provides the Partnership with approximately $175 million in borrowing availability.

* * * * *

F - 23

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

ONEOK Texas Field Services, L.P.

     We have audited the accompanying balance sheets of ONEOK Texas Field Services, L.P. (the “Company”) as of December 31, 2004 and November 30, 2005, and the related statements of operations, partnership capital, and cash flows for the years ended December 31, 2003 and 2004 and the eleven-month period ended November 30, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

     We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

     In our opinion, such financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2004 and November 30, 2005, and the results of its operations and its cash flows for the years ended December 31, 2003 and 2004 and for the eleven-month period ended November 30, 2005, in conformity with accounting principles generally accepted in the United States of America.

     As described in the notes 1 and 9 to the financial statements, on December 1, 2005, Eagle Rock Field Services, L.P. (a subsidiary of Eagle Rock Midstream Resources, L.P.) acquired ONEOK Texas Field Services, L.P.

/s/ DELOITTE & TOUCHE LLP

Tulsa, Oklahoma
April 28, 2006

F-24

ONEOK TEXAS FIELD SERVICES, L.P.

BALANCE SHEETS

As of December 31, 2004 and November 30, 2005

	December 31,			November 30,
	2004			2005
ASSETS
CURRENT ASSETS:
Trade accounts receivable — net	$	30,923,722		$	57,504,280
Other current assets		103,583			72,638
Total current assets		31,027,305			57,576,918
PROPERTY, PLANT, AND EQUIPMENT		277,416,065			283,937,499
Less accumulated depreciation and amortization		(33,476,890	)		(41,450,158	)
Property, plant, and equipment — net		243,939,175			242,487,341
GOODWILL		18,739,673			18,739,673
AMOUNT DUE FROM AFFILIATES — Net		10,911,596			57,543,486
INVESTMENTS AND OTHER		13,172			99,845
TOTAL ASSETS	$	304,630,921		$	376,447,263
LIABILITIES AND PARTNERSHIP CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	28,050,478		$	44,846,894
Accrued taxes		227,865			8,371,637
Merger consideration earnest money		—			15,000,000
Other current liabilities		158,364			966,197
Total current liabilities		28,436,707			69,184,728
DEFERRED INCOME TAXES		70,226,307			71,785,476
OTHER DEFERRED CREDITS		1,623,828			1,769,464
Total liabilities		100,286,842			142,739,668
COMMITMENTS AND CONTINGENCIES (Note 6)
PARTNERSHIP CAPITAL		204,344,079			233,707,595
TOTAL LIABILITIES AND PARTNERSHIP CAPITAL	$	304,630,921		$	376,447,263

See notes to financial statements.

F-25

ONEOK TEXAS FIELD SERVICES, L.P.

STATEMENTS OF OPERATIONS

For the Years Ended December 31, 2003 and 2004 and for the
Eleven-Month Period Ended November 30, 2005

					Period Ended
	Years Ended December 31,				November 30,
	2003		2004		2005
REVENUES	$	297,289,534	$	335,518,977	$	396,953,100
COSTS AND EXPENSES:
Cost of natural gas and natural gas liquids		249,283,649		263,840,261		316,978,910
Operations and maintenance		22,394,552		25,218,165		25,326,379
Depreciation and amortization		7,187,244		8,267,893		8,157,159
Ad valorem taxes		1,509,920		2,208,776		2,192,117
Total costs and expenses		280,375,365		299,535,095		352,654,565
OPERATING INCOME		16,914,169		35,983,882		44,298,535
OTHER INCOME:
Other income — net		51,752		23,145		17,312
Interest income		189,598		645,329		858,793
Total other income		241,350		668,474		876,105
INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE		17,155,519		36,652,356		45,174,640
INCOME TAX PROVISION		6,071,125		12,730,580		15,811,124
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE		11,084,394		23,921,776		29,363,516
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE — Net of tax		227,083		—		—
NET INCOME	$	10,857,311	$	23,921,776	$	29,363,516

See notes to financial statements.

F-26

ONEOK TEXAS FIELD SERVICES, L.P.

STATEMENTS OF PARTNERSHIP CAPITAL

For the Years Ended December 31, 2003 and 2004 and for the
Eleven-Month Period Ended November 30, 2005

					Period Ended
	Years Ended December 31,				November 30,
	2003		2004		2005
PARTNERSHIP CAPITAL — Beginning of period	$	169,564,992	$	180,422,303	$	204,344,079
NET INCOME		10,857,311		23,921,776		29,363,516
PARTNERSHIP CAPITAL — End of period	$	180,422,303	$	204,344,079	$	233,707,595

See notes to financial statements.

F-27

ONEOK TEXAS FIELD SERVICES, L.P.

STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2003 and 2004 and for the
Eleven-Month Period Ended November 30, 2005

							Period Ended
	Years Ended December 31,						November 30,
	2003			2004			2005
OPERATING ACTIVITIES:
Net income	$	10,857,311		$	23,921,776		$	29,363,516
Adjustments to reconcile net income to net cash provided by operating activities Depreciation and amortization		7,187,244			8,267,893			8,157,159
Provision for deferred income taxes		10,942,967			7,325,058			1,559,008
Changes in assets and liabilities:
Accounts receivable and other current assets		(23,791,047	)		(30,904,634	)		(56,598,772	)
Accounts payable and accrued liabilities		21,363,098			34,705,323			64,320,201
Other assets and liabilities		5,659,611			(1,502,400	)		801,622
Net cash provided by operating activities		32,219,184			41,813,016			47,602,734
INVESTING ACTIVITIES:
Capital expenditures		(5,203,298	)		(5,567,410	)		(6,705,325	)
Other investing activities		—			—			(2,281	)
Net cash used in investing activities		(5,203,298	)		(5,567,410	)		(6,707,606	)
FINANCING ACTIVITIES — Increase in amounts due from parent		(27,015,886	)		(36,245,606	)		(40,895,128	)
CHANGE IN CASH AND CASH EQUIVALENTS		—			—			—
CASH AND CASH EQUIVALENTS — Beginning of period		—			—			—
CASH AND CASH EQUIVALENTS — End of period		—			—			—

See notes to financial statements.

F-28

ONEOK TEXAS FIELD SERVICES, L.P.

NOTES TO FINANCIAL STATEMENTS

For the Years Ended December 31, 2003 and 2004, and for the
Eleven-Month Period Ended November 30, 2005

1. ORGANIZATION AND DESCRIPTION OF BUSINESS

     Through November 30, 2005, ONEOK Texas Field Services, L.P. (the “Company”) was a wholly-owned subsidiary of ONEOK, Inc. (“ONEOK”), and is the predecessor to Eagle Rock Energy Partners, L.P. The Company purchases, gathers and processes natural gas and extracts, sells and markets natural gas liquids (“NGLs”) in the Texas Panhandle area. We own or lease six processing facilities, and approximately 3,900 miles of gathering pipelines. On December 1, 2005, the Company merged with Eagle Rock Field Services L.P., a subsidiary of Eagle Rock Midstream Resources, L.P. Subsequent to the merger, Eagle Rock Midstream Resources, L.P. changed its name to Eagle Rock Field Services, Inc.

2. SUMMARY OF ACCOUNTING POLICIES

     Critical Accounting Policies— The following is a summary of our most critical accounting policies, which are defined as those policies most important to the portrayal of our financial condition and results of operations and requiring management’s most difficult, subjective, or complex judgment, particularly because of the need to make estimates concerning the impact of inherently uncertain matters. The development and selection of our critical accounting policies and estimates are a reflection of the policies discussed with the audit committee of ONEOK’s Board of Directors for ONEOK’s corporate accounting policies.

     Derivatives and Risk Management Activities— To minimize the risk of fluctuations in natural gas, NGLs and crude oil prices, ONEOK periodically enters into futures transactions and swaps on behalf of its subsidiary companies in order to hedge anticipated sales and purchases of natural gas and crude oil production, fuel requirements and NGL inventories on a consolidated basis. The Company, therefore, does not account for these derivative transactions on its books.

     Impairment of Goodwill and Long-Lived Assets— We assess our goodwill for impairment at least annually based on Statement of Financial Accounting Standards (“SFAS”) No. 142,Goodwill and Other Intangible Assets.An initial assessment is made by comparing the fair value of the operations with goodwill, as determined in accordance with SFAS No. 142, to the book value. If the fair value is less than the book value, an impairment is indicated and we must perform a second test to measure the amount of the impairment. In the second test, we calculate the implied fair value of the goodwill by deducting the fair value of all tangible and intangible net assets of the operations with goodwill from the fair value determined in step one of the assessment. If the carrying value of the goodwill exceeds this calculated implied fair value of the goodwill, we will record an impairment charge. We performed our annual tests of goodwill as of January 1, 2004 and 2005, and there was no impairment indicated.

     We assess our long-lived assets for impairment based on SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets.A long-lived asset is tested for impairment whenever events or changes in circumstances indicate that its carrying amount may exceed its fair value. Fair values are based on the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the assets.

     Examples of long-lived asset impairment indicators include:

• a significant decrease in the market price of a long-lived asset or asset group;

• a significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition;

• a significant adverse change in legal factors or in the business climate that could affect the value of a long-lived asset or asset group, including an adverse action or assessment by a regulator that would exclude allowable costs from the rate-making process;

• an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset or asset group;

• a current-period operating cash flow loss combined with a history of operating cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset or asset group; and

F-29

• a current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life;

     Pension and Postretirement Employee Benefits— ONEOK has a defined benefit pension plan covering substantially all full-time employees and a postretirement employee benefits plan covering most employees. No bargaining unit employees hired after December 31, 2004, are eligible for ONEOK’s defined benefit pension plan; however, they are covered by a profit sharing plan. ONEOK’s actuarial consultant calculates the expense and liability related to these plans and uses statistical and other factors that attempt to anticipate future events. These factors include assumptions about the discount rate, expected return on plan assets, rate of future compensation increases, age and employment periods. In determining the projected benefit obligations and the costs, assumptions can change from period to period and result in material changes in the costs and liabilities we recognize. Our statements of operations reflect the estimated annual expenses that ONEOK incurred on our behalf associated with pension and postretirement employee benefits by allocation.

     Contingencies— Our accounting for contingencies covers a variety of business activities including contingencies for legal exposures and environmental exposures. We accrue these contingencies when our assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be reasonably estimated in accordance with SFAS No. 5,Accounting for Contingencies.We base our estimates on currently available facts and our estimates of the ultimate outcome or resolution. Actual results may differ from our estimates resulting in an impact, either positive or negative, on earnings.

Significant Accounting Policies

     Cash and Cash Equivalents— the Company’s cash management function is performed by ONEOK. As a part of this function, the Company’s cash receipts and disbursements are transferred to ONEOK accounts on a daily basis and remitted to the Company as cash is required.

     Property, Plant, and Equipment— Gas processing plants and all other properties are stated at cost. Gas processing plants are depreciated using various rates based on estimated lives of available gas reserves. All other property and equipment are depreciated using the straight-line method over its estimated useful life. The weighted average useful lives are as follows:

Pipeline and equipment	33 years
Gas processing and equipment	25 years
Office furniture and equipment	20 years

     The costs of maintenance and repairs, which are not significant improvements, are expensed when incurred. Expenditures to extend the useful lives of the assets are capitalized.

     Revenue Recognition— We recognize revenue when services are rendered or product is delivered. We receive fees for gathering natural gas production from oil and natural gas wells under three primary contract arrangements.

• Keep-Whole— We extract NGLs and return to the producer volumes of merchantable natural gas containing the same amount of BTUs as the raw natural gas that the producer delivered to us. We then sell the natural gas liquids to an affiliate.

• Percent of Proceeds— We retain a percentage of the NGLs and/or a percentage of the natural gas as payment for gathering, compressing and processing the producer’s raw natural gas. Both the natural gas and natural gas liquids are sold to affiliates.

• Fee— We are paid a fee for the services provided such as BTUs gathered, compressed, treated and/or processed.

     Income Taxes— In 2001, the Company filed an election to be treated as a C corporation for federal income tax purposes, and was included in the consolidated federal income tax return of ONEOK. For financial reporting purposes, the Company computes its income taxes as if it filed a separate federal income tax return. Thus, deferred income taxes are recognized for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities.

     Asset Retirement Obligations— On January 1, 2003, we adopted SFAS No. 143,Accounting for Asset Retirement Obligations.SFAS No. 143 applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset.

F-30

     SFAS No. 143 requires that we recognize the fair value of a liability for an asset retirement obligation in the period when it is incurred if a reasonable estimate of the fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If the obligation is settled for an amount other than the carrying amount of the liability, we will recognize a gain or loss on settlement.

     All legal obligations for asset retirement obligations were identified and the fair value of these obligations was determined as of January 1, 2003. The obligations primarily relate to retirements of gas processing plants, compressor sites and meter sites associated with the business. As a result of the adoption of SFAS No. 143, we recorded a long-term liability of approximately $1.44 million, an increase to property, plant and equipment, net of accumulated depreciation, of approximately $1.08 million, and a cumulative effect loss of approximately $0.21 million, net of tax, in the first quarter of 2003. The related depreciation and amortization expense is immaterial to our financial statements. Subsequent changes to these amounts have been immaterial to our financial statements.

     Use of Estimates— Certain amounts included in or affecting our financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time the financial statements are prepared. Items which may be estimated include, but are not limited to, the economic useful life of assets, fair value of assets and liabilities, provisions for uncollectible accounts receivable, unbilled revenues for gas delivered but for which meters have not been read, gas purchased expense for gas received but for which no invoice has been received, provision for income taxes including any deferred tax valuation allowances, the results of litigation and various other recorded or disclosed amounts. Accordingly, the reported amounts of our assets and liabilities, revenues and expenses, and related disclosures are necessarily affected by these estimates.

     We evaluate these estimates on an ongoing basis using historical experience, consultation with experts and other methods we consider reasonable based on the particular circumstances. Nevertheless, actual results may differ significantly from the estimates. Any effects on our financial position or results of operations from revisions to these estimates are recorded in the period when the facts that give rise to the revision become known.

     Allocated Expenses— Our historical income statements reflect all of the expenses that the parent incurred on its behalf. The Company’s financial statements therefore include certain expenses incurred by its parent which may include, but are not necessarily limited to, the following:

• Officer and employee salaries

• Rent or depreciation

• Advertising

• Accounting, tax, and legal services

• Other selling, general and administrative expenses

• Costs for pension, medical, postretirement, and other employee benefits

     Environmental Expenditures— Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures that relate to an existing condition caused by past operations and that do not generate current or future revenue are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. No environmental liabilities have been recorded as of November 30, 2005 or December 31, 2004, respectively.

F-31

3. PROPERTY, PLANT, AND EQUIPMENT

     Property, plant, and equipment consisted of the following.

	As of			As of
	December 31			November 30,
	2004			2005
Land and buildings	$	101,587		$	101,587
Pipelines and related assets		272,878,005			277,318,829
Office equipment, furniture, and fixtures		1,783			127,044
Constructions in progress		3,418,233			5,404,689
Other		1,016,457			985,350
Total		277,416,065			283,937,499
Less accumulated depreciation		(33,476,890	)		(41,450,158	)
Net	$	243,939,175		$	242,487,341

4. RELATED-PARTY TRANSACTIONS

     The majority of the Company’s natural gas and natural gas liquids sales were to affiliates. Total sales to affiliates were $285.6 million, $322.9 million and $386.3 million for the years ended December 31, 2003 and 2004 and for the eleven-month period ended November 30, 2005, respectively. Trade receivables due from affiliates were $22.9 million and $56.5 million at December 31, 2004 and November 30, 2005, respectively. Additionally, ONEOK and its subsidiaries (affiliates) provided a variety of services to the Company, including cash management and financing services, employee benefits provided through ONEOK’s benefit plans, administrative services provided by ONEOK employees and management, insurance and office space leased in ONEOK’s headquarters building and other field locations. Where costs are specifically incurred on behalf of an affiliate, the costs are billed directly to the affiliate by ONEOK. In other situations, the costs are allocated to the affiliates through a variety of methods, depending upon the nature of the expense and the activities of the affiliates. For example, a benefit which applies equally to all employees is allocated based upon the number of employees in each affiliate. An expense benefiting the consolidated company but having no direct basis for allocation is allocated by a method using a combination of gross plant and investment, operating income and labor expense. All costs directly charged or allocated to the Company by affiliates are included in the statements of income and all such operating costs have been allocated by ONEOK and its affiliates.

     Our cash management function, including cash receipts and disbursements, were performed by ONEOK. These cash receipts and disbursements are included in amount due from affiliate reflected in our balance sheets. The net amount due from/(to) ONEOK was approximately $10.9 million and $57.5 million at December 31, 2004 and November 30, 2005, respectively. Amounts payable to ONEOK have no stated maturity date or interest rate. As of December 31, 2004 and November 30, 2005, ONEOK represented the balance due from/(to) parent would not be called within a twelve month period. As a result, the amount classified as due from parent has been classified as a non-current asset in the accompanying balance sheets. In connection with the cash management function, interest is allocated to the Company for funds held by ONEOK. The methodology for allocating interest income is based on affiliate cash activity and interest rates developed from market rates on ONEOK’s cash balances.

5. FAIR VALUE OF FINANCIAL INSTRUMENTS

     The fair value of cash and cash equivalents, accounts receivable and accounts payable are not materially different from their carrying amounts because of the short term nature of these instruments.

6. COMMITMENTS AND CONTINGENCIES

     Leases— We utilize assets under operating leases in several areas of operation. Combined rental expense, including leases with no continuing commitment, amounted to $1.2 million, $1.7 million and $1.6 million for the years ended December 31, 2003 and 2004, and the period ended November 30, 2005, respectively.

     Future minimum lease payments under non-cancelable operating leases as of November 30, 2005 are immaterial.

     Environmental— The Company is subject to multiple environmental laws and regulations affecting many aspects of present and future operations, including air emissions, water quality, wastewater discharges, solid wastes and hazardous material and substance management. These laws and regulations generally require the Company to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Failure to comply with these laws, regulations, permits and licenses may expose the Company to fines, penalties and/or interruptions in our operations that

F-32

could be material to the results of operations. If an accidental leak or spill of hazardous materials occurs from our lines or facilities, in the process of transporting natural gas or NGLs, or at any facility that we own, operate or otherwise use, the Company could be held jointly and severally liable for all resulting liabilities, including investigation and clean up costs, which could materially affect our results, operations and cash flow. In addition, emission controls required under the Federal Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot assure that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material adverse effect on our business, financial condition and results of operations.

     The Company’s expenditures for environmental evaluation and remediation to date have not been significant in relation to the results of operations and there were no material effects upon earnings related to compliance with environmental regulations.

     Other— The Company is a party to other litigation matters and claims, which are normal in the course of our operations. While the results of litigation and claims cannot be predicted with certainty, we believe the final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position, or liquidity.

     Regulatory Compliance— In the ordinary course of business, the Company is subject to various laws and regulations. In the opinion of management, compliance with existing laws and regulations will not materially affect the Company’s financial position.

7. INCOME TAXES

     Earnings are subject to federal income taxes. The following table shows the components of the Company’s income tax provision (benefit):

						Period Ended
	Years Ended December 31,					November 30,
	2003			2004		2005
Current income taxes (benefit)	$	(4,871,842	)	$	5,405,522	$	14,252,116
Deferred income taxes		10,942,967			7,325,058		1,559,008
Total provision for income taxes before cumulative effect of change in accounting principle		6,071,125			12,730,580		15,811,124
Tax benefit related to cumulative effect of change in accounting principle		(122,275	)		—		—
Total provision for income taxes	$	5,948,850		$	12,730,580	$	15,811,124

     Taxes computed at the corporate federal income tax rate reconcile to the reported income tax provision as follows:

							Period Ended
	Years Ended December 31,						November 30,
	2003			2004			2005
Pretax income	$	17,155,519		$	36,652,356		$	45,174,640
Federal statutory income tax rate		35	%		35	%		35	%
Provision for federal income taxes at statutory rate		6,004,432			12,828,325			15,811,124
Other — net		66,693			(97,745	)		—
Income tax provision before cumulative effect of change in accounting principle	$	6,071,125		$	12,730,580		$	15,811,124

     The Company recognizes the amount of taxes payable or refundable for the current year and recognizes deferred tax liabilities and assets for the expected future tax consequences of events and transactions that have been recognized in its financial statements or tax returns. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some or all of its deferred tax assets will not be realized. Realization of the deferred income tax assets is dependent on generating sufficient taxable income in future years.

     Deferred tax assets and liabilities are recognized for the estimated future tax effects of temporary differences between the tax basis of assets or liabilities and its reported amount in the financial statements. The measurement of deferred tax assets and liabilities is based on enacted tax laws and rules currently in effect in each of the taxing jurisdictions in which the Company has operations. Generally, deferred tax assets and liabilities are classified as current or noncurrent according to the classification of the related asset or liability for financial reporting. The estimated deferred tax effect of temporary differences and carryforwards as of December 31, 2004 and November 30, 2005 were as follows:

F-33

	December 31,		November 30,
	2004		2005
DEFERRED TAX ASSETS — Other accrued liabilities	$	212,580	$	254,919
Deferred tax liabilities:
Excess of tax over book depreciation and depletion		70,377,637		71,984,249
Other		61,250		56,146
Total deferred tax liabilities		70,438,887		72,040,395
Net deferred tax liabilities	$	70,226,307	$	71,785,476

8. EMPLOYEE BENEFIT PLANS

     Employee Benefit Plans— The Company’s income statements reflect the estimated annual expenses that ONEOK incurred on its behalf associated with pension, medical, postretirement and other employee benefits by allocation. Such allocated amounts were $1.0 million, $1.5 million and $1.7 million for the years ended December 31, 2003 and 2004, and the eleven-month period ended November 30, 2005, respectively. Primary benefit plans offered were as follows:

     Retirement Plans— We have defined benefit and defined contribution retirement plans covering substantially all employees. Certain officers and key employees are also eligible to participate in supplemental retirement plans.

     Other Postretirement Benefit Plans— We sponsor welfare care plans that provide postretirement medical benefits and life insurance to substantially all employees who retire under the retirement plans with at least five years of service. The postretirement medical plan is contributory, with retiree contributions adjusted periodically, and contains other cost sharing feature such as deductibles and coinsurance. Nonbargaining employees retiring between the ages of 50 and 55 who elect postretirement medical coverage and all nonbargaining employees hired on or after January 1, 1999 who elect postretirement medical coverage, pay 100 percent of the retiree premium for participation in the plan. Additionally, any employee who came to us through various acquisitions may be further limited in their eligibility to participate or receive any contributions from us for postretirement medical benefits.

     Thrift Plan— ONEOK has a Thrift Plan covering substantially all employees. Employee contributions are discretionary. Subject to certain limits, we match employee contributions. the Company’s income statements reflect the estimated annual expenses that ONEOK incurred on our behalf associated with the thrift plan by allocation.

     Profit Sharing Plan— ONEOK has a profit sharing plan for all nonbargaining unit employees hired after December 31, 2004. Nonbargaining unit employees who were employed prior to January 1, 2005, were given a one-time opportunity to make an irrevocable election to participate in the profit sharing plan and not accrue any additional benefits under the defined benefit pension plan after December 31, 2004. ONEOK made a contribution to the profit sharing plan each quarter equal to one percent of each participant’s compensation during the quarter. Additional discretionary employer contributions may be made at the end of each year. Employee contributions are not allowed under the plan. The Company’s income statements reflect the estimated annual expenses that ONEOK incurred on our behalf associated with the profit sharing plan by allocation.

9. SUBSEQUENT EVENT

     On December 1, 2005 Eagle Rock Field Services, L.P. (a subsidiary of Eagle Rock Midstream Resources, L.P.) acquired ONEOK Texas Field Services, L.P. for $528.0 million. In association with the purchase, prior to November 30, 2005, the Company received merger consideration earnest money of $15.0 million from Eagle Rock Pipeline, L.P.

* * * * * *

F-34

Index to Exhibits

Exhibit Number	Description
3.1	Certificate of Limited Partnership of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 3.1 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
3.2	Amended and Restated Agreement of Limited Partnership of Eagle Rock Energy Partners, L.P. (included as Appendix A to the Prospectus and including specimen unit certificate for the common units) (incorporated by reference to Exhibit 3.2 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
3.3	Certificate of Limited Partnership of Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 3.3 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
3.4	Limited Partnership Agreement of Eagle Rock Energy GP, L.P. (incorporated by reference to Exhibit 3.4 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
3.5	Certificate of Formation of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 3.5 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
3.6	Amended and Restated Limited Liability Company Agreement of Eagle Rock Energy G&P, LLC (incorporated by reference to Exhibit 3.6 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
4.1	Registration Rights Agreement dated March 27, 2006, among Eagle Rock Pipeline, L.P. and the Purchasers listed thereto (incorporated by reference to Exhibit 4.1 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
4.2	Tag Along Agreement dated March 27, 2006, among Eagle Rock Pipeline, L.P., Eagle Rock Pipeline GP, LLC, Eagle Rock Holdings, L.P. and the Purchasers listed thereto. (incorporated by reference to Exhibit 4.2 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
4.3	Form of Registration Rights Agreement between Eagle Rock Energy Partners, L.P. and Eagle Rock Holdings, L.P. (incorporated by reference to Exhibit 4.3 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
4.4	Form of Common Unit Certificate (included as Exhibit A to the Amended and Restated Partnership Agreement of Eagle Rock Energy Partners, L.P., which is included as Appendix A to the Prospectus) (incorporated by reference to Exhibit 3.2 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.1	Amended and Restated Credit and Guaranty Agreement (incorporated by reference to Exhibit 3.1 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.2	Form of Omnibus Agreement (incorporated by reference to Exhibit 3.1 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.3**	Form of Eagle Rock Energy Partners, L.P. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.4	Sale, Contribution and Exchange Agreement by and among the general and limited partners of Midstream Gas Services, L.P., Eagle Rock Energy Services, L.P. and Eagle Rock Pipeline, L.P. (incorporated by reference to Exhibit 10.4 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.5†	Natural Gas Liquids Exchange Agreement by and between ONEOK Hydrocarbon, L.P. and ONEOK Texas Field Services, L.P. (incorporated by reference to Exhibit 10.5 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.6†	Gas Sales and Purchase Agreement between MC Panhandle, Inc. (Chesapeake Energy Marketing Inc.) and MidCon Gas Services Corp. (Eagle Rock Field Services, L.P.) (incorporated by reference to Exhibit 10.6 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.7†	Brookeland Gas Facilities Gas Gathering and Processing Agreement between Union Pacific Resources Company (Anadarko E&P Company LP) and Sonat Exploration Company (Eagle Rock Field Services, L.P.) (incorporated by reference to Exhibit 10.7 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.8†	Minimum Volume Agreement between ONEOK Texas Field Services L.P. and Peak Operating of Texas, LLC (incorporated by reference to Exhibit 10.8 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.9†	Gas Purchase Agreement between ONEOK Texas Field Services L.P. and Peak Operating of Texas, LLC (incorporated by reference to Exhibit 10.9 of the registrant’s registration statement on Form S-1 (File No. 333-134750))

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Exhibit Number	Description
10.10†	Gas Purchase Contract between Warren Petroleum Company (Eagle Rock Field Services, L.P.) and Wallace Oil & Gas, Inc. (Cimarex Energy Co.) (incorporated by reference to Exhibit 10.10 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.11	Form of Contribution, Conveyance and Assumption Agreement (incorporated by reference to Exhibit 10.11 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.12**	Employment Agreement dated August 2, 2006 between Eagle Rock Energy G&P, LLC and Richard W. FitzGerald (incorporated by reference to Exhibit 10.12 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
10.13	Base Contract for Sale and Purchase of Natural Gas between Eagle Rock Field Services, L.P. and Odyssey Energy Services, LLC (incorporated by reference to Exhibit 10.13 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
14.1	Code of Ethics posted on the Company’s website atwww.eaglerockenergy.com.
21.1	List of Subsidiaries of Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 21.1 of the registrant’s registration statement on Form S-1 (File No. 333-134750))
23.1*	Consent of Deloitte & Touche LLP
24.1*	Powers of Attorney (included on page 5 of the 10-K/A)
31.1*	Certification of Periodic Financial Reports by Joseph A. Mills in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002
31.2*	Certification of Periodic Financial Reports by Alfredo Garcia in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002
32.1*	Certification of Periodic Financial Reports by Joseph A. Mills in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002
32.2*	Certification of Periodic Financial Reports by Alfredo Garcia in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002

*	Filed herewith
**	Management contract or compensatory plan or arrangement required to be filed as an exhibit hereto.
†	Portions of this exhibit have been omitted pursuant to a request for confidential treatment.

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