XFRA:E4R Eagle Rock Energy Partners LP Quarterly Report 10-Q Filing - 3/31/2012

Effective Date 3/31/2012

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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 March 31, 2012
 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 registrants 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.
Large accelerated Filer  x
Accelerated Filer  o
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 134,455,182 common units outstanding as of May 1, 2012.





TABLE OF CONTENTS
 
 
 
Page 
PART I. FINANCIAL INFORMATION
Item 1.
Financial Statements
 
Unaudited Condensed Consolidated Balance Sheets as of March 31, 2012 and December 31, 2011
 
 
Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2012 and 2011
 
 
Unaudited Condensed Consolidated Statement of Members' Equity for the three months ended March 31, 2012
 
 
Unaudited Condensed Consolidated Statements of Cash Flow for the three months ended March 31, 2012 and 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.
Mine Safety Disclosures
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)

 
March 31,
2012
 
December 31,
2011
ASSETS
 
 
 
CURRENT ASSETS:
 
 
 
Cash and cash equivalents
$
181

 
$
877

Accounts receivable(a)
107,057

 
97,832

Risk management assets
17,646

 
13,080

Prepayments and other current assets
14,178

 
13,739

Total current assets
139,062

 
125,528

PROPERTY, PLANT AND EQUIPMENT — Net
1,749,998

 
1,763,674

INTANGIBLE ASSETS — Net
103,609

 
109,702

DEFERRED TAX ASSET
1,306

 
1,432

RISK MANAGEMENT ASSETS
17,489

 
24,290

OTHER ASSETS
18,495

 
21,062

TOTAL
$
2,029,959

 
$
2,045,688

 
 

 
 

LIABILITIES AND MEMBERS' EQUITY
 

 
 

CURRENT LIABILITIES:
 

 
 

Accounts payable
$
139,934

 
$
145,985

Accrued liabilities
16,308

 
12,734

Taxes payable
341

 
487

Risk management liabilities
11,584

 
11,649

Total current liabilities
168,167

 
170,855

LONG-TERM DEBT
814,203

 
779,453

ASSET RETIREMENT OBLIGATIONS
33,095

 
33,303

DEFERRED TAX LIABILITY
44,608

 
45,216

RISK MANAGEMENT LIABILITIES
16,438

 
6,893

OTHER LONG TERM LIABILITIES
2,622

 
2,621

COMMITMENTS AND CONTINGENCIES (Note 12)


 


MEMBERS' EQUITY (b)
950,826

 
1,007,347

TOTAL
$
2,029,959

 
$
2,045,688

________________________ 

(a)
Net of allowance for bad debt of $852 as of March 31, 2012 and $1,347 as of December 31, 2011.
(b)
130,765,853 and 127,606,229 common units were issued and outstanding as of March 31, 2012 and December 31, 2011, respectively. These amounts do not include unvested restricted common units granted under the Partnership's long-term incentive plan of 2,711,710 and 2,560,110 as of March 31, 2012 and December 31, 2011, respectively.

See accompanying notes to unaudited condensed consolidated financial statements.  


2

EAGLE ROCK ENERGY PARTNERS, L.P.


UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
($ in thousands, except per unit amounts)
 
 
 
Three Months Ended March 31,
 
 
2012
 
2011
 REVENUE:
 
 

 
 

Natural gas, natural gas liquids, oil, condensate and sulfur sales
 
$
222,713

 
$
203,055

Gathering, compression, processing and treating fees
 
11,511

 
13,245

Commodity risk management losses
 
(8,608
)
 
(60,445
)
Other revenue
 
139

 
1,509

Total revenue
 
225,755

 
157,364

COSTS AND EXPENSES:
 
 

 
 

Cost of natural gas, natural gas liquids, and condensate
 
130,454

 
147,319

Operations and maintenance
 
27,049

 
19,475

Taxes other than income
 
5,150

 
3,316

General and administrative
 
16,841

 
11,776

Impairment
 
45,522

 
324

Depreciation, depletion and amortization
 
39,294

 
23,698

Total costs and expenses
 
264,310

 
205,908

OPERATING LOSS
 
(38,555
)
 
(48,544
)
OTHER EXPENSE:
 
 

 
 

Interest expense, net
 
(10,241
)
 
(3,221
)
Interest rate risk management losses
 
(1,579
)
 
(2,662
)
Other expense, net
 
(49
)
 
(50
)
Total other expense
 
(11,869
)
 
(5,933
)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
 
(50,424
)
 
(54,477
)
INCOME TAX BENEFIT
 
(91
)
 
(42
)
LOSS FROM CONTINUING OPERATIONS
 
(50,333
)
 
(54,435
)
DISCONTINUED OPERATIONS, NET OF TAX
 

 
718

NET LOSS
 
$
(50,333
)
 
$
(53,717
)
 
 
NET INCOME PER COMMON UNIT—BASIC AND DILUTED:
 
 
 
 
Loss from Continuing Operations
 
 
 
 
Common units - Basic and Diluted
$
(0.40
)
 
$
(0.65
)
 
Discontinued Operations
 
 
 
 
Common units - Basic and Diluted
$

 
$
0.01

 
Net Loss
 
 
 
 
Common units - Basic and Diluted
$
(0.40
)
 
$
(0.64
)
 
Weighted Average Units Outstanding (in thousands)
 
 
 
 
Common units - Basic and Diluted
128,162

 
84,235

 
 See accompanying notes to unaudited condensed consolidated financial statements.  



3

EAGLE ROCK ENERGY PARTNERS, L.P.



UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF MEMBERS’ EQUITY
FOR THE THREE MONTHS ENDED MARCH 31, 2012
(in thousands, except unit amounts)
 
Number of
Common
Units
 
Common
Units
 
Total
BALANCE — December 31, 2011
127,606,229

 
$
1,007,347

 
$
1,007,347

Net loss

 
(50,333
)
 
(50,333
)
Distributions

 
(27,340
)
 
(27,340
)
Exercised warrants
3,159,624

 
18,958

 
18,958

Equity based compensation

 
2,194

 
2,194

BALANCE — March 31, 2012
130,765,853

 
$
950,826

 
$
950,826


 See accompanying notes to unaudited condensed consolidated financial statements.  


4

EAGLE ROCK ENERGY PARTNERS, L.P.


UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
($ in thousands)
 
Three Months Ended March 31,
 
2012
 
2011
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
Net loss
$
(50,333
)
 
$
(53,717
)
Adjustments to reconcile net income to net cash provided by operating activities:

 

Discontinued operations

 
(718
)
Depreciation, depletion and amortization
39,294

 
23,698

Impairment
45,522

 
324

Amortization of debt issuance costs
699

 
240

Reclassing financing derivative settlements
(3,617
)
 

Equity-based compensation
2,194

 
910

Other
77

 
235

Changes in assets and liabilities—net of acquisitions:
 
 
 
Accounts receivable
(9,225
)
 
(19,177
)
Prepayments and other current assets
(439
)
 
(4,740
)
Risk management activities
11,715

 
51,433

Accounts payable
(661
)
 
25,107

Accrued liabilities
3,574

 
(3,919
)
Other assets
1,885

 

Other current liabilities
(1,696
)
 
(42
)
Net cash provided by operating activities
38,989

 
19,634

CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
Additions to property, plant and equipment
(68,521
)
 
(16,135
)
Purchase of intangible assets
(1,099
)
 
(691
)
Net cash used in investing activities
(69,620
)
 
(16,826
)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
Proceeds from long-term debt
169,450

 
32,745

Repayment of long-term debt
(134,750
)
 
(55,000
)
Proceeds from derivative contracts
3,617

 

Exercise of warrants
18,958

 
27,312

Distributions to members and affiliates
(27,340
)
 
(12,778
)
Net cash provided by (used in) financing activities
29,935

 
(7,721
)
CASH FLOWS FROM DISCONTINUED OPERATIONS:
 
 
 
Operating activities

 
915

Net cash provided by discontinued operations

 
915

NET DECREASE IN CASH AND CASH EQUIVALENTS
(696
)
 
(3,998
)
CASH AND CASH EQUIVALENTS—Beginning of period
877

 
4,049

CASH AND CASH EQUIVALENTS—End of period
$
181

 
$
51

 
 
 
 
NONCASH INVESTING AND FINANCING ACTIVITIES:
 
 
 
Investments in property, plant and equipment, not paid
$
25,984

 
$
8,810

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
 
 
 
Interest paid—net of amounts capitalized
$
3,379

 
$
2,988

Cash paid for taxes
$
521

 
$
106

See accompanying notes to unaudited condensed consolidated financial statements.  

5


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


NOTE 1. ORGANIZATION AND DESCRIPTION OF BUSINESS
 
Description of Business—Eagle Rock Energy Partners, L.P. ("Eagle Rock Energy" or the "Partnership") is a domestically-focused growth-oriented limited partnership engaged in the business of (i) gathering, compressing, treating, processing and transporting natural gas; fractionating and transporting natural gas liquids ("NGLs"); crude oil logistics and marketing; and natural gas marketing and trading (collectively the "Midstream Business"); and (ii) developing and producing interests in oil and natural gas properties (the "Upstream Business"). The Partnership's midstream assets are located in four significant natural gas producing regions; the Texas Panhandle, East Texas/Louisiana, South Texas and the Gulf of Mexico. These four regions are productive, mature, natural gas producing basins that have historically experienced significant drilling activity. 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 reports its Midstream Business results through three segments: the Texas Panhandle Segment, the East Texas and Other Midstream Segment and the Marketing and Trading Segment.  The Partnership's upstream assets are located in four significant oil and gas producing regions: (i) Southern Alabama (which includes the associated gathering, processing and treating assets); (ii) Mid-Continent (which includes areas in Oklahoma, Arkansas, Texas Panhandle and North Texas); (iii) Permian (which includes areas in West Texas); and (iv) East/South Texas/Mississippi. The Partnership reports its Upstream Business through one segment.

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 the Partnership.

NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
Basis of Presentation and Principles of Consolidation—The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). 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, 2011. That report contains a more comprehensive summary of the Partnership's major accounting policies. In the opinion of management, the accompanying unaudited condensed consolidated financial statements contain all appropriate adjustments, all of which are normally recurring adjustments unless otherwise noted, considered necessary to present fairly the financial position of the Partnership and its consolidated subsidiaries and the results of operations and cash flows for the respective periods. Operating results for the three month period ended March 31, 2012 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2012.

Eagle Rock Energy is the owner of non-operating undivided interests in certain gas processing plants and gas gathering systems. 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 unaudited condensed consolidated financial statements.

The Partnership has provided a discussion of significant accounting policies in its Annual Report on Form 10-K for the year ended December 31, 2011. Certain items from that discussion are repeated or updated below as necessary to assist in the understanding of these financial statements.
Use of Estimates—The preparation of financial statements in conformity with 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. 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.

Inventory—Inventory is stated at the lower of cost or market, with cost being determined using the average cost method. At March 31, 2012 and December 31, 2011, the Partnership had $0.7 million and $1.4 million, respectively, of crude

6


oil finished goods inventory which is recorded as part of Other Current Assets within the unaudited condensed consolidated balance sheet.

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
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.

For its oil and natural gas long-lived assets, 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 and/or forward prices 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. Unproved properties (both individually significant and insignificant) are assessed periodically within specific geographic areas and, if necessary, impairments are charged to expense.

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.  

See Notes 4 and 6 for further discussion on impairment charges.
 
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 natural gas 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 March 31, 2012 and December 31, 2011, the Partnership's Upstream Segment had an imbalance receivable balance of $0.5 million and $0.3 million, respectively, and it had a long-term payable balance of $1.6 million as of March 31, 2012 and December 31, 2011.
 
Transportation and Exchange Imbalances—In the course of transporting natural gas and NGLs for others, the

7


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 unaudited condensed consolidated balance sheets and marked-to-market using current market prices in effect for the reporting period of the outstanding imbalances. For the Midstream Business, as of March 31, 2012, the Partnership had imbalance receivables totaling $0.3 million and imbalance payables totaling $1.4 million. For the Midstream Business, as of December 31, 2011, the Partnership had imbalance receivables totaling $0.6 million and imbalance payables totaling $0.5 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.

 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 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 normal sales, with the exception of certain contracts with our natural gas trading and marketing business. 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 unaudited condensed consolidated balance sheet at the instrument's fair value with changes in fair value reflected in the unaudited condensed 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 unaudited condensed consolidated statement of cash flows. See Note 10 for a description of the Partnership's risk management activities.

Other Reclassifications—Certain prior period financial statement balances have been reclassified to conform to the current year presentation. These reclassification had no effect on the recorded net income.
    
NOTE 3. NEW ACCOUNTING PRONOUNCEMENTS
 
In May 2011, the Financial Accounting Standards Board ("FASB") issued additional guidance intended to result in convergence between 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 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 was effective for the Partnership on January 1, 2012 and did not have a significant impact on the Partnership’s fair value measurements, financial condition, results of operations or cash flows.

In December 2011, the FASB issued new guidance related to disclosure requirements about the nature of an entity's rights of set-off and related arrangements associated with its financial instruments and derivative instruments. The new disclosures are designed to make financial statements that are prepared under U.S. GAAP more comparable to those prepared under IFRS. To better facilitate comparison between financial statements prepared under U.S. GAAP and IFRS, the new disclosures will give financial statement users information about both gross and net exposures. The disclosure requirements are effective for annual reporting periods beginning on or after January 1, 2013, and interim periods therein, with retrospective application required. The Partnership is currently evaluating the impact, if any, of the adoption of this guidance on its consolidated financial statements and related disclosures.




8


NOTE 4. PROPERTY PLANT AND EQUIPMENT
 
Fixed assets consisted of the following:
 
March 31,
2012
 
December 31,
2011
 
  ($ in thousands)
Land
$
2,607

 
$
2,607

Plant
292,203

 
290,460

Gathering and pipeline
653,963

 
681,227

Equipment and machinery
33,946

 
31,720

Vehicles and transportation equipment
4,115

 
4,169

Office equipment, furniture, and fixtures
1,168

 
1,318

Computer equipment
10,053

 
9,539

Linefill
4,324

 
4,324

Proved properties
1,084,888

 
1,050,872

Unproved properties
84,618

 
91,363

Construction in progress
73,805

 
56,588

 
2,245,690

 
2,224,187

Less: accumulated depreciation, depletion and amortization
(495,692
)
 
(460,513
)
Net property plant and equipment
$
1,749,998

 
$
1,763,674

    
The following table sets forth the total depreciation, depletion, capitalized interest and impairment expense by type of asset within the Partnership's unaudited condensed consolidated statements of operations:

 
Three Months Ended March 31,
 
2012
 
2011
 
 
($ in thousands)
 
Depreciation
$
14,255

 
$
13,615

 
Depletion
$
22,050

 
$
7,152

 
 
 
 
 
 
Capitalized interest costs
$
358

 
$
20

 
 
 
 
 
 
Impairment expense:
 
 
 
 
Unproved properties (a)
$

 
$
324

 
Plant assets (b)
$
4,164

 
$

 
Pipeline assets (b)
$
37,148

 
$

 

__________________________________
(a)
During the three months ended March 31, 2011, the Partnership incurred impairment charges in its Upstream Business related to certain drilling locations in its unproved properties which the Partnership no longer intends to develop based on the performance of offsetting wells.
(b)
During the three months ended March 31, 2012, the Partnership incurred impairment charges in its Midstream Business related to certain plants and pipelines in its East Texas and Other Midstream Segment due to reduced throughput volumes as its producer customers curtailed their drilling activities due to the continued decline in natural gas prices.

 


NOTE 5. ASSET RETIREMENT OBLIGATIONS

The Partnership recognizes asset retirement obligations 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. For its producing oil and natural gas properties, the Partnership makes estimates of property abandonment costs that, in some cases, will not be incurred until a substantial number of years in the future. Such cost

9


estimates could be subject to significant revisions in subsequent years due to changes in regulatory requirements, technological advances and other factors that may be difficult to predict. 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. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of (i) remediation costs, (ii) remaining lives, (iii) future inflation factors and (iv) a credit-adjusted risk free interest rate.

A reconciliation of the Partnership's liability for asset retirement obligations is as follows:
 
2012
 
2011
 
 ($ in thousands)
Asset retirement obligations—December 31 
$
33,303

 
$
24,711

Additional liabilities
815

 

Liabilities settled 
(1,551
)
 
(148
)
Additional liability related to acquisitions

 
45

Accretion expense
528

 
407

Asset retirement obligations—March 31
$
33,095

 
$
25,015

 

NOTE 6. 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 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 March 31, 2012.  Amortization expense was approximately $3.0 million and $2.9 million for the three months ended March 31, 2012 and 2011, respectively. Intangible assets consisted of the following: 
 
March 31,
2012
 
December 31,
2011
 
($ in thousands)
Rights-of-way and easements—at cost
$
97,088

 
$
99,143

Less: accumulated amortization
(26,911
)
 
(25,570
)
Contracts
120,331

 
121,387

Less: accumulated amortization
(86,899
)
 
(85,258
)
Net intangible assets
$
103,609

 
$
109,702

        
The following table sets forth the impairment expense by type of intangible asset within the Partnership's unaudited condensed consolidated statements of operations (in thousands):
 
Three Months Ended March 31,
 
2012
 
2011
Impairment expense:
 
 
 
Rights-of-way (a)
$
3,154

 
$

Contracts (a)
$
1,056

 
$

_____________________________________
(a)
During the three months ended March 31, 2012, the Partnership incurred impairment charges in its Midstream Business related to certain rights-of-way and contracts in its East Texas and Other Midstream Segment due to reduced throughput volumes as its producer customers curtailed their drilling activities due to the continued decline in natural gas prices.


    



Estimated future amortization expense related to the intangible assets at March 31, 2012, is as follows (in thousands):

10


Year ending December 31,
 
2012
$
8,198

2013
9,731

2014
7,004

2015
7,004

2016
7,004

Thereafter
64,668


NOTE 7. LONG-TERM DEBT

Long-term debt consisted of the following:
 
March 31,
2012
 
December 31,
2011
 
($ in thousands)
Revolving credit facility:
$
516,200

 
$
481,500

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

 
300,000

Unamortized bond discount senior notes due 2019
(1,997
)
 
(2,047
)
Total senior notes
298,003

 
297,953

Total long-term debt
$
814,203

 
$
779,453


The Partnership currently pays an annual fee on the unused commitment, which was 0.50%. As of March 31, 2012, the Partnership had approximately $156.5 million of availability under its revolving credit facility.
As of March 31, 2012, the Partnership was in compliance with the financial covenants under the revolving credit facility.

NOTE 8. MEMBERS’ EQUITY

At March 31, 2012 and December 31, 2011, there were 130,765,853 and 127,606,229 common units outstanding, respectively. In addition, there were 2,711,710 and 2,560,110 unvested restricted common units outstanding at March 31, 2012 and December 31, 2011, respectively.
    
During the three months ended March 31, 2012 and 2011, 3,159,624 and 4,552,007 warrants were exercised, respectively, for an equivalent number of newly issued common units. As of March 31, 2012 and December 31, 2011, 2,548,081 and 5,707,705 warrants, respectively, were outstanding. The final exercise date for the remaining outstanding warrants is May 15, 2012, after which any unexercised warrants will expire.

The Partnership has declared a cash distribution for each quarter since its initial public offering. The table below summarizes the distributions paid and declared for the three months ended March 31, 2012. 
Quarter Ended
 
Distribution
per Unit
 
Record Date
 
Payment Date
December 31, 2011
 
$
0.2100

 
February 7, 2012
 
February 14, 2012
March 31, 2012+
 
$
0.2200

 
May 8, 2012
 
May 15, 2012
_____________________________
+
The distribution excludes certain restricted unit grants.




11


NOTE 9. RELATED PARTY TRANSACTIONS
   
The following table summarizes transactions between the Partnership and affiliated entities:
 
 
Three Months Ended March 31,
 
 
2012
 
2011
Affiliates of NGP:
 
($ in thousands)
Natural gas purchases from affiliates
 
$
941

 
$
1,549

Payable as of March 31,
 
281

 

Payable as of December 31,
 


 
371



NOTE 10. RISK MANAGEMENT ACTIVITIES
 
Interest Rate Swap Derivative Instruments

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.

The following table sets forth certain information regarding the Partnership's various interest rate swaps as of March 31, 2012:
    
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

 
2.950
%

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 changes in the future prices of crude oil, natural gas and NGLs on its forecasted equity production, the Partnership engages in 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 not 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 future equity share of the commodities.

12


 
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 converts 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 not designated, for accounting purposes, any of its commodity derivative instruments as hedges and therefore marks these derivative contracts to fair value (see Note 11).  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, 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 created a subsidiary to enhance its ability to market natural gas on behalf of itself and third parties. This subsidiary, 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), ING Capital Markets LLC, BBVA Compass Bank and Royal Bank of Canada.

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.


13


Commodity derivatives, as of March 31, 2012, that will mature during the years ended December 31, 2012, 2013 and 2014:
Underlying
 
Type
 
Notional
Volumes
(units) (a)
 
Floor
Strike
Price
($/unit)(b)
 
Cap
Strike
Price
($/unit)(b)
Portion of Contracts Maturing in 2012
 
 
 
 
 
 
 
 
Natural Gas
 
Costless Collar
 
2,610,000

 
$
5.48

 
$
6.76

Natural Gas
 
Swap (Pay Floating/Receive Fixed)
 
8,970,000

 
5.76

 
 
Natural Gas
 
Swap (Pay Fixed/Receive Floating)
 
(780,000
)
 
3.97

 
 
Crude Oil
 
Costless Collar
 
617,682

 
76.90

 
96.79

Crude Oil
 
Swap (Pay Floating/Receive Fixed)
 
680,151

 
83.10

 
 
Ethane
 
Swap (Pay Floating/Receive Fixed)
 
9,450,000

 
0.73

 
 
Propane
 
Swap (Pay Floating/Receive Fixed)
 
23,587,200

 
1.38

 
 
IsoButane
 
Swap (Pay Floating/Receive Fixed)
 
5,972,400

 
1.80

 
 
Normal Butane
 
Swap (Pay Floating/Receive Fixed)
 
10,584,000

 
1.73

 
 
Natural Gasoline
 
Swap (Pay Floating/Receive Fixed)
 
3,855,600

 
2.22

 
 
Portion of Contracts Maturing in 2013
 
 
 
 
 
 
 
 
Natural Gas
 
Costless Collar
 
3,540,000

 
4.84

 
5.47

Natural Gas
 
Swap (Pay Floating/Receive Fixed)
 
8,570,000

 
5.38

 
 
Crude Oil
 
Costless Collar
 
99,000

 
74.85

 
104.57

Crude Oil
 
Swap (Pay Floating/Receive Fixed)
 
1,930,200

 
96.82

 
 
Propane
 
Swap (Pay Floating/Receive Fixed)
 
25,200,000

 
1.23

 
 
Portion of Contracts Maturing in 2014
 
 
 
 
 
 
 
 
Natural Gas
 
Swap (Pay Floating/Receive Fixed)
 
4,200,000

 
5.55

 
 
Crude Oil
 
Swap (Pay Floating/Receive Fixed)
 
1,680,000

 
97.36

 
 
_______________________
(a)
Volumes of natural gas are measured in MMbtu, volumes of crude oil are measured in barrels, and volumes of natural gas liquids are measured in gallons.
(b)
Amounts represent the weighted average price. The weighted average prices are in $/MMbtu for natural gas, $/barrel for crude oil and $/gallon for natural gas liquids.

Commodity Derivative Instruments - Marketing & Trading

The Partnership operates a subsidiary to conduct natural gas marketing and trading activities. This subsidiary engages in activities intended to capitalize on favorable price differentials between various receipt and delivery locations. The subsidiary's activities are governed by its risk policy.

The subsidiary enters into both financial derivatives and physical contracts. The subsidiary's financial derivatives, primarily basis swaps, are transacted: (i) to economically hedge subscribed capacity exposed to market rate fluctuations, and (ii) to mitigate the price risk related to other purchase and sales of natural gas. By entering into a basis swap, one pricing index is exchanged for another, effectively locking in the margin between the natural gas purchase and sale by removing index spread risk on the combined physical and financial transaction.
  
A commodity-related derivative contract may be designated as a "normal" purchase or sale if the commodity is to be physically received or delivered for use or sale in the normal course of business. If designated as "normal", the derivative contact is accounted for under the accrual method of accounting (not marked-to-market) with no balance sheet or income statement recognition of the contract until settlement. Commodity-related contracts that do not qualify for the normal designation are accounted for as derivatives and are marked-to-market each period.


14


Marketing and Trading commodity derivative instruments, as of March 31, 2012, that will mature during the years ended December 31, 2012 and 2013:

Type
 
Notional Volumes (MMbtu)
Portion of Contracts Maturing in 2012
 
 
Basis Swaps - Purchases
 
6,635,000

Basis Swaps - Sales
 
6,635,000

Index Swap - Sales
 
3,980,000

Swap (Pay Floating/Receive Fixed)
 
1,725,000

Forward purchase contract - index
 
7,199,760

Forward sales contract - index
 
21,776,221

Forward purchase contract - fixed price
 
1,749,000

Portion of Contracts Maturing in 2013
 
 
Forward purchase contract - index
 
1,800,000



Changes in the fair value of these financial and physical contracts are recorded as adjustments to natural gas sales.

Fair Value of Interest Rate and Commodity Derivatives
 
Fair values of interest rate and commodity derivative instruments not designated as hedging instruments in the unaudited condensed consolidated balance sheet as of March 31, 2012 and December 31, 2011:
 
As of March 31, 2012
 
Derivative Assets
 
Derivative Liabilities
 
Balance Sheet Classification
 
Fair Value
 
Balance Sheet Classification
 
Fair Value
 
($ in thousands)
Interest rate derivatives - liabilities
Current assets
 
$

 
Current liabilities
 
$
(11,617
)
Interest rate derivatives - liabilities
Long-term assets
 

 
Long-term liabilities
 
(10,597
)
Commodity derivatives - assets
Current assets
 
29,816

 
Current liabilities
 
17,693

Commodity derivatives - assets
Long-term assets
 
21,907

 
Long-term liabilities
 
2,885

Commodity derivatives - liabilities
Current assets
 
(12,171
)
 
Current liabilities
 
(17,661
)
Commodity derivatives - liabilities
Long-term assets
 
(4,417
)
 
Long-term liabilities
 
(8,725
)
Total derivatives
 
 
$
35,135

 
 
 
$
(28,022
)
 
 
 
 
 
 
 
 
 
As of
December 31, 2011
 
Derivative Assets
 
Derivative Liabilities
 
Balance Sheet Classification
 
Fair Value
 
Balance Sheet Classification
 
Fair Value
 
($ in thousands)
Interest rate derivatives - liabilities
Current assets
 
$

 
Current liabilities
 
$
(12,678
)
Interest rate derivatives - liabilities
Long-term assets
 

 
Long-term liabilities
 
(11,331
)
Commodity derivatives - assets
Current assets
 
24,240

 
Current liabilities
 
15,357

Commodity derivatives - assets
Long-term assets
 
26,611

 
Long-term liabilities
 
5,217

Commodity derivatives - liabilities
Current assets
 
(11,160
)
 
Current liabilities
 
(14,328
)
Commodity derivatives - liabilities
Long-term assets
 
(2,321
)
 
Long-term liabilities
 
(779
)
Total derivatives
 
 
$
37,370

 
 
 
$
(18,542
)
            

15


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 March 31,
 
 
 
2012
 
2011
Interest rate derivatives
Interest rate risk management losses
 
$
(1,579
)
 
$
(2,662
)
Commodity derivatives
Commodity risk management gains (losses)
 
(8,608
)
 
(60,445
)
Commodity derivatives -trading
Natural gas, natural gas liquids, oil, condensate and sulfur sales
 
637

 

 
Total
 
$
(9,550
)
 
$
(63,107
)
 

NOTE 11. FAIR VALUE OF FINANCIAL INSTRUMENTS
 
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Partnership utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk inherent in the inputs to the valuation technique. The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).
 
The three levels of the fair value hierarchy are as follows:
 
Level 1 – Quoted prices are available in active markets for identical assets and liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide information on an ongoing basis.
 
Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the market place throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
 
Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value.
 
As of March 31, 2012, the Partnership has recorded its interest rate swaps and commodity derivative instruments (see Note 10), which includes crude oil, natural gas and NGLs, at fair value. The Partnership reviews the classification of the inputs at the end of each period and has classified the inputs to measure the fair value of its interest rate swaps, crude oil derivatives and natural gas derivatives as Level 2.  In prior periods, the Partnership has classified the inputs to measure its NGL derivatives as Level 3 as the NGL market was considered to be less liquid and thinly traded. As of September 30, 2011, the Partnership concluded that the inputs for its NGL derivatives were considered to be more observable due to the NGL market being more liquid through the term of our contracts and has classified these inputs as Level 2.


16


The following tables disclose the fair value of the Partnership's derivative instruments as of March 31, 2012 and December 31, 2011
 
As of March 31, 2012
 
Level 1
 
Level 2
 
Level 3
 
Netting (a)
 
Total
 
($ in thousands)
Assets:
 
 
 
 
 
 
 
 
 
Crude oil derivatives
$

 
$
1,873

 
$

 
$
(13,737
)
 
$
(11,864
)
Natural gas derivatives

 
64,478

 

 
(18,367
)
 
46,111

NGL derivatives

 
5,950

 

 
(5,062
)
 
888

Total 
$

 
$
72,301

 
$

 
$
(37,166
)
 
$
35,135

 
 
 
 
 
 
 
 
 
 
Liabilities:
 

 
 

 
 

 
 

 
 

Crude oil derivatives
$

 
$
(37,959
)
 
$

 
$
13,737

 
$
(24,222
)
Natural gas derivatives

 
(1,220
)
 

 
18,367

 
17,147

NGL derivatives

 
(3,795
)
 

 
5,062

 
1,267

Interest rate swaps

 
(22,214
)
 

 

 
(22,214
)
Total 
$

 
$
(65,188
)
 
$

 
$
37,166

 
$
(28,022
)
____________________________
(a)
Represents counterparty netting under agreement governing such derivative contracts.
 
As of
December 31, 2011
 
Level 1
 
Level 2
 
Level 3
 
Netting (a)
 
Total
 
($ in thousands)
Assets:
 
 
 
 
 
 
 
 
 
Crude oil derivatives
$

 
$
11,795

 
$

 
$
(14,150
)
 
$
(2,355
)
Natural gas derivatives

 
58,374

 

 
(17,930
)
 
40,444

NGL derivatives

 
1,256

 

 
(1,975
)
 
(719
)
Total 
$

 
$
71,425

 
$

 
$
(34,055
)
 
$
37,370

 
 
 
 
 
 
 
 
 
 
Liabilities:
 

 
 

 
 

 
 

 
 

Crude oil derivatives
$

 
$
(24,051
)
 
$

 
$
14,150

 
$
(9,901
)
Natural gas derivatives

 
(1,290
)
 

 
17,930

 
16,640

NGL derivatives

 
(3,247
)
 

 
1,975

 
(1,272
)
Interest rate swaps

 
(24,009
)
 

 

 
(24,009
)
Total 
$

 
$
(52,597
)
 
$

 
$
34,055

 
$
(18,542
)
____________________________
(a)
Represents counterparty netting under agreement governing such derivative contracts.
 
The following table sets forth a reconciliation of changes in the fair value of the Level 3 NGL derivatives during the three months ended March 31, 2012 and 2011 (in thousands):
 
Three Months Ended March 31,
 
2012
 
2011
Net liability beginning balance
$

 
$
(5,733
)
Settlements 

 
3,737

Total gains or losses (realized and unrealized) 

 
(10,268
)
Net liability ending balance
$

 
$
(12,264
)

The Partnership valued its Level 3 NGL derivatives using forward curves, interest rate curves, and volatility parameters, when applicable. In addition, the impact of counterparty credit risk is factored into the value of derivative assets, and the

17


Partnership's credit risk is factored into the value of derivative liabilities.
 
The Partnership recognized no gains (losses) in the three months ended March 31, 2012 related to Level 3 assets and liabilities. The Partnership recognized losses of $9.0 million in the three months ended March 31, 2011, that are attributable to the change in unrealized gains or losses related to those Level 3 assets and liabilities still held at March 31, 2011, 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. 
 
Fair Value of Assets and Liabilities Measured on a Non-recurring Basis

The following table discloses the fair value of the Partnership's assets measured at fair value on a nonrecurring basis as of March 31, 2012 (in thousands):
 
March 31,
2012
 
Level 1
 
Level 2
 
Level 3
 
Total Losses
Plant assets
$
180

 
$

 
$

 
$
180

 
$
4,164

Pipeline assets
$
1,089

 
$

 
$

 
$
1,089

 
$
37,148

Rights-of-way
$
167

 
$

 
$

 
$
167

 
$
3,154

Contracts
$
49

 
$

 
$

 
$
49

 
$
1,056


The Partnership calculated the fair value of the impaired assets using a discounted cash flow analysis to determine the excess of the asset's carrying value over its fair value. Significant inputs to the valuation of fair value of the proved properties included estimates of (i) future estimated cash flows, including revenue, expenses and capital expenditures, (ii) estimated timing of cash flows (iii) estimated forward commodity prices, adjusted for estimate location differentials and (iv) a discount rate reflective of our cost of capital. See Notes 4 and 6 for a further discussion of the impairment charges.

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 March 31, 2012, the outstanding debt associated with the Partnership's revolving credit facility bore interest at a floating rate; as such, the Partnership believes that the carrying value of this debt approximates its fair value. The Partnership's 8 3/8% Senior Notes due 2019 (the "Senior Notes") bear interest at a fixed rate; based on the market price of the Senior Notes as of March 31, 2012, the Partnership estimates that the fair value of the Senior Notes was $310.5 million compared to a carrying value of $298.0 million. Fair value of the senior notes was estimated based on prices quoted from third-party financial institutions, which are characteristic of Level 2 fair value measurement inputs.
  

NOTE 12. COMMITMENTS AND CONTINGENT LIABILITIES
 
Litigation—The Partnership is subject to lawsuits which arise from time to time in the ordinary course of business, such as the interpretation and application of contractual terms related to the calculation of payment for liquids and natural gas proceeds. The Partnership had no accruals as of March 31, 2012 and December 31, 2011 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 the Partnership's 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

18


insurance covering the replacement cost of all owned real and personal property, including coverage for losses due to boiler and machinery breakdown, earthquake, flood and consequent business interruption/extra expense; (5) control of well/operator's extra expense insurance for operated and non-operated wells in the Upstream Segment; and (6) corporate liability insurance including coverage for Directors and Officers and Employment Practices liabilities.  In addition, the Partnership maintains excess liability insurance providing limits in excess of the established primary limits for commercial general liability and automobile liability insurance.
 
All coverages are subject to industry accepted policy terms, conditions, limits and deductibles comparable to that obtained by other energy companies with similar operations. The cost of insurance for the energy industry continued to fluctuate over the past year, reflecting the changing conditions in the insurance markets. 

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 March 31, 2012 and December 31, 2011, the Partnership had accrued approximately $3.2 million 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. The Partnership did not surpass such rates in 2011 and does not anticipate doing so in 2012. With respect to 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 $2.3 million and $2.4 million for the three months ended March 31, 2012 and 2011, respectively. Rental expense for leases with escalation clauses is recognized on a straight-line basis over the initial lease term.

NOTE 13. SEGMENTS
     
During the fourth quarter of 2011, the Partnership's chief executive officer (who is our chief operating decision-maker "CODM") decided that due to the relative size of the East Texas/Louisiana, South Texas and Gulf of Mexico segments, these three reporting segments would be collapsed into a single reporting segment and that a new Marketing and Trading reporting segment would be created.  The Partnership's Marketing and Trading results were previously presented within its Texas Panhandle Segment.  The Partnership now conducts, evaluates and reports on its Midstream Business within three distinct segments—the Texas Panhandle Segment, the East Texas and Other Midstream Segment, which consolidates its former East Texas/Louisiana, South Texas and Gulf of Mexico Segments, and the Marketing and Trading Segment. The Partnership's Upstream Segment and functional (Corporate and Other) segment remain unchanged from what has been previously reported.
    
Based on the Partnership’s approach to managing its assets, the Partnership believes its operations consist of three segments in its Midstream Business, one Upstream Segment and one Corporate segment:

(i)    Midstream—Texas Panhandle Segment:
gathering, compressing, treating, processing and transporting natural gas; fractionating, transporting and marketing NGLs;


19


(ii)    Midstream—East Texas and Other Midstream Segment:
gathering, compressing, processing and treating natural gas and marketing of natural gas, NGLs and condensate in South Texas, East Texas, Louisiana, Gulf of Mexico and inland waters of Texas;

(iii)    Midstream—Marketing and Trading Segment:
crude oil logistics and marketing in the Texas Panhandle and Alabama; and natural gas marketing and trading;

(iv)    Upstream Segment:
 crude oil, condensate, natural gas, NGLs and sulfur production from operated and non-operated wells; and
  
(v)    Corporate and Other Segment:
 risk management, intersegment eliminations and other corporate activities such as general and administrative expenses.
 
The Partnership's 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:

Three Months Ended March 31, 2012
 
Texas
Panhandle
Segment
 
East Texas and Other
Midstream
Segment
 
Marketing
and Trading Segment
 
Total
Midstream
Business
 
Upstream
Segment
 
Corporate
and Other Segment
 
Total
Segments
($ in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sales to external customers
 
$
78,030

 
$
47,831

 
$
66,582

 
$
192,443

 
$
41,920

 
 
$
(8,608
)
(a)
 
$
225,755

Intersegment sales
 
25,446

 
9,523

 
(37,819
)
 
(2,850
)
 
15,339

 
 
(12,489
)
 
 

Cost of natural gas and natural gas liquids
 
71,488

 
45,508

 
13,458

 
130,454

 

 
 

 
 
130,454

Intersegment cost of natural gas, oil and condensate
 

 

 
13,631

 
13,631

 

 
 
(13,631
)
 
 

Operating costs and other expenses
 
12,238

 
5,129

 

 
17,367

 
14,832

 
 
16,841

 
 
49,040

Depreciation, depletion, amortization and impairment
 
9,517

 
52,657

 
30

 
62,204

 
22,220

 
 
392

 
 
84,816

Operating income (loss) from continuing operations
 
$
10,233

 
$
(45,940
)
 
$
1,644

 
$
(34,063
)
 
$
20,207

 
 
$
(24,699
)
 
 
$
(38,555
)
Capital Expenditures
 
$
33,393

 
$
2,685

 
$
142

 
$
36,220

 
$
27,228

 
 
$
725

 
 
$
64,173

Segment Assets
 
$
596,243

 
$
359,347

 
$
32,982

 
$
988,572

 
$
990,275

 
 
$
51,112

(b)
 
$
2,029,959


Three Months Ended March 31, 2011
 
Texas
Panhandle
Segment
 
East Texas and Other
Midstream
Segment
 
Marketing
and Trading Segment
 
Total
Midstream
Business
 
Upstream
Segment
 
Corporate
and Other Segment
 
Total
Segments
($ in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sales to external customers
 
$
100,412

 
$
73,978

 
$
24,452

 
$
198,842

 
$
18,967

(c)
 
$
(60,445
)
(a)
 
$
157,364

Intersegment sales
 

 

 

 

 
9,503

 
 
(9,503
)
 
 

Cost of natural gas and natural gas liquids
 
71,954

 
58,480

 
16,885

 
147,319

 

 
 

 
 
147,319

Intersegment cost of natural gas, oil and condensate
 

 

 
7,089

 
7,089

 

 
 
(7,089
)
 
 

Operating costs and other expenses
 
9,401

 
5,384

 

 
14,785

 
8,006


 
11,776

 
 
34,567

Intersegment operations and maintenance
 

 

 

 

 
42

 
 
(42
)
 
 

Depreciation, depletion, amortization and impairment
 
9,121

 
6,960

 

 
16,081

 
7,554

 
 
387

 
 
24,022

Operating income (loss) from continuing operations
 
$
9,936

 
$
3,154

 
$
478

 
$
13,568

 
$
12,868

 
 
$
(74,980
)
 
 
$
(48,544
)
Capital Expenditures
 
$
7,390

 
$
1,028

 
$

 
$
8,418

 
$
5,662

 
 
$
102

 
 
$
14,182

Segment Assets
 
$
568,732

 
$
399,328

 
$
21,944

 
$
990,004

 
$
361,981

 
 
$
6,037

(b)
 
$
1,358,022

______________________________
(a)
Represents results of the Partnership's commodity risk management activity.
(b)
Includes elimination of intersegment transactions. 
(c)
Sales to external customers for the three months ended March 31, 2011 includes $2.0 million of business interruption insurance recovery related to the shutdown of the Eustace plant in 2011 and 2010 in the Upstream Segment, which is recognized as part of Other revenue in the unaudited condensed consolidated statement of operations.





20


NOTE 14. INCOME TAXES
 
Provision for Income Taxes -The Partnership's provision for income taxes relates to (i) state taxes for the Partnership and (ii) federal taxes for Eagle Rock Energy Acquisition Co., Inc. and Eagle Rock Energy Acquisition Co. II, Inc. and their wholly-owned subsidiary corporations, Eagle Rock Upstream Development Company, Inc. and Eagle Rock Upstream Development Company II, Inc., which are subject to federal income taxes (collectively, the "C Corporations").
Effective Rate - The effective rate for the three months ended March 31, 2012 was 0.2% compared to 0.1% for the three months ended March 31, 2011. Due to the fact that the effective rate is a ratio of total tax expense compared to pre-tax book net income, the change is due primarily to book and tax temporary differences for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011.
    

NOTE 15. EQUITY-BASED COMPENSATION
 
Eagle Rock Energy G&P, LLC, the general partner of the general partner of the Partnership, has a long-term incentive plan, as amended ("LTIP"), for its employees, directors and consultants who provide services to the Partnership and its subsidiaries and affiliates. The LTIP provides for the issuance of an aggregate of up to 7,000,000 common units, to be granted either as options, restricted units or phantom units, of which, as of March 31, 2012, a total of 2,692,141 common units remained available for issuance. Grants of common units under the LTIP are made at the discretion of the board. Distributions declared and paid on outstanding restricted units are paid directly to the holders of the restricted units. No options or phantom units have been issued to date.

The restricted units granted are valued at the market price as of the date issued. The awards generally vest over three years on the basis of one third of the award each year. The Partnership recognizes compensation expense on a straight-line basis over the requisite service period for the restricted unit grants. During the restriction period, distributions associated with the granted awards will be distributed to the awardees.
 
A summary of the restricted common units’ activity for the three months ended March 31, 2012 is provided below:
 
Number of
Restricted
Units
 
Weighted
Average
Fair Value
Outstanding at December 31, 2011
2,560,110

 
$
8.71

Granted
166,200

 
$
10.66

Forfeited
(14,600
)
 
$
9.18

Outstanding at March 31, 2012
2,711,710

 
$
8.83

    
For the three months ended March 31, 2012 and 2011, non-cash compensation expense of approximately $2.2 million and $0.9 million, respectively, was recorded related to the granted restricted units as general and administrative expense on the audited consolidated statements of operations.
 
As of March 31, 2012, unrecognized compensation costs related to the outstanding restricted units under the LTIP totaled approximately $18.6 million. The remaining expense is to be recognized over a weighted average of 2.31 years.
NOTE 16. EARNINGS PER UNIT
 
Basic earnings per unit is computed by dividing the net income (loss) by the weighted average number of units outstanding during a period. To determine net income (loss) allocated to each class of ownership (common and restricted common units), the Partnership first allocates net income (loss) in accordance with the amount of distributions made for the quarter by each class, if any. The remaining net income (loss) is allocated to each class in proportion to the class weighted average number of units outstanding for a period, as compared to the weighted average number of units for all classes for the period.

As of March 31, 2012 and 2011, the Partnership had unvested restricted common units outstanding, which are considered dilutive securities. These units will be considered in the diluted weighted average common unit outstanding number in periods of net income. In periods of net losses, these units are excluded from the diluted weighted average common unit outstanding number.


21


Any warrants outstanding during the period are considered to be dilutive securities. These outstanding warrants will be considered in the diluted weighted average common units outstanding number in periods of net income, except if the exercise price of the outstanding warrants is greater than the average market price of the common units for such periods. In periods of net losses, the outstanding warrants are excluded from the diluted weighted average common units outstanding.

The following table presents the Partnership's calculation of basic and diluted units outstanding for the periods indicated:
 
Three Months Ended March 31,
 
2012
 
2011
 
(in thousands)
Weighted average units outstanding during period:
 
 
 
Common units - Basic and diluted
128,162

 
84,235

 
The restricted common units granted under the LTIP, as discussed in Note 15, contain non-forfeitable rights to the distributions declared by the Partnership and therefore meet the definition of participating securities. Participating securities are required to be included in the computation of earnings per unit pursuant to the two-class method.

The following table presents the Partnership's basic and diluted income per unit for the three months ended March 31, 2012:
 
 
Total
 
Common Units
 
Restricted Common Units
 
 
($ in thousands, except for per unit amounts)
Net loss
 
(50,333
)
 
 
 
 
Distributions
 
29,366

 
$
28,769

 
$
597

Assumed net loss after distribution to be allocated
 
(79,699
)
 
(79,699
)
 

Assumed net loss to be allocated
 
$
(50,333
)
 
$
(50,930
)
 
$
597

 
 
 
 
 
 
 
Basic and diluted loss per unit
 
 
 
$
(0.40
)
 
 

The following table presents the Partnership's basic and diluted income per unit for the three months ended March 31, 2011:
 
 
Total
 
Common Units
 
Restricted Common Units
 
 
($ in thousands, except for per unit amounts)
Net loss from continuing operations
 
$
(54,435
)
 
 
 
 
Distributions
 
12,852

 
$
12,635

 
$
217

Assumed net loss from continuing operations after distribution to be allocated
 
(67,287
)
 
(67,287
)
 

Assumed allocation of net loss from continuing operations
 
(54,435
)
 
(54,652
)
 
217

Discontinued operations, net of tax
 
718

 
718

 

Assumed net loss to be allocated
 
$
(53,717
)
 
$
(53,934
)
 
$
217

 
 
 
 
 
 
 
Basic and diluted loss from continuing operations per unit
 
 
 
$
(0.65
)
 
 
Basic and diluted discontinued operations per unit
 
 
 
$
0.01

 
 
Basic and diluted loss per unit
 
 
 
$
(0.64
)
 
 
    





22


NOTE 17.   DISCONTINUED OPERATIONS

The following table represents activity from discontinued operations for the three months ended March 31, 2011:
 
 
Wildhorse System (a)
 
Minerals Business (b)
($ in thousands)
 
 
 
 
Revenues
 
$
5,089

 
$
318

Income from Operations
 
$
452

 
$
318

Discontinued operations, net of tax
 
$
400

 
$
318

_____________________________
(a)
On May 20, 2011, the Partnership sold its Wildhorse Gathering System (which was accounted for in its East Texas and Other Midstream Segment).
(b)
On May 24, 2010, the Partnership completed the sale of its Minerals Business. During the three months ended March 31, 2011, the Partnership received payments related to pre-effective date operations and recorded this amount as part of discontinued operations for the period.



NOTE 18. SUBSIDIARY GUARANTORS
 
As of March 31, 2012, the Partnership had issued registered debt securities guaranteed by its subsidiaries.  As of March 31, 2012, all guarantors are wholly-owned or available to be pledged and such guarantees are joint and several and full and unconditional.  In accordance with Rule 3-10 of Regulation S-X, the Partnership has prepared Unaudited Condensed Consolidating Financial Statements as supplemental information.  The following condensed unaudited consolidating balance sheets at March 31, 2012 and December 31, 2011, unaudited condensed consolidating statements of operations for the three months ended March 31, 2012 and 2011, and unaudited condensed consolidating statements of cash flows for the three months ended March 31, 2012 and 2011, present financial information for Eagle Rock Energy as the parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the co-issuer and the subsidiary guarantors, which are all 100% owned by the parent, on a stand-alone basis, and the consolidation and elimination entries necessary to arrive at the information for the Partnership on a consolidated basis.  The subsidiary guarantors are not restricted from making distributions to the Partnership.

 Unaudited Condensed Consolidating Balance Sheet
March 31, 2012
 
Parent Issuer
 
Co-Issuer
 
Subsidiary Guarantors
 
Non-Guarantor Investments
 
Consolidating
Entries
 
Total
 
($ in thousands)
ASSETS:
 
 
 
 
 
 
 
 
 
 
 
Accounts receivable – related parties
$
562,754

 
$

 
$

 
$

 
$
(562,754
)
 
$

Other current assets
18,641

 
1

 
120,420

 

 

 
139,062

Total property, plant and equipment, net
1,635

 

 
1,748,363

 

 

 
1,749,998

Investment in subsidiaries
1,200,938

 

 

 
1,007

 
(1,201,945
)
 

Total other long-term assets
28,224

 

 
112,675

 

 

 
140,899

Total assets
$
1,812,192

 
$
1

 
$
1,981,458

 
$
1,007

 
$
(1,764,699
)
 
$
2,029,959

LIABILITIES AND EQUITY:
 
 
 
 
 
 
 
 
 
 
 
Accounts payable – related parties
$

 
$

 
$
562,754

 
$

 
$
(562,754
)
 
$

Other current liabilities
23,216

 

 
144,951

 

 

 
168,167

Other long-term liabilities
23,947

 

 
72,816

 

 

 
96,763

Long-term debt
814,203

 

 

 

 

 
814,203

Equity
950,826

 
1

 
1,200,937

 
1,007

 
(1,201,945
)
 
950,826

Total liabilities and equity
$
1,812,192

 
$
1

 
$
1,981,458

 
$
1,007

 
$
(1,764,699
)
 
$
2,029,959



23


Unaudited Condensed Consolidating Balance Sheet
December 31, 2011
 
Parent Issuer
 
Co-Issuer
 
Subsidiary
Guarantors
 
Non-Guarantor Investments
 
Consolidating Entries
 
Total
 
($ in thousands)
ASSETS:
 
 
 
 
 
 
 
 
 
 
 
Accounts receivable – related parties
$
541,384

 
$

 
$

 
$

 
$
(541,384
)
 
$

Other current assets
15,749

 
1

 
109,778

 

 

 
125,528

Total property, plant and equipment, net
1,393

 

 
1,762,281

 

 

 
1,763,674

Investment in subsidiaries
1,229,606

 

 

 
1,033

 
(1,230,639
)
 

Total other long-term assets
30,928

 

 
125,558

 

 

 
156,486

Total assets
$
1,819,060

 
$
1

 
$
1,997,617

 
$
1,033

 
$
(1,772,023
)
 
$
2,045,688

LIABILITIES AND EQUITY:
 
 
 
 
 
 
 
 
 
 
 
Accounts payable – related parties
$

 
$

 
$
541,384

 
$

 
$
(541,384
)
 
$

Other current liabilities
18,110

 

 
152,745

 

 

 
170,855

Other long-term liabilities
14,150

 

 
73,883