EAGLE ROCK ENERGY PARTNERS L P - FORM 8-K - EX-99.1 - EXHIBIT 99.1 - November 14, 2011

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8-K - FORM 8-K - EAGLE ROCK ENERGY PARTNERS L Pa8-kcoverpagec.htm
EX-23.2 - EXHIBIT 23.2 - EAGLE ROCK ENERGY PARTNERS L Pexhibit232c.htm
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EX-23.1 - EXHIBIT 23.1 - EAGLE ROCK ENERGY PARTNERS L Pexhibit231c.htm

EXHIBIT 99.1

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 accompanying consolidated balance sheets of Eagle Rock Energy Partners, L.P. and subsidiaries (the Partnership) as of December 31, 2010 and 2009, and the related consolidated statements of operations, members' equity, and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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 consolidated financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 3 to the consolidated financial statements, on December 31, 2009, the Partnership changed its method of accounting for oil and gas reserves. As discussed in Note 20 to the consolidated financial statements, the accompanying consolidated financial statements have been retrospectively adjusted for the addition of a Co-Issuer to the condensed consolidating financial information relating to subsidiary guarantees of registered debt. As discussed in Note 21 to the consolidated financial statements, the accompanying consolidated financial statements have been retrospectively adjusted for discontinued operations.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership's internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 11, 2011 (not presented herein) expressed an unqualified opinion on the Partnership's internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP
Houston, Texas
March 11, 2011, except for the retrospective adjustment for discontinued operations discussed in Note 21, as to which the date is May 17, 2011 and the retrospective adjustment for the addition of a Co-Issuer to the condensed consolidating financial information relating to subsidiary guarantees of registered debt discussed in Note 20, as to which the date is November 14, 2011







1




2
EAGLE ROCK ENERGY PARTNERS, L.P.


CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2010 AND 2009
($ in thousands)

 
December 31,
2010
 
December 31,
2009
ASSETS
 
 
 
CURRENT ASSETS:
 
 
 
Cash and cash equivalents
$
4,049

 
$
2,732

Accounts receivable(a)
75,695

 
85,784

Risk management assets
—

 
2,479

Due from affiliates
—

 
490

Prepayments and other current assets
2,498

 
2,790

Assets held for sale
8,615

 
172,176

Total current assets
90,857

 
266,451

PROPERTY, PLANT AND EQUIPMENT — Net
1,137,239

 
1,124,695

INTANGIBLE ASSETS — Net
113,634

 
128,767

DEFERRED TAX ASSET
1,969

 
1,562

RISK MANAGEMENT ASSETS
1,075

 
3,410

OTHER ASSETS
4,623

 
9,933

TOTAL
$
1,349,397

 
$
1,534,818

 
 

 
 

LIABILITIES AND MEMBERS' EQUITY
 

 
 

CURRENT LIABILITIES:
 

 
 

Accounts payable
$
91,886

 
$
89,342

Due to affiliate
56

 
60

Accrued liabilities
10,940

 
11,110

Taxes payable
1,102

 
2,416

Risk management liabilities
39,350

 
51,650

Liabilities held for sale
1,705

 
2,094

Total current liabilities
145,039

 
156,672

LONG-TERM DEBT
530,000

 
754,383

ASSET RETIREMENT OBLIGATIONS
24,711

 
19,829

DEFERRED TAX LIABILITY
38,662

 
40,246

RISK MANAGEMENT LIABILITIES
31,005

 
32,715

OTHER LONG TERM LIABILITIES
867

 
575

COMMITMENTS AND CONTINGENCIES (Note 12)
 

 
 

MEMBERS' EQUITY:
 

 
 

Common Unitholders(b)
579,113

 
484,282

Subordinated Unitholders(c)
—

 
52,058

General Partner(c)
—

 
(5,942
)
Total members' equity
579,113

 
530,398

TOTAL
$
1,349,397

 
$
1,534,818

________________________ 

(a)
Net of allowance for bad debt of $4,496 as of December 31, 2010 and $4,818 as of December 31, 2009.
(b)
83,425,378 and 54,203,471 units were issued and outstanding as of December 31, 2010 and 2009, respectively. These amounts do not include unvested restricted common units granted under the Partnership's long-term incentive plan of 1,744,454 and 1,371,019 as of December 31, 2010 and 2009, respectively.
(c)
20,691,495 subordinated units and 844,551 general partner units were issued and outstanding as of December 31, 2009. On May 24, 2010 and July 30, 2010, all of the subordinated and general partner units, respectively, were contributed to the Partnership and subsequently cancelled.


 See notes to consolidated financial statements.


F-3
EAGLE ROCK ENERGY PARTNERS, L.P.


 CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
($ in thousands)
 
 
Years Ended December 31,
 
2010
 
2009
 
2008
 REVENUE:
 

 
 

 
 

Natural gas, natural gas liquids, oil, condensate and sulfur sales
$
688,052

 
$
633,357

 
$
1,227,779

Gathering, compression, processing and treating fees
50,608

 
44,005

 
38,497

Commodity risk management (losses) gains
(8,786
)
 
(106,290
)
 
161,765

Other revenue
2,435

 
1,858

 
716

Total revenue
732,309

 
572,930

 
1,428,757

COSTS AND EXPENSES:
 

 
 

 
 

Cost of natural gas and natural gas liquids
468,304

 
470,099

 
886,019

Operations and maintenance
76,415

 
71,496

 
73,203

Taxes other than income
12,226

 
10,709

 
18,210

General and administrative
45,775

 
45,819

 
45,618

Other operating (income) expense
—

 
(3,552
)
 
10,699

Impairment expense
6,666

 
21,788

 
142,116

Goodwill impairment
—

 
—

 
30,994

Depreciation, depletion and amortization
106,398

 
108,530

 
108,356

Total costs and expenses
715,784

 
724,889

 
1,315,215

OPERATING (LOSS) INCOME
16,525

 
(151,959
)
 
113,542

OTHER INCOME (EXPENSE):
 

 
 

 
 

Interest income
111

 
187

 
771

Other income
501

 
934

 
1,318

Interest expense
(15,147
)
 
(21,591
)
 
(32,884
)
Interest rate risk management losses
(27,135
)
 
(6,347
)
 
(32,931
)
Other expense
(51
)
 
(1,070
)
 
(955
)
Total other (expense) income
(41,721
)
 
(27,887
)
 
(64,681
)
(LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
(25,196
)
 
(179,846
)
 
48,861

INCOME TAX PROVISION (BENEFIT)
(2,585
)
 
989

 
(1,459
)
(LOSS) INCOME FROM CONTINUING OPERATIONS
(22,611
)
 
(180,835
)
 
50,320

DISCONTINUED OPERATIONS, NET OF TAX
17,262

 
9,577

 
37,200

NET (LOSS) INCOME
$
(5,349
)
 
$
(171,258
)
 
$
87,520

 
 See notes to consolidated financial statements.
 









F-4
EAGLE ROCK ENERGY PARTNERS, L.P.


CONSOLIDATED STATEMENTS OF OPERATIONS (continued)
FOR THE YEARS ENDED December 31, 2010, 2009 AND 2008
(in thousands, except per unit amounts)

 
Years Ended December 31,
 
2010
 
2009
 
2008
NET (LOSS) INCOME PER COMMON UNIT—BASIC AND DILUTED:
 
 
 
 
 
Basic:
 
 
 
 
 
(Loss) Income from Continuing Operations
 
 
 
 
 
Common units
$
(0.26
)
 
$
(2.38
)
 
$
0.67

Subordinated units
$
(0.48
)
 
$
(2.48
)
 
$
0.67

General partner units
$
(0.39
)
 
$
(2.38
)
 
$
0.67

Discontinued Operations
 
 
 
 
 
Common units
$
0.22

 
$
0.13

 
$
0.51

Subordinated units
$
0.22

 
$
0.13

 
$
0.51

General partner units
$
0.22

 
$
0.13

 
$
0.51

Net Income (Loss)
 
 
 
 
 
Common units
$
(0.04
)
 
$
(2.26
)
 
$
1.18

Subordinated units
$
(0.26
)
 
$
(2.36
)
 
$
1.18

General partner units
$
(0.17
)
 
$
(2.26
)
 
$
1.18

Weighted Average Units Outstanding (in thousands)
 
 
 
 
 
Common units
68,625

 
53,496

 
51,534

Subordinated units
8,163

 
20,691

 
20,691

General partner units
488

 
845

 
845

 
 
 
 
 
 
Diluted:
 
 
 
 
 
(Loss) Income from Continuing Operations
 
 
 
 
 
Common units
$
(0.26
)
 
$
(2.38
)
 
$
0.67

Subordinated units
$
(0.48
)
 
$
(2.48
)
 
$
0.67

General partner units
$
(0.39
)
 
$
(2.38
)
 
$
0.67

Discontinued Operations
 
 
 
 
 
Common units
$
0.22

 
$
0.13

 
$
0.51

Subordinated units
$
0.22

 
$
0.13

 
$
0.51

General partner units
$
0.22

 
$
0.13

 
$
0.51

Net (Loss) Income
 
 
 
 
 
Common units
$
(0.04
)
 
$
(2.26
)
 
$
1.18

Subordinated units
$
(0.26
)
 
$
(2.36
)
 
$
1.18

General partner units
$
(0.17
)
 
$
(2.26
)
 
$
1.18

Weighted Average Units Outstanding (in thousands)
 
 
 
 
 
Common units
68,625

 
53,496

 
51,699

Subordinated units
8,163

 
20,691

 
20,691

General partner units
488

 
845

 
845


See notes to consolidated financial statements.  


F-5
EAGLE ROCK ENERGY PARTNERS, L.P.


CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
($ in thousands)

 
Years Ended December 31,
 
2010
 
2009
 
2008
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
 
 
Net (loss) income
$
(5,349
)
 
$
(171,258
)
 
$
87,520

Adjustments to reconcile net (loss) income to net cash provided by operating activities:

 
 
 

Discontinued Operations
(17,262
)
 
(9,577
)
 
(37,200
)
Depreciation, depletion and amortization
106,398

 
108,530

 
108,356

Impairment
6,666

 
21,788

 
173,110

Amortization of debt issuance costs
1,305

 
1,068

 
958

Equity in earnings of unconsolidated affiliates
20

 
(153
)
 
—

Distribution from unconsolidated affiliates—return on investment
67

 
164

 
—

Reclassing financing derivative settlements
(1,131
)
 
(8,939
)
 
11,063

Equity-based compensation
5,407

 
6,685

 
7,694

Gain of sale of assets
(371
)
 
(476
)
 
(1,265
)
Other operating income
—

 
(3,552
)
 
—

Other
196

 
210

 
(1,618
)
Changes in assets and liabilities—net of acquisitions:

 
 
 

Accounts receivable
10,208

 
18,982

 
44,747

Prepayments and other current assets
292

 
(172
)
 
941

Risk management activities
(9,195
)
 
147,751

 
(199,339
)
Accounts payable
(3,787
)
 
(36,929
)
 
(43,292
)
Due to affiliates
328

 
8,437

 
(12,491
)
Accrued liabilities
41

 
(6,411
)
 
(1,258
)
Other assets
1,058

 
1,487

 
23

Other current liabilities
(763
)
 
(407
)
 
836

Net cash provided by operating activities
94,128

 
77,228

 
138,785

CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
 
 
Additions to property, plant and equipment
(64,497
)
 
(36,134
)
 
(66,741
)
Acquisitions, net of cash acquired
(30,984
)
 
—

 
(262,245
)
Proceeds from sale of asset
171,686

 
476

 
1,294

Purchase of intangible assets
(2,660
)
 
(1,626
)
 
(2,975
)
Net cash provided by (used in) investing activities
73,545

 
(37,284
)
 
(330,667
)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
 
 
Proceeds from long-term debt
90,617

 
131,000

 
432,128

Repayment of long-term debt
(315,000
)
 
(176,000
)
 
(199,814
)
Payment of debt issuance costs
—

 
—

 
(789
)
Proceeds from derivative contracts
1,131

 
8,939

 
(11,063
)
Proceeds from Rights Offering
53,893

 
—

 
—

Transaction fees
(3,066
)
 
(1,480
)
 
—

Exercise of warrants
5,351

 
—

 
—

Repurchase of common units
(1,177
)
 
(64
)
 
—

Distributions to members and affiliates
(7,195
)
 
(35,655
)
 
(117,646
)
Net cash (used in) provided by financing activities
(175,446
)
 
(73,260
)
 
102,816

CASH FLOWS FROM DISCONTINUED OPERATIONS:
 
 
 
 
 
Operating activities
9,194

 
19,713

 
42,366

Investing activities
(104
)
 
(1,581
)
 
(3,936
)
Net cash provided by discontinued operations
9,090

 
18,132

 
38,430

NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS
1,317

 
(15,184
)
 
(50,636
)
CASH AND CASH EQUIVALENTS—Beginning of period
2,732

 
17,916

 
68,552

CASH AND CASH EQUIVALENTS—End of period
$
4,049

 
$
2,732

 
$
17,916

 
 
 
 
 
 
Interest paid—net of amounts capitalized
$
14,272

 
$
26,311

 
$
29,822

Units issued in acquisitions and from escrow for acquisitions
$
2,089

 
$
3,000

 
$
24,236

Cash paid for taxes
$
1,923

 
$
1,517

 
$
705

Issuance of common units for transaction fee
$
29,000

 
$
—

 
$
—

Investments in property, plant and equipment, not paid
$
10,922

 
$
3,761

 
$
5,534

Deferred tranasaction fees, not paid
$
—

 
$
1,155

 
$
—

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, 2010, 2009 AND 2008
($ in thousands)

 
General
Partner
 
Number of
Common
Units
 
Common
Units
 
Number of
Subordinated
Units
 
Subordinated
Units
 
Total
BALANCE — January 1, 2008
$
(3,155
)
 
50,699,647

 
$
617,563

 
20,691,495

 
$
112,360

 
$
726,768

Net income
1,009

 
—

 
61,794

 
—

 
24,717

 
87,520

Equity issued in acquisitions
—

 
2,181,818

 
24,236

 
—

 
—

 
24,236

Distribution to affiliates
—

 
—

 
(857
)
 
—

 
—

 
(857
)
Distributions
(1,643
)
 
—

 
(82,588
)
 
—

 
(33,415
)
 
(117,646
)
Vesting of restricted units
—

 
162,302

 
—

 
—

 
—

 
—

Equity-based compensation
75

 
—

 
5,442

 
—

 
2,177

 
7,694

BALANCE — December 31, 2008
(3,714
)
 
53,043,767

 
625,590

 
20,691,495

 
105,839

 
727,715

Net loss
(1,921
)
 
—

 
(122,270
)
 
—

 
(47,067
)
 
(171,258
)
Distributions
(379
)
 
—

 
(26,738
)
 
—

 
(8,538
)
 
(35,655
)
Vesting of restricted units
—

 
334,403

 
—

 
—

 
—

 
—

Repurchase of common units
—

 
(17,492
)
 
(64
)
 
—

 
—

 
(64
)
Equity-based compensation
72

 
—

 
4,789

 
—

 
1,824

 
6,685

Units returned from escrow
—

 
(7,065
)
 
(25
)
 
—

 
—

 
(25
)
Units issued from escrow
—

 
849,858

 
3,000

 
—

 
—

 
3,000

BALANCE — December 31, 2009
(5,942
)
 
54,203,471

 
484,282

 
20,691,495

 
52,058

 
530,398

Net income (loss)
734

 
—

 
(24,225
)
 
—

 
18,142

 
(5,349
)
Distributions
(483
)
 
—

 
(35,869
)
 
—

 
—

 
(36,352
)
Vesting of restricted units
—

 
798,301

 
—

 
—

 
—

 
—

Rights offering
—

 
21,557,164

 
53,893

 
—

 
—

 
53,893

Transaction costs for rights offering
—

 
—

 
(4,147
)
 
—

 
—

 
(4,147
)
Exercise of warrants
—

 
891,919

 
5,351

 
—

 
—

 
5,351

Units released from escrow
—

 
330,604

 
2,089

 
—

 
—

 
2,089

Repurchase of common units
—

 
(181,292
)
 
(1,177
)
 
—

 
—

 
(1,177
)
Equity based compensation
43

 
—

 
4,570

 
—

 
794

 
5,407

Payment of tranaction fee to Eagle Rock Holdings, L.P.
—

 
4,825,211

 
29,000

 
—

 
—

 
29,000

Cancellation of subordinated units
—

 
—

 
70,994

 
(20,691,495
)
 
(70,994
)
 
—

Acquisition of General Partner
5,648

 
1,000,000

 
(5,648
)
 
—

 
—

 
—

BALANCE — December 31, 2010
$
—

 
83,425,378

 
$
579,113

 
—

 
$
—

 
$
579,113


 See notes to consolidated financial statements.


F-7

EAGLE ROCK ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

NOTE 1. ORGANIZATION AND DESCRIPTION OF BUSINESS
 
Basis of Presentation and Principles of Consolidation—The accompanying financial statements include consolidated assets, liabilities and the results of operations of Eagle Rock Energy Partners, L.P. (“Eagle Rock Energy” or the “Partnership”). The general partner of Eagle Rock Energy is Eagle Rock Energy GP, L.P, and the general partner of Eagle Rock Energy GP, L.P. is Eagle Rock Energy G&P, LLC, both of which became wholly-owned subsidiaries of the Partnership on July 30, 2010, as further discussed in Notes 8 and 9. The transaction with Eagle Rock Energy GP, L.P. was accounted for by the Partnership as a recapitalization. The acquisition of Eagle Rock Energy G&P, LLC was accounted for as an acquisition of entities under common control, which requires the Partnership to present its financial statements as if the two entities had always been combined, similar to the pooling of interests method. The balance sheet as of December 31, 2009 and the cash flow statements for the year ended December 31, 2009 have been retrospectively adjusted to reflect the amounts due to Eagle Rock Energy G&P, LLC as accounts payable rather than due to affiliates. No retrospective adjustments were made to the statements of operations for the twelve months ended December 30, 2010, 2009 and 2008, as Eagle Rock Energy G&P, LLC did not have any operations outside of the services provided to and reimbursed by the Partnership through an omnibus agreement. In February 2011, the Partnership classified the assets and liabilities of its Wildhorse gathering system as held for sale and the operations as discontinued. Financial information for the years ended December 31, 2010, 2009 and 2008 have been retrospectively adjusted as assets and liabilities held for sale and discontinued operations (see Notes 13 and 21).

Recent Developments—  On May 21, 2010, a majority of the Partnership's unaffiliated unitholders approved the Recapitalization and Related Transactions, as defined and further discussed in Note 9.  As a result of this approval, the Partnership's subordinated units and incentive distribution rights were contributed and subsequently cancelled (see Note 8), and the Partnership consummated the sale of all of its fee mineral and royalty interests as well as its equity investment in Ivory Working Interests, L.P. (collectively, the "Minerals Business").  Operations related to the Minerals Business for the year ended December 31, 2010, have been recorded as part of discontinued operations.  Financial information related to the Minerals Business for the years ended December 31, 2009 and 2008 have been retrospectively adjusted to be reflected as assets and liabilities held-for-sale and discontinued operations (see Notes 13 and 19).  In addition, the Partnership launched a rights offering to the holders of its common units and general partner units on June 1, 2010, in which it distributed transferable subscription rights (“Rights”) to subscribe for common units and warrants to purchase additional common units.  This rights offering expired on June 30, 2010, and the Partnership issued 21,557,164 common units and 21,557,164 warrants on or about July 8, 2010.  See Note 8 for a further discussion of the rights offering.
 
Description of Business—Eagle Rock Energy is a growth-oriented limited partnership engaged in the business of gathering, compressing, treating, processing, transporting and selling natural gas, fractionating and transporting natural gas liquids, or NGLs (the “Midstream Business”) and the business of acquiring, developing and producing interests in oil and natural gas properties (the “Upstream Business”). The Partnership's natural gas pipelines gather natural gas from designated points near producing wells and transport these volumes to third-party pipelines, the Partnership's gas processing plants, utilities and industrial consumers. Natural gas transported to the Partnership's gas processing plants, either on the Partnership's pipelines or third party pipelines, is treated to remove contaminants and conditioned or processed into marketable natural gas and natural gas liquids. The Partnership conducts its midstream operations within Louisiana and three geographic areas of Texas and accordingly reports its Midstream Business results through four segments: the Texas Panhandle Segment, the South Texas Segment, the East Texas/Louisiana Segment and the Gulf of Mexico Segment.  On October 1, 2008, the Partnership completed the acquisition of 100% of the outstanding units of Millennium Midstream Partners, L.P. (“MMP”) (see Note 4).   The MMP assets include natural gas gathering and related compression and processing facilities in West Texas, Central Texas, East Texas, Southern Louisiana and the Gulf of Mexico that are now a part of the Partnership's East Texas/Louisiana Segment, South Texas Segment and which created the Partnership's Gulf of Mexico Segment.
 
On April 30, 2008, the Partnership completed the acquisition of all of the outstanding capital stock of Stanolind Oil and Gas Corp. (“Stanolind”).  The Stanolind assets include operated oil and natural gas producing properties in the Permian Basin, primarily in Ward, Crane and Pecos Counties, Texas.

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 of America. Eagle Rock Energy is the owner of a non-operating undivided interest in the Indian Springs gas processing plant and the Camp Ruby gas gathering system. Eagle Rock Energy owns these interests as

F-8

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 intercompany accounts and transactions are eliminated in the consolidated financial statements.

Oil and Natural Gas Accounting Policies
 
The Partnership utilizes the successful efforts method of accounting for its oil and natural gas properties. Leasehold costs are capitalized when incurred. Costs incurred to drill and complete development wells are capitalized. Unproved properties are assessed periodically within specific geographic areas and, if necessary, impairments are charged to expense. Geological and geophysical expenses and delay rentals are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if the well is determined to be unsuccessful. The Partnership carries the costs of an exploratory well as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well as long as the Partnership is making sufficient progress towards assessing the reserves and the economic and operating viability of the project.
 
Depletion of producing oil and natural gas properties is recorded based on units of production. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for acquisition costs using all proved reserves. Authoritative guidance requires that acquisition costs of proved properties be amortized on the basis of all proved reserves, (developed and undeveloped) and that capitalized development costs (wells and related equipment and facilities) be amortized on the basis of proved developed reserves.
 
Upon sale or retirement of complete fields of depreciable or depleted property, the book value thereof, less proceeds or salvage value, is charged or credited to income.
 
Impairment of Oil and Natural Gas Properties
 
The Partnership reviews its proved properties at the field level when management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a projection of future oil and natural gas reserves that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, and future inflation levels. If the carrying amount of an asset exceeds the sum of the undiscounted estimated future net cash flows, the Partnership recognizes impairment expense equal to the difference between the carrying value and the fair value of the asset, which is estimated to be the expected present value of discounted future net cash flows from proved reserves utilizing the Partnership's weighted average cost of capital. During the year ended December 31, 2010, the Partnership incurred impairment charges of $0.1 million in its Upstream Segment due to adjustments to reserves. During the year ended December 31, 2009, the Partnership incurred impairment charges of $8.1 million in its Upstream Segment, of which $7.9 million was a result of a decline in natural gas prices, production declines and lower natural gas liquids yields at its Flomaton field and $0.2 million in other fields due to lower natural gas prices. During the year ended December 31, 2008, the Partnership recorded impairment charges of $107.0 million in its Upstream Business as a result of substantial declines in commodity prices in the fourth quarter.  The Partnership cannot predict the amount of additional impairment charges that may be recorded in the future.
 
Unproved leasehold costs are reviewed periodically and a loss is recognized to the extent, if any, that the cost of the property has been impaired. Unproved properties that are individually insignificant are amortized. Unproved properties that are individually significant are assessed for impairment on a property-by-property basis. If considered impaired, costs are charged to expense when such impairment is deemed to have occurred. During the year ended December 31, 2010, the Partnership recorded impairment charges of $3.4 million to certain fields in its unproved properties as the Partnership determined it would not be technologically feasible to develop these unproved locations.
 
Asset Retirement Obligations
 
The Partnership is required to make estimates of the future costs of the retirement obligations of its producing oil and natural gas properties. This requirement necessitates that the Partnership make estimates of property abandonment costs that, in some cases, will not be incurred until a substantial number of years in the future. Such cost estimates could be subject to significant revisions in subsequent years due to changes in regulatory requirements, technological advances and other factors that may be difficult to predict.
 

F-9

Other Significant Accounting Policies
 
Use of Estimates—The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported period. Significant estimates are required for proved oil and natural gas reserves, which can affect the carrying value of oil and natural gas properties. The Partnership evaluates its estimates and assumptions on a regular basis. The Partnership bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from those estimates and such differences could be material.

Cash and Cash Equivalents—Cash and cash equivalents include certificates of deposit and other highly liquid investments 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. 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 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.  The following is the activity within the Partnership's allowance for doubtful accounts during the years ended December 31, 2010, 2009 and 2008.
 
 
2010
 
2009
 
2008
($ in thousands)
 
 
 
 
 
Balance at beginning of period
$
4,818

 
$
12,080

 
$
1,046

Charged to bad debt expense
(122
)
 
535

 
11,136

Write-offs/adjustments charged to allowance
(200
)
 
(7,797
)
 
(102
)
Balance at end of period
$
4,496

 
$
4,818

 
$
12,080

 
Of the $11.1 million charged to bad debt expense during the year ended December 31, 2008, $10.7 relates to outstanding receivables from SemGroup, L.P., which filed for bankruptcy in July 2008.  During the year ended December 31, 2009, the Partnership wrote off $7.3 million related to SemGroup, L.P. This amount relates to the non-503(b)(9) claims and the portion of the receivables sold in August 2009 (see Note 18 for further discussion).
 
Certain Other Concentrations—The Partnership relies on natural gas producers for its Midstream Business's natural gas and natural gas liquid supply, with the top two producers (by segment) accounting for 24% of its natural gas supply in the Texas Panhandle Segment, 20% of its natural gas supply in the East Texas/Louisiana Segment and 62% of its natural gas supply in the South Texas Segment, and in the Gulf of Mexico Segment, three customers accounted for 84% of its natural gas supply for the year ended December 31, 2010. While there are numerous natural gas and natural gas liquid producers, and some of these producers 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. These percentages are calculated based on MMBtus gathered during the year ended December 31, 2010. For the year ended December 31, 2010, ONEOK Hydrocarbon, the Partnership's largest customer, represented 29% of its total sales revenue (including realized and unrealized gains on commodity derivatives).
 
Inventory—Inventory is stated at the lower of cost or market, with cost being determined using the standard cost method, which approximates actual costs on a first-in-first-out or average basis. At December 31, 2010, the Partnership had $0.5 million of crude oil finished goods inventory which is recorded as part of Other Current Assets within the Consolidated Balance Sheet.


F-10

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, and oil and gas properties, which are carried at cost less accumulated depreciation, depletion and amortization. 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 over estimated useful lives of the Partnership's newly developed or acquired assets. The weighted average useful lives are as follows:
 
Plant Assets
20 years
Pipelines and equipment
20 years
Gas processing and equipment
20 years
Office furniture and equipment
5 years
 
The Partnership capitalizes interest costs on major projects during extended construction time periods. Such interest costs are allocated to property, plant and equipment and amortized over the estimated useful lives of the related assets. During the years ended December 31, 2010, 2009 and 2008, the Partnership capitalized interest costs of approximately $0.4 million, $0.1 million, and $0.4 million, respectively.
 
Impairment of Long-Lived Assets—Management evaluates whether the carrying value of non-oil and natural gas 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 assets. 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.
 
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.  During the year ended December 31, 2010, the Partnership recorded impairment charges of $29.3 million related to its Midstream Business due to (i) $3.1 million due to the notification during the second quarter 2010 that a significant gathering contract on its Raymondville system in its South Texas Segment would be terminated during the third quarter of 2010 and (ii) $26.2 million, recorded within discontinued operations in our South Texas Segment, due to an anticipated decline in volumes on its Wildhorse gathering system. During the year ended December 31, 2009, the Partnership recorded impairment charges related to certain processing plants, pipelines and contracts in its Midstream business of $13.7 million due to reduced throughput volumes.  During the year ended December 31, 2008, the Partnership recorded an impairment charge related to certain processing plants, pipelines and contracts in its Midstream business of $35.1 million due to the substantial decline in commodity prices in the fourth quarter as well as declining drilling activity by its producer customers.  Due to the percent-of-proceeds, fixed recovery and keep-whole contract arrangements the Partnership operates under with some of its producer customers, cash flows are dependent up the selling price of the natural gas and natural gas liquids processed by its plants.  Under these arrangements, lower commodity prices result in lower margins.  In addition, lower commodity prices influence the drilling activity of the Partnership's producer customers.  Lower drilling activity reduces the future volumes of natural gas projected to flow through the Partnership's gathering systems, thus reducing

F-11

both the equity volumes attributable to the Partnership and the fees generated under the fee-based arrangements the Partnership operates under as part of its Midstream Business.

Goodwill—Goodwill acquired in connection with business combinations represent the excess of consideration over the fair value of tangible net assets and identifiable intangible assets acquired. Certain assumptions and estimates are employed in determining the fair value of assets acquired and liabilities assumed, as well as in determining the allocation of goodwill to the appropriate reporting unit.
 
During the year ended December 31, 2008, the Partnership performed its annual impairment test in May 2008 and determined that no impairment appeared evident. The Partnership's goodwill impairment test involves a comparison of the fair value of each of its reporting units with their carrying value. The fair value is determined using discounted cash flows and other market-related valuation models. Certain estimates and judgments are required in the application of the fair value models.  As a result of the impairment charge incurred within the Partnership's Upstream Segment during the fourth quarter of 2008 which resulted from the substantial decline in commodity prices during the fourth quarter of 2008, the Partnership performed an assessment of its goodwill and recorded an impairment charge of $31.0 million, which reduced its goodwill amount to zero.  No such impairment was recorded in the years ended December 31, 2010 or 2009.  At December 31, 2010, 2009 and 2008, the Partnership had gross goodwill of $31.0 million, $31.0 million and $31.0 million, respectively, and accumulated impairment losses of $31.0 million, $31.0 million and $31.0 million, respectively.
 
Other Assets— As of December 31, 2010, other assets primarily consist of costs associated with: debt issuance costs, net of amortization ($1.9 million); business deposits to various providers and state or regulatory agencies ($1.6 million); and investment in unconsolidated affiliates ($1.1 million). As of December 31, 2009, other assets primarily consist of costs associated with: debt issuance costs, net of amortization ($3.2 million); business deposits to various providers and state or regulatory agencies ($1.1 million); and investment in unconsolidated affiliates ($13.3 million).
 
Within the Partnership's investments of unconsolidated affiliates, the Partnership owns 5.0% of the common units of each of Buckeye Pipeline, L.P. and Trinity River, LLC. The Partnership also owns a 50% joint venture in Valley Pipeline, LLC. and Sweeny Gathering, L.P.  These investments are accounted for under the equity method and as of December 31, 2010 are not considered material to the Partnership's financial position or results of operations.
 
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. For the Midstream Business, as of December 31, 2010, the Partnership had imbalance receivables totaling $0.8 million and imbalance payables totaling $1.2 million, respectively. For the Midstream business, as of December 31, 2009, the Partnership had imbalance receivables totaling $0.3 million and imbalance payables totaling $2.9 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, crude oil 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 the Partnership generates revenues from transportation fees.
 
Revenues associated with sales of natural gas, NGLs, crude oil and condensate are recognized when title passes to the customer, which is when the risk of ownership passes to the customer and physical delivery occurs. Revenues associated with transportation and processing fees are recognized when the service is provided.
 

F-12

For gathering and processing services, Eagle Rock Energy either receives fees or commodities from natural gas producers depending on the type of contract. 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. Commodities received are in turn sold and recognized as revenue in accordance with the criteria outlined above. Under the keep-whole contract type, Eagle Rock Energy purchases wellhead natural gas to return to the producer and sells processed natural gas and NGLs to third parties.
 
Transportation, compression and processing-related revenues 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.
 
The Partnership's Upstream Segment has elected the entitlements method to account for production imbalances. Imbalances occur when the Partnership sells more or less than its entitled ownership percentage of total production. In accordance with the entitlements method, any amount received in excess of the partnership's share is treated as a liability. If the Partnership receives less than its entitled share, the underproduction is recorded as a receivable. As of December 31, 2010, the Partnership's Upstream Segment had an imbalance receivable balance of $0.5 million. As of December 31, 2009, the Partnership's Upstream Segment had an imbalance receivable balance of $1.9 million and an imbalance payable balance of $0.5 million.
 
A significant portion of the Partnership's sale and purchase arrangements are accounted for on a gross basis in the consolidated 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. Under authoritative guidance, purchase and sale agreements with the same counterparty are required to be recorded on a net basis.  For the years ended December 31, 2010, 2009 and 2008, the Partnership did not enter into any purchase and sale agreements with the same counterparty.

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.
 
Income Taxes—Provision for income taxes is primarily applicable to the Partnership's state tax obligations under the Revised Texas Franchise Tax (the “Revised Texas Franchise Tax”) and certain federal and state tax obligations of Eagle Rock Energy Acquisition Co., Inc. and Eagle Rock Upstream Development Company, Inc., both of which are consolidated subsidiaries. Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities of the tax paying entities for financial reporting and tax purposes.
 
In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax. In May 2006, the State of Texas expanded its pre-existing franchise tax to include limited partnerships, limited liability companies, corporations and limited liability partnerships. As a result of the change in tax law, the Partnership's tax status in the State of Texas changed from non-taxable to taxable effective with the 2007 tax year.
 
Since the Partnership is structured as a pass-through entity, it is not subject to federal income taxes. As a result, its partners are individually responsible for paying federal and certain income taxes on their share of the Partnership's taxable income. Since the Partnership does not have access to information regarding each partner's tax basis, it cannot readily determine the total difference in the basis of the Partnership's net assets for financial and tax reporting purposes.
 
In accordance with authoritative guidance, the Partnership must recognize the tax effects of any uncertain tax positions it may adopt, if the position taken by it is more likely than not sustainable. If a tax position meets such criteria, the tax effect to be recognized by the Partnership would be the largest amount of benefit with more than a 50% chance of being realized upon settlement. This guidance was effective January 1, 2007, and the Partnership's adoption of this guidance had no material impact on its financial position, results of operations or cash flows. See Note 15 for additional information regarding the Partnership's income taxes.
 

F-13

Derivatives—Authoritative guidance establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It 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. The guidance provides that normal purchase and normal sale contracts, when appropriately designated, are not subject to the guidance. 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 and crude oil purchase and sales contracts are designated as normal purchases and sales. Substantially all forward contracts fall within a one-month to four-year term; however, the Partnership does have certain contracts which extend through the life of the dedicated production. The terms of these contracts generally preclude unplanned netting. 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 consolidated 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 11 for a description of the Partnership's risk management activities.

Fair Value Measurement—Authoritative guidance establishes accounting and reporting standards for assets and liabilities carried at fair value. The guidance provides definitions of fair value and expands the disclosure requirements with respect to fair value a specifies a hierarchy of valuation techniques based on the inputs used to measure fair value. See Note 10 for additional information regarding the Partnership's assets and liabilities carried at fair value.

NOTE 3. NEW ACCOUNTING PRONOUNCEMENTS
 
The Financial Accounting Standards Board (the “FASB”) has codified a single source of U.S. Generally Accepted Accounting Principles (U.S. GAAP), the Accounting Standards Codification.  Unless needed to clarify a point to readers, the Partnership will refrain from citing specific section references when discussing application of accounting principles or addressing new or pending accounting rule changes.

In January 2010, the FASB issued updated authoritative guidance which aligns the current oil and natural gas reserve estimation and disclosure requirements of the Extractive Industries - Oil and Gas guidance, as discussed above.  This guidance expands the disclosures required for equity method investments, revises the definition of oil- and natural gas-producing activities to include nontraditional resources in reserves unless not intended to be upgraded into synthetic oil or natural gas, amends the definition of proved oil and natural gas reserves to require 12-month average pricing in estimating reserves, amends and adds definitions in the Master Glossary that is used in estimating proved oil and natural gas quantities and provides guidance on geographic areas with respect to disclosure of information about significant reserves. This guidance must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate and is effective for entities with annual reporting periods ending on or after December 31, 2009. The Partnership adopted this guidance effective December 31, 2009. (See Note 21).
 
In June 2009, the FASB issued authoritative guidance which reflects the FASB’s response to issues entities have encountered when applying previous guidance.  In addition, this guidance addresses concerns expressed by the SEC, members of the United States Congress, and financial statement users about the accounting and disclosures required in the wake of the subprime mortgage crisis and the deterioration in the global credit markets.  In addition, because this guidance eliminates the exemption from consolidation for qualified special-purpose entities (“QSPEs”) a transferor will need to evaluate all existing QSPEs to determine whether they must be consolidated.   This guidance was effective for the Partnership on January 1, 2010 and did not have a material impact on its consolidated financial statements   
 
In June 2009, the FASB issued authoritative guidance, which amends the consolidation guidance applicable to variable interest entities ("VIEs"). The amendments will significantly affect the overall consolidation analysis.  While the FASB’s discussions leading up to the issuance of this guidance focused extensively on structured finance entities, the amendments to the consolidation guidance affect all entities and enterprises, as well as qualifying special-purpose entities (QSPEs) that were excluded from previous guidance.  Accordingly, an enterprise will need to carefully reconsider its previous conclusions, including (1) whether an entity is a VIE, (2) whether the enterprise is the VIE’s primary beneficiary, and (3) what type of financial statement disclosures are required.  This guidance was effective for the Partnership on January 1, 2010 and did not have a material impact on its consolidated financial statements.  


F-14

In September 2009, the FASB issued a consensus which revises the standards for recognizing revenue on arrangements with multiple deliverables.  Before evaluating how to recognize revenue for transactions with multiple revenue generating activities, an entity should identify all the deliverables in the arrangement and, if there are multiple deliverables, evaluate each deliverable to determine the unit of accounting and whether it should be treated separately or in combination.  The consensus removes certain thresholds for separation, provides criteria for allocation of revenue amongst deliverables and expands disclosure requirements.  This standard was effective for the Partnership on January 1, 2011 and will not have a material impact on the Partnership's consolidated financial statements. 

In January 2010, the FASB issued additional guidance on fair value disclosures. The new guidance clarifies two existing disclosure requirements and requires new disclosures such as: (1) a “gross” presentation of activities (purchases, sales, and settlements) within the Level 3 rollforward reconciliation, which will replace the “net” presentation format; and (2) detailed disclosures about the transfers in and out of Level 1 and 2 measurements. This guidance is effective for the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 rollforward information, which is required for annual reporting periods beginning after December 15, 2010, and for interim reporting periods within those years. The Partnership adopted the fair value disclosures guidance on January 1, 2010, except for the gross presentation of the Level 3 rollforward information which was not required to be adopted by the Partnership until January 1, 2011. The presentation of the table disclosing the assets and liabilities by hierarchy level as of December 31, 2009 has been changed to conform to the presentation as of December 31, 2010 (see Note 10).

NOTE 4. ACQUISITIONS
 
2010 Acquisitions

On September 30, 2010, the Partnership acquired certain additional interests in the Big Escambia Creek Field (and the
nearby Flomaton and Fanny Church Fields) from Indigo Minerals, LLC for $3.9 million in cash on hand. These interests are in wells in which the Partnership currently owns significant interests and are nearly 100% operated by the Partnership. The entire purchase price was allocated to proved properties.

On October 19, 2010, the Partnership acquired certain natural gas gathering systems and related facilities located primarily in Wheeler and Hemphill Counties in the Texas Panhandle from Centerpoint Energy Field Services, Inc. ("CEFS"). The closing purchase price for the assets was $27.0 million, subject to customary post-closing adjustments. The assets acquired include over 200 miles of gathering pipeline and related compression and dehydration facilities, together with gas gathering contracts, rights of way and other intangible assets. The assets are located in the core of the highly active and prolific Granite Wash play and are highly complementary to the Partnership's existing East Panhandle system.

The preliminary purchase price was allocated based on their respective fair value as determined by management with the assistance of K.E. Andrews & Company, a third-party valuation specialist.  The purchase price allocation is set forth below (in thousands):
 
Property, plant and equipment
$
22,917

Intangibles, rights-of-way
4,583

Other current assets
147

Other current liabilities
(344
)
Asset retirement obligations
(260
)
 
$
27,043

 
The Partnership commenced recording results of operations related to these assets acquired from CEFS on October 19, 2010.


F-15

2008 Acquisitions
 
Update on Millennium Acquisition. On October 1, 2008, the Partnership completed the acquisition of 100% of the outstanding units of Millennium Midstream Partners, L.P. (“MMP”). MMP is in the natural gas gathering and processing business, with assets located in East, Central and West Texas and South Louisiana. With respect to the South Louisiana assets acquired in the acquisition, the Yscloskey and North Terrebonne facilities were flooded with three to four feet of water as a result of the storm surges caused by Hurricanes Ike and/or Gustav. The North Terrebonne facility came back on-line in November 2008 and the Yscloskey facility came back on-line in January 2009. The former owners of MMP provided the Partnership indemnity coverage for Hurricanes Gustav and Ike to the extent losses are not covered by insurance and established an escrow account of 1,818,182 common units and $0.6 million in cash available for the Partnership to recover against for this purpose. As of December 31, 2009, the escrow account held 391,304 common units. During the year ended December 31, 2010, the Partnership released 330,604 units out of escrow to the former owners of MMP and recovered the remaining 60,700 units held in escrow. As of December 31, 2010, the Partnership had an additional claim for $0.2 million cash out of escrow.

As a result of releasing the 330,604 units out of escrow to the former owners of MMP, the Partnership adjusted its purchase price allocation with respect to the Millennium Acquisition. As of December 31, 2010, the total purchase price was $212.9 million. With respect to the Millennium Acquisition, the Partnership increased the amount allocated to pipelines, plants
and intangibles by $1.2 million, $0.8 million and $0.3 million, respectively.

NOTE 5. PROPERTY PLANT AND EQUIPMENT AND ASSET RETIREMENT OBLIGATIONS
 
Fixed assets consisted of the following:
 
 
December 31, 2010
 
December 31, 2009
 
  ($ in thousands)
Land
$
2,629

 
$
1,559

Plant
251,436

 
242,010

Gathering and pipeline
666,163

 
642,778

Equipment and machinery
26,408

 
22,279

Vehicles and transportation equipment
4,251

 
4,232

Office equipment, furniture, and fixtures
1,120

 
1,248

Computer equipment
8,486

 
6,912

Corporate
126

 
126

Linefill
4,269

 
4,269

Proved properties
471,781

 
435,789

Unproved properties
1,304

 
7,264

Construction in progress
42,416

 
15,513

 
1,480,389

 
1,383,979

Less: accumulated depreciation, depletion and amortization
(343,150
)
 
(259,284
)
Net property plant and equipment
$
1,137,239

 
$
1,124,695

 
Depreciation expense for the years ended December 31, 2010, 2009 and 2008 was approximately $54.2 million, $51.5 million and $43.6 million, respectively. Depletion expense for the year ended December 31, 2010, 2009 and 2008 was approximately $30.0 million, $33.7 million and $45.0 million, respectively. During the year ended December 31, 2010, the Partnership recorded impairment charges of $2.6 million related to its pipeline and plant assets due to the notification during the second quarter 2010 that a significant gathering contract in its South Texas Segment would be terminated during the third quarter of 2010, $0.1 million of proved properties in its Upstream segment due to adjustments to reserves and $3.4 million of impairment charges related to unproved properties in the Upstream Segment due to the fact that the Partnership determined it would not be technologically feasible to develop these unproved locations. During the year ended December 31, 2009, the Partnership recorded impairment charges related to its pipeline assets and proved properties of $12.6 million and $8.1 million, respectively.  During the year ended December 31, 2008, the Partnership recorded impairment charges related to its plants, gathering and pipeline assets and proved properties of $4.3 million, $19.5 million and $107.0 million, respectively.
 

F-16

Asset Retirement Obligations—The Partnership recognizes asset retirement obligations for its oil and gas working interests associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. The Partnership records the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. The Partnership recognizes asset retirement obligations for its midstream assets in accordance with the term “conditional asset retirement obligation,” which refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional upon a future event that may or may not be within the Partnership's control. Although uncertainty about the timing and/or method of settlement may exist and may be conditional upon a future event, the obligation to perform the asset retirement activity is unconditional. Accordingly, the Partnership is required to recognize a liability for the fair value of a conditional asset retirement obligation upon initial recognition if the fair value of the liability can be reasonably estimated. As of December 31, 2009, the Partnership had $1.0 million restricted in an escrow account for purposes of settling associated asset retirement obligations in the State of Alabama, which was released out of escrow during the year ended December 31, 2010.
 
A reconciliation of the Partnership's liability for asset retirement obligations is as follows:
 
 
2010
 
2009
 
2008
 
 ($ in thousands)
Asset retirement obligations—January 1 
$
19,829

 
$
19,872

 
$
11,337

Additional liability
1,019

 
—

 
204

Liabilities settled 
(1,175
)
 
(1,324
)
 
—

Revision to liabilities
2,582

 
—

 
—

Additional liability related to acquisitions
663

 
—

 
7,260

Accretion expense
1,793

 
1,281

 
1,071

Asset retirement obligations—December 31
$
24,711

 
$
19,829

 
$
19,872

 
During the year ended December 31, 2010, the Partnership made revisions of $2.6 million to increase certain asset retirement obligations due to changes in the estimate of the costs to remediate, as well as changes in the estimates of the timing of settlement.

NOTE 6. 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 $22.2 million, $23.2 million and $19.7 million for the years ended December 31, 2010, 2009 and 2008, respectively. Estimated aggregate amortization expense for each of the five succeeding years is as follows: 2011—$12.1 million; 2012—$11.7 million; 2013—$10.5 million; 2014—$7.0 million; and 2015 —$7.0 million.  Intangible assets consisted of the following (as of December 31, 2010 and 2009): 
 
December 31, 2010
 
December 31, 2009
 
($ in thousands)
Rights-of-way and easements—at cost
$
91,490

 
$
84,746

Less: accumulated amortization
(20,552
)
 
(15,504
)
Contracts
122,601

 
121,150

Less: accumulated amortization
(79,905
)
 
(61,625
)
Net intangible assets
$
113,634

 
$
128,767

 
The amortization period for the Partnership's rights-of-way and easements is 20 years. The amortization period for contracts range from 5 to 20 years, and are approximately 8 years on average as of December 31, 2010.  During the year ended December 31, 2010, the Partnership recorded impairment charges of $0.5 million related to rights-of-way. During the year ended December 31, 2009, the Partnership recorded impairment charges related to its Rights-of-way and easements of $1.1 million.  During the year ended December 31, 2008, the Partnership recorded impairment charges related to its rights-of-way and easements and contracts of $3.7 million and $7.6 million, respectively.
 

F-17

NOTE 7. LONG-TERM DEBT
 
Long-term debt consisted of:
 
December 31, 2010
 
December 31, 2009
 
($ in thousands)
Revolving credit facility
$
530,000

 
$
754,383

Total debt
530,000

 
754,383

Less: current portion
—

 
—

Total long-term debt
$
530,000

 
$
754,383

 
On December 13, 2007, the Partnership entered into a senior secured revolving credit facility (the “Revolving Credit Facility”) with aggregate commitments of $800 million. During the year ended December 31, 2008, the Partnership exercised $180 million of its $200 million accordion feature of the Revolving Credit Facility, which increased the total commitment to $980 million.  The Revolving Credit Facility was entered into with a syndicate of commercial and investment banks, led by Wachovia Capital Markets, LLC and Bank of America Securities LLC as joint lead arrangement agents and joint book runners. The Revolving Credit Facility provided for $980 million aggregate principal amount of revolving commitments and had a maturity date of December 13, 2012. The Revolving Credit Facility provided the Partnership with the ability to potentially increase the total amount of revolving commitments by an additional $20 million to a total of $1 billion.  Subsequently, as a result of Lehman Brothers’ bankruptcy filing, the amount of available commitments was reduced by the unfunded portion of Lehman Brother's commitment in an amount of approximately $9.1 million to a total of $970.9 million and the potential increase in commitments was reduced by approximately $0.5 million to a total of approximately $19.5 million.

On March 8, 2010, the Partnership entered into the Second Amendment (the “Credit Facility Amendment”) to its Revolving Credit Facility. In connection with its unitholders' approval of the Global Transaction Agreement and related matters (see Note 9), the Credit Facility Amendment became effective.

The Credit Facility Amendment modified the definition of “Change in Control” in such a way that the exercising of the GP Acquisition Option, as defined in Note 9, did not trigger a “Change in Control” event and potential default. In addition to modifying the definition of “Change in Control,” the Credit Facility Amendment also:

•
reduced the maximum permitted Senior Secured Leverage Ratio (as such term is defined in the credit agreement) from 4.25 to 1.0 under the current credit agreement to 3.75 to 1.0 (and from 4.75 to 1.0 to 4.25 to 1.0 for specified periods following certain permitted acquisitions). The Senior Secured Leverage Ratio covenant is only relevant if the Partnership has unsecured senior or subordinated notes outstanding;

•
obligated the Partnership to use $100 million of the proceeds from the sale of the Minerals Business (described in Note 19) to make a mandatory prepayment towards its outstanding borrowings under the revolving credit facility, which mandatory prepayment was made on May 25, 2010; and

•
reduced, upon such mandatory prepayment, its borrowing capacity under the revolving credit facility by the $100 million amount of such mandatory prepayment to $880 million; however, this did not impact its availability under the Partnership's revolving credit facility because it is limited by compliance with financial covenants.

The Credit Facility Amendment further clarifies that the proceeds from the sale of the Minerals Business in excess of$100 million may be used to immediately reduce debt, but will not result in a mandatory prepayment unless such proceeds are not reinvested in Property (as defined in the credit agreement) within the 270-day post-closing period (i.e. by February 18, 2011) provided in the credit agreement. On May 28, 2010, the Partnership repaid an additional $72 million towards its outstanding borrowings under the revolving credit facility from proceeds from the sale of the Minerals Business. The Partnership does not anticipate any further reductions in commitments under the Credit Facility resulting from the sale of the Minerals Business.

At the Partnership's election, its outstanding indebtedness bears interest on the unpaid principal amount either at a base rate plus the applicable margin (currently 0.75% per annum based on the Partnership's total leverage ratio and utilization of its borrowing base as part of its total indebtedness); or at the Adjusted Eurodollar Rate plus the applicable margin (currently 1.875% per annum based on the Partnership's total leverage ratio and utilization of its borrowing base as part of its total

F-18

indebtedness). At December 31, 2010, the weighted average interest rate on the Partnership's outstanding debt balance was 5.94%.
 
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-, six-, nine- or twelve months, as selected by the Partnership. The Partnership pays a commitment fee equal to (1) the average of the daily differences between (a) the revolver commitments and (b) the sum of the aggregate principal amount of all outstanding loans times (2) 0.30% per annum, based on its current leverage ratio and borrowing base utilization. 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 where 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 obligation under the Revolving Credit Facility are secured by first priority liens on substantially all for the Partnership's assets, including a pledge of all of the capital stock of each of its subsidiaries.

The Revolving Credit Facility contains various covenants which limit the Partnership's ability to grant 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 Revolving Credit Facility 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 2.5% of tangible net worth.
 
The Revolving Credit Facility also contains covenants, which, amount other things, require the Partnership, on a consolidated basis, to maintain specified ratios or conditions as follows:
 
•
Consolidated EBITDA (as defined) to Consolidated Interest Expense (as defined) of not less than 2.5 to 1.0;
 
•
Total Funded Indebtedness (as defined) to Adjusted Consolidated EBITDA (as defined) of not more than 5.0 to 1.0 (5.25 to 1.0 for the three quarters following a material acquisition); and
 
•
Borrowing Base Indebtedness (as defined) not to exceed the Borrowing Base (as defined) as re-determined from time to time.

As of December 31, 2010, the Partnership was in compliance with the financial covenants under its revolving credit facility and has not been subject to mandatory repayments and/or a commitment reduction for asset and property sales, reductions in borrowing base and for insurance/condemnation proceeds.
 
The Partnership's credit facility accommodates, through the use of a  borrowing base for its Upstream Business and traditional cash-flow based covenants for its Midstream Business, the allocation of indebtedness to either its Upstream Business (to be measured against the borrowing base) or to its Midstream Business (to be measured against the cash-flow based covenant.

On October 19, 2010, the Partnership announced that the borrowing base under its revolving credit facility, which relates to our Upstream Business, was set at $140 million by its commercial lenders as part of its regularly scheduled semi-annual borrowing base redetermination. This was an increase from the $130 million our borrowing base was set at during the April 2010 redetermination. The redetermined borrowing base was effective October 1, 2010, with no additional fees or increase in interest rate spread incurred.

Based upon total commitments as of December 31, 2010, the Partnership had approximately $341 million of unused capacity under the Revolving Credit Facility at December 31, 2010 on which the Partnership pays a 0.35% commitment fee per year.

The Revolving Credit Facility includes a sub-limit for the issuance of standby letters of credit for a total of $200 million. At December 31, 2010, the Partnership had $0.8 million of outstanding letters of credit.

In certain instances defined in the Revolving Credit Facility, the Partnership's outstanding debt is subject to mandatory repayments and/or is subject to a commitment reduction for asset and property sales, reductions in borrowing base and for insurance/condemnation proceeds.

F-19


During the year ended December 31, 2008, the Partnership incurred an additional $0.8 million of debt issuance costs in connection with exercising the accordion feature of the Revolving Credit Facility.  During the years ended December 31, 2010, 2009 and 2008, the Partnership recorded approximately $1.3 million, $1.1 million and $1.0 million of debt issuance amortization expense, respectively. As of December 31, 2010 the unamortized amount of debt issuance cost was $1.9 million.
 
Scheduled maturities of long-term debt as of December 31, 2010, were as follows: 
 
Principal Amount
 
($ in thousands)
2011
—

2012
530,000

 
$
530,000

 


F-20

NOTE 8. MEMBERS’ EQUITY
 
At December 31, 2010, there were 83,425,378 common units outstanding. In addition, there were 1,744,454 restricted unvested common units outstanding.
 
As a result of the approval of certain of the Recapitalization and Related Transactions, as further discussed in Note 9, on May 24, 2010, the Partnership's general partner and Eagle Rock Holdings, L.P. ("Holdings") contributed to the Partnership all 20,691,495 of the outstanding subordinated units and all of the outstanding incentive distribution rights in the Partnership. In connection with the contribution of the subordinated units and incentive distribution rights, the Partnership (i) issued 4,825,211 common units to Holdings as payment of the transaction fee contemplated by the Global Transaction Agreement (as defined in Note 9) and (ii) adopted and entered into a Second Amended and Restated Agreement of Limited Partnership.

Pursuant to the Partnership's Second Amended and Restated Agreement of Limited Partnership, among other things: (i) the subordinated units and incentive distribution rights were cancelled; (ii) the concepts of a subordination period and a minimum quarterly distribution (and, as a result, the concept of arrearages on the common units) were eliminated; and (iii) provisions were included that provide the Partnership an option to acquire its general partner and its general partner entities, which were acquired on July 30, 2010, as further discussed below.

On June 1, 2010, the Partnership launched its rights offering and distributed 21,557,164 Rights to the holders of its common and general partner units as of close of business on May 27, 2010, the record date. Each common and general partner unitholder received 0.35 Rights for each unit held as of the record date. Each Right entitled the holder (including holders of Rights acquired during the subscription period) to purchase for $2.50 in cash (i) one common unit and (ii) one warrant to purchase one additional common unit at $6.00 on certain specified days beginning on August 15, 2010 and ending on May 15, 2012. The warrants are exercisable only on each March 15, May 15, August 15 and November 15 during the period in which the warrants remain outstanding. The rights offering expired on June 30, 2010, and the Partnership issued 21,557,164 common units and 21,557,164 warrants on or about July 8, 2010 for gross proceeds of $53.9 million. During the three months ended September 30, 2010, the Partnership used the proceeds received from the rights offering to repay $50.0 million of outstanding borrowings under the revolving credit facility. On August 15, 2010, 284,722 warrants were exercised for 284,722 newly issued common units, for which the Partnership received proceeds of $1.7 million. On November 15, 2010, 607,197 warrants were exercised for 607,197 newly issued common units, for which the Partnership received proceeds of $3.6 million. As of December 31, 2010, 20,665,245 warrants were still outstanding.

On July 27, 2010, the Partnership gave notice to Holdings of its intention to exercise the GP Acquisition Option (as defined in Note 9). The transaction closed on July 30, 2010, and the Partnership issued 1,000,000 common units to Holdings to acquire the Partnership's general partner entities. As a result, the Partnership's 844,551 outstanding general partner units were cancelled. In connection with the completion of the GP Acquisition Option, the Partnership's board of directors (the "Board") was expanded to include two additional independent directors who were appointed by the Conflicts Committee on July 30, 2010.

During the year ended December 31, 2010, the Partnership released 330,604 common units that were previously held in an escrow account related to its acquisition of MMP to the former owners of MMP.

During the year ended December 31, 2009, the Partnership recovered and cancelled 7,065 common units that were being held in an escrow account related to its acquisition of MacLondon Energy, L.P. and released 849,858 common units that were previously held in an escrow account related to its Millennium Acquisition to the former owners of MMP.


F-21

The Partnership has declared a cash distribution for each quarter since its initial public offering. The table below summarizes these distributions for the last three years. 
Quarter Ended
 
Distribution
per Unit
 
Record Date
 
Payment Date
March 31, 2008
 
$
0.4000

 
May 9, 2008
 
May 15, 2008
June 30, 2008
 
$
0.4100

 
August 8, 2008
 
August 14, 2008
September 30, 2008
 
$
0.4100

 
November 7, 2008
 
November 14, 2008
December 31, 2008
 
$
0.4100

 
February 10, 2009
 
February 13, 2009
March 31, 2009*
 
$
0.0250

 
May 11, 2009
 
May 15, 2009
June 30, 2009*
 
$
0.0250

 
August 10, 2009
 
August 14, 2009
September 30, 2009*
 
$
0.0250

 
November 9, 2009
 
November 13, 2009
December 31, 2009*
 
$
0.0250

 
February 8, 2010
 
February 12, 2010
March 31, 2010*
 
$
0.0250

 
May 7, 2010
 
May 14, 2010
June 30, 2010*
 
$
0.0250

 
August 9, 2010
 
August 13, 2010
September 30, 2010+
 
$
0.0250

 
November 8, 2010
 
November 12, 2010
December 31, 2010+
 
$
0.1500

 
February 7, 2011
 
February 14, 2011
______________________________

+
The distribution per unit represents distributions made only on common units.
*
The distribution per unit represents distributions made only on common units and general partner units.

NOTE 9. RELATED PARTY TRANSACTIONS
   
During the year ended December 31, 2010, 2009 and 2008 the Partnership incurred $6.8 million, $8.8 million and $0.6 million, respectively, in expenses with related parties, of which there was an outstanding accounts payable balance of $0.5 million and $0.7 million as of December 31, 2010 and 2009, respectively.

Related to its investments in unconsolidated subsidiaries, during the year ended December 31, 2010 and 2009, the Partnership recorded income of less than $0.1 million for each of the periods. There were no outstanding accounts receivable balances as of December 31, 2010 and 2009.

The Partnership receives services from Stanolind Field Services ("SFS"), which was an entity controlled by Natural Gas Partners ("NGP"). On August 2, 2010, SFS ceased being a related party of the Partnership as NGP sold all of its interests in SFS. During the periods from January 1, 2010 through August 2, 2010 and during the years ended December 31, 2009 and 2008, the Partnership incurred approximately $0.6 million, $2.2 million and 2.1 million, respectively, for services performed by SFS. As of December 31, 2010 and 2009, there were no outstanding accounts payable balances.

As of December 31, 2010 and 2009, the Partnership had zero and $0.5 million, respectively, due from Holdings relating to payments made by the Partnership on Holdings' behalf.

As of December 31, 2010 and 2009, the Partnership had $0.1 million due to Sweeny Gathering, L.P. (the Partnership owns a 50% joint venture in this entity), for money the Partnership has collected on their behalf.

During 2009 and 2008, the Partnership leased office space from Montierra Minerals & Production, L.P. (“Montierra”), which is owned by NGP and certain members of the Partnership's senior management, including the Chief Executive Officer. During the years ended December 31, 2009 and 2008, the Partnership made rental payments of $0.1 million for each year. In addition, the Partnership was reimbursed by Montierra for services performed by its employees on behalf of Montierra of less than $0.1 million, $0.1 million and $0.2 million for the years ended December 31, 2010, 2009 and 2008, respectively. As of December 31, 2010 and 2009, no amounts were due to or from Montierra.

As of December 31, 2010 and 2009, the Partnership had an outstanding receivable balance of zero and $0.7 million, respectively, due from an affiliate of NGP.
In connection with the closing of the Partnership's initial public offering, on October 24, 2006, it entered into a registration rights agreement with Eagle Rock Holdings, L.P. in connection with its contribution to the Partnership of all of Eagle Rock Holdings, L.P.'s limited and general partner interests in Eagle Rock's predecessor. In the registration rights agreement, the Partnership agreed, for the benefit of Eagle Rock Holdings, L.P., to register the common units it holds, the

F-22

common units issuable upon conversion of the subordinated units that it holds and any common units or other equity securities issuable in exchange for the common units and subordinated units it holds. The registration rights agreement is still in effect and the Partnership is in compliance with all obligations of the agreement.
    
In connection with the closing of the acquisition of certain fee minerals, royalties, overriding royalties and non-operated working interest properties from Montierra and NGP-VII Co-Investment Opportunities, L.P. ("Co-Invest"), the Partnership entered into a registration rights agreements with Montierra and Co-Invest. In the registration rights agreements, the Partnership agreed, for the benefit of Montierra and Co-Invest, to register the common units it holds, the common units issuable upon conversion of the subordinated units that it holds and any common units or other equity securities issuable in exchange for the common units and subordinated units it holds. The registration rights agreement is still in effect and the Partnership is in compliance with all obligations of the agreement.

On April 30, 2008, the Partnership completed the acquisition of all of the outstanding capital stock of Stanolind, for an aggregate purchase price of $81.8 million. Because of the potential conflict of interest between the interests of the Company and the public unitholders of Eagle Rock, the Board of Directors authorized the Company's Conflicts Committee to review, evaluate, and, if determined appropriate, approve the Stanolind Acquisition. The Conflicts Committee, consisting of independent Directors of the Company, determined that the Stanolind Acquisition was fair and reasonable to Eagle Rock and its public unitholders and recommended to the Board of Directors of the Company that the transaction be approved and authorized. In determining the purchase consideration for the Stanolind Acquisition, the Conflicts Committee considered the valuation of the properties involved in the transaction, the valuation of the units to be offered as consideration in the transaction, and the cash flow of Stanolind. Based on the recommendation of the Conflicts Committee, the Board of Directors approved the transaction.

Recapitalization and Related Transactions

On December 21, 2009, the Partnership announced that it, through certain of its affiliates, had entered into definitive agreements with affiliates of NGP and Black Stone Minerals Company, L.P. (“Black Stone”) to improve its liquidity and simplify its capital structure. The definitive agreements included: (i) a Securities Purchase and Global Transaction Agreement, entered into between Eagle Rock Energy and NGP, including Eagle Rock Energy's general partner entities controlled by NGP, and (ii) a Purchase and Sale Agreement (the “Minerals Business Sale Agreement”), entered into between Eagle Rock Energy and Black Stone for the sale of Eagle Rock Energy's Minerals Business. The Securities Purchase and Global Transaction Agreement was amended on January 12, 2010 to allow for greater flexibility in the payment of the contemplated transaction fee to Holdings, which is controlled by NGP (the Partnership refers to the amended Securities Purchase and Global Transaction Agreement as the “Global Transaction Agreement”). The Partnership refers to the transactions contemplated by the Global Transaction Agreement and Minerals Business Sale Agreement collectively as the “Recapitalization and Related Transactions.”

On May 21, 2010, at a reconvened special meeting of the Partnership's common unitholders, a majority of the Partnership's unaffiliated unitholders approved, among other things, the Recapitalization and Related Transactions.

The Recapitalization and Related Transactions included the following key provisions,

•
An option in favor of the Partnership, to issue 1,000,000 common units to capture the value of its controlling interest through (i) acquiring the Partnership's general partner, and such general partner's general partner, and thereafter canceling the 844,551 general partner units outstanding, and (ii) reconstituting its board of directors to allow its common unitholders to elect the majority of its directors (the “GP Acquisition Option”);

•
The sale of the Partnership's Minerals Business to Black Stone for which we received net proceeds of $171.6 million. The Partnership retained approximately $2.9 million of cash received from net revenues received from the Minerals Business after the effective date of the sale, making its total proceeds from the sale of the Minerals Business $174.5 since January 1, 2010;

•
The simplification of the Partnership's capital structure through the contribution, and resulting cancellation, of the incentive distribution rights and the approximate 20.7 million subordinated units held by Holdings;

•
A rights offering for which Holdings and NGP agreed to fully participate with respect to 9.5 million common and general partner units owned or controlled by NGP as well as with respect to common units it received (see below) as payment of the transaction fee; and

•
For a period of up to four months following unitholder approval of the amended Global Transaction

F-23

Agreement, NGP's commitment to back-stop (primarily through Holdings) up to $41.6 million, at a price of $3.10 per unit, an Eagle Rock Energy equity offering to be undertaken at the sole option of the Partnership's Conflicts Committee.

In exchange for NGP's and Holdings' contributions and commitments under the Global Transaction Agreement, Eagle Rock paid Holdings a transaction fee of $29 million in newly-issued common units. The units were valued at $6.0101 per unit, based on 90% of the volume-adjusted trailing 10-day average of the trading price of Eagle Rock's common units as of April 24, 2010, resulting in a total of approximately 4.8 million common units paid to Holdings upon completion of the Minerals Business sale on May 24, 2010.

The sale of the Minerals Business closed on May 24, 2010, and the Partnership received $171.6 million in net proceeds (after consideration of approximately $2.9 million of net revenues received from the Minerals Business after the effective date) (see Note 17).

The subordinated units and incentive distribution rights were contributed and subsequently cancelled on May 24, 2010
(see Note 8).

The rights offering was launched on June 1, 2010 and expired on June 30, 2010 (see Note 8).

On July 27, 2010, the Partnership gave notice to Holding of its intention to exercise the GP Acquisition Option. On July 30, 2010, the Partnership closed the acquisition and cancelled the general partner units (see Note 8).

NGP's commitment to back-stop an Eagle Rock Energy equity offering expired on September 21, 2010.

See Note 7 for a discussion of an amendment to the Partnership's revolving credit facility related to the Recapitalization and Related Transactions.

See Note 12 for a discussion of a settled lawsuit that alleged certain claims related to the Recapitalization and Related
Transactions.

In connection with the Recapitalization and Related Transactions, the Partnership incurred legal (not including related litigation costs), accounting, advisory and similar costs, beginning in May 2009 through December 31, 2010, totaling
$6.6 million. Of these costs, the Partnership expensed $2.5 million, of which $0.4 million was recorded as part of discontinued operations, and capitalized $4.1 million as transactions costs within Members' Equity.


F-24

NOTE 10. FAIR VALUE OF FINANCIAL MEASUREMENTS
 
Effective January 1, 2008, the Partnership adopted authoritative guidance which, among other things, requires enhanced disclosures about assets and liabilities carried at fair value.
 
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Partnership utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk inherent in the inputs to the valuation technique. The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).
 
The three levels of the fair value hierarchy are as follows:
 
Level 1 – Quoted prices are available in active markets for identical assets and liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide information on an ongoing basis.
 
Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the market place throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
 
Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value.
 
As of December 31, 2010, the Partnership has recorded its interest rate swaps and commodity derivative instruments (see Note 11), which includes crude oil, natural gas and natural gas liquids (“NGLs”), at fair value. The Partnership has classified the inputs to measure the fair value of its interest rate swap, crude oil derivatives and natural gas derivatives as Level 2.  Because the NGL market is thinly traded and considered to be less liquid, the Partnership has classified the inputs related to its NGL derivatives as Level 3. The following table discloses the fair value of the Partnership's derivative instruments as of December 31, 2010 and 2009: 
 
As of
December 31, 2010
 
Level 1
 
Level 2
 
Level 3
 
Netting(a)
 
Total
 
($ in thousands)
Assets:
 
 
 
 
 
 
 
 
 
Crude oil derivatives
$
—

 
$
—

 
$
—

 
$
(1,292
)
 
$
(1,292
)
Natural gas derivatives
—

 
16,731

 
—

 
(14,364
)
 
2,367

NGL derivatives
—

 
—

 
168

 
(168
)
 
—

Total 
$
—

 
$
16,731

 
$
168

 
$
(15,824
)
 
$
1,075

 
 
 
 
 
 
 
 
 
 
Liabilities:
 

 
 

 
 

 
 
 
 

Crude oil derivatives
$
—

 
$
(45,664
)
 
$
—

 
$
1,292

 
$
(44,372
)
Natural gas derivatives
—

 
(35
)
 
—

 
14,364

 
14,329

NGL derivatives
—

 
—

 
(5,901
)
 
168

 
(5,733
)
Interest rate swaps
—

 
(34,579
)
 
—

 
—

 
(34,579
)
Total 
$
—

 
$
(80,278
)
 
$
(5,901
)
 
$
15,824

 
$
(70,355
)
__________________________

(a)
Represents counterparty netting under agreements governing such derivative contracts.

F-25


 
As of
December 31, 2009
 
Level 1
 
Level 2
 
Level 3
 
Netting(a)
 
Total
 
($ in thousands)
Assets:
 
 
 
 
 
 
 
 
 
Crude oil derivatives
$
—

 
$
9,089

 
$
—

 
(9,086
)
 
$
3

Natural gas derivatives
—

 
8,761

 
—

 
(3,475
)
 
5,286

Interest rate swaps
—

 
600

 
—

 
—

 
600

Total 
$
—

 
$
18,450

 
$
—

 
$
(12,561
)
 
$
5,889

 
 
 
 
 
 
 
 
 
 
Liabilities:
 

 
 

 
 

 
 
 
 

Crude oil derivatives
$
—

 
$
(54,125
)
 
$
—

 
9,086

 
$
(45,039
)
Natural gas derivatives
—

 
—

 
—

 
3,475

 
3,475

NGL derivatives
—

 
—

 
(14,784
)
 
—

 
(14,784
)
Interest rate swaps
—

 
(28,017
)
 
—

 
—

 
(28,017
)
Total 
$
—

 
$
(82,142
)
 
$
(14,784
)
 
$
12,561

 
$
(84,365
)
__________________________

(a)
Represents counterparty netting under agreements governing such derivative contracts.

The fair value hierarchy of derivative assets and liabilities presented as of December 31, 2009 has been changed from the previously presented 2009 disclosures to reflect gross assets and liabilities reconciled to the net presentation in the consolidated balance sheet due to counterparty netting under agreements governing such derivative contracts.

As of December 31, 2010 and 2009, risk management current assets in the Consolidated Balance Sheet include put premiums and other derivative costs, net of amortization, of zero and $4.0 million, respectively.
 
The following table sets forth a reconciliation of changes in the fair value of the Level 3 NGL derivatives during the years ended December 31, 2010, 2009 and 2008 (in thousands):
 
Year Ended December 31,
 
 
2010
 
2009
 
2008
 
Net asset (liability) balance as of January 1
$
(14,784
)
 
$
14,016

 
$
(52,793
)
 
Settlements 
12,358

 
66

 
16,098

 
Total gains or losses (realized and unrealized) 
(3,307
)
 
(28,866
)
 
50,711

 
Net (liability) asset balance as of December 31
$
(5,733
)
 
$
(14,784
)
 
$
14,016

 

The Partnership values its Level 3 NGL derivatives using forward curves, volatility curves, volatility skew parameters, interest rate curves and model parameters. In addition, the impact of counterparty credit risk is factored into the value of derivative assets and the Partnership's credit risk is factored into the value of derivative liabilities.
 
The Partnership recognized (losses) gains of $(5.7) million, $(15.2) million, and $50.0 million in the years ended December 31, 2010, 2009 and 2008, respectively, that are attributable to the change in unrealized gains or losses related to those assets and liabilities still held at December 31, 2010, 2009 and 2008, which are included in the commodity risk management (losses) gains.  
 
Realized and unrealized losses related to the interest rate derivatives are recorded as part of interest rate risk management gains and losses in the Consolidated Statements of Operations.  Realized and unrealized gains and losses and premium amortization related to the Partnership's commodity derivatives are recorded as a component of revenue in the Consolidated Statements of Operations. 
 

F-26

The following table discloses the fair value of the Partnership's assets measured at fair value on a nonrecurring basis for the year ended December 31, 2010 (in thousands):
 
 
December 31, 2010
 
Level 1
 
Level 2
 
Level 3
 
Total
Losses
Plant assets
$
131

 
$
—

 
$
—

 
$
131

 
$
725

Pipeline assets
$
6,498

 
$
—

 
$
—

 
$
6,498

 
$
25,410

Rights-of-way
$
85

 
$
—

 
$
—

 
$
85

 
$
1,609

Contracts
$
—

 
$
—

 
$
—

 
$
—

 
$
1,595

Unproved properties
$
—

 
$
—

 
$
—

 
$
—

 
$
3,432

Proved properties
$
132

 
$
—

 
$
—

 
$
132

 
$
104

 
In connection with the preparation of these financial statements for the year ended December 31, 2010, the Partnership wrote down plant assets with a carrying value of $0.9 million to their fair value of $0.1 million, pipeline assets with a carrying value of $31.9 million to their fair value of $6.5 million, rights-of-way with a carrying value of $1.7 million to their fair value of $0.1 million, contracts with a carrying value of $1.6 million to their fair value of zero, proved properties with a carrying value of $0.2 million to their fair value of $0.1 million and unproved properties with a carrying value of $3.4 million to their fair value of zero, resulting in an impairment charge of $32.9 million being included in earnings for the year ended December 31, 2010, of which $26.2 million was recorded within discontinued operations. The impairment charges related to plant assets, pipeline assets, rights-of-way and contracts related specifically to the Midstream Business due to the loss during the second quarter 2010 of a significant contract on the Partnership's Raymondville system within its South Texas Segment and due to an anticipated decline in volumes on the Partnership's Wildhorse gathering system within its South Texas Segment, while the impairment of the Upstream Segment's unproved properties was due to the Partnership determining that it was not technologically feasible to develop these unproved locations and the Upstream Segment's proved properties was due to adjustments to its reserves. The Partnership calculated the fair value of the impaired assets on its Raymondville system and its proved properties using discounted cash flow analysis to determine the excess of the asset's carrying value over its fair value. The Partnership calculated the fair value of the impaired assets on its Wildhorse gathering system based on an unsolicited value of the system provided by a market participant.
 
The carrying amount of cash equivalents is believed to approximate their fair values because of the short maturities of these instruments. The fair value of accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments.
 
The Partnership believes that the fair value of its Revolving Credit Facility does not approximate its carrying value as of December 31, 2010 because the applicable floating rate margin on the Revolving Credit Facility was a below-market rate. The fair value of the Revolving Credit Facility has been estimated based on similar transactions that occurred during the twelve months ended December 31, 2010 and the first two months of 2011.  The Partnership's estimate of the fair value of the borrowings under its Revolving Credit Facility as of December 31, 2010 was $518.0 million versus a carrying value of $530.0 million. The Partnership's estimate of the fair value of the borrowings under its Revolving Credit Facility as of December 31, 2009 was $713.2 million versus a carrying value of $754.4 million.

NOTE 11. RISK MANAGEMENT ACTIVITIES
 
To mitigate its interest rate risk, 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 these swaps is to eliminate interest rate variability by converting LIBOR-based variable-rate payments to fixed-rate payments. Amounts received or paid under these swaps were recorded as reductions or increases in interest expense.
 
On March 30, 2009, the Partnership amended all of its existing interest rate swaps to change the interest rate the Partnership received from three month LIBOR to one month LIBOR through January 9, 2011.  During this time period, the fixed rate to be paid by the Partnership was reduced, on average, by 20 basis points.  After January 9, 2011, the interest rate to be received by the Partnership changed back to three month LIBOR, and the fixed rate the Partnership pays reverted back to the original rate through the end of swap maturities in 2012.
 

F-27

The table below summarizes the terms, amounts received or paid and the fair values of the various interest rate swaps:
Effective Date
 
Expiration
Date
 
Notional
Amount
 
Fixed
Rate (a)
12/31/2008
 
12/31/2012
 
$
150,000,000

 
2.360% / 2.560%
9/30/2008
 
12/31/2012
 
150,000,000

 
4.105% / 4.295%
10/3/2008
 
12/31/2012
 
300,000,000

 
3.895% / 4.095%
_________________________________
(a)
First amount is the rate the Partnership pays through January 9, 2011 and the second amount is the interest rate the Partnership pays from January 10, 2011 through December 31, 2012.
 
The Partnership's interest rate derivative counterparties include Wells Fargo Bank N.A. and The Royal Bank of Scotland plc.
 
Commodity Derivative Instruments
 
The prices of crude oil, natural gas and NGLs are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors which are beyond the Partnership's control.  These risks can cause significant changes in the Partnership's cash flows and affect its ability to achieve its distribution objective and comply with the covenants of its revolving credit facility.  In order to manage the risks associated with the future prices of crude oil, natural gas and NGLs, the Partnership engages in non-speculative risk management activities that take the form of commodity derivative instruments.  The Partnership has determined that it is necessary to hedge a substantial portion of its expected production in order to meaningfully reduce its future cash flow volatility.  The Partnership generally limits its hedging levels to 80% of expected future production.   While hedging at this level of production does not eliminate all of the volatility in the Partnership's cash flows, it allows the Partnership to mitigate the risk of situations where a modest loss of production would put it in an over-hedged position.  The Partnership may hedge for periods of time above the 80% of expected future production levels where it deems it prudent to reduce extreme future price volatility.  However, hedging to that level requires approval of the Board of Directors, which the Partnership obtained for its 2009 and 2010 hedging activity.  At times, the Partnership's strategy may involve entering into hedges with strike prices above current future prices or resetting existing hedges to higher price levels in order to meet its cash flow objectives or to stay in compliance with its revolving credit facility.  In addition, the Partnership may also terminate or unwind hedges or portions of hedges when the expected future volumes do not support the level of hedges.  Expected future production for its Upstream Business is derived from the proved reserves, adjusted for price-dependent expenses and revenue deductions.  For the Midstream Business, expected future production is based on the expected production from wells currently flowing to the Partnership's processing plants, plus additional volumes the Partnership expects to receive from future drilling activity by its producer customer base.  The Partnership's expectations for its Midstream Business volumes associated with future drilling are based on information it receives from its producer customer base and historical observations. The Partnership applies the appropriate contract terms to these projections to determine its expected future equity share of the commodities.
 
The Partnership uses put options, costless collars and fixed-price swaps to achieve its hedging objectives, and often hedges its expected future volumes of one commodity with derivatives of the same commodity.  In some cases, however, the Partnership believes it is better to hedge future changes in the price of one commodity with a derivative of another commodity, which it refers to as “cross-commodity” hedging.  The Partnership will often hedge the changes in future NGL prices (propane and heavier) using crude oil hedges because NGL prices have been highly correlated to crude oil prices and hedging NGLs directly is usually less attractive due to the relative illiquidity in the NGL forward market.  The Partnership will also use natural gas hedges to hedge a portion of its expected future ethane production because forward prices for ethane are often heavily discounted from its current prices.  Also, natural gas prices provide support for ethane prices because in many processing plants ethane can be recombined with the residue gas stream and sold as natural gas.  When the Partnership uses cross-commodity hedging, it will convert the expected volumes of the underlying commodity to equivalent volumes of the hedged commodity.  In the case of NGLs hedged with crude oil derivatives, these conversions are based on the linear regression of the prices of the two commodities observed during the previous 36 months and management's judgment regarding future price relationships of the commodities.  In the case where ethane is hedged with natural gas derivatives, the conversion is based on the thermal content of ethane.
 
The Partnership has a risk management policy which allows management to execute crude oil, natural gas and NGL hedging instruments in order to reduce exposure to substantial adverse changes in the prices of these commodities. The Partnership continually monitors and ensures compliance with this risk management policy through senior level executives in its operations, finance and legal departments.

F-28

 
The Partnership has not designated any of its commodity derivative instruments as hedges and therefore is marking these derivative contracts to fair value.  Changes in fair values of the commodity derivative instruments are recorded as an adjustment to the mark-to-market gains (losses) on risk management transactions within revenue.
 
By using derivative instruments to economically hedge exposure to changes in commodity prices, the Partnership exposes itself to credit risk, which is the failure of the counterparty to perform under the terms of the derivative contract. The Partnership's counterparties are all participants or affiliates of participants within its Revolving Credit Facility (see Note 7), which is secured by substantially all of the assets of the Partnership. Therefore, the Partnership is not required to post any collateral, nor does it require collateral from its counterparties. The Partnership minimizes the credit risk in derivative instruments by limiting its exposure to any single counterparty and monitoring the creditworthiness of its counterparties on an ongoing basis. In addition, the Partnership's derivative contracts, for certain counterparties, are subject to counterparty netting agreements governing such derivatives and therefore the risk of loss is somewhat mitigated.

The Partnership's commodity derivative counterparties include BNP Paribas, Wells Fargo Bank, N.A, Comerica Bank, Barclays Bank PLC, Bank of Nova Scotia, The Royal Bank of Scotland plc, Bank of America N.A., J Aron and Company (an affiliate of Goldman Sachs), BBVA Compass Bank and Credit Suisse Energy LLC (an affiliate of Credit Suisse Group AG).

On November 23, 2010, the Partnership entered into a series of hedging transactions to unwind existing contracts. The Partnership unwound; (i) 20,000 barrels a month of an "out-of-the-money" WTI crude oil swap with a price of $80.05, (ii) 15,000 barrels a month of a 20,000 barrels a month "out-of-the-money" WTI crude oil swap with a price of $75.00 and (iii)23,000 barrels a month of a "in-the-money" WTI crude oil swap covering 29,000 barrels per month for the first half of the 2011 calendar year and 23,000 barrels a month covering the second half of the 2011 calendar year with a price a $86.20. For these transactions, the Partnership paid $2.2 million. The Partnership was using these WTI crude oil derivatives to hedge against changes in NGL prices. To continue hedging these NGL volumes, the Partnership then entered into the following derivative transactions for the 2011 calendar year on November 23, 2010: a 996,000 gallon per month OPIS normal butane swap at $1.50 per gallon, a 462,000 gallon per month OPIS iso butane swap at $1.5425 per gallon, a 378,000 gallon per month OPIS natural gasoline swap at $1.8525 per gallon, a 1,680,000 gallon per month OPIS propane swap for $1.1165 per gallon and a 252,000 gallon per month OPIS propane swap for $1.11 per gallon.

On December 20, 2010, the Partnership entered into a 34,000 MMbtu per month Henry Hub natural gas swap at $4.45 per MMbtu. For this swap, the Partnership will be paying the fixed price, where normally, for the swaps it enters into, it pays the floating price. The Partnership was using a portion of its Henry Hub natural gas swaps to hedge against changes in ethane prices and this transaction effectively unwinds a portions of these swaps. To continue hedging these ethane volumes, the Partnership then entered into a 1,428,000 gallon per month OPIS ethane swap at a price of $0.545 per gallon.

In addition, during the year ended December 31, 2010, the Partnership entered into the following derivative transactions for its 2011 calendar year: a 12,000 barrel per month NYMEX WTI costless collar with a floor strike price at $75.00 per barrel and a cap strike price of $89.85 per barrel on February 16, 2010, a 17,000 barrel per month NYMEX WTI swap at $83.30 on June 18, 2010 and a NYMEX WTI swap covering 29,000 barrels per month for the first half of the calendar year and 23,000 barrels per month for the second half of the calendar year with a strike price of $86.20 per barrel on August 23, 2010.

F-29

 
The following table, as of December 31, 2010, sets forth certain information regarding the Partnership's commodity derivatives that will mature during the year ended December 31, 2011:
Underlying
 
Period
 
Notional
Volumes
(units)
 
Type
 
Floor
Strike
Price
($/unit)
 
Cap
Strike
Price
($/unit)
Natural Gas:
 
 
 
 
 
 
 
 
 
 
NYMEX Henry Hub
 
Jan-Dec 2011
 
1,200,000 mmbtu
 
Costless Collar
 
$
7.50

 
$
8.85

NYMEX Henry Hub
 
Jan-Dec 2011
 
720,000 mmbtu
 
Swap
 
7.085

 
 

NYMEX Henry Hub
 
Jan-Dec 2011
 
2,280,000 mmbtu
 
Swap
 
6.57

 
 

NYMEX Henry Hub
 
Jan-Dec 2011
 
(408,000) mmbtu
 
Swap
 
4.45

 
 
Crude Oil:
 
 
 
 
 
 
 
 

 
 

NYMEX WTI
 
Jan-Dec 2011
 
139,152 bbls
 
Costless Collar
 
75.00

 
85.70

NYMEX WTI
 
Jan-Dec 2011
 
360,000 bbls
 
Costless Collar
 
80.00

 
92.40

NYMEX WTI
 
Jan-Dec 2011
 
144,000 bbls
 
Costless Collar
 
75.00

 
89.85

NYMEX WTI
 
Jan-Dec 2011
 
125,256 bbls
 
Swap
 
80.00

 
 

NYMEX WTI
 
Jan-Dec 2011
 
120,000 bbls
 
Swap
 
65.10

 
 

NYMEX WTI
 
Jan-Dec 2011
 
60,000 bbls
 
Swap
 
75.00

 
 

NYMEX WTI
 
Jan-Dec 2011
 
360,000 bbls
 
Swap
 
65.60

 
 

NYMEX WTI
 
Jan-Dec 2011
 
204,000 bbls
 
Swap
 
83.30

 
 

NYMEX WTI
 
Jan-Jun 2011
 
36,000 bbls
 
Swap
 
86.20

 
 

Natural Gas Liquids:
 
 
 
 
 
 
 
 

 
 

OPIS NButane Mt. Belv non TET
 
Jan-Dec 2011
 
11,592,000 gallons
 
Swap
 
1.50

 
 
OPIS IsoButane Mt. Belv non TET
 
Jan-Dec 2011
 
5,544,000 gallons
 
Swap
 
1.5425

 
 
OPIS Natural Gasoline Mt. Belv non TET
 
Jan-Dec 2011
 
4,536,000 gallons
 
Swap
 
1.8525

 
 
OPIS Propane Mt. Belv non TET
 
Jan-Dec 2011
 
20,160,000 gallons
 
Swap
 
1.1165

 
 
OPIS Propane Mt. Belv non TET
 
Jan-Dec 2011
 
3,024,000 gallons
 
Swap
 
1.11

 
 
OPIS Ethane Mt. Belv non TET
 
Jan-Dec 2011
 
17,136,000 gallons
 
Swap
 
0.545

 
 



F-30

The following table, as of December 31, 2010, sets forth certain information regarding the Partnership's commodity derivatives that will mature during the year ended December 31, 2012:
Underlying
 
Period
 
Notional
Volumes
(units)
 
Type
 
Floor
Strike
Price
($/unit)
 
Cap
Strike
Price
($/unit)
Natural Gas:
 
 
 
 
 
 
 
 
 
 
NYMEX Henry Hub
 
Jan-Dec 2012
 
1,080,000 mmbtu
 
Costless Collar
 
$
7.35

 
$
8.65

NYMEX Henry Hub
 
Jan-Dec 2012
 
3,120,000 mmbtu
 
Swap
 
6.77

 
 

Crude Oil:
 
 
 
 
 
 
 
 

 
 

NYMEX WTI
 
Jan-Dec 2012
 
135,576 bbls
 
Costless Collar
 
75.30

 
86.30

NYMEX WTI
 
Jan-Dec 2012
 
360,000 bbls
 
Costless Collar
 
80.00

 
98.50

NYMEX WTI
 
Jan-Dec 2012
 
192,000 bbls
 
Costless Collar
 
75.00

 
94.75

NYMEX WTI
 
Jan-Dec 2012
 
108,468 bbls
 
Swap
 
80.30

 
 

NYMEX WTI
 
Jan-Dec 2012
 
240,000 bbls
 
Swap
 
68.30

 
 

NYMEX WTI
 
Jan-Dec 2012
 
240,000 bbls
 
Swap
 
76.50

 
 

NYMEX WTI
 
Jan-Dec 2012
 
240,000 bbls
 
Swap
 
82.02

 
 

NYMEX WTI
 
Jan-Dec 2012
 
420,000 bbls
 
Swap
 
90.65

 
 


On February 16, 2010, the Partnership entered into a 12,000 barrels per month WTI costless collar with a floor strike price at $75.00 per barrel and a cap strike price of $89.85 per barrel for its 2011 calendar year.   On February 17, 2010, the Partnership entered into a 16,000 barrels per month NYMEX WTI costless collar with a floor strike price at $75.00 per barrel and a cap strike price of $94.75 per barrel for its 2012 calendar year.

The following table, as of December 31, 2010, sets forth certain information regarding the Partnership's commodity derivatives that will mature during the year ended December 31, 2013:

Underlying
 
Period
 
Notional
Volumes
(units)
 
Type
 
Floor
Strike
Price
($/unit)
 
Cap
Strike
Price
($/unit)
Natural Gas:
 
 
 
 
 
 
 
 
 
 
NYMEX Henry Hub
 
Jan-Dec 2013
 
600,000 mmbtu
 
Swap
 
$
5.65

 
 
NYMEX Henry Hub
 
Jan-Dec 2013
 
600,000 mmbtu
 
Swap
 
5.30

 
 
NYMEX Henry Hub
 
Jan-Dec 2013
 
600,000 mmbtu
 
Swap
 
5.305

 
 
Crude Oil:
 
 
 
 
 
 
 
 

 
 
NYMEX WTI
 
Jan-Dec 2013
 
240,000 bbls
 
Swap
 
90.20

 
 
NYMEX WTI
 
Jan-Dec 2013
 
720,000 bbls
 
Swap
 
89.85

 
 
NYMEX WTI
 
Jan-Dec 2013
 
384,000 bbls
 
Swap
 
90.75

 
 
NYMEX WTI
 
Jan-Dec 2013
 
120,000 bbls
 
Swap
 
88.20

 
 
 

F-31

Fair Value of Interest Rate and Commodity Derivatives
 
Fair values of interest rate and commodity derivative instruments not designated as hedging instruments in the consolidated balance sheet as of December 31, 2010 and 2009:
 
As of December 31, 2010
 
Derivative Assets
 
Derivative Liabilities
 
Balance Sheet Classification
 
Fair Value
 
Balance Sheet Classification
 
Fair Value
 
($ in thousands)
Interest rate derivatives - liabilities
 
 
$
—

 
Current liabilities
 
$
(19,822
)
Interest rate derivatives - liabilities
 
 
—

 
Long-term liabilities
 
(14,757
)
Commodity derivatives - assets
Current assets
 
—

 
Current liabilities
 
9,150

Commodity derivatives - assets
Long-term assets
 
2,402

 
Long-term liabilites
 
5,347

Commodity derivatives - liabilities
Current assets
 
—

 
Current liabilities
 
(28,678
)
Commodity derivatives - liabilities
Long-term assets
 
(1,327
)
 
Long-term liabilities
 
(21,595
)
Total derivatives
 
 
$
1,075

 
 
 
$
(70,355
)
 
 
 
 
 
 
 
 
 
As of December 31, 2009
 
Derivative Assets
 
Derivative Liabilities
 
Balance Sheet Classification
 
Fair Value
 
Balance Sheet Classification
 
Fair Value
 
($ in thousands)
Interest rate derivatives - assets
Long-term assets
 
$
600

 
 
 
$
—

Interest rate derivatives - liabilities
 
 
—

 
Current liabilities
 
(16,988
)
Interest rate derivatives - liabilities
 
 
—

 
Long-term liabilities
 
(11,029
)
Commodity derivatives - assets
Current assets
 
3,494

 
Current liabilities
 
9,842

Commodity derivatives - assets
Long-term assets
 
2,830

 
Long-term liabilities
 
1,684

Commodity derivatives - liabilities
Current assets
 
(1,015
)
 
Current liabilities
 
(44,504
)
Commodity derivatives - liabilities
Long-term assets
 
(20
)
 
Long-term liabilities
 
(23,370
)
Total derivatives
 
 
$
5,889

 
 
 
$
(84,365
)
 
The following table sets forth the location of gains and losses for derivatives not designated as hedging instruments within the Partnership's Consolidated Statement of Operations (in thousands):
 
 
 
Amount of Gain (Loss) recognized in Income on Derivatives
 
 
2010
 
2009
 
2008
Interest rate derivatives
Interest rate risk management losses
$
(27,135
)
 
$
(6,347
)
 
$
(32,931
)
Commodity derivatives
Commodity risk management (losses) gains
(8,786
)
 
(106,290
)
 
161,765

Total
 
$
(35,921
)
 
$
(112,637
)
 
$
128,834

 
The Partnership's hedge counterparties are participants in its credit agreement, and the collateral for the outstanding borrowings under its credit agreement is used as collateral for the Partnership's hedges.  The Partnership does not have rights to collateral from its counterparties, nor does it have rights of offset against borrowings under its credit agreement.
 
NOTE 12. COMMITMENTS AND CONTINGENT LIABILITIES
 
Litigation—The Partnership is subject to several lawsuits which arise from time to time in the ordinary course of business, such as the interpretation and application of contractual terms related to the calculation of payment for liquids and natural gas proceeds. The Partnership has accruals of approximately zero and $0.1 million as of December 31, 2010 and 2009, respectively, related to these matters. The Partnership has been indemnified up to a certain dollar amount for two of these lawsuits. 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,

F-32

the Partnership would expect to 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.
 
On February 9, 2010, a lawsuit, alleging certain claims related to the Recapitalization and Related Transactions (see Note 9), was filed on behalf of one of the Partnership's public unitholders in the Court of Chancery of the State of Delaware naming the Partnership, its general partner, certain affiliates of its general partner, including the general partner of its general partner, and each member of the Partnership's Board of Directors as defendants. The complaint alleged a breach by the defendants of their fiduciary duties to the Partnership and the public unitholders and sought to enjoin the Recapitalization and Related Transactions. The Partnership believed the allegations made in the complaint were without merit. On March 11, 2010, in an effort to minimize the further cost, expense, burden and distraction of any litigation relating to the lawsuit, the parties to the lawsuit entered into a Memorandum of Understanding regarding the terms of a potential settlement of the lawsuit. On August 16, 2010, the parties to the lawsuit filed a Stipulation and Agreement of Compromise, Settlement and Release with the Court of Chancery of the State of Delaware. The settlement resolved the allegations by the plaintiff against the defendants in connection with the Recapitalization and Related Transactions and provides a release and settlement by a proposed class of the Partnership common unitholders during the period from September 17, 2009 through and including the date of the closing of the transactions of all claims against the defendants as they relate to the Recapitalization and Related Transactions. At a hearing on October 28, 2010, the Court of Chancery of the State of Delaware approved the settlement and entered a final Order and Judgment. The order approving the settlement became final on November 29, 2010. During the year ended December 31, 2010, the Partnership incurred $1.2 million of costs, and as of December 31, 2010, the Partnership no longer had an accrual relating to this matter. In addition, the Partnership had recorded a receivable related to this matter of approximately $0.6 million for amounts it expects to recover under its Directors and Officers insurance, of which approximately $0.3 million remains outstanding as of December 31, 2010.
 
Insurance—The Partnership covers its operations and assets with insurance which management believes is consistent with that in force for other companies engaged in similar commercial operations with similar type properties.  This insurance includes: (1) commercial general liability insurance covering liabilities to third parties for bodily injury, property damage and pollution arising out of Eagle Rock Energy operations; (2) workers’ compensation liability coverage for employees to required statutory limits; (3) automobile liability insurance covering liability to third parties for bodily injury and property damage arising out of the operation of all owned, hired and non-owned vehicles by its employees on company business; (4) property insurance covering the replacement cost of all owned real and personal property, including coverage for losses due to boiler and machinery breakdown, earthquake, flood and consequent business interruption/extra expense; (5) control of well/operator's extra expense insurance for operated and non operated wells in the Upstream Segment; and (6) corporate liability insurance including coverage for Directors and Officers and Employment Practices liabilities.  In addition, the Partnership maintains excess liability insurance providing limits in excess of the established primary limits for commercial general liability and automobile liability insurance.
 
All coverages are subject to industry accepted policy terms, conditions, limits and deductibles comparable to that obtained by other energy companies with similar operations. The cost of insurance for the energy industry continued to fluctuate over the past year, reflecting the changing conditions in the insurance markets.
 
Regulatory Compliance—In the ordinary course of business, the Partnership is subject to various laws and regulations. In the opinion of management, the Partnership is in material compliance with existing laws and regulations.
 
Environmental—The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, the Partnership must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on the Partnership's combined results of operations, financial position or cash flows. At December 31, 2010 and 2009, the Partnership had accrued approximately $4.0 million and $4.4 million, respectively, for environmental matters.
 
During 2009, the Partnership completed voluntary self-audits of its compliance with air quality standards, which included permitting in the Texas Panhandle Segment as well as a majority of its other Midstream Business locations and some of its Upstream Business locations in Texas. These audits were performed pursuant to the Texas Environmental, Health and

F-33

Safety Audit Privilege Act, as amended. The Partnership completed the disclosures to the Texas Commission on Environmental Quality (“TCEQ”), and the Partnership has substantially addressed the deficiencies that it disclosed therein. The Partnership does not foresee at this time any impediment in timely addressing the remaining deficiencies identified as a result of these audits.

Since January 1, 2010, the Partnership has received additional Notices of Enforcement (“NOEs”) and Notices of Violation (“NOVs”) from the TCEQ related to air compliance matters and expects to receive additional NOEs or NOVs from the TCEQ from time to time throughout 2011. Though the TCEQ has the discretion to adjust penalties and settlements upwards based on a compliance history containing multiple, successive NOEs, the Partnership does not expect that the resolution of any existing NOE or any future similar NOE will vary significantly from the administrative penalties and agreed settlements experienced by it to date.
 
Retained Revenue Interest—Certain assets of the Partnership's Upstream Segment are subject to retained revenue interests.  These interests were established under purchase and sale agreements that were executed by the Partnership's predecessors in title.  The terms of these agreements entitle the owners of the retained revenue interests to a portion of the revenues received from the sale of the hydrocarbons above specified base oil and natural gas prices.  These retained revenue interests do not represent a real property interest in the hydrocarbons.  The Partnership's reported revenues are reduced to account for the retained revenue interests on a monthly basis.
 
The retained revenue interests affect the Partnership's interest at the Big Escambia Creek, Flomaton and Fanny Church fields in Escambia County, Alabama. With respect to the Partnership's Flomaton and Fanny Church fields, these retained revenue interests are in effect for any calendar year in which the Partnership surpasses certain average net production rates, while for the Partnership's Big Escambia field, the retained revenue interest commenced in 2010 and is expected to continue through the end of 2019.
 
Other Commitments—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 approximately $7.8 million, $8.9 million, and $5.8 million for the years ended December 31, 2010, 2009 and 2008, respectively. Rental expense for leases with escalation clauses is recognized on a straight-line basis over the initial lease term. At December 31, 2010, commitments under long-term non-cancelable operating leases for the next five years are as follows: 2011—$4.2 million; 2012—$4.0 million; 2013—$2.4 million; 2014—$1.7 million and 2015—$1.7 million.
 

F-34

NOTE 13. SEGMENTS
 
On May 24, 2010, the Partnership completed the sale of its fee mineral and royalty interests as well as its equity investment in Ivory Working Interests, L.P. (collectively, the “Minerals Business”). In February 2011, the Partnership classified the assets and liabilities of its Wildhorse gathering system as held for sale. As authoritative guidance requires the operations for components of entities that are classified as held for sale or have been disposed of be recorded as part of discontinued operations, operating results for the Minerals Business and the Wildhorse gathering system for the years ended December 31, 2010, 2009 and 2008 have been excluded from the Partnership’s segment presentation below. See Note 19 for a further discussion of the sale of the Partnership’s Minerals Business and Note 21 for a further discussion of the Wildhorse gathering system.

Based on the Partnership’s approach to managing its assets, the Partnership believes its operations consist of four geographic segments in its Midstream Business, one upstream segment that is its Upstream Business and one functional (Corporate and Other) segment:
 
(i)
Midstream—Texas Panhandle Segment:
gathering, compressing, processing and treating natural gas and marketing of natural gas, NGLs and condensate in the Texas Panhandle;

(ii)
Midstream—South Texas Segment:
gathering, compressing, processing and treating natural gas and marketing of natural gas, NGLs and condensate in South Texas;

(iii)
Midstream—East Texas/Louisiana Segment:
gathering, compressing, processing, treating and transporting natural gas and marketing of natural gas, NGLs and condensate and related NGL transportation in East Texas and Louisiana;

(iv)
 Midstream—Gulf of Mexico Segment:
gathering and processing of natural gas and fractionating, transporting and marketing of NGLs in South Louisiana, Gulf of Mexico and inland waters of Texas;
 
(v)
Upstream Segment:
 crude oil, natural gas and sulfur production from operated and non-operated wells; and
  
(vi)
Corporate and Other Segment:
 risk management, intersegment eliminations and other corporate activities such as general and administrative expenses.
 

F-35

The Partnership's chief operating decision-maker (“CODM”) currently reviews its operations using these segments. The CODM evaluates segment performance based on segment operating income or loss from continuing operations. Summarized financial information concerning the Partnership's reportable segments is shown in the following table:
Midstream Business
Year Ended December 31, 2010
 
Texas
Panhandle
Segment
 
South
Texas
Segment
 
East Texas /
Louisiana
Segment
 
Gulf of
Mexico Segment
 
Total
Midstream
Business
($ in thousands)
 
 
 
 
 
 
 
 
 
 
Sales to external customers
 
$
358,235

 
$
56,885

 
$
204,349

 
$
32,954

 
$
652,423

Cost of natural gas, natural gas liquids and condensate
 
237,467

 
51,573

 
151,236

 
28,028

 
468,304

Intersegment cost of oil and condensate
 
5,587

 
—

 
—

 
—

 
5,587

Operating costs and other expenses
 
35,032

 
1,839

 
17,275

 
1,771

 
55,917

Depreciation, depletion, amortization and impairment
 
45,876

 
6,388

 
18,452

 
6,838

 
77,554

Operating income (loss) from continuing operations
 
$
34,273

 
$
(2,915
)
 
$
17,386

 
$
(3,683
)
 
$
45,061

Capital Expenditures
 
$
29,282

 
$
90

 
$
15,756

 
$
180

 
$
45,308

Segment Assets
 
$
566,641

 
$
56,961

 
$
269,640

 
$
82,475

 
$
975,717

Total Segments
Year Ended December 31, 2010
 
Total
Midstream
Business
 
Upstream
Segment
 
Corporate
and Other Segment
Total
Segments
($ in thousands)
 
 
 
 
 
 
 
 
 
 
Sales to external customers
 
$
652,423

 
$
88,672

(c)
 
$
(8,786
)
(a)
 
$
732,309

Intersegment sales
 
—

 
6,063

 
 
(6,063
)
 
 
—

Cost of natural gas, natural gas liquids and condensate
 
468,304

 
—

 
 
—

 
 
468,304

Intersegment cost of oil and condensate
 
5,587

 
—

 
 
(5,587
)
 
 
—

Operating costs and other (income) expenses
 
55,917

 
32,724

(b) 
 
45,775

 
 
134,416

Intersegment operations and maintenance
 
—

 
47

 
 
(47
)
 
 
—

Depreciation, depletion, amortization and impairment
 
77,554

 
33,960

 
 
1,550

 
 
113,064

Operating income (loss) from continuing operations
 
$
45,061

 
$
28,004

 
 
$
(56,540
)
 
 
$
16,525

Capital Expenditures
 
$
45,308

 
$
26,772

 
 
$
1,609

 
 
$
73,689

Segment Assets
 
$
975,717

 
$
359,474

 
 
$
14,206

(d)
 
$
1,349,397

_________________________________
(a)
Represents results of the Partnership's derivatives activity.
(b)
Includes costs to dispose of sulfur in the Upstream segment of $0.7 million for the year ended December 31, 2010.
(c)
Sales to external customers for the year ended December 31, 2010 includes $3.0 million of business interruption insurance recovery related to the shutdown of the Eustace plant in 2010 in the Upstream Segment, which is recognized in Other revenue on the Consolidated Statement of Operations.
(d)
Includes elimination of intersegment transactions.


F-36


Midstream Business
Year Ended December 31, 2009
 
Texas
Panhandle
Segment
 
South
Texas
Segment
 
East Texas /
Louisiana
Segment
 
Gulf of
Mexico Segment
 
Total
Midstream
Business
($ in thousands)
 
 
 
 
 
 
 
 
 
 
Sales to external customers
 
$
293,952

 
$
78,476

 
$
209,518

 
$
33,641

(c)
$
615,587

Cost of natural gas, natural gas liquids and condensate
 
206,985

 
73,785

 
162,957

 
26,372

 
470,099

Operating costs and other expenses
 
31,873

 
1,904

 
17,985

 
1,907

 
53,669

Depreciation, depletion, amortization and impairment
 
46,085

 
11,332

 
23,129

 
6,576

 
87,122

Operating income (loss) from continuing operations
 
$
9,009

 
$
(8,545
)
 
$
5,447

 
$
(1,214
)
 
$
4,697

Capital Expenditures
 
$
7,293

 
$
69

 
$
18,188

 
$
358

 
$
25,908

Segment Assets
 
$
539,899

 
$
93,837

 
$
285,327

 
$
87,780

 
$
1,006,843

Total Segments
Year Ended December 31, 2009
 
Total
Midstream
Business
 
Upstream
Segment
 
Corporate
and Other Segment
Total
Segments
($ in thousands)
 
 
 
 
 
 
 
 
 
Sales to external customers
 
$
615,587

 
$
63,633

 
$
(106,290
)
(a)
 
$
572,930

Cost of natural gas, natural gas liquids and condensate
 
470,099

 
—

 
—

 
 
470,099

Operating costs and other expenses
 
53,669

 
24,984

(b)
45,819

 
 
124,472

Depreciation, depletion, amortization and impairment
 
87,122

 
42,123

 
1,073

 
 
130,318

Operating income (loss) from continuing operations operations
 
$
4,697

 
$
(3,474
)
 
$
(153,182
)
 
 
$
(151,959
)
Capital Expenditures
 
$
25,908

 
$
8,437

 
$
2,022

 
 
$
36,367

Segment Assets
 
$
1,006,843

 
$
363,667

 
$
164,308

 
 
$
1,534,818


 
Midstream Business
Year Ended December 31, 2008
 
Texas
Panhandle
Segment
 
South
Texas
Segment
 
East Texas /
Louisiana
Segment
 
Gulf of
Mexico Segment
 
Total
Midstream
Business
($ in thousands)
 
 
 
 
 
 
 
 
 
 
Sales to external customers
 
$
603,066

 
$
167,202

 
$
322,040

 
$
1,655

 
$
1,093,963

Cost of natural gas, natural gas liquids and condensate
 
459,064

 
156,549

 
269,030

 
1,376

 
886,019

Operating costs and other expenses
 
34,269

 
2,489

 
16,569

 
605

 
53,932

Depreciation, depletion, amortization and impairment
 
43,688

 
11,909

 
40,553

 
1,521

 
97,671

Operating income (loss) from continuing operations
 
66,045

 
$
(3,745
)
 
$
(4,112
)
 
$
(1,847
)
 
$
56,341

Capital Expenditures
 
$
30,738

 
$
1,145

 
$
17,391

 
$
—

 
$
49,274

Segment Assets
 
$
563,556

 
$
107,655

 
$
313,383

 
$
80,106

 
$
1,064,700

Total Segments
Year Ended December 31, 2008
 
Total
Midstream
Business
 
Upstream
Segment
 
Corporate
and Other Segment
Total
Segments
($ in thousands)
 
 
 
 
 
 
 
 
 
Sales to external customers
 
$
1,093,963

 
$
173,029

 
$
161,765

(a)
 
$
1,428,757

Cost of natural gas, natural gas liquids and condensate
 
886,019

 
—

 
—

 
 
886,019

Operating costs and other expenses
 
53,932

 
37,481

 
56,317

 
 
147,730

Depreciation, depletion, amortization and impairment
 
97,671

 
183,008

 
787

 
 
281,466

Operating income (loss) from continuing operations operations
 
$
56,341

 
$
(47,460
)
 
$
104,661

 
 
$
113,542

Capital Expenditures
 
$
49,274

 
$
20,655

 
$
751

 
 
$
70,680

Segment Assets
 
$
1,064,700

 
$
397,785

 
$
310,576

 
 
$
1,773,061

_________________________________
(a)
Represents results of the Partnership's derivatives activity.
(b)
Includes costs to dispose of sulfur in the Upstream segment of $2.2 million for the year ended December 31, 2009.
(c)
Sales to external customers for the year ended December 31, 2009 includes $1.6 million of business interruption insurance recovery related to the damage incurred from Hurricane Ike and Gustav in the Gulf of Mexico Segment, which is recognized in Other revenue on the Consolidated Statement of Operations.
 

F-37

NOTE 14. EMPLOYEE BENEFIT PLAN
 
The Partnership offers a defined contribution benefit plan to its employees. The plan, which was amended in December 2007 to eliminate, in part, a requirement that an employee have been with the Partnership longer than six months, 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 may, at its sole discretion and election, contribute up to 6% of a participating employee's base salary annually, subject to vesting requirements. Expenses under the plan for the years ended December 31, 2010, 2009 and 2008 were approximately $1.0 million, $0.7 million and $1.4 million, respectively.
 
NOTE 15. INCOME TAXES
 
The Partnership's provision for income taxes relates to (i) state taxes for the Partnership and (ii) federal taxes for Eagle Rock Energy Acquisition Co., Inc, (acquiring entity of Redman Energy Holdings, L.P. and Redman Energy Holdings II, L.P. and certain assets owned by NGP Income Co-Investment Opportunities Fund II, L.P. (collectively the "Redman Acquisition") in 2007)  and Eagle Rock Energy Acquisition Co. II, Inc. (acquiring entity of certain entities acquired in the Stanolind Acquisition in 2008) and their wholly owned corporations, Eagle Rock Upstream Development Company, Inc., (successor entity of certain entities acquired in the Redman acquisition) and Eagle Rock Upstream Development Company II, Inc. (successor entity of certain entities acquired in the Stanolind acquisition), which are subject to federal income taxes (the “C Corporations”).   In addition, with the amendment of the Texas Franchise Tax in 2006, the Partnership has become a taxable entity in the state of Texas. The Partnership's federal and state income tax provision is summarized below (in thousands):
 
 
For the Year Ended December 31,
 
2010
 
2009
 
2008
Current:
 
 
 
 
 
Federal
$
236

 
$
680

 
$
140

State
(240
)
 
1,464

 
831

Total current provision
(4
)
 
2,144

 
971

Deferred:
 
 
 
 
 
Federal
(2,204
)
 
1,862

 
(6,766
)
State
513

 
235

 
2,217

Total deferred
(1,691
)
 
2,097

 
(4,549
)
Total (benefit) provision for income taxes
(1,695
)
 
4,241

 
(3,578
)
Add Back:  Valuation allowance for Federal tax attributes
—

 
(3,154
)
 
2,444

Total (benefit) provision for income taxes less valuation allowance
(1,695
)
 
1,087

 
(1,134
)
Income taxes from discontinued operations
(890
)
 
(98
)
 
(325
)
Total (benefit) provision for income taxes on continuing operations
$
(2,585
)
 
$
989

 
$
(1,459
)

The effective rate for the years ended December 31, 2010, 2009 and 2008 are shown in the table below.  For 2010 and 2008, the effective tax rates are attributable to the state and federal taxes being applied to their respective book incomes. In 2009, the federal and state based income taxes were applied against book losses which resulted in a 100% effective tax rate.   A reconciliation of the provision for income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows (in thousands):
 

F-38

 
For the Year Ended December 31,
 
2010
 
2009
 
2008
Pre-tax net book income (loss) from continuing operations
$
(25,196
)
 
$
(179,846
)
 
$
48,861

Texas Margin Tax current and deferred
(617
)
 
1,601

 
2,723

Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities
(1,498
)
 
(963
)
 
(4,182
)
Tax attributes used
(470
)
 
(2,803
)
 
(2,444
)
Valuation allowance
—

 
3,154

 
2,444

(Benefit) provision for income taxes from continuing operations
$
(2,585
)
 
$
989

 
$
(1,459
)
Effective income tax rate on continuing operations
10.3
%
 
100.0
%
 
(3.0
)%

Significant components of deferred tax liabilities and deferred tax assets as of December 31, 2010 and 2009 are as follows (in thousands):

 
December 31, 2010
 
December 31, 2009
Deferred Tax Assets:
 
 
 
Statutory depletion carryover
$
1,765

 
$
1,562

AMT credit carryforward
204

 
—

Total deferred tax
1,969

 
1,562

Less: valuation allowance
—

 
—

Net Deferred Tax Assets
1,969

 
1,562

 
 
 
 
Deferred Tax Liabilities:
 
 
 
Property, plant, equipment & amortizable assets
(3,295
)
 
(3,012
)
Unrealized hedging transactions
(540
)
 
(609
)
Book/tax differences from partnership investment
(34,827
)
 
(36,625
)
Total Deferred Tax Liabilities
(38,662
)
 
(40,246
)
Total Net Deferred Tax Liabilities
(36,693
)
 
(38,684
)
Current potion of total net deferred tax liabilities
—

 
—

Long-term portion of total net deferred tax liabilities
$
(36,693
)
 
$
(38,684
)

The Partnership had depletion deduction carryforwards and AMT credit carryforwards of $2.0 million and $1.6 million at December 31, 2010 and 2009, respectively.
 
The largest single component of Partnership's deferred tax liabilities is related to federal income taxes of the C Corporations described above.  Book/tax differences were created by the Redman and Stanolind Acquisitions. These book/tax temporary differences result in a net deferred tax liability of $32.9 million at December 31, 2010, which will be reduced as allocation of built-in gain in proportion to the assets contributed brings the book and tax basis closer together over time. This deferred tax liability was recognized in conjunction with the purchase accounting adjustments for long term assets.  The additional $3.8 million in deferred tax liabilities are related to book/tax differences in property, plant, and equipment and unrealized hedging transactions.
 
On May 18, 2006, the State of Texas enacted House Bill 3 which revised the pre-existing state franchise tax. In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax, including previously non-taxable entities such as limited partnerships and limited liability partnerships. The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits.
 
Although the bill states that the Revised Texas Franchise Tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses. Due to the enactment of the Revised Texas Franchise Tax, the Partnership recorded a net deferred tax liability of $3.8 million, $3.6 million

F-39

and $3.4 million as of December 31, 2010, 2009 and 2008, respectively. The offsetting net changes of $0.2 million, $0.2 million and $1.5 million are shown in the Consolidated Statements of Operations for the years ended December 31, 2010, 2009 and 2008, respectively, as a component of provision for income taxes.
 
The Partnership adopted authoritative guidance related to accounting for uncertainty in income taxes on January 1, 2007.  The Partnership has taken a position which is deemed to be “more likely than not” to be upheld upon review, if any, with respect to the deductibility of certain costs for the purpose of its franchise tax liability on a state franchise return.   The Partnership has recorded a provision for the portion of this tax liability equal to the probability of recognition. In addition, the Partnership has accrued interest and penalties associated with these liabilities and has recorded these amounts within its state deferred income tax expense. The amount stated below relates to the tax returns filed for 2010 and 2009, which are still open under current statute. A reconciliation of the beginning and ending amount of the unrecognized tax benefits (liabilities) is as follows (in thousands): 
Balance as of December 31, 2009                                                                                                               
$
(267
)
Increases related to prior year tax positions                                                                                                       
—

Increases related to current year tax positions 
(302
)
Balance as of December 31, 2010                                                                                                                
$
(569
)

NOTE 16. EQUITY-BASED COMPENSATION
 
Eagle Rock Energy G&P, LLC, the general partner of the general partner for the Partnership, has a long-term incentive plan as amended (“LTIP”) for its employees, directors and consultants who provide services to the Partnership and its subsidiaries and affiliates. On September 17, 2010, at a special meeting of the unitholders of the Partnership, the Partnership's unitholders approved an amendment and restatement of the Partnership's Long Term Incentive Plan (the "Amended Plan") to (i) increase the number of Partnership common units reserved for issuance under the Amended Plan by 5,000,000 units, (ii) provide for the grant of unit appreciation rights and other unit based awards, and (iii) make certain other non-material changes to the Amended Plan. The Amended Plan became effective following its approval by the Partnership's unitholders. Subsequent to approval, the LTIP provides for the issuance of an aggregate of 7,000,000 common units, to be granted either as options, restricted units or phantom units. Distributions declared and paid on outstanding restricted units are paid directly to the holders of the restricted units. The Partnership has historically only issued restricted units under the LTIP. No options or phantom units have been issued to date.

The weighted average fair value of the units granted during the years ended December 31, 2010, 2009 and 2008 were $6.60, $5.58 and $14.89, respectively. The awards generally vest on the basis of one third of the award each year. During the restriction period, distributions associated with the granted awards will be distributed to the awardees. No options or phantom units have been issued to date.
 
A summary of the restricted common units’ activity for the year ended December 31, 2010, is provided below:
 
Number of
Restricted
Units
 
Weighted
Average
Fair Value
Outstanding at December 31, 2009
1,371,019

 
$
9.35

Granted
1,293,845

 
$
6.60

Vested
(798,301
)
 
$
11.80

Forfeitures
(122,109
)
 
$
8.19

Outstanding at December 31, 2010
1,744,454

 
$
6.27

 
 For the years ended December 31, 2010, 2009, and 2008, non-cash compensation expense of approximately $5.4 million, $6.3 million, and $6.0 million, respectively, was recorded related to the granted restricted units. The GP Acquisition, as discussed in Note 8, triggered a change of control under certain award agreements for outstanding restricted common units awarded under the Partnership's LTIP and the accelerated vesting of the 315,607 affected outstanding restricted units, of which 84,086 were cancelled by the Partnership in satisfaction of $0.5 million in related employee tax liability paid by the Partnership, which are included in amounts discussed below. As a result of the accelerated vesting, the Partnership recognized an additional $2.8 million in equity-based compensation in the third quarter of 2010. In addition, during the three months ended September 30, 2010, the Partnership recorded a reduction to compensation expense of $2.2 million as a result of adjusting its forfeiture rate.
 

F-40

As of December 31, 2010, unrecognized compensation costs related to the outstanding restricted units under the Partnership's LTIP totaled approximately $8.9 million. The remaining expense is to be recognized over a weighted average of 2.56 years.
 
Due to the vesting of certain restricted units during the years ended December 31, 2010 and 2009, 181,292 and 17,492, respectively, were repurchased by the Partnership for $1.2 million and $0.1 million, respectively, as consideration for the related employee tax liability paid by the Partnership.  No units were repurchased in during the year ended December 31, 2008.  Pursuant to the terms of the LTIP, these repurchased units are available for future grants under the LTIP.
 
In addition to equity awards under the LTIP, Eagle Rock Holdings, L.P. (“Holdings”), which is controlled by NGP, has from time to time granted equity in Holdings to certain employees working on behalf of the Partnership, some of which are named executive officers. During years ended December 31, 2010, 2009 and 2008, Holdings granted 40,000, 160,000 and 417,000, respectively, “Tier I” incentive interests to certain Eagle Rock Energy employee. The Partnership recorded a portion of the value of the incentive units as compensation expense in the Partnership's Consolidated Statements of Operations. This allocation is based on management's estimation of the total value of the incentive unit grant and of the grantees' portion of time dedicated to the Partnership. The Partnership recorded non-cash compensation expense of $0.1 million, $0.4 million and $1.7 million based on management's estimates related to the Tier I incentive unit grants made by Holdings during years ended December 31, 2010, 2009 and 2008, respectively.

NOTE 17. EARNINGS PER UNIT
 
Basic earnings per unit are computed by dividing the net income (loss) by the weighted average number of units outstanding during a period. To determine net income (loss) allocated to each class of ownership (common, subordinated and general partner), the Partnership first allocates net income (loss) in accordance with the amount of distributions made for the quarter by each class, if any. The remaining net income (loss) is allocated to each class in proportion to the class weighted average number of units outstanding for a period, as compared to the weighted average number of units for all classes for the period.

The Partnership has unvested restricted common units outstanding, which are considered dilutive securities . These units will be considered in the diluted weighted average common unit outstanding number in periods of net income. In periods of net losses, these units are excluded from the diluted weighted average common unit outstanding number.

As part of its rights offering, the Partnership granted warrants, as discussed in Note 8. Any warrants outstanding during the period are consider to be dilutive securities. These outstanding warrants will be considered in the diluted weighted average common unit outstanding number in periods of net income, except if the exercise price of the outstanding warrants is greater than the average market price of the common units for such periods. In periods of net losses, the outstanding warrants are excluded from the diluted weighted average common unit outstanding number.

For the years ended December 31, 2010, 2009 and 2008, the Partnership determined that it is more dilutive to apply the two-class method versus the treasury stock method in calculating dilutive earnings per unit. Thus, the unvested restricted common units are included in the computation of the diluted weighted average common unit outstanding calculation, but the denominator in the computation of diluted earnings per unit only includes the basic weighted average common units outstanding.

Under the Partnership's original partnership agreement, which was amended and restated on May 24, 2010, in connection with approval of the Recapitalization and Related Transactions, for any quarterly period, incentive distribution rights (“IDRs”) participated in net income only to the extent of the amount of cash distributions actually declared, thereby excluding the IDRs from participating in undistributed earnings or losses. Accordingly, undistributed net income is assumed to be allocated to the other ownership interests on a pro-rata basis. During the years ended December 31,2010 and 2009, the Partnership did not declare a quarterly distribution for the IDRs. On May 24, 2010, the Partnership's general partner contributed all of the outstanding IDRs to the Partnership (see Notes 8 and 9), and they were eliminated.

In addition, all of the subordinated units and general partner units, as discussed in Notes 8 and 9, were contributed to the Partnership and cancelled on May 24, 2010 and July, 30, 2010, respectively. As a result, the number of subordinated units and general partner units used in the calculation of earnings per unit for the three and nine months ended September 30, 2010 is based on the weighted average amount of time they were outstanding during those periods.

The restricted common units granted under the LTIP, as discussed in Note 15, contain non-forfeitable rights to the distributions declared by the Partnership and therefore meet the definition of participating securities. Participating securities are

F-41

required to be included in the computation of earnings per unit pursuant to the two-class method.

The following table presents the Partnership's calculation of basic and diluted units outstanding for the periods indicated:
 
 
For the Year Ended December 31,
 
2010
 
2009
 
2008
 
(Unit amounts in thousands)
Basic weighted average unit outstanding during period:
 
 
 
 
 
Common units
68,625

 
53,496

 
51,534

Subordinated units
8,163

 
20,691

 
20,691

General partner units
488

 
845

 
845

 
 
 
 
 
 
Diluted weighted average unit outstanding during period:
 

 
 

 
 

Common units
68,625

 
53,496

 
51,699

Subordinated units
8,163

 
20,691

 
20,691

General partner units
488

 
845

 
845

 
The following table presents the Partnership's basic and diluted loss per unit for the year ended December 31, 2010:

 
 
Total
 
Common Units
 
Restricted Common Units
 
Subordinated Units
 
General Partner Units
 
 
($ in thousands, except for per unit amounts)
Loss from continuing operations
 
$
(22,611
)
 
 
 
 
 
 
 
 
Distributions declared
 
14,943

 
$
14,658

 
$
243

 
$
—

 
$
42

Assumed loss from continuing operations after distribution to be allocated
 
(37,554
)
 
(32,788
)
 
(633
)
 
(3,901
)
 
(232
)
Assumed allocation of loss from continuing operations
 
(22,611
)
 
(18,130
)
 
(390
)
 
(3,901
)
 
(190
)
Discontinued operations
 
17,262

 
15,071

 
291

 
1,793

 
107

Assumed net loss to be allocated
 
$
(5,349
)
 
$
(3,059
)
 
$
(99
)
 
$
(2,108
)
 
$
(83
)
 
 
 
 
 
 
 
 
 
 
 
Basic and diluted loss from continuing operations per unit
 
 
 
$
(0.26
)
 
 
 
$
(0.48
)
 
$
(0.39
)
Basic and diluted discontinued operations per unit
 
 
 
$
0.22

 
 
 
$
0.22

 
$
0.22

Basic and diluted loss per unit
 
 
 
$
(0.04
)
 
 
 
$
(0.26
)
 
$
(0.17
)



F-42

The following table presents the Partnership's basic and diluted loss per unit for the year ended December 31, 2009:

 
 
Total
 
Common Units
 
Restricted Common Units
 
Subordinated Units
 
General Partner Units
 
 
($ in thousands, except for per unit amounts)
Loss from continuing operations
 
$
(180,835
)
 
 
 
 
 
 
 
 
Distributions declared
 
5,498

 
$
5,350

 
$
64

 
$
—

 
$
84

Assumed loss from continuing operations after distribution to be allocated
 
(186,333
)
 
(132,851
)
 
—

 
(51,385
)
 
(2,097
)
Assumed allocation of loss from continuing operations
 
(180,835
)
 
(127,501
)
 
64

 
(51,385
)
 
(2,013
)
Discontinued operations
 
9,577

 
6,828

 
—

 
2,641

 
108

Assumed net loss to be allocated
 
$
(171,258
)
 
$
(120,673
)
 
$
64

 
$
(48,744
)
 
$
(1,905
)
 
 
 
 
 
 
 
 
 
 
 
Basic and diluted loss from continuing operations per unit
 
 
 
$
(2.38
)
 
 
 
$
(2.48
)
 
$
(2.38
)
Basic and diluted discontinued operations per unit
 
 
 
$
0.13

 
 
 
$
0.13

 
$
0.13

Basic and diluted loss per unit
 
 
 
$
(2.26
)
 
 
 
$
(2.36
)
 
$
(2.26
)
 
    The following table presents the Partnership's basic and diluted income per unit for the year ended December 31, 2008:

 
 
Total
 
Common Units
 
Restricted Common Units
 
Subordinated Units
 
General Partner Units
 
 
($ in thousands, except for per unit amounts)
Income from continuing operations
 
$
50,320

 
 
 
 
 
 
 
 
Distributions declared
 
120,256

 
$
84,000

 
$
1,152

 
$
33,727

 
$
1,377

Assumed loss from continuing operations after distribution to be allocated
 
(69,936
)
 
(49,324
)
 
—

 
(19,804
)
 
(808
)
Assumed allocation of income from continuing operations
 
50,320

 
34,676

 
1,152

 
13,923

 
569

Discontinued operations
 
37,200

 
26,236

 
—

 
10,534

 
430

Assumed net income to be allocated
 
$
87,520

 
$
60,912

 
$
1,152

 
$
24,457

 
$
999

 
 
 
 
 
 
 
 
 
 
 
Basic and diluted income from continuing operations per unit
 
 
 
$
0.67

 
 
 
$
0.67

 
$
0.67

Basic and diluted discontinued operations per unit
 
 
 
$
0.51

 
 
 
$
0.51

 
$
0.51

Basic and diluted income per unit
 
 
 
$
1.18

 
 
 
$
1.18

 
$
1.18


NOTE 18.  OTHER OPERATING EXPENSE
 
Other operating (income) expense for the year ended December 31, 2009, includes income of $3.6 million due to the recovery of $2.2 million of assets previously written off and the release of $1.4 million of liabilities assumed as part of the Partnership's purchase price allocation for its acquisitions of Escambia Asset Co., LLC and Redman Energy Holdings, L.P.  During the period, the Partnership received additional information about collectability of these assets and determined that it no longer had any obligation under these liabilities.
 
In July 2008, SemGroup, L.P. and certain of its subsidiaries (“SemGroup”) filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code.  The Partnership historically sold portions of its condensate production from its Texas

F-43

Panhandle and East Texas midstream systems to SemGroup.  As a result of the bankruptcy, the Partnership took a $10.7 million bad debt charge during the year ended December 31, 2008, which is included in “Other Operating Expense” in the consolidated statement of operations.  In August 2009, the Partnership sold $3.9 million of its outstanding receivables from SemGroup, which represented its 20-day administrative claims under 503(b)(9) of the United States Bankruptcy Code, for which it received a payment of $3.0 million.  Due to certain repurchase obligations under the assignment agreement, the Partnership recorded the payment as a current liability within accounts payable as of December 31, 2010 and anticipates maintaining the balance as a liability until it is clear that the repurchase obligations can no longer be triggered.

NOTE 19.   DISCONTINUED OPERATIONS

On April 1, 2009, the Partnership sold its producer services business (which was accounted for in its South Texas Segment) by assigning and novating the contracts under this business to a third-party purchaser. The Partnership sold the producer services business to a third-party purchaser as it was a low-margin business that was not core to the Partnership's operations. The Partnership received an initial payment of $0.1 million for the sale of the business. In addition the Partnership received a contingency payment of $0.1 million in October 2009. The Partnership will also continue to receive a monthly payment equivalent to $0.01 per MMbtu on the volume of gas that flows pursuant to the assigned contracts through March 31, 2011. Producer services was a business in which the Partnership would negotiate new well connections on behalf of small producers to pipelines other than its own. During the year ended December 31, 2010, this business generated revenues of $0.1 million and no cost of natural gas and NGLs. During the year ended December 31, 2009, this business generated revenues of $19.2 million and cost of natural gas and NGLs of $18.9 million. During the year ended December 31, 2008, this business generated revenues of $265.1 million and cost of natural gas and NGLs of $263.3 million. For the year ended December 31, 2010, 2009 and 2008, $0.1 million. $0.3 million and $1.8 million, respectively, of revenues minus the cost of natural gas and NGLs have been reported as discontinued operations.

On May 24, 2010, the Partnership completed the sale of its Minerals Business, for which it received net proceeds of approximately $171.6 million in cash after purchase price adjustments made to reflect an effective date of January 1, 2010 for the sale, as established in the agreement governing the sale. The Partnership retained approximately $2.9 million of cash from net revenues received from the Minerals Business after the effective date. The Partnership recorded a gain of $37.7 million on the sale, which is recorded as part of discontinued operations for the year ended December 31, 2010. Further upward or downward adjustments to the purchase price may occur post-closing to reflect customary true-ups. During the six months ended December 31, 2010, the Partnership received payments of $0.3 million related to pre-effective date operations and have recorded this amount as part of discontinued operations for the period. For the year ended December 31, 2010, the Minerals Business generated revenues of $8.9 million and income from operations of $5.5 million. For the year ended December 31, 2009, the Minerals Business generated revenues of $15.7 million and income from operations of $7.8 million. For the year ended December 31, 2008, the Minerals Business generated revenues of $43.0 million and income from operations of $31.7 million. During the years ended December 31, 2010, 2009 and 2008, the Minerals Business incurred state tax expense on discontinued operations of $0.4 million, $0.2 million and $0.4 million, respectively. During the years ended December 31, 2010, 2009 and 2008, the Minerals Business recorded a gain to discontinued operations of $5.5 million, $9.1 million and $35.4 million, respectively, excluding the gain recognized by the Partnership on the sale of the Minerals Business.

Assets and liabilities held for sale represent the assets and liabilities of the Partnership's Minerals Business. As of December 31, 2009, assets held for sale consists of the following: (i) accounts receivable of $3.0 million, (ii) net proved reserves of $55.2 million, (iii) unproved reserves of $64.9 million and (iv) the Partnership's equity investment in Ivory Working Interests, L.P. of $12.0 million. As of December 31, 2009, liabilities held for sale was made up of accounts payable.

NOTE 20. SUBSIDIARY GUARANTORS
 
In the future, the Partnership may issue registered debt securities guaranteed by its subsidiaries.  The Partnership expects that all guarantors would be wholly-owned or available to be pledged and that such guarantees would be joint and several and full and unconditional.  In accordance with practices accepted by the SEC, the Partnership has prepared Condensed Consolidating Financial Statements..  The following Condensed Consolidating Balance Sheets at December 31, 2010 and 2009, and Condensed Consolidating Statements of Operations and Condensed Consolidating Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008, present financial information for Eagle Rock Energy Partners, L.P. as the Parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the co-issuer and the subsidiary guarantors, which are all 100% owned by the Parent, on a stand-alone basis, and the consolidation and elimination entries necessary to arrive at the information for the Partnership on a consolidated basis.  The subsidiary guarantors are not restricted from making distributions to the Partnership. The Condensed Consolidating Balance Sheet as of December 31, 2010 and 2009 and the Condensed Consolidating Statements of Operations and Condensed Consolidating Statements of Cash Flows for the years ended December 31, 2010 and 2009 have been retrospectively adjusted to

F-44

disclose separately the co-issuer.

Condensed Consolidating Balance Sheet
December 31, 2010
(in thousands)
Parent Issuer
 
Co-Issuer
 
Subsidiary Guarantors
 
Non-guarantor investments
 
Consolidating
Entries
 
Total
ASSETS:
 
 
 
 
 
 
 
 
 
 
 
Accounts receivable – related parties
$
42,667

 
$
—

 
$
—

 
$
—

 
$
(42,667
)
 
$
—

Assets held for sale
—

 
—

 
8,615

 
—

 
—

 
8,615

Other current assets
5,694

 
1

 
76,547

 
—

 
—

 
82,242

Total property, plant and equipment, net
1,200

 
—

 
1,136,039

 
—

 
—

 
1,137,239

Investment in subsidiaries
1,113,603

 
—

 
—

 
1,116

 
(1,114,719
)
 
—

Total other long-term assets
3,622

 
—

 
117,679

 
—

 
—

 
121,301

Total assets
$
1,166,786

 
$
1

 
$
1,338,880

 
$
1,116

 
$
(1,157,386
)
 
$
1,349,397

LIABILITIES AND EQUITY:
 
 
 
 
 
 
 
 
 
 
 
Accounts payable – related parties
$
—

 
$
—

 
$
42,667

 
$
—

 
$
(42,667
)
 
$
—

Liabilities held for sale
—

 
—

 
1,705

 
—

 
—

 
1,705

Other current liabilities
31,208

 
—

 
112,126

 
—

 
—

 
143,334

Other long-term liabilities
26,465

 
—

 
68,780

 
—

 
—

 
95,245

Long-term debt
530,000

 
—

 
—

 
—

 
—

 
530,000

Equity
579,113

 
1

 
1,113,602

 
1,116

 
(1,114,719
)
 
579,113

Total liabilities and equity
$
1,166,786

 
$
1

 
$
1,338,880

 
$
1,116

 
$
(1,157,386
)
 
$
1,349,397



Condensed Consolidating Balance Sheet
December 31, 2009
(in thousands)
Parent Issuer
 
Co-Issuer
 
Subsidiary
Guarantors
 
Non-guarantor investments
 
Consolidating Entries
 
Total
ASSETS:
 
 
 
 
 
 
 
 
 
 
 
Accounts receivable – related parties
$
87,433

 
$
—

 
$
—

 
$
—

 
$
(87,433
)
 
$
—

Assets held for sale
—

 
—

 
172,176

 
—

 
—

 
172,176

Other current assets
5,171

 
1

 
89,103

 
—

 
—

 
94,275

Total property, plant and equipment, net
212

 
—

 
1,124,483

 
—

 
—

 
1,124,695

Investment in subsidiaries
1,244,384

 
—

 
—

 
1,205

 
(1,245,589
)
 
—

Total other long-term assets
5,620

 
—

 
138,052

 
—

 
—

 
143,672

Total assets
$
1,342,820

 
$
1

 
$
1,523,814

 
$
1,205

 
$
(1,333,022
)
 
$
1,534,818

LIABILITIES AND EQUITY:
 
 
 
 
 
 
 
 
 
 
 
Accounts payable – related parties
$
—

 
$
—

 
$
87,433

 
$
—

 
$
(87,433
)
 
$
—

Liabilities held for sale
—

 
—

 
2,094

 
—

 
—

 
2,094

Other current liabilities
42,099

 
—

 
112,479

 
—

 
—

 
154,578

Other long-term liabilities
15,940

 
—

 
77,425

 
—

 
—

 
93,365

Long-term debt
754,383

 
—

 
—

 
—

 
—

 
754,383

Equity
530,398

 
1

 
1,244,383

 
1,205

 
(1,245,589
)
 
530,398

Total liabilities and equity
$
1,342,820

 
$
1

 
$
1,523,814

 
$
1,205

 
$
(1,333,022
)
 
$
1,534,818




F-45

Condensed Consolidating Statement of Operations
For the year ended December 31, 2010
(in thousands)
Parent Issuer
 
Co-Issuer
 
Subsidiary Guarantors
 
Non-guarantor investments
 
Consolidating
Entries
 
Total
Total revenues
$
(8,296
)
 
$
—

 
$
740,605

 
$
—

 
$
—

 
$
732,309

Cost of natural gas and natural gas liquids
—

 
—

 
468,304

 
—

 
—

 
468,304

Operations and maintenance
—

 
—

 
76,415

 
—

 
—

 
76,415

Taxes other than income
2

 
—

 
12,224

 
—

 
—

 
12,226

General and administrative
3,680

 
—

 
42,095

 
—

 
—

 
45,775

Depreciation, depletion, amortization and impairment
165

 
—

 
112,899

 
—

 
—

 
113,064

(Loss) income from operations
(12,143
)
 
—

 
28,668

 
—

 
—

 
16,525

Interest expense
(15,145
)
 
 
 
(2
)
 
—

 
—

 
(15,147
)
Other non-operating income
8,300

 
 
 
2,755

 
26

 
(10,469
)
 
612

Other non-operating expense
(14,988
)
 
 
 
(22,667
)
 
—

 
10,469

 
(27,186
)
(Loss) income before income taxes
(33,976
)
 
—

 
8,754

 
26

 
—

 
(25,196
)
Income tax provision (benefit)
517

 
—

 
(3,102
)
 
—

 
—

 
(2,585
)
Equity in earnings of subsidiaries
29,144

 
—

 
—

 
—

 
(29,144
)
 
—

(Loss) income from continuing operations
(5,349
)
 
—

 
11,856

 
26

 
(29,144
)
 
(22,611
)
Discontinued operations
—

 
—

 
17,262

 
—

 
—

 
17,262

Net (loss) income
$
(5,349
)
 
$
—

 
$
29,118

 
$
26

 
$
(29,144
)
 
$
(5,349
)


Condensed Consolidating Statement of Operations
For the year ended December 31, 2009
(in thousands)
Parent Issuer
 
Co-Issuer
 
Subsidiary Guarantors
 
Non-guarantor investments
 
Consolidating Entries
 
Total
Total revenues
$
(37,432
)
 
$
—

 
$
610,362

 
$
—

 
$
—

 
$
572,930

Cost of natural gas and natural gas liquids
—

 
—

 
470,099

 
—

 
—

 
470,099

Operations and maintenance
—

 
—

 
71,496

 
—

 
—

 
71,496

Taxes other than income
—

 
—

 
10,709

 
—

 
—

 
10,709

General and administrative
2,803

 
—

 
43,016

 
—

 
—

 
45,819

Other operating income
—

 
—

 
(3,552
)
 
—

 
—

 
(3,552
)
Depreciation, depletion, amortization and impairment
—

 
—

 
130,318

 
—

 
—

 
130,318

Loss from operations
(40,235
)
 
—

 
(111,724
)
 
—

 
—

 
(151,959
)
Interest expense
(21,568
)
 
—

 
(23
)
 
—

 
—

 
(21,591
)
Other non-operating income
6,886

 
—

 
2,788

 
153

 
(8,706
)
 
1,121

Other non-operating expense
(5,572
)
 
—

 
(10,551
)
 
—

 
8,706

 
(7,417
)
Income (loss) before income taxes
(60,489
)
 
—

 
(119,510
)
 
153

 
—

 
(179,846
)
Income tax provision (benefit)
1,547

 
—

 
(558
)
 
—

 
—

 
989

Equity in losses of subsidiaries
(109,222
)
 
—

 
—

 
—

 
109,222

 
—

Loss from continuing operations
(171,258
)
 
—

 
(118,952
)
 
153

 
109,222

 
(180,835
)
Discontinued operations
—

 
—

 
9,577

 
—

 
—

 
9,577

Net loss
$
(171,258
)
 
$
—

 
$
(109,375
)
 
$
153

 
$
109,222

 
$
(171,258
)



F-46

Condensed Consolidating Statement of Operations
For the year ended December 31, 2008
(in thousands)
Parent Issuer
 
Subsidiary Guarantors
 
Consolidating Entries
 
Total
Total revenues
$
8,809

 
$
1,419,948

 
$
—

 
$
1,428,757

Cost of natural gas and natural gas liquids
—

 
886,019

 
—

 
886,019

Operations and maintenance
—

 
73,203

 
—

 
73,203

Taxes other than income
—

 
18,210

 
—

 
18,210

General and administrative
15

 
45,603

 
—

 
45,618

Other operating expense
—

 
10,699

 
—

 
10,699

Depreciation, depletion, amortization and impairment
—

 
281,466

 
—

 
281,466

Income from operations
8,794

 
104,748

 
—

 
113,542

Interest expense
(33,842
)
 
—

 
—

 
(33,842
)
Other non-operating income
5,617

 
2,318

 
(5,846
)
 
2,089

Other non-operating expense
(5,665
)
 
(33,109
)
 
5,846

 
(32,928
)
(Loss) income before income taxes
(25,096
)
 
73,957

 
—

 
48,861

Income tax provision (benefit)
1,087

 
(2,546
)
 
—

 
(1,459
)
Equity in earnings of subsidiaries
113,703

 
—

 
(113,703
)
 
—

Income from continuing operations
87,520

 
76,503

 
(113,703
)
 
50,320

Discontinued operations
—

 
37,200

 
—

 
37,200

Net income
$
87,520

 
$
113,703

 
$
(113,703
)
 
$
87,520

 
 

F-47

Condensed Consolidating Statement of Cash Flows
For the year ended December 31, 2010
(in thousands)
Parent Issuer
 
Co-Issuer
 
Subsidiary Guarantors
 
Non-guarantor investments
 
Consolidating Entries
 
Total
Net cash flows provided by operating activities
$
43,756

 
$
—

 
$
50,318

 
$
54

 
$
—

 
$
94,128

CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
 
Additions to property, plant and equipment
(1,152
)
 
—

 
(63,345
)
 
—

 
—

 
(64,497
)
Purchase of intangible assets
—

 
—

 
(2,660
)
 
—

 
—

 
(2,660
)
Acquisitions,net of cash acquired
—

 
—

 
(30,984
)
 
—

 
—

 
(30,984
)
Proceeds from sale of asset
171,686

 
—

 
—

 
—

 
—

 
171,686

Contributions to subsidiaries
(27,043
)
 
—

 
—

 
—

 
27,043

 
—

Net cash flows provided by (used in) investing activities
143,491

 
—

 
(96,989
)
 
—

 
27,043

 
73,545

CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
 
Proceeds from long-term debt
90,617

 
—

 
—

 
—

 
—

 
90,617

Repayment of long-term debt
(315,000
)
 
—

 
—

 
—

 
—

 
(315,000
)
Proceeds from derivative contracts
—

 
—

 
1,131

 
—

 
—

 
1,131

Deferred transaction fees
(3,066
)
 
—

 
—

 
—

 
—

 
(3,066
)
Proceeds from Rights Offering
53,893

 
—

 
—

 
—

 
—

 
53,893

Exercise of Warrants
5,351

 
—

 
—

 
—

 
—

 
5,351

Repurchase of common units
(1,177
)
 
—

 
—

 
—

 
—

 
(1,177
)
Contributions from parent
—

 
—

 
27,043

 
—

 
(27,043
)
 
—

Distributions to members and affiliates
(7,195
)
 
—

 
—

 
—

 
—

 
(7,195
)
Net cash flows provided by (used in) financing activities
(176,577
)
 
—

 
28,174

 
—

 
(27,043
)
 
(175,446
)
Net cash flows provided by discontinued operations
—

 
—

 
9,090

 
—

 
—

 
9,090

Net (decrease) increase in cash and cash equivalents
10,670

 
—

 
(9,407
)
 
54

 
—

 
1,317

Cash and cash equivalents at beginning of year
4,922

 
1

 
(2,180
)
 
(11
)
 
—

 
2,732

Cash and cash equivalents at end of year
$
15,592

 
$
1

 
$
(11,587
)
 
$
43

 
$
—

 
$
4,049




F-48

Condensed Consolidating Statement of Cash Flows
For the year ended December 31, 2009
(in thousands)
Parent Issuer
 
Co-Issuer
 
Subsidiary Guarantors
 
Non-guarantor Investments
 
Consolidating Entries
 
Total
Net cash flows provided by operating activities
$
57,934

 
$
—

 
$
19,305

 
$
(11
)
 
$
—

 
$
77,228

CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
 
Additions to property, plant and equipment
(84
)
 
—

 
(36,050
)
 
—

 
—

 
(36,134
)
Purchase of intangible assets
—

 
—

 
(1,626
)
 
—

 
—

 
(1,626
)
Proceeds from sale of asset
—

 
—

 
476

 
—

 
—

 
476

Contributions to subsidiaries
(1
)
 
—

 
—

 
—

 
1

 
—

Net cash flows used in investing activities
(85
)
 
—

 
(37,200
)
 
—

 
1

 
(37,284
)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
 
Proceeds from long-term debt
131,000

 
—

 
—

 
—

 
—

 
131,000

Repayment of long-term debt
(176,000
)
 
—

 
—

 
—

 
—

 
(176,000
)
Proceeds from derivative contracts
—

 
—

 
8,939

 
—

 
—

 
8,939

Deferred transactions fees
(1,480
)
 
—

 
—

 
—

 
—

 
(1,480
)
Repurchase of common units
(64
)
 
—

 
—

 
—

 
—

 
(64
)
Contributions from parent
—

 
1

 
—

 
—

 
(1
)
 
—

Distributions to members and affiliates
(35,655
)
 
—

 
—

 
—

 
—

 
(35,655
)
Net cash flows (used in) provided by financing activities
(82,199
)
 
1

 
8,939

 
—

 
(1
)
 
(73,260
)
Net cash flows provided by discontinued operations
—

 
—

 
18,132

 
—

 
—

 
18,132

Net (decrease) increase in cash and cash equivalents
(24,350
)
 
1

 
9,176

 
(11
)
 
—

 
(15,184
)
Cash and cash equivalents at beginning of year
29,272

 
—

 
(11,356
)
 
—

 
—

 
17,916

Cash and cash equivalents at end of year
$
4,922

 
$
1

 
$
(2,180
)
 
$
(11
)
 
$
—

 
$
2,732


F-49

Condensed Consolidating Statement of Cash Flows
For the year ended December 31, 2008
(in thousands)
Parent Issuer
 
Subsidiary Guarantors
 
Non-guarantor Investments
 
Consolidating Entries
 
Total
Net cash flows provided by operating activities
$
106,073

 
$
32,712

 
$
—

 
$
—

 
$
138,785

CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
 
 
 
 
 
 
Additions to property, plant and equipment
(128
)
 
(66,613
)
 
—

 
—

 
(66,741
)
Purchase of intangible assets
—

 
(2,975
)
 
—

 
—

 
(2,975
)
Investment in partnerships
—

 
—

 
—

 
—

 
—

Acquisitions, net of cash acquired
(857
)
 
(261,388
)
 
—

 
—

 
(262,245
)
Proceeds from sale of asset
—

 
1,294

 
—

 
—

 
1,294

Contributions to subsidiaries
(261,981
)
 
—

 
—

 
261,981

 
—

Net cash flows used in investing activities
(262,966
)
 
(329,682
)
 
—

 
261,981

 
(330,667
)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
 
 
 
 
 
 
Proceeds from long-term debt
432,128

 
—

 
—

 
—

 
432,128

Repayment of long-term debt
(199,814
)
 
—

 
—

 
—

 
(199,814
)
Proceeds from derivative contracts
—

 
(11,063
)
 
—

 
—

 
(11,063
)
Payment of debt issuance costs
(789
)
 
—

 
—

 
—

 
(789
)
Contributions from parent
—

 
261,981

 
—

 
(261,981
)
 
—

Distributions to members and affiliates
(117,646
)
 
—

 
—

 
—

 
(117,646
)
Net cash flows provided by financing activities
113,879

 
250,918

 
—

 
(261,981
)
 
102,816

Net cash flows provided by discontinued operations
—

 
38,430

 
—

 
—

 
38,430

Net decrease in cash and cash equivalents
(43,014
)
 
(7,622
)
 
—

 
—

 
(50,636
)
Cash and cash equivalents at beginning of year
72,286

 
(3,734
)
 
—

 
—

 
68,552

Cash and cash equivalents at end of year
$
29,272

 
$
(11,356
)
 
$
—

 
$
—

 
$
17,916


NOTE 21. SUBSEQUENT EVENTS

In February 2011, the Partnership classified its Wildhorse Gathering System (which was accounted for in its South Texas Segment) and thus has retrospectively classified the assets and liabilities as held for sale and the operations as discontinued. As of December 31, 2010, liabilities held for sale consisted of accounts payable, and assets held for sale consisted of the following: (i) $2.1 million of accounts receivable, (ii) $6.2 million of pipelines and equipment, net and $0.3 million of intangible assets, net. As of December 31, 2009, liabilities held for sale consisted of accounts payable, and assets held for sale consisted of the following: (i) $2.3 million of accounts receivable, (ii) $31.0 million of pipelines and equipment, net and $3.6 million of intangible assets, net.

During the year ended December 31, 2010, the Wildhorse Gathering System generated revenues of $26.1 million and an operating loss of $25.9 million, which includes an impairment charge of $26.2 million. During the year ended December 31, 2009, the Wildhorse Gathering System generated revenues of $21.8 million and operating income of $0.2 million. During the year ended December 31, 2008, the Wildhorse Gathering System generated revenues of $6.5 million and operating income of less than $0.1 million.

NOTE 22. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
 
Oil and Natural Gas Reserves
 
Users of this information should be aware that the process of estimating quantities of proved oil and natural gas reserves is very complex, and requires significant subjective decisions in the evaluation of the available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and changing operating and market conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although reasonable effort is made to ensure the reported reserve estimates represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

F-50

 
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. Reserve data represent estimates only and should not be construed as being exact. Moreover, the Standardized Measure of Oil and Gas (“SMOG”) should not be construed as the current market value of the proved oil and natural gas reserves or the costs that would be incurred to obtain equivalent reserves. A market value determination would include many additional factors including (a) anticipated future changes in natural gas and crude oil prices, production and development costs, (b) an allowance for return on investment, (c) the value of additional reserves, not considered proved at present, which may be recovered as a result of further exploration and development activities, and (d) other business risks.

Recent Developments

On May 24, 2010, the Partnership sold its Minerals Business (see Notes 1, 13 and 19). Financial information, including reserve amounts and changes, related to the Minerals Business have been retrospectively adjusted to be reflected as assets and liabilities held-for-sale and discontinued operations, as discussed further in Note 1.
 
Proved Reserves Summary
 
The following table illustrates the Partnership's estimated net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by Cawley, Gillespie and Associates. Oil and natural gas liquids prices for 2010 are based on a prior twelve month average West Texas Intermediate spot price of $79.63 per barrel and are adjusted for quality, transportation fees, and regional price differentials. Natural gas prices for 2010 are based on a prior 12 month average Henry Hub spot market price of $4.37 per MMBtu and are adjusted for energy content, transportation fees, and regional price differentials. All prices are held constant in accordance with SEC guidelines.  All of the Partnership's reserves are located in the United States.


F-51

 
Proved Reserves - 2008
 
Oil
(MBbls)
 
Gas
(MMcf)
 
Natural Gas
Liquids (MBbls)
Proved reserves, January 1, 2008
10,081

 
44,643

 
5,743

Extensions and discoveries
139

 
2,639

 
45

Purchase of minerals in place
3,513

 
8,157

 
1,432

Production
(832
)
 
(4,123
)
 
(482
)
Revision of previous estimates
(2,864
)
 
(6,182
)
 
(1,099
)
Changes from discontinued operations
(31
)
 
(546
)
 
—

Proved reserves, December 31, 2008
10,006

 
44,588

 
5,639

 
 
 
 
 
 
Proved developed reserves - continuing operations, December 31, 2008
6,425

 
31,286

 
4,883

Proved developed reserves - discontiued operations, December 31, 2008
2,775

 
4,871

 
—

Proved undeveloped reserves - continuing operations, December 31, 2008
806

 
8,431

 
756

 
 
 
 
 
 
 
Proved Reserves - 2009
 
Oil
(MBbls)
 
Gas
(MMcf)
 
Natural Gas
Liquids (MBbls)
Proved reserves, January 1, 2009
10,006

 
44,588

 
5,639

Extensions and discoveries
298

 
1,782

 
241

Purchase of minerals in place
18

 
—

 
—

Production
(829
)
 
(6,647
)
 
(493
)
Revision of previous estimates
797

 
(1,030
)
 
718

Changes from discontinued operations
162

 
(53
)
 
—

Proved reserves, December 31, 2009
10,452

 
38,640

 
6,105

 
 
 
 
 
 
Proved developed reserves - continuing operations, December 31, 2009
7,121

 
26,263

 
5,410

Proved developed reserves - discontinued operations, December 31, 2009
2,937

 
4,819

 
—

Proved undeveloped reserves - continuing operations, December 31, 2009
394

 
7,558

 
695

 
 
 
 
 
 
 
Proved Reserves - 2010
 
Oil
(MBbls)
 
Gas
(MMcf)
 
Natural Gas
Liquids (MBbls)
Proved reserves, January 1, 2010
10,452

 
38,640

 
6,105

Extensions and discoveries
7

 
3,930

 
—

Purchase of minerals in place
216

 
555

 
102

Production
(808
)
 
(3,514
)
 
(437
)
Revision of previous estimates
1,766

 
3,590

 
406

Change from discontinued operations
(54
)
 
(342
)
 
—

Sale of minerals in place
(2,883
)
 
(4,477
)
 
—

Proved reserves, December 31, 2010
8,696

 
38,382

 
6,176

 
 
 
 
 
 
Proved developed reserves - continuing operations, December 31, 2010
8,299

 
29,686

 
5,758

Proved undeveloped reserves - continuing operations, December 31, 2010
397

 
8,696

 
418

 
In 2009, the Partnership experienced significant revisions to its proved reserves.  The Partnership revised its oil and natural gas liquids reserves upwards due to changes in production forecasts and engineering factors such as condensate and natural gas liquids yields.  The Partnership also revised its natural gas reserves downward due to technical factors (such as increased shrinkage related to fuel usage and plant processing) and economic factors.  Revisions due to economic factors are due to the relatively low prior twelve

F-52

month average natural gas price that was used to determine the reserves and higher operating cost estimates in its Permian Basin operations.  The Partnership also experienced negative oil and natural gas revisions in its Permian Basin operations, particularly in its lease in the Ward Estes and surrounding fields.  These revisions were primarily due to poorer than expected performance in recent San Andres drilling and recompletions, changes to decline curves to reflect recent production performance, and the upward adjustment of operating costs which rendered several leases non-commercial.  The Partnership is working to improve its cost structure on these leases and is optimistic that some of these negative reserves may be reversed in the future.

Proved Reserves Summary - Equity Method Entities

As part of the sale of the Minerals Business, the Partnership sold it 13.2% limited partner interest in IWI, which it had accounted for under the equity method. IWI is managed by Black Stone and is not required to make public disclosures about its proved reserves and the agreements that governed the Partnership's rights as limited partners in IWI do not require Black Stone to provide us with detailed reserve data of the type that would be sufficient to make all of the disclosures that the SEC now requires with respect to proved reserves of equity method entities. As a result, the Partnership lacks the date needed to prepare the Supplemental Oil and Gas Disclosures for its equity interests.

Capitalized Costs Relating to Oil and Natural Gas Producing Activities
 
The following table illustrates the total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization at December 31, 2010, 2009 and 2008:
 
 
As of
December 31, 2010
 
As of
December 31, 2009
 
As of
December 31, 2008
($ in thousands)
 
 
 
 
 
Evaluated properties
$
471,781

 
$
435,789

 
$
437,865

Unevaluated properties—excluded from depletion
1,304

 
7,264

 
7,599

Gross oil and gas properties
473,085

 
443,053

 
445,464

Accumulated depreciation, depletion, amortization
(125,832
)
 
(95,135
)
 
(60,833
)
Net oil and gas properties
347,253

 
347,918

 
384,631

Net oil and gas properties held-for-sale
—

 
120,149

 
127,807

Total net oil and gas properties
$
347,253

 
$
468,067

 
$
512,438

 
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities
 
Costs incurred in property acquisition, exploration and development activities were as follows for the years ended December 31, 2010, 2009 and 2008:
 
 
Years Ended December 31,
 
2010
 
2009
 
2008
($ in thousands)
 
 
 
 
 
Property acquisition costs, proved
$
4,222

 
$
512

 
$
110,747

Property acquisition costs, unproved
259

 
20

 
7,597

Exploration and extension well costs
—

 
1

 
1,610

Development costs
25,922

 
8,137

 
12,294

Total costs
$
30,403

 
$
8,670

 
$
132,248

 
The Partnership's exploration and extension well costs are primarily related to low risk drilling around its existing fields.
    
 No costs were incurred associated with the Minerals Business which is classified as Discontinued Operations on the Consolidated Statements of Operations and Assets Held for Sale on the Consolidated Balances sheet.


F-53

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
 
The following information has been developed utilizing authoritative guidance procedures and is based on oil and natural gas reserves estimated by the Partnership's independent reserves engineer. It can be used for some comparisons, but should not be the only method used to evaluate the Partnership or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flow be viewed as representative of the current value of the Partnership.
 
The Partnership believes that the following factors should be taken into account when reviewing the following information:
 
•
future costs and selling prices will probably differ from those required to be used in these calculations;
 
•
due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations; and
 
•
a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues.
 
Under the Standardized Measure, future cash inflows were estimated by applying year-end oil and natural gas prices to the estimated future production of year-end proved reserves. Estimates of future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor.
 
In the Partnership's 2009 Standardized Measure calculations it included the future revenues that would be associated with the sales of sulfur; however the cash flows only partially offset the costs of transporting and marketing the sulfur.  As such, it is a net negative cash flow in the Standardized Measure.  Also, the Partnership included the expected impact of the retained revenue interests as a revenue reduction.
 
The recent changes to the disclosure rules relating to proved reserves require the inclusion of the Partnership's share of the reserves associated with entities that it reports under the equity method.  As discussed above, the Partnership sold these interests as part of the sale of its Minerals Business. As the Partnership did not have the right and has been unable to gather the data needed to include these reserves in its Standardized Measure calculations, the tables below reflect only the reserves for the Partnership's consolidate entities.
 
The Standardized Measure is as follows as of December 31, 2010, 2009 and 2008:
 
As of
December 31, 2010
 
As of
December 31, 2009
 
As of
December 31, 2008
($ in thousands)
 
 
 
 
 
Future cash inflows
$
1,027,417

 
$
650,564

 
$
654,901

Future production costs
(336,080
)
 
(307,605
)
 
(316,920
)
Future development costs
(97,745
)
 
(72,577
)
 
(60,189
)
Future net cash flows before income taxes
593,592

 
270,382

 
277,792

Future income tax (expense) benefit
(1,005
)
 
554

 
1,992

Future net cash flows before 10% discount
592,587

 
270,936

 
279,784

10% annual discount for estimated timing of cash flows
(258,594
)
 
(111,321
)
 
(116,773
)
Standardized measure of discounted future net cash flows related to continuing operations
333,993

 
159,615

 
163,011

Standardized measure of discounted future net cash flows related to discontinued operations
—

 
55,038

 
46,733

Total standardized measure of discounted future net cash flows
$
333,993

 
$
214,653

 
$
209,744

 

F-54

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
 
The following is a summary of the changes in the Standardized Measure of discounted future net cash flows for the Partnership's proved oil and natural gas reserves for the years ended December 31, 2010, 2009 and 2008:
 
 
Years Ended December 31,
 
2010
 
2009
 
2008
($ in thousands)
 
 
 
 
 
Beginning of year
$
214,653

 
$
209,744

 
$
556,960

Sale of oil and gas produced, net of production costs
(54,353
)
 
(40,824
)
 
(99,968
)
Net changes in prices and production costs
147,003

 
6,146

 
(257,840
)
Extensions, discoveries and improved recovery, less related costs
5,492

 
7,859

 
5,603

Previously estimated development costs incurred during the period
25,922

 
(8,137
)
 
(12,294
)
Net changes in future development costs
(30,033
)
 
8,733

 
11,766

Revisions of previous quantity estimates
74,864

 
9,404

 
(50,144
)
Purchases of property
7,342

 
347

 
45,239

Sales of property
(70,845
)
 
—

 
—

Accretion of discount
14,528

 
14,777

 
42,524

Net changes in income taxes
(793
)
 
(908
)
 
1,069

Other
(15,594
)
 
(793
)
 
7,860

Change from discontinued operations
15,807

 
8,305

 
(41,031
)
End of year
$
333,993

 
$
214,653

 
$
209,744

 
Results of Operations
 
The following are the results of operations for the Partnership's oil and natural gas producing activities for the years ended December 31, 2010, 2009 and 2008:
Year Ended December 31,
 
2010
 
2009
 
2008
($ in thousands)
 
 
 
 
 
 
Revenues
 
$
87,211

 
$
67,159

 
$
138,082

Costs and expenses:
 
 
 
 
 
 
Production costs
 
32,858

 
26,335

 
38,114

General and administrative
 
6,349

 
5,151

 
4,282

Depreciation, depletion, and amortization
 
30,424

 
34,009

 
44,997

Impairment
 
3,536

 
8,114

 
107,017

Total costs and expenses
 
73,167

 
73,609

 
$
194,410

Results of continuing operations
 
14,044

 
(6,450
)
 
(56,328
)
Discontinued operations
 
5,262

 
5,686

 
17,642

Total result of operations
 
$
19,306

 
$
(764
)
 
$
(38,686
)
 
* * * *


F-55

EAGLE ROCK ENERGY PARTNERS L P Reports