10-Q 1 q22011form10q.htm FORM 10-Q Q2 2011 Form 10Q
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

x
 
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
For the quarterly period ended June 30, 2011
OR 
o
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
Commission File No. 001-33016 
EAGLE ROCK ENERGY PARTNERS, L.P.
(Exact Name of Registrant as Specified in Its Charter)

 
 
Delaware
 
68-0629883
 
 
 
 
(State or Other Jurisdiction of
Incorporation or Organization)
 
(I.R.S. Employer
Identification Number)
 
 

1415 Louisiana Street, Suite 2700
Houston, Texas 77002
 (Address of principal executive offices, including zip code)
 
(281) 408-1200
(Registrant's telephone number, including area code)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  o
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes  x   No  o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one): 
Large accelerated filer  o
 
Accelerated filer  x
 
Non-accelerated filer  o
 
Smaller Reporting Company  o
 
(Do not check if a smaller reporting company)
 
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  o    No  x
 
The issuer had 121,763,523 common units outstanding as of August 1, 2011.









TABLE OF CONTENTS
 
 
 
Page 
PART I. FINANCIAL INFORMATION
Item 1.
Financial Statements
 
Unaudited Condensed Consolidated Balance Sheets as of June 30, 2011 and December 31, 2010
 
Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2011 and 2010
 
Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2011 and 2010
 
Unaudited Condensed Consolidated Statement of Member's Equity for the six months ended June 30, 2011
 
Notes to the Unaudited Condensed Consolidated Financial Statements
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
Item 4.
Controls and Procedures
PART II. OTHER INFORMATION
Item 1.
Legal Proceedings
Item 1A.
Risk Factors
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
Item 3.
Defaults Upon Senior Securities
Item 4.
[Removed and Reserved]
Item 5.
Other Information
Item 6.
Exhibits
 

 

1



PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.
 
EAGLE ROCK ENERGY PARTNERS, L.P.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
($ in thousands)

 
June 30,
2011
 
December 31,
2010
ASSETS
 
 
 
CURRENT ASSETS:
 
 
 
Cash and cash equivalents
$
6,825

 
$
4,049

Accounts receivable(a)
94,629

 
75,695

Risk management assets
1,976

 

Prepayments and other current assets
9,031

 
2,498

Assets held for sale

 
8,615

Total current assets
112,461

 
90,857

PROPERTY, PLANT AND EQUIPMENT — Net
1,705,056

 
1,137,239

INTANGIBLE ASSETS — Net
112,365

 
113,634

DEFERRED TAX ASSET
1,739

 
1,969

RISK MANAGEMENT ASSETS
2,936

 
1,075

OTHER ASSETS
18,879

 
4,623

TOTAL
$
1,953,436

 
$
1,349,397

 
 

 
 

LIABILITIES AND MEMBERS' EQUITY
 

 
 

CURRENT LIABILITIES:
 

 
 

Accounts payable
$
130,006

 
$
91,886

Due to affiliate
44

 
56

Accrued liabilities
12,537

 
10,940

Taxes payable
598

 
1,102

Risk management liabilities
30,371

 
39,350

Liabilities held for sale

 
1,705

Total current liabilities
173,556

 
145,039

LONG-TERM DEBT
745,855

 
530,000

ASSET RETIREMENT OBLIGATIONS
32,973

 
24,711

DEFERRED TAX LIABILITY
39,994

 
38,662

RISK MANAGEMENT LIABILITIES
20,697

 
31,005

OTHER LONG TERM LIABILITIES
2,307

 
867

COMMITMENTS AND CONTINGENCIES (Note 13)
 

 
 

MEMBERS' EQUITY (b)
938,054

 
579,113

TOTAL
$
1,953,436

 
$
1,349,397

________________________ 

(a)
Net of allowance for bad debt of $1,345 as of June 30, 2011 and $4,496 as of December 31, 2010.
(b)
119,879,395 and 83,425,378 common units were issued and outstanding as of June 30, 2011 and December 31, 2010, respectively. These amounts do not include unvested restricted common units granted under the Partnership's long-term incentive plan of 1,821,328 and 1,744,454 as of June 30, 2011 and December 31, 2010, respectively.

See notes to unaudited condensed consolidated financial statements.  


2

EAGLE ROCK ENERGY PARTNERS, L.P.


 UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
($ in thousands)
 
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2011
 
2010
 
2011
 
2010
 REVENUE:
 
 
 
 
 

 
 

Natural gas, natural gas liquids, oil, condensate and sulfur sales
$
265,317

 
$
164,972

 
$
468,372

 
$
356,973

Gathering, compression, processing and treating fees
12,304

 
16,230

 
25,549

 
28,713

Commodity risk management gains (losses)
34,338

 
35,592

 
(26,107
)
 
46,387

Other revenue
(244
)
 
(251
)
 
1,265

 
(215
)
Total revenue
311,715

 
216,543

 
469,079

 
431,858

COSTS AND EXPENSES:
 
 
 
 
 

 
 

Cost of natural gas, natural gas liquids, and condensate
172,674

 
108,643

 
319,993

 
246,545

Operations and maintenance
21,951

 
19,926

 
41,426

 
38,797

Taxes other than income
5,189

 
2,806

 
8,505

 
6,340

General and administrative
15,902

 
12,806

 
27,678

 
25,817

Other operating income
(2,893
)
 

 
(2,893
)
 

Impairment
4,560

 
3,130

 
4,884

 
3,130

Depreciation, depletion and amortization
31,576

 
27,469

 
55,274

 
54,913

Total costs and expenses
248,959

 
174,780

 
454,867

 
375,542

OPERATING INCOME
62,756

 
41,763

 
14,212

 
56,316

OTHER INCOME (EXPENSE):
 
 
 
 
 

 
 

Interest income
3

 
173

 
6

 
175

Interest expense
(6,311
)
 
(4,384
)
 
(9,535
)
 
(8,798
)
Interest rate risk management losses
(1,643
)
 
(9,306
)
 
(4,305
)
 
(19,018
)
Other (expense) income
(114
)
 
(21
)
 
(164
)
 
78

Total other (expense) income
(8,065
)
 
(13,538
)
 
(13,998
)
 
(27,563
)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
54,691

 
28,225

 
214

 
28,753

INCOME TAX (BENEFIT) PROVISION
(691
)
 
(425
)
 
(733
)
 
274

INCOME FROM CONTINUING OPERATIONS
55,382

 
28,650

 
947

 
28,479

DISCONTINUED OPERATIONS, NET OF TAX
(311
)
 
39,493

 
407

 
43,645

NET INCOME
$
55,071

 
$
68,143

 
$
1,354

 
$
72,124

 
 See notes to unaudited condensed consolidated financial statements.  
 









3

EAGLE ROCK ENERGY PARTNERS, L.P.


UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (continued)
(in thousands, except per unit amounts)

 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2011
 
2010
 
2011
 
2010
NET INCOME PER COMMON UNIT—BASIC AND DILUTED:
 
 
 
 
 
 
 
Income from Continuing Operations
 
 
 
 
 
 
 
Common units - Basic
$
0.50

 
$
0.41

 
$

 
$
0.40

Common units - Diluted
$
0.47

 
$
0.41

 
$

 
$
0.40

Subordinated units - Basic and diluted
 
 
$
0.38

 
 
 
$
0.35

General partner units - Basic and diluted
 
 
$
0.41

 
 
 
$
0.40

Discontinued Operations
 
 
 
 
 
 
 
Common units - Basic
$

 
$
0.56

 
$

 
$
0.59

Common units - Diluted
$

 
$
0.56

 
$

 
$
0.59

Subordinated units - Basic and diluted
 
 
$
0.56

 
 
 
$
0.59

General partner units - Basic and diluted
 
 
$
0.56

 
 
 
$
0.59

Net Income
 
 
 
 
 
 
 
Common units - Basic
$
0.50

 
$
0.96

 
$
0.01

 
$
0.98

Common units - Diluted
$
0.47

 
$
0.96

 
$
0.01

 
$
0.98

Subordinated units - Basic and diluted
 
 
$
0.94

 
 
 
$
0.93

General partner units - Basic and diluted
 
 
$
0.96

 
 
 
$
0.98

Weighted Average Units Outstanding (in thousands)
 
 
 
 
 
 
 
Common units - Basic
108,117

 
56,597

 
96,130

 
55,344

Common units - Diluted
115,897

 
56,808

 
103,950

 
55,515

Subordinated units - Basic and diluted
 
 
12,278

 
 
 
16,683

General partner units - Basic and diluted
 
 
845

 
 
 
845


See notes to unaudited condensed consolidated financial statements.  


4

EAGLE ROCK ENERGY PARTNERS, L.P.


UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
($ in thousands)
 
Six Months Ended
June 30,
 
2011
 
2010
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
Net income
$
1,354

 
$
72,124

Adjustments to reconcile net income to net cash provided by operating activities:

 

Discontinued operations
(407
)
 
(43,645
)
Depreciation, depletion and amortization
55,274

 
54,913

Impairment
4,884

 
3,130

Amortization of debt discount
18

 

Amortization of debt issuance costs
601

 
820

Write-off of debt issuance costs
427

 

Equity in earnings of unconsolidated affiliates
11

 

Distribution from unconsolidated affiliates—return on investment
57

 
67

Reclassing financing derivative settlements
(2,443
)
 
(628
)
Equity-based compensation
1,934

 
3,358

Loss (gain) of sale of assets
137

 
(19
)
Other operating income
(2,893
)
 

Other
(374
)
 
801

Changes in assets and liabilities—net of acquisitions:

 

Accounts receivable
(2,215
)
 
9,346

Prepayments and other current assets
(3,268
)
 
(635
)
Risk management activities
(19,769
)
 
(45,707
)
Accounts payable
(8,701
)
 
(6,026
)
Due to affiliates

 
(3,552
)
Accrued liabilities
1,681

 
(904
)
Other assets
(17
)
 
(84
)
Other current liabilities
(598
)
 
(697
)
Net cash provided by operating activities
25,693

 
42,662

CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
Additions to property, plant and equipment
(31,195
)
 
(23,910
)
Acquisitions, net of cash acquired
(220,326
)
 

Proceeds from sale of assets
6,093

 
171,664

Purchase of intangible assets
(1,315
)
 
(968
)
Net cash (used in) provided by investing activities
(246,743
)
 
146,786

CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
Proceeds from long-term debt
709,329

 
36,000

Repayment of long-term debt
(791,329
)
 
(225,000
)
Proceeds from senior notes
297,837

 

Payment of debt issuance costs
(13,802
)
 

Proceeds from derivative contracts
2,443

 
628

Exercise of warrants
45,897

 

Payment of transaction costs

 
(2,557
)
Repurchase of common units
(119
)
 
(219
)
Distributions to members and affiliates
(26,250
)
 
(3,024
)
Net cash provided by (used in) financing activities
224,006

 
(194,172
)
CASH FLOWS FROM DISCONTINUED OPERATIONS:
 
 
 
Operating activities
(180
)
 
8,417

Investing activities

 
(104
)
Net cash (used in) provided by discontinued operations
(180
)
 
8,313

NET INCREASE IN CASH AND CASH EQUIVALENTS
2,776

 
3,589

CASH AND CASH EQUIVALENTS—Beginning of period
4,049

 
2,732

CASH AND CASH EQUIVALENTS—End of period
$
6,825

 
$
6,321

 
 
 
 
NONCASH INVESTING AND FINANCING ACTIVITIES:
 
 
 
Units issued for acquisitions
$
336,125

 
$
2,089

Issuance of common units for transaction fee
$

 
$
29,000

Transaction fees, not paid
$
1,234

 
$
478

Investments in property, plant and equipment, not paid
$
20,653

 
$
8,429

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
 
 
 
Interest paid—net of amounts capitalized
$
11,225

 
$
8,325

Cash paid for taxes
$
984

 
$
1,437

See notes to unaudited condensed consolidated financial statements.  

5

EAGLE ROCK ENERGY PARTNERS, L.P.


UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF MEMBERS’ EQUITY

($ in thousands, except unit amounts)
 
Number of
Common
Units
 
Common
Units
BALANCE — January 1, 2011
83,425,378

 
$
579,113

Net income

 
1,354

Distributions

 
(26,250
)
Vesting of restricted units
62,071

 

Exercised warrants
7,649,544

 
45,897

Repurchase of common units
(10,772
)
 
(119
)
Equity based compensation

 
1,934

Units issued for acquisitions
28,753,174

 
336,125

BALANCE — June 30, 2011
119,879,395

 
$
938,054


 See notes to unaudited condensed consolidated financial statements.  


6


EAGLE ROCK ENERGY PARTNERS, L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 are wholly-owned subsidiaries of Eagle Rock Energy. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements presented in the Partnership's annual report on Form 10-K for the year ended December 31, 2010. That report contains a more comprehensive summary of the Partnership's major accounting policies. In the opinion of management, the accompanying unaudited condensed consolidated financial statements contain all of the appropriate adjustments, all of which are normally recurring adjustments unless otherwise noted, considered necessary to present fairly the financial position of the Partnership and its consolidated subsidiaries and the results of operations and cash flows for the respective periods. Operating results for the three and six months ended June 30, 2011 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2011.

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 or natural gas liquids ("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 in the Partnership's pipelines or third party pipelines, is treated to remove contaminants and conditioned or processed into marketable natural gas and NGLs. 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.  The Partnership reports its Upstream Business through one segment.

Other Reclassifications—Certain prior period financial statement balances have been reclassified to conform to the current year presentation. These reclassifications had no effect on the recorded net income and are not significant.

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 ("U.S. GAAP"). 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 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.
The preparation of financial statements in conformity with U.S. GAAP 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 and derivative valuations. 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.

The Partnership has provided a discussion of significant accounting policies in its annual report on Form 10-K for the year ended December 31, 2010. Certain items from that discussion are repeated or updated below as necessary to assist in understanding these financial statements.


7


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 is found to have 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
 
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 negative revision or unfavorable 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 each of the three and six months ended June 30, 2011 and 2010, the Partnership did not incur any impairment charges related to proved properties. 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. In the first quarter of 2011, the Partnership incurred $0.3 million of impairment charges related to certain drilling locations in its unproved properties which the Partnership no longer intends to develop based on the performance of offsetting wells. During each of the three months ended June 30, 2011 and 2010, the Partnership did not incur any impairment charges related to unproved properties.
 
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 changes 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


8


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 three and six months ended June 30, 2011, the Partnership recorded an impairment charge of $4.6 million in its Texas Panhandle Segment to fully write-down its idle Turkey Creek plant. The Partnership determined that the components of its Turkey Creek plant could not be used elsewhere within the business and thus the Partnership decided to remove all above ground equipment and structures.

Other Significant Accounting Policies

Transportation and Exchange Imbalances—In the course of transporting natural gas and NGLs for others, the Partnership may receive for redelivery different quantities of natural gas or NGLs 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 NGLs 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 June 30, 2011, the Partnership had imbalance receivables totaling $0.8 million and imbalance payables totaling $1.9 million. 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. 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.
 
Inventory—Inventory is stated at the lower of cost or market, with cost being determined using the average cost method. At June 30, 2011 and December 31, 2010, the Partnership had $3.1 million and $0.5 million, respectively, of crude oil finished goods inventory which is recorded as part of Other Current Assets within the unaudited condensed consolidated balance sheet.

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, condensate and sulfur; 
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, condensate and sulfur 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 in the period when the services are provided.
 
For gathering and processing services, the Partnership either receives fees or commodities from natural gas producers under various types of contracts, including, percentage-of-proceeds, fixed recovery and percent-of-index arrangements. The Partnership also recognizes fee-based service revenues for services such as transportation, compression and processing.

The Partnership's Upstream Segment recognizes revenues based on the amount of natural gas sold to purchasers. The volumes of natural gas sold may differ from the volumes to which the Partnership is entitled based on its interests in the properties. Differences between volumes sold and volumes based on entitlements create natural gas imbalances. Material imbalances are reflected as adjustments to reported natural gas reserves and future cash flows.  As of June 30, 2011 and December 31, 2010, the Partnership's Upstream Segment had an imbalance receivable balance of $1.3 million and $0.5 million, respectively, and it had a long-term payable balance of $1.4 million as of June 30, 2011.
 
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 sale contracts, when appropriately designated, are not subject to the guidance. Normal purchases and sales are contracts which provide for the purchase or sale of something, other than a financial

9


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. The terms of these contracts generally preclude unplanned netting. The Partnership uses financial instruments such as swaps, collars 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 and specifies a hierarchy of valuation techniques based on the inputs used to measure fair value. See Note 12 for additional information regarding the Partnership's assets and liabilities carried at fair value.
    
NOTE 3. NEW ACCOUNTING PRONOUNCEMENTS
 
In September 2009, the Financial Accounting Standards Board ("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 did not have a material impact on the Partnership's 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, which was adopted by the Partnership on January 1, 2011 (see Note 12).

In May 2011, the FASB issued additional guidance intended to result in convergence between U.S. GAAP and International Financial Reporting Standards (“IFRS”) requirements for measurement of and disclosures about fair value. The amendments are not expected to have a significant impact on companies applying U.S. GAAP. Key provisions of the amendments include: a prohibition on grouping financial instruments for purposes of determining fair value, except when an entity manages market and credit risks on the basis of the entity’s net exposure to the group; an extension of the prohibition against the use of a blockage factor to all fair value measurements (that prohibition currently applies only to financial instruments with quoted prices in active markets); and a requirement that for recurring Level 3 fair value measurements, entities disclose quantitative information about unobservable inputs, a description of the valuation process used and qualitative details about the sensitivity of the measurements. In addition, for items not carried at fair value but for which fair value is disclosed, entities will be required to disclose the level within the fair value hierarchy that applies to the fair value measurement disclosed. This guidance is effective for interim and annual periods beginning after December 15, 2011. The adoption of this guidance is not expected to have a significant impact on the Partnership’s fair value measurements, financial condition, results of operations or cash flows.

10



NOTE 4. ACQUISITIONS

Acquisition of CC Energy II L.L.C.

On May 3, 2011, the Partnership completed the acquisition of all of the outstanding membership interests of CC Energy II L.L.C (together with its subsidiaries, "Crow Creek Energy"), a portfolio company of Natural Gas Partners, VIII, L.P. ("NGP VIII") (the "Crow Creek Acquisition"). Crow Creek Energy has oil and natural gas properties located in multiple basins across Oklahoma, north Texas and Arkansas (the "Mid-Continent" properties) and provides the Partnership with an extensive inventory of low-risk development prospects in established plays such as the Golden Trend Field and developing plays such as the Cana Shale. The aggregate purchase price of $563.7 million has been calculated as follows (in thousands, except unit and per unit amounts):
Number of Partnership Common Units Issued
28,753,174

Closing common unit price on May 3, 2011
$
11.69

Value of common units issued
$
336,125

Crow Creek Energy outstanding debt assumed
212,638

Cash
14,945

Total purchase price
$
563,708

The number of common units of the Partnership issued was determined based on the value of the equity to be issued to the sellers of $301.9 million divided by $10.50, the ceiling price of the agreed upon range in the contribution agreement between the Partnership and Crow Creek Energy. The cash portion of the acquisition consideration and the repayment of Crow Creek Energy’s outstanding debt were funded through borrowings under the Partnership’s revolving credit facility. In addition, the Partnership incurred $2.3 million of acquisition related expenses, which are included within general and administrative expenses for the three and six months ended June 30, 2011.
The following presents the preliminary purchase price allocation for the Crow Creek Energy assets, based on preliminary estimates of fair value (in thousands):
Current assets
$
25,329

Oil and gas properties
575,637

Property, plant and equipment
4,463

Intangible assets
3,192

Other assets
450

Derivatives
3,355

Current liabilities
(37,032
)
Asset retirement obligations
(7,483
)
Deferred tax liability
(2,763
)
Other liabilities
(1,440
)
 
$
563,708

As of June 30, 2011, the purchase price and the allocation of the purchase price are considered preliminary due to the pending completion of certain final closing purchase price adjustments and the final calculation of the asset retirement obligations and the deferred tax liability.

11


The amounts of Crow Creek Energy's revenue and net income included within the Partnership's condensed consolidated statement of operations for the six months ended June 30, 2011, and the pro forma revenue and net income of the combined entity had the acquisition date been January 1, 2010, are as follows:
 
Revenue
 
Net Income
 
Net Income Per Diluted Common Unit
 
($ in thousands)
 
 
Actual from May 3, 2011 to June 30, 2011
$
23,589

 
$
15,651

 
 
Supplemental pro forma from January 1, 2011 to June 30, 2011
$
490,135

 
$
6,813

 
$
0.05

Supplemental pro forma from January 1, 2010 to June 30, 2010
$
476,651

 
$
97,132

 
$
0.92

NOTE 5. PROPERTY PLANT AND EQUIPMENT
 
Fixed assets consisted of the following:
 
June 30,
2011
 
December 31,
2010
 
  ($ in thousands)
Land
$
2,607

 
$
2,629

Plant
277,250

 
251,436

Gathering and pipeline
670,228

 
666,163

Equipment and machinery
28,478

 
26,408

Vehicles and transportation equipment
4,256

 
4,251

Office equipment, furniture, and fixtures
1,121

 
1,120

Computer equipment
8,502

 
8,486

Corporate
126

 
126

Linefill
4,269

 
4,269

Proved properties
971,447

 
471,781

Unproved properties
106,364

 
1,304

Construction in progress
21,113

 
42,416

 
2,095,761

 
1,480,389

Less: accumulated depreciation, depletion and amortization
(390,705
)
 
(343,150
)
Net property plant and equipment
$
1,705,056

 
$
1,137,239

 
Depreciation expense for the three and six months ended June 30, 2011 and 2010 was approximately $13.5 million, $27.1 million, $12.9 million and $26.4 million, respectively. Depletion expense for the three and six months ended June 30, 2011 and 2010 was approximately $15.2 million, $22.3 million, $8.8 million and $17.0 million, respectively. During the three and six months ended June 30, 2011, the Partnership recorded impairment charges of $4.6 million and $4.9 million, respectively, of which $0.3 million related to unproved properties during the six months ended June 30, 2011 and $4.6 million related to plant assets in its Panhandle Segment during the three and six months ended June 30, 2011. During the three and six months ended June 30, 2010, the Partnership recorded impairment charges of $2.0 million and $0.6 million, respectively, to its pipeline and plant assets due to the loss of a significant gathering contract in its South Texas Segment.  The Partnership capitalizes interest costs on major projects during extended construction time periods. Such interest costs are allocated to property, plant and equipment and amortized over the estimated useful lives of the related assets. During the three and six months ended June 30, 2011 and 2010, the Partnership capitalized interest costs of $0.1 million for each of the periods.

NOTE 6. 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

12


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.
 
A reconciliation of the Partnership's liability for asset retirement obligations is as follows:
 
Six Months Ended
June 30,
 
2011
 
2010
 
 ($ in thousands)
Asset retirement obligations—January 1 
$
24,711

 
$
19,829

Additional liabilities
54

 

Liabilities settled 
(148
)
 
(261
)
Additional liability related to acquisitions
7,528

 

Accretion expense
828

 
1,062

Asset retirement obligations—June 30
$
32,973

 
$
20,630

 

NOTE 7. INTANGIBLE ASSETS
 
Intangible assets consist of rights-of-way and easements and acquired customer contracts, which the Partnership amortizes over the term of the agreement or estimated useful life. The Partnership recorded impairment charges of $0.5 million related to rights-of-way in the three and six months ended June 30, 2010. The Partnership did not incur any impairment charges during the three and six months ended June 30, 2011. Amortization expense was approximately $2.9 million, $5.9 million, $5.8 million and $11.5 million for the three and six months ended June 30, 2011 and 2010, respectively. Estimated aggregate amortization expense for the remainder of 2011 and each of the four succeeding years is as follows: 2011—$6.1 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 June 30, 2011 and December 31, 2010): 
 
June 30, 2011
 
December 31, 2010
 
($ in thousands)
Rights-of-way and easements—at cost
$
96,057

 
$
91,490

Less: accumulated amortization
(23,104
)
 
(20,552
)
Contracts
121,387

 
122,601

Less: accumulated amortization
(81,975
)
 
(79,905
)
Net intangible assets
$
112,365

 
$
113,634

    
The amortization period for the Partnership's rights-of-way and easements is 20 years. The amortization period for contracts ranges from 5 to 20 years and is approximately 8 years on average as of June 30, 2011.  
 

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NOTE 8. LONG-TERM DEBT

Long-term debt consisted of the following:
 
June 30,
2011
 
December 31,
2010
 
($ in thousands)
Revolving credit facility:
$
448,000

 
$
530,000

Senior Notes:
 
 

8 3/8% senior notes due 2019
300,000

 

Unamortized bond discount-senior notes due 2019
(2,145
)
 

Total senior notes
297,855

 

Total long-term debt
$
745,855

 
$
530,000


Revolving Credit Facility

On June 22, 2011, the Partnership entered into an Amended and Restated Credit Agreement (the “Credit Agreement”) with Wells Fargo Bank, National Association, as administrative agent and swingline lender, Bank of America, N.A. and The Royal Bank of Scotland plc, as co-syndication agents, BNP Paribas, as documentation agent, and the other lenders who are parties to the Credit Agreement. The Credit Agreement amended and restated the Partnership’s prior $880 million Credit Agreement (the “Prior Credit Agreement”). Upon the effectiveness of the Credit Agreement, all commitments of the lenders party to the Prior Credit Agreement were terminated and all loans and other indebtedness of the Partnership under the Prior Credit Agreement were renewed and extended, inclusive of new lender commitments, on the terms and conditions of the Credit Agreement. The Credit Agreement matures on June 22, 2016.
The credit facility under the Credit Agreement consists of aggregate initial commitments of $675 million that may, at the Partnership’s request and subject to the terms and conditions of the Credit Agreement, be increased up to an aggregate total amount of $1.2 billion. Availability under the credit facility is subject to a borrowing base comprised of two components: the upstream component and the midstream component. The upstream component of the borrowing base is determined semi-annually as an amount equal to the loan value of the proved oil and gas reserves of the Partnership and its subsidiaries as determined by the lenders party to the Credit Agreement. The midstream component of the borrowing base is determined quarterly as an amount equal to the lesser of (i) 55% of the total borrowing base (subject to increase for certain periods following certain material acquisitions up to 60% of the total borrowing base) and (ii) 3.75 times Consolidated EBITDA (as defined in the Credit Agreement) attributable to the midstream assets of the Partnership and its subsidiaries for the trailing four fiscal quarters. Pro forma adjustments to each component of the borrowing base, and thus total availability under the credit facility, are made upon the occurrence of certain events including material acquisitions and dispositions. Availability under the Credit Agreement is based on the lower of the current borrowing base and the total commitments. As of June 30, 2011, the Partnership had approximately $218.4 million of availability under the credit facility. The Partnership currently pays a 0.45% commitment fee per year on the difference between total commitments and the amount drawn under the credit facility.
The initial borrowings under the Credit Agreement were used to repay in full the borrowings under the Prior Credit Agreement and to pay fees and expenses incurred in connection with the Credit Agreement. Also, in connection with the Credit Agreement, the Partnership incurred debt issuance costs of $6.4 million and recorded a charge of $0.4 million to write off a portion of the unamortized debt issuance costs related to the Prior Credit Agreement. As of June 30, 2011, the Partnership had unamortized debt issuance costs of $7.5 million.
The Credit Agreement includes a sub limit for the issuance of standby letters of credit for a total of $150 million. As of June 30, 2011, the Partnership had $3.4 million of outstanding letters of credit.
In general, at the Partnership's election, interest will accrue on the credit facility at either LIBOR plus a margin ranging from 1.75% to 2.75% (currently 2.25% per annum based on the Partnership's borrowing base utilization percentage) or the base rate plus a margin ranging from 0.75% to 1.75% (currently 1.25% per annum based on the Partnership's borrowing base utilization percentage). The applicable margin is determined based on the utilization of the then existing borrowing base. The credit facility under the Credit Agreement may be prepaid, without any premium or penalty, at any time. The base rate is generally the highest of the federal funds rate plus 0.5%, the prime rate as announced from time to time by the Administrative Agent, or daily LIBOR for a term of one month plus 1.0%. As of June 30, 2011, the weighted average interest rate (excluding the impact of interest rate swaps) on the Partnership's outstanding debt under its revolving credit facility was 2.43%.

14


The obligations under the Credit Agreement are secured by first priority liens on substantially all of the Partnership’s material assets, including a pledge of all of the equity interests of each of the Partnership’s material subsidiaries.
The Credit Agreement requires the Partnership and certain of its subsidiaries to make certain representations and warranties that are customary for credit facilities of this type. The Credit Agreement also contains affirmative and negative covenants that are customary for credit facilities of this type, including compliance with financial covenants. The financial covenants prohibit the Partnership from:
permitting, as of any fiscal quarter-end, the ratio of the Partnership’s Consolidated EBITDA (as defined in the Credit Agreement) for the four fiscal quarter period ending with such fiscal quarter to Consolidated Interest Expense (as defined in the Credit Agreement) for such four fiscal quarter period to be less than 2.50 to 1.00;
permitting, as of any fiscal quarter-end, the ratio of the Partnership's Total Funded Indebtedness (as defined in the Credit Agreement) to Consolidated EBITDA for the four fiscal quarter period ending with such fiscal quarter to be greater than 4.50 to 1.00; and
permitting the ratio of the Partnership’s consolidated current assets (including availability under the Credit Agreement up to the loan limit, as defined within the Credit Agreement but excluding non-cash assets under the accounting guidance for derivatives) to consolidated current liabilities (excluding non-cash obligations under the accounting guidance for derivatives) to be less than 1.00 to 1.00.
As of June 30, 2011, the Partnership was in compliance with the financial covenants under the Credit Agreement.
Senior Notes

On May 27, 2011, the Partnership, along with its subsidiary, Eagle Rock Energy Finance Corp. ("Finance Corp"), as co-issuer, completed the sale of $300 million of senior unsecured notes (the "Senior Notes") through a private placement. The Senior Notes bear a coupon of 8 3/8%. The Senior Notes will mature on June 1, 2019 and interest is payable on each June 1 and December 1, commencing December 1, 2011. After the original discount of $2.2 million and excluding related offering expenses, the Partnership received net proceeds of approximately $297.8 million, which were used to repay borrowings outstanding under the Prior Credit Agreement. As of June 30, 2011, the Partnership had an unamortized debt discount of $2.1 million, which is recorded as an offset to the principal amount of the Senior Notes, and unamortized debt issuance costs of $8.5 million.

The Senior Notes are general unsecured senior obligations and rank equally in right of payment with all of the Partnership's existing and future senior indebtedness and rank senior in right of payment to any of the Partnership's future subordinated indebtedness. The Senior Notes are effectively junior in right of payment to all of the Partnership's existing and future secured indebtedness and other obligations, including borrowings outstanding under the Partnership's Credit Agreement, to the extent of the value of the assets securing such indebtedness and other obligations. The Senior Notes are jointly and severally guaranteed on a senior unsecured basis by the Partnership's existing and future subsidiaries, who are referred to as the "subsidiary guarantors," that guarantee our credit facility or other indebtedness.

The indenture, as supplemented, governing the Senior Notes, among other things, restricts the Partnership's ability and the ability of the Partnership's restricted subsidiaries to: (i) incur, assume or guarantee additional indebtedness or issue redeemable stock; (ii) pay dividends on stock, repurchase stock or redeem subordinated debt; (iii) make certain investments; (iv) enter into certain transactions with affiliates; (v) create liens on their assets; (vi) sell or otherwise dispose of certain assets, including capital stock of subsidiaries; (vii) restrict dividends, loans or other asset transfers from the Partnership's restricted subsidiaries; (viii) enter into new lines of business; and (ix) consolidate with or merge with or into, or sell all or substantially all of their properties (taken as a whole) to, another person.

The Partnership has the option to redeem all or a portion of the Senior Notes at any time on or after June 1, 2015 at the redemption prices specified in the indenture plus accrued and unpaid interest. The Partnership may also redeem the Senior Notes, in whole or in part, at a "make-whole" redemption price specified in the Indenture, plus accrued and unpaid interest, at any time prior to June 1, 2015. In addition, the Partnership may redeem up to 35% of the Senior Notes prior to June 1, 2014 under certain circumstances with the net cash proceeds from certain equity offerings at 108.375% of the principal amount of the notes redeemed.

In connection with the issuance and sale of the Senior Notes, the Partnership entered into a registration rights agreement (the "Senior Notes Registration Rights Agreement") with representatives of the initial purchasers. Pursuant to the Senior Notes Registration Rights Agreement, the Partnership agreed to file a registration statement with the Securities and

15


Exchange Commission so that holders can exchange the Senior Notes for registered notes that have substantially identical terms as the Senior Notes and evidence the same indebtedness as the Senior Notes. In addition, the subsidiary guarantors agreed to exchange the guarantee related to the Senior Notes for a registered guarantee having substantially the same terms as the original guarantees. The Partnership is obligated to use commercially reasonable efforts to cause the exchange to be completed by June 30, 2012. If the Partnership fails to satisfy these obligations on a timely basis, it will be required to pay an additional 1% of interest to holders of the Senior Notes, until the exchange offer is completed or the shelf registration statement is declared (or becomes) effective, as applicable.

NOTE 9. MEMBERS’ EQUITY
 
At June 30, 2011, there were 119,879,395 common units outstanding. In addition, there were 1,821,328 unvested restricted common units outstanding.
 
During the six months ended June 30, 2011, 7,649,544 warrants were exercised for a total of 7,649,544 newly issued common units. As of June 30, 2011 and December 31, 2010, 13,015,701 and 20,665,245 warrants were outstanding, respectively.

On February 7, 2011, the Partnership declared its fourth quarter 2010 cash distribution of $0.15 per unit to its common unitholders of record as of the close of business on February 14, 2011. The distribution was paid on February 14, 2011.

On April 26, 2011, the Partnership declared its first quarter 2011 cash distribution of $0.15 per unit to its common unitholders of record as of the close of business on May 9, 2011, except for the common units issued in connection with the acquisition of CC Energy II L.L.C. on May 3, 2011, which were not eligible to receive the first quarter 2011 distribution (see Note 4 for further discussion). The distribution was paid on May 13, 2011.  

On July 27, 2011, the Partnership declared its second quarter 2011 cash distribution of $0.1875 per unit to its common unitholders of record as of the close of business on August 5, 2011. The distribution will be paid on August 12, 2011.

NOTE 10. RELATED PARTY TRANSACTIONS
   
During the three and six months ended June 30, 2011 and 2010, the Partnership purchased natural gas from certain companies affiliated with one or more NGP private equity firms and incurred $1.6 million, $3.2 million, $1.7 million and $4.0 million, respectively, in expenses owed to these related parties, of which there was an outstanding accounts payable balance of $0.6 million and $0.5 million as of June 30, 2011 and December 31, 2010, respectively.

The Partnership received 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 because NGP sold all of its interests in SFS. During the three and six months ended June 30, 2010, the Partnership incurred approximately $0.4 million and $1.1 million, respectively, for services performed by SFS. As of both June 30, 2011 and December 31, 2010, there were no outstanding accounts payable balances to SFS.

On May 3, 2011, the Partnership completed the acquisition of Crow Creek Energy, a portfolio company of NGP VIII (see Note 4). Due to Crow Creek Energy being a portfolio company of NGP VIII and NGP's ownership interest in the Partnership and board of directors representation, the Board of Directors of the general partner of the Partnership's general partner, authorized its Conflicts Committee to review, evaluate, and, if determined appropriate, approve the acquisition of Crow Creek Energy, due to the potential conflict of interest among the Partnership, the NGP Parties and the Partnership's public unitholders. The Conflicts Committee, consisting of independent directors of the Partnership, determined that the acquisition of Crow Creek Energy was fair and reasonable to the Partnership and its public unitholders and recommended to the Board of Directors that the transaction be approved and authorized. In determining the consideration for the acquisition of Crow Creek Energy, the Conflicts Committee, with the assistance of a third-party, 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 flows of Crow Creek Energy.

In connection with the closing of the acquisition of Crow Creek Energy, the Partnership entered into a registration rights agreement ("Registration Rights Agreement") with NGP VIII. The Registration Rights Agreement grants NGP VIII and certain of its affiliates registration rights with respect to the common units acquired pursuant to the Partnership's acquisition of Crow Creek Energy and their outstanding warrants to purchase common units that were previously acquired by NGP VIII and certain of its affiliates in connection with the Partnership's previously completed recapitalization transaction. Pursuant to the Registration Rights Agreement, NGP VIII and certain of its affiliates have the ability to demand that the Partnership register for resale their common units acquired pursuant to the acquisition of Crow Creek Energy and their existing warrants to purchase

16


common units. This registration may be an underwritten offering at the discretion of NGP VIII and certain of its affiliates. NGP VIII and certain of its affiliates may demand up to four such registrations, subject to an increase to up to seven if the registration rights are amended. Additionally, the Registration Rights Agreement provides that NGP VIII and certain of its affiliates have piggyback registration rights in certain circumstances, which would require inclusion of their common units and warrants on registration statements that the Partnership files, subject to certain customer exceptions. There are no limits on the number of times NGP VIII and certain of its affiliates can exercise these piggyback registration rights.
    
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 June 20, 2011, in conjunction with the refinancing of the credit facility under its Prior Credit Agreement (see Note 8), the Partnership consummated the following transactions to restructure certain of its interest rate swaps:

Terminated a $150 million notional amount 2.56% fixed rate interest rate swap at a cost of $5.0 million; and

Extended $250 million notional amount of its interest rate swaps from their original maturity date of December 31, 2012 to a new maturity date of June 22, 2015 and blended the existing swap rate for these extended swaps with the then prevailing interest rate swap rate, which lowered the rate from 4.095% to 2.95%. There was no cost associated with this extension.
 
The following table sets forth certain information regarding the Partnership's various interest rate swaps as of June 30, 2011:
Effective Date
 
Expiration
Date
 
Notional
Amount
 
Fixed
Rate 
9/30/2008
 
12/31/2012
 
150,000,000

 
4.295
%
10/3/2008
 
12/31/2012
 
50,000,000

 
4.095
%
6/22/2011
 
6/22/2015
 
250,000,000

 
2.95
%
    
The Partnership's interest rate derivative counterparties include Wells Fargo Bank National Association 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 objectives 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%, on an incurrence basis, of expected future production and has historically hedged substantially less than 80%, on an incurrence basis, of its expected future production for periods beyond 24 months. 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.  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

17


future equity share of the commodities.
 
The Partnership uses fixed-price swaps, costless collars and put options 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 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 may 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 and reports this information to the Board of Directors at least quarterly.
 
The Partnership has not designated, for accounting purposes, any of its commodity derivative instruments as hedges and therefore marks these derivative contracts to fair value (see Note 12).  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 counterparty credit risk. Historically. the Partnership's counterparties have all been participants or affiliates of participants within its revolving credit facility (see Note 8), 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. In July 2011, the Partnership formed Eagle Rock Gas Services to market natural gas on behalf of itself and third parties. Eagle Rock Gas Services, through its financial derivative activity, will have credit exposure to additional 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.

The Partnership's commodity derivative counterparties include BNP Paribas, Wells Fargo Bank, National Association, Comerica Bank, Bank of Nova Scotia, The Royal Bank of Scotland plc, Bank of America N.A., J Aron and Company (an affiliate of Goldman Sachs) and BBVA Compass Bank.

During the three months ended June 30, 2011, the Partnership entered into the following hedging transactions:

20,000 barrel per month NYMEX WTI crude oil swap at $104.85 per barrel for its 2013 calendar year;
45,000 barrel per month NYMEX WTI crude oil swap at $102.45 per barrel for its 2014 calendar year;
105,000 MMbtu per month Henry Hub natural gas swap at $5.30 per MMbtu for its 2013 calendar year;
80,000 MMbtu per month Henry Hub natural gas swap at $4.87 per MMbtu for its 2012 calendar year;
2,100,000 gallon per month OPIS ethane swap at $0.69 per gallon for June through December 2011;
150,000 MMbtu per month Henry Hub natural gas swap at $4.76 per MMbtu for July through December 2011;
200,000 MMbtu per month Henry Hub natural gas swap at $5.06 per MMbtu for its calendar year 2012;
300,000 MMbtu per month Henry Hub natural gas swap at $5.34 per MMbtu for its calendar year 2013;
100,000 MMbtu per month Henry Hub natural gas swap at $5.54 per MMbtu for its calendar year 2014; and
250,000 MMbtu per month Henry Hub natural gas swap at $5.55 per MMbtu for its calendar year 2014.

As part of the Crow Creek Acquisition (see Note 4), the Partnership acquired the following commodity derivative contracts (volumes presented include amounts that settled during the three months ended June 30, 2011):
Natural Gas - Inside FERC Panhandle East Natural Gas and Centerpoint Energy Gas Transmission Co. - East - Inside FERC:
Puts - An average of 142,500 MMbtu per month at an average strike price of $5.58 for the remaining months of 2011.

18


Swaps - An average of 485,000 MMbtu per month at an average strike price of $5.90 for the remaining months of 2011. An average of 410,000 MMbtu per month at an average strike price of $5.67 for calendar year 2012. An average of 159,167 MMbtu per month at an average strike price of $5.50 for calendar year 2013.
Costless collars - An average of 162,500 MMbtu per month with an average floor price of $6.00 and an average cap price of $7.84 for the remaining months of 2011. An average of 252,500 MMbtu per month with an average floor price of $4.972 and an average cap price of $6.42 for calendar year 2012. An average of 295,000 MMbtu per month with an average floor price of $4.93 and an average cap price of $5.49.
    
Crude Oil -NYMEX WTI:

Puts - 8,000 barrels per month at a strike price of $55.00 for the remaining months of 2011.
Swaps - An average of 8,750 barrels per month at an average strike price of $61.68 for the remaining months of 2011. An average of 2,000 barrels per month at a strike price of $81.50 for the last six months of 2012 An average of 3,000 barrels per month at a strike price of $81.95 for the last nine months of 2013.
Costless collars - An average of 9,500 barrels per month with an average floor price of $83.21 and an average cap price of $117.40 for the remaining months of 2011. An average of 12,000 barrels per month with an average floor price of $72.73 and an average cap price of $106.06 for calendar year 2012. An average of 8,250 barrels per month with an average floor price of $74.38 and an average cap price of 106.72 for calendar year 2013.
    
In conjunction with the refinancing of its revolving credit facility (see Note 8), the Partnership consummated the following transactions to restructure certain of its existing commodity hedges to remove two institutions not continuing as lenders under the Credit Agreement.

Terminated, at a cost of $1.7 million, the remainder of a calendar year 2011 17,000 barrel per month WTI crude oil swap at $83.30 per barrel. The Partnership entered into a 17,000 barrel per month WTI crude oil swap at $96.50 per barrel for July through December 31, 2011 to re-hedge these volumes.
Terminated, at a cost of $3.1 million, a calendar year 2013 32,000 barrel per month WTI crude oil swaps at $90.75 per barrel. In July 2011, the Partnership entered into a 32,000 barrel per month WTI crude oil swap at $101.96 per barrel for calendar year 2013 to re-hedge these volumes.
Novated a portfolio of calendar year 2011, 2012 and 2013 hedges and, at a cost of $14.6 million, adjusted the strike price to reflect current market prices of the following novated hedges:

The remainder of a calendar year 2011 252,000 gallon per month OPIS propane swap from $1.11 per gallon to $1.55 a gallon;
The remainder of a calendar year 2011 5,000 barrel per month WTI crude oil swap from $75.00 per barrel to $95.44 per barrel;
A calendar year 2012 20,000 barrel per month WTI crude oil swap from $76.00 per barrel to $97.42 per barrel;
A calendar year 2013 20,000 barrel per month WTI crude oil swap from $90.20 per barrel to $98.01 per barrel; and
A calendar year 2013 60,000 barrel per month WTI crude oil swap from $89.95 per barrel to $98.01 per barrel.


19


The following tables set forth certain information regarding the Partnership's commodity derivatives. Within each table, some trades of the same commodities with the same tenors have been aggregated and shown as weighted averages.

Commodity derivatives, as of June 30, 2011, that will mature during the year ended December 31, 2011:
Underlying
 
Period
 
Notional
Volumes
(units)
 
Type
 
Weighted Average Floor
Strike
Price
($/unit)
 
Weighted Average Cap
Strike
Price
($/unit)
Natural Gas:
 
 
 
 
 
 
 
 
 
 
NYMEX Henry Hub
 
Jul-Dec 2011
 
600,000 mmbtu
 
Costless Collar
 
$
7.500

 
$
8.850

IF Panhandle East
 
Jul-Dec 2011
 
960,000 mmbtu
 
Costless Collar
 
5.844

 
7.631

IF Panhandle East
 
Jul-Dec 2011
 
300,000 mmbtu
 
Put
 
5.000

 
 
IF Centerpoint East
 
Jul-Dec 2011
 
480,000 mmbtu
 
Put
 
5.375

 
 
NYMEX Henry Hub
 
Jul-Dec 2011
 
1,950,000 mmbtu
 
Swap
 
6.248

 
 
NYMEX Henry Hub
 
Jul-Dec 2011
 
(204,000) mmbtu
 
Swap
 
4.450

 
 
IF Panhandle East
 
Jul-Dec 2011
 
2,220,000 mmbtu
 
Swap
 
5.887

 
 
IF Centerpoint East
 
Jul-Dec 2011
 
660,000 mmbtu
 
Swap
 
5.375

 
 
Crude Oil:
 
 
 
 
 
 
 
 
 
 
NYMEX WTI
 
Jul-Dec 2011
 
369,576 bbls
 
Costless Collar
 
78.085

 
92.746

NYMEX WTI
 
Jul-Dec 2011
 
48,000 bbls
 
Put
 
55.000

 
 
NYMEX WTI
 
Jul-Dec 2011
 
494,628 bbls
 
Swap
 
75.068

 
 
Natural Gas Liquids:
 
 
 
 
 
 
 
 
 
 
OPIS Nbutane Mt. Belv non TET
 
Jul-Dec 2011
 
5,796,000 gallons
 
Swap
 
1.500

 
 
OPIS IsoButane Mt. Belv non TET
 
Jul-Dec 2011
 
2,772,000 gallons
 
Swap
 
1.543

 
 
OPIS Natural Gasoline Mt. Belv non TET
 
Jul-Dec 2011
 
2,268,000 gallons
 
Swap
 
1.853

 
 
OPIS Propane Mt. Belv non TET
 
Jul-Dec 2011
 
11,592,000 gallons
 
Swap
 
1.173

 
 
OPIS Ethane Mt. Belv non TET
 
Jul-Dec 2011
 
21,168,000 gallons
 
Swap
 
0.631

 
 



20


Commodity derivatives, as of June 30, 2011, that will mature during the year ended December 31, 2012:
Underlying
 
Period
 
Notional
Volumes
(units)
 
Type
 
Weighted Average Floor
Strike
Price
($/unit)
 
Weighted Average Cap
Strike
Price
($/unit)
Natural Gas:
 
 
 
 
 
 
 
 
 
 
NYMEX Henry Hub
 
Jan-Dec 2012
 
1,080,000 mmbtu
 
Costless Collar
 
$
7.350

 
$
8.650

IF Panhandle East
 
Jan-May 2012
 
1,350,000 mmbtu
 
Costless Collar
 
5.287

 
6.912

IF Panhandle East
 
Jan-Dec 2012
 
1,680,000 mmbtu
 
Costless Collar
 
4.364

 
5.476

NYMEX Henry Hub
 
Jan-Dec 2012
 
6,480,000 mmbtu
 
Swap
 
5.854

 
 
IF Panhandle East
 
Jan-May 2012
 
750,000 mmbtu
 
Swap
 
5.715

 
 
IF Panhandle East
 
Jan-Dec 2012
 
720,000 mmbtu
 
Swap
 
5.110

 
 
IF Centerpoint East
 
Jan-May 2012
 
300,000 mmbtu
 
Swap
 
5.795

 
 
IF Centerpoint East
 
Jun-Dec 2012
 
3,150,000 mmbtu
 
Swap
 
5.715

 
 
Crude Oil:
 
 
 
 
 
 
 
 
 
 
NYMEX WTI
 
Jan-Dec 2012
 
699,576 bbls
 
Costless Collar
 
77.631

 
95.314

NYMEX WTI
 
Jan-May 2012
 
50,000 bbls
 
Costless Collar
 
70.000

 
101.705

NYMEX WTI
 
Jan-Jun 2012
 
18,000 bbls
 
Costless Collar
 
70.000

 
92.740

NYMEX WTI
 
June 2012
 
54,000 bbls
 
Costless Collar
 
73.889

 
107.669

NYMEX WTI
 
Jul-Dec 2012
 
10,000 bbls
 
Costless Collar
 
75.000

 
112.500

NYMEX WTI
 
Jan-Dec 2012
 
1,248,468 bbls
 
Swap
 
85.097

 
 
NYMEX WTI
 
Jul-Dec 2012
 
12,000 bbls
 
Swap
 
81.500

 
 

Commodity derivatives, as of June 30, 2011, that will mature during the year ended December 31, 2013:
Underlying
 
Period
 
Notional
Volumes
(units)
 
Type
 
Weighted Average Floor
Strike
Price
($/unit)
 
Weighted Average Cap
Strike
Price
($/unit)
Natural Gas:
 
 
 
 
 
 
 
 
 
 
IF Panhandle East
 
Jan-Dec 2013
 
1,440,000 mmbtu
 
Costless Collar
 
$
4.450

 
$
5.430

IF Panhandle East
 
Jan-May 2013
 
700,000 mmbtu
 
Costless Collar
 
5.100

 
5.610

IF Panhandle East
 
Jun-Dec 2013
 
1,400,000 mmbtu
 
Costless Collar
 
5.100

 
5.450

NYMEX Henry Hub
 
Jan-Dec 2013
 
6,660,000 mmbtu
 
Swap
 
5.350

 
 
IF Centerpoint East
 
Jan-May 2013
 
500,000 mmbtu
 
Swap
 
5.970

 
 
IF Panhandle East
 
Jan-May 2013
 
500,000 mmbtu
 
Swap
 
5.353

 
 
IF Panhandle East
 
Jun-Dec 2013
 
910,000 mmbtu
 
Swap
 
5.260

 
 
Crude Oil:
 
 
 
 
 
 
 
 
 
 
NYMEX WTI
 
Jan-Dec 2013
 
36,000 bbls
 
Costless Collar
 
80.000

 
108.000

NYMEX WTI
 
Jan-Mar 2013
 
27,000 bbls
 
Costless Collar
 
78.085

 
92.746

NYMEX WTI
 
Apr-Dec 2013
 
36,000 bbls
 
Costless Collar
 
70.000

 
96.410

NYMEX WTI
 
Jan-Dec 2013
 
1,320,000 bbls
 
Swap
 
98.360

 
 
NYMEX WTI
 
Apr-Dec 2013
 
27,000 bbls
 
Swap
 
81.950

 
 


21


Commodity derivatives, as of June 30, 2011, that will mature during the year ended December 31, 2014:
Underlying
 
Period
 
Notional
Volumes
(units)
 
Type
 
Weighted Average Floor
Strike
Price
($/unit)
 
Weighted Average Cap
Strike
Price
($/unit)
Natural Gas:
 
 
 
 
 
 
 
 
 
 
NYMEX Henry Hub
 
Jan-Dec 2014
 
4,200,000 mmbtu
 
Swap
 
$
5.546

 
 
Crude Oil:
 
 
 
 
 
 
 
 
 
 
NYMEX WTI
 
Jan-Dec 2014
 
540,000 bbls
 
Swap
 
102.450

 
 

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 June 30, 2011 and December 31, 2010:
 
As of
June 30, 2011
 
Derivative Assets
 
Derivative Liabilities
 
Balance Sheet Classification
 
Fair Value
 
Balance Sheet Classification
 
Fair Value
 
($ in thousands)
Interest rate derivatives - liabilities
 
 
$

 
Current liabilities
 
$
(12,629
)
Interest rate derivatives - liabilities
 
 

 
Long-term liabilities
 
(11,619
)
Commodity derivatives - assets
Current assets
 
9,153

 
Current liabilities
 
10,795

Commodity derivatives - assets
Long-term assets
 
5,237

 
Long-term liabilities
 
7,492

Commodity derivatives - liabilities
Current assets
 
(7,177
)
 
Current liabilities
 
(28,537
)
Commodity derivatives - liabilities
Long-term assets
 
(2,301
)
 
Long-term liabilities
 
(16,570
)
Total derivatives
 
 
$
4,912

 
 
 
$
(51,068
)
 
 
 
 
 
 
 
 
 
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 liabilities
 
9,150

Commodity derivatives - assets
Long-term assets
 
2,402

 
Long-term liabilities
 
5,347

Commodity derivatives - liabilities
 
 

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

 
 
 
$
(70,355
)
    
The following table sets forth the location of gains and losses for derivatives not designated as hedging instruments within the Partnership's unaudited condensed consolidated statement of operations (in thousands):
Amount of Gain (Loss) Recognized in Income on Derivatives
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
 
 
2011
 
2010
 
2011
 
2010
Interest rate derivatives
Interest rate risk management losses
 
$
(1,643
)
 
$
(9,306
)
 
$
(4,305
)
 
$
(19,018
)
Commodity derivatives
Commodity risk management gains (losses)
 
34,338

 
35,592

 
(26,107
)
 
46,387

 
Total
 
$
32,695

 
$
26,286

 
$
(30,412
)
 
$
27,369

 

22


NOTE 12. FAIR VALUE OF FINANCIAL INSTRUMENTS
 
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.
 

23


As of June 30, 2011, the Partnership has recorded its interest rate swaps and commodity derivative instruments (see Note 11), which includes crude oil, natural gas and 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 considered to be less liquid and thinly traded, 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 June 30, 2011 and December 31, 2010
 
As of
June 30, 2011
 
Level 1
 
Level 2
 
Level 3
 
Netting (a)
 
Total
 
($ in thousands)
Assets:
 
 
 
 
 
 
 
 
 
Crude oil derivatives
$

 
$
1,727

 
$

 
$
(7,245
)
 
$
(5,518
)
Natural gas derivatives

 
30,853

 

 
(16,499
)
 
14,354

NGL derivatives

 

 
61

 
(3,985
)
 
(3,924
)
Total 
$

 
$
32,580

 
$
61

 
$
(27,729
)
 
$
4,912

 
 
 
 
 
 
 
 
 
 
Liabilities:
 

 
 

 
 

 
 

 
 

Crude oil derivatives
$

 
$
(44,835
)
 
$

 
$
7,245

 
$
(37,590
)
Natural gas derivatives

 
(20
)
 

 
16,499

 
16,479

NGL derivatives

 

 
(9,693
)
 
3,985

 
(5,708
)
Interest rate swaps

 
(24,249
)
 

 

 
(24,249
)
Total 
$

 
$
(69,104
)
 
$
(9,693
)
 
$
27,729

 
$
(51,068
)
____________________________
(a)
Represents counterparty netting under agreement governing such derivative contracts.
 
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 agreement governing such derivative contracts.
 

24


The following table sets forth a reconciliation of changes in the fair value of the Level 3 NGL derivatives during the three and six months ended June 30, 2011 and 2010 (in thousands):
 
Three Months Ended
June 30,
Six Months Ended
June 30,
 
2011
 
2010
 
2011
 
2010
Net liability beginning balance
$
(12,264
)
 
$
(7,658
)
 
$
(5,733
)
 
$
(14,784
)
Settlements 
5,669

 
2,265

 
9,406

 
6,394

Total gains or losses (realized and unrealized) 
(3,037
)
 
3,533

 
(13,305
)
 
6,530

Net liability ending balance
$
(9,632
)
 
$
(1,860
)
 
$
(9,632
)
 
$
(1,860
)

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 $(1.6) million, $(7.5) million, $3.4 million and $5.1 million in the three and six months ended June 30, 2011 and 2010, respectively, that are attributable to the change in unrealized gains or losses related to those assets and liabilities still held at June 30, 2011 and 2010, 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 unaudited condensed 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 unaudited condensed consolidated statements of operations. 
 
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.
 
As of June 30, 2011, the outstanding debt associated with the Credit Agreement bore interest at a floating rate; as such, the Partnership believes that the carrying value of this debt approximates its fair value. The outstanding debt associated with the Senior Notes bears interest at a fixed rate; based on the market price of the Senior Notes as of June 30, 2011, the Partnership estimates that the fair value of the Senior Notes is $298.1 million compared to a carrying value of $297.9 million.

NOTE 13. COMMITMENTS AND CONTINGENT LIABILITIES
 
Litigation—The Partnership is subject to lawsuits which arise from time to time in the ordinary course of business, such as the interpretation and application of contractual terms related to the calculation of payment for liquids and natural gas proceeds. The Partnership had no accruals as of June 30, 2011 and December 31, 2010 related to legal matters, and current lawsuits are not expected to have a material adverse effect on our financial position, results of operations or cash flows. The Partnership has been indemnified up to a certain dollar amount for two lawsuits. If there ultimately is a finding against the Partnership in these two indemnified cases, the Partnership would expect to make a claim against the indemnification up to limits of the indemnification.

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

25


obtained by other energy companies with similar operations. The cost of insurance for the energy industry continued to fluctuate over the past year, reflecting the changing conditions in the insurance markets.
 
Regulatory Compliance—In the ordinary course of business, the Partnership is subject to various laws and regulations. In the opinion of management, the Partnership is in material compliance with existing laws and regulations.
 
Environmental—The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, the Partnership must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on the Partnership's combined results of operations, financial position or cash flows. At June 30, 2011 and December 31, 2010, the Partnership had accrued approximately $3.9 million and $4.0 million, respectively, for environmental matters.
    
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 Creek field, the retained revenue interest commenced in 2010 and continues 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 operations. Rental expense, including leases with no continuing commitment, amounted to approximately $2.0 million, $4.4 million, $1.7 million and $3.5 million for the three and six months ended June 30, 2011 and 2010, respectively. Rental expense for leases with escalation clauses is recognized on a straight-line basis over the initial lease term.

26


NOTE 14. SEGMENTS
 
On May 24, 2010, the Partnership completed the sale of its Minerals Business, and on May 20, 2011, the Partnership completed its sale of its Wildhorse Gathering System, which was previously reported under the South Texas Segment. As authoritative guidance requires, the operations for components of entities disposed of be recorded as part of discontinued operations, operating results for the Minerals Business for the three and six months ended June 30, 2010 and operating results for the the Wildhorse Gathering System for each of the three and six months ended June 30, 2011 and 2010, have been excluded from the Partnership’s segment presentation below. See Note 18 for a further discussion of the sale of the Partnership’s Minerals Business and the Wildhorse 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 and one functional (Corporate) segment:
 
(i)
Midstream—Texas Panhandle Segment:
gathering, compressing, processing and treating natural gas and marketing of natural gas, NGLs and condensate in the Texas Panhandle and crude oil logistics and marketing in the Texas Panhandle and Alabama;

(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, NGLs 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.
 

27


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 tables:
Midstream Business
Three Months Ended June 30, 2011
 
Texas
Panhandle
Segment
 
South
Texas
Segment
 
East Texas /
Louisiana
Segment
 
Gulf of
Mexico Segment
 
Total
Midstream
Business
($ in thousands)
 
 
 
 
 
 
 
 
 
 
Sales to external customers
 
$
160,300

 
$
11,313

 
$
55,641

 
$
10,799

 
$
238,053

Cost of natural gas and natural gas liquids
 
111,488

 
10,714

 
41,386

 
9,086

 
172,674

Intersegment cost of oil and condensate
 
13,903

 

 

 

 
13,903

Operating costs and other (income) expenses
 
11,207

 
278

 
4,651

 
444

 
16,580

Depreciation, depletion, amortization and impairment
 
13,676

 
735

 
4,561

 
1,664

 
20,636

Operating income (loss) from continuing operations
 
$
10,026

 
$
(414
)
 
$
5,043

 
$
(395
)
 
$
14,260

Capital Expenditures
 
$
7,861

 
$
16

 
$
1,455

 
$

 
$
9,332

Segment Assets
 
$
569,463

 
$
48,236

 
$
255,668

 
$
79,561

 
$
952,928

Total Segments
Three Months Ended June 30, 2011
 
Total
Midstream
Business
 
Upstream
Segment
 
Corporate
and Other Segment
 
Total
Segments
($ in thousands)
 
 
 
 
 
 
 
 
 
 
Sales to external customers
 
$
238,053

 
$
39,324

 
 
$
34,338

(a)
 
$
311,715

Intersegment sales
 

 
13,021

 
 
(13,021
)
 
 

Cost of natural gas and natural gas liquids
 
172,674

 

 
 

 
 
172,674

Intersegment cost of oil and condensate
 
13,903

 

 
 
(13,903
)
 
 

Operating costs and other (income) expenses
 
16,580

 
10,560

 
 
13,009

 
 
40,149

Intersegment operations and maintenance
 

 
24

 
 
(24
)
 
 

Depreciation, depletion, amortization and impairment
 
20,636

 
15,180

 
 
320

 
 
36,136

Operating income from continuing operations
 
$
14,260

 
$
26,581

 
 
$
21,915

 
 
$
62,756

Capital Expenditures
 
$
9,332

 
$
19,158

 
 
$
682

 
 
$
29,172

Segment Assets
 
$
952,928

 
$
973,316

 
 
$
27,192

(c)
 
$
1,953,436

Midstream Business
Three Months Ended June 30, 2010
 
Texas
Panhandle
Segment
 
South
Texas
Segment
 
East Texas /
Louisiana
Segment
 
Gulf of
Mexico Segment
 
Total
Midstream
Business
($ in thousands)
 
 
 
 
 
 
 
 
 
 
Sales to external customers
 
$
84,003

 
$
14,480

 
$
50,779

 
$
7,428

 
$
156,690

Cost of natural gas and natural gas liquids
 
54,732

 
13,041

 
34,477

 
6,393

 
108,643

Operating costs and other expenses
 
8,413

 
654

 
4,210

 
531

 
13,808

Depreciation, depletion, amortization and impairment
 
11,639

 
3,741

 
4,112

 
1,567

 
21,059

Operating income (loss) from continuing operations
 
$
9,219

 
$
(2,956
)
 
$
7,980

 
$
(1,063
)
 
$
13,180

Capital Expenditures
 
$
7,743

 
$
55

 
$
5,267

 
$
5

 
$
13,070

Segment Assets
 
$
523,867

 
$
52,932

 
$
316,744

 
$
82,821

 
$
976,364

Total Segments
Three Months Ended June 30, 2010