EAGLE ROCK ENERGY PARTNERS L P - FORM 8-K/A - EX-99.1 - EXHIBIT 99.1 CROW CREEK FINANCIAL STATEMENTS

Attached files

file	filename
8-K/A - FORM 8-K/A - EAGLE ROCK ENERGY PARTNERS L P	form8k.htm
EX-99.2 - EXHIBIT 99.2 PRO FORMA FINANCIAL STATEMENTS - EAGLE ROCK ENERGY PARTNERS L P	exhibit992a.htm
EX-23.1 - EXHIBIT 23.1 CONSENT - EAGLE ROCK ENERGY PARTNERS L P	exhibit231a.htm
EX-99.3 - EXHIBIT 99.3 - EAGLE ROCK ENERGY PARTNERS L P	exhibit993a.htm

EXHIBIT 99.1

Unaudited Consolidated Financial Statements

CC ENERGY II L.L.C. AND SUBSIDIARIES

March 31, 2011

CC ENERGY II L.L.C. AND SUBSIDIARIES

Consolidated Balance Sheets

March 31, 2011 and December 31, 2010

(unaudited)



		2011			2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	410,991		$	6,245,361
Accounts receivable-
Oil and natural gas sales		11,783,874			12,526,309
Joint operations and other, net		3,134,191			2,244,023
Prepaid well costs		2,475,391			2,791,642
Prepaid expenses and other current assets		2,563,236			2,743,911
Gas balancing receivable		1,103,607			1,103,607
Derivative financial instruments		11,837,238			15,382,726
Total current assets		33,308,528			43,037,579
PROPERTY AND EQUIPMENT, at cost:
Oil and natural gas properties, full cost method		625,185,101			601,547,602
Other		555,032			545,292
		625,740,133			602,092,894
Less- accumulated depreciation, depletion and amortization		266,188,219			259,696,598
Total property and equipment		359,551,914			342,396,296
PRODUCTION TAX REFUND RECEIVABLE		449,523			449,523
DEFERRED FINANCING COSTS, net of accumulated amortization		834,052			997,648
DERIVATIVE FINANCIAL INSTRUMENTS		5,815,816			7,392,489
Total assets	$	399,959,833		$	394,273,535

LIABILITIES AND MEMBERS' EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	18,320,418		$	18,332,680
Revenue and royalties due others		12,400,564			13,616,421
Derivative financial instruments		5,038,794			3,671,767
Drilling advances from partners		1,000,956			788,969
Gas balancing liability		219,083			219,083
Total current liabilities		36,979,815			36,628,920
GAS BALANCING LIABILITY		1,440,106			1,440,106
LONG-TERM DEBT		206,495,009			207,444,780
ASSET RETIREMENT OBLIGATIONS		7,402,761			7,200,847
DERIVATIVE FINANCIAL INSTRUMENTS		3,533,515			1,322,773
COMMITMENTS AND CONTINGENCIES (Note J)
Total liabilities		255,851,206			254,037,426
MEMBERS' EQUITY:
Members' equity interest		144,473,378			140,722,490
Accumulated other comprehensive loss		(364,751	)		(486,381	)
		144,108,627			140,236,109
Total liabilities and members' equity	$	399,959,833		$	394,273,535

The accompanying notes are an integral part of these consolidated financial statements.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Consolidated Statements of Operations

For the Three Months Ended March 31, 2011 and 2010

(unaudited)



		2011			2010

REVENUES:
Oil and natural gas sales	$	20,760,044		$	14,057,595

COSTS AND EXPENSES:
Lease operating and workover		1,821,621			1,422,704
Severance and ad valorem taxes		1,240,022			901,786
General and administrative		1,065,864			1,025,962
Depreciation, depletion and amortization		6,491,621			3,594,254
OPERATING INCOME (LOSS)		10,140,916			7,112,889

NON-OPERATING INCOME (EXPENSE):
Professional services fees and other income		27,638			14,744
Realized gains and losses on commodity derivative
financial instruments, net		3,955,675			1,829,020
Unrealized gains and losses on commodity derivative
financial instruments, net		(8,341,411	)		9,528,105
Interest expense		(1,708,379	)		(2,834,548	)
Interest income		3,138			5,329
Sale transaction expenses		(317,389	)		—
Other expenses		(9,300	)		(23,618	)
NET INCOME	$	3,750,888		$	15,631,921

The accompanying notes are an integral part of these consolidated financial statements.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Consolidated Statements of Changes in Members' Equity

For the Three Months Ended March 31, 2011 and 2010

(unaudited)



					Accumulated
					Other
	Equity				Comprehensive
	Units		Amount		Loss			Total
BALANCE, January 1, 2011	198,725,000	$	140,722,490	$	(486,381	)	$	140,236,109
Capital contributions	—		—		—			—
Comprehensive income:
Net income	—		3,750,888		—			3,750,888
Reclassifications of derivative
settlements to net income	—		—		233,004			233,004
Current period change in fair
value of derivative
instruments used for
hedging purposes	—		—		(111,374	)		(111,374	)
Total comprehensive income								3,872,518

BALANCE, March 31, 2011	198,725,000	$	144,473,378	$	(364,751	)	$	144,108,627

The accompanying notes are an integral part of these consolidated financial statements.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Consolidated Statements of Cash Flows

For Three Months Ended March 31, 2011 and 2010

(unaudited)



		2011			2010

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	3,750,888		$	15,631,921
Adjustments to reconcile net income (loss) to cash provided
by operating activities-
Depreciation, depletion and amortization		6,491,621			3,594,254
Amortization of deferred financing costs included in interest expense		163,596			82,698
Accretion of asset retirement obligation included in general and
administrative expense		67,823			47,023
Unrealized losses (gains) on commodity derivative financial instruments, net		8,341,411			(9,528,105	)
Changes in assets and liabilities-
Accounts receivable		(147,733	)		587,061
Prepaid expenses and other current assets		496,926			672,578
Commodity derivative financial instruments		480,149			357,450
Accounts payable and accrued liabilities		(12,262	)		1,137,322
Revenue and royalties due others		(1,215,857	)		(493,376	)
Drilling advances received from partners		211,987			(168,946	)
Net cash provided by operating activities		18,628,549			11,919,880
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures-
Acquisitions of oil and natural gas properties		(1,040,752	)		(2,323,077	)
Drilling activities		(25,179,226	)		(9,300,424	)
Purchase of other property and equipment		(9,740	)		(7,554	)
Proceeds from the sale of oil and natural gas properties and other assets		2,716,570			—
Net cash used in investing activities		(23,513,148	)		(11,631,055	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayment of lines of credit		(949,771	)		(1,000,000	)
Net cash used in financing activities		(949,771	)		(1,000,000	)
NET DECREASE IN CASH AND CASH EQUIVALENTS		(5,834,370	)		(711,175	)

CASH AND CASH EQUIVALENTS, beginning of period		6,245,361			1,647,050

CASH AND CASH EQUIVALENTS, end of period	$	410,991		$	935,875

NON-CASH INVESTING AND FINANCING INFORMATION:

Accrued capital expenditures	$	14,568,746			4,840,096
Asset retirement obligations incurred	$	186,811		$	4,503
Asset retirement obligations on property dispositions	$	(52,720	)	$	—

SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of $152,457 and $60,115 capitalized8 capitalized	$	1,627,946		$	2,733,269

The accompanying notes are an integral part of these consolidated financial statements.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Unaudited Consolidated Financial Statements

March 31, 2011 and 2010 and December 31, 2010

(unaudited)

A - ORGANIZATION AND OPERATIONS

CC Energy II L.L.C. (“CCEII”), a Delaware limited liability company, was formed on June 7, 2006, by four managing members, who currently serve as officers, for the purpose of acquiring, developing, producing, exploring for and selling gas, crude oil and related hydrocarbon products. On October 31, 2006, the Operating Agreement of CCEII and the Limited Liability Company Agreements of each of its two subsidiaries were amended and restated to add Natural Gas Partners VIII, L.P. (“NGP”) as a managing member and primary capital provider. Under the terms of the Operating Agreement, CCEII will be dissolved no later than December 31, 2016 unless the Operating Agreement is amended before that date to extend the time period.

CCEII is the sole member of Crow Creek Energy II L.L.C. and Crow Creek Operating Company II L.L.C., its wholly-owned subsidiaries. CCEII conducts business through its wholly-owned subsidiaries and sells natural gas and crude oil and related products to domestic pipelines and other markets primarily in the Mid-Continent region of the United States.

B - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES


1.	Principles of Consolidation

The consolidated financial statements include the accounts of CCEII and its two wholly-owned subsidiaries (collectively, the “Company”). All significant intercompany accounts and transactions have been eliminated in consolidation.


2.	Cash and Cash Equivalents

The Company considers all investments purchased with initial maturities of three months or less to be cash equivalents. Cash equivalents consist primarily of investments in highly liquid securities. The carrying amounts of cash and cash equivalents reported in the balance sheets approximate their fair values.

Certain of the Company's cash balances at March 31, 2011 are insured by the Federal Deposit Insurance Corporation (“FDIC”) up to $250,000 per financial institution. At times, cash balances may be in excess of the FDIC insurance limit.


3.	Oil and Natural Gas Properties

The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain related employee costs, incurred for the purpose of finding oil and natural gas are capitalized. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Costs, including related employee costs, associated with production and general corporate activities are expensed in the period incurred. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Unaudited Consolidated Financial Statements - continued

March 31, 2011 and 2010 and December 31, 2010

(unaudited)

The Company computes the provision for depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties using the units-of-production method based upon production and estimates of proved reserve quantities. Unevaluated costs and related carrying costs are excluded from the amortization base until the properties associated with these costs are evaluated. The amortization base includes estimated future development costs and estimated future dismantlement, restoration and abandonment costs, net of estimated salvage values. DD&A per equivalent Mcf of the Company's oil and natural gas properties was $1.70 and $1.60 for the three months ended March 31, 2011 and 2010, respectively.

The Company excludes the costs directly associated with acquisition and evaluation of unproved properties from the DD&A calculation until it is determined whether or not proved reserves can be assigned to the properties. These properties are assessed at least annually to ascertain whether impairment has occurred. Such costs are transferred into the amortization base on an ongoing basis as projects are evaluated and proved reserves established or impairment determined. The Company excluded approximately $19,180,000 and $3,729,000 related to undeveloped and unproved properties from the amortization base as of March 31, 2011 March 31, 2010 and December 31, 2010, respectively. The majority of the unproved properties excluded from the amortization base at the end of each period consist of costs incurred for oil and natural gas leases, plus capitalized interest, associated with probable reserves.

The Company capitalizes interest, if debt is outstanding, on expenditures for significant development projects until such projects are ready for their intended use. During the three months ended March 31, 2011 and 2010, the Company had $152,457 and $60,115, respectively, of capitalized interest related to the allocated cost of acquired probable and possible reserves and other undeveloped prospect costs.

The Company's unamortized costs of oil and natural gas properties are limited to the sum of the future net revenues attributable to proved oil and natural gas reserves using unescalated prices determined under Security Exchange Commission (“SEC”) rules, discounted at 10%, plus the lower of cost or fair value of any unproved properties, as adjusted for related income tax effects (the “Full Cost Ceiling”). If the Company's unamortized costs of oil and natural gas properties exceed the Full Cost Ceiling, a provision for additional DD&A is required. The Company's capitalized costs were not in excess of the Full Cost Ceiling at March 31, 2011.


4.	Reserve Estimation

In January 2010, the Financial Accounting Standards Board issued an update to the Oil and Gas topic, which aligns the oil and natural gas reserve estimation and disclosure requirements with the requirements in the SEC's final rule, Modernization of the Oil and Gas Reporting Requirements (the “Final Rule”). The Final Rule permits the use of new technologies to determine proved reserves estimates if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volume estimates. The Final Rule will also allow inclusion of oil and natural gas extracted from nontraditional sources in reserve estimates. In addition, the new disclosure requirements require companies to report proved oil and natural gas reserves using an average price based upon the prior 12-month period rather than a year-end price.

The Final Rule changes the full cost accounting method by requiring the denominator used in the units-of-production amortization method to conform to the proved reserves determined under the Final Rule. The Final Rule also requires the full cost ceiling to be computed using the same pricing requirements (12-month average price) that are used in determining reserve quantities.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Unaudited Consolidated Financial Statements - continued

March 31, 2011 and 2010 and December 31, 2010

(unaudited)


5.	Other Property and Equipment

Other property and equipment consists of office furniture, fixtures and equipment, computer hardware and software, leasehold improvements and Company owned vehicles. Depreciation of other property and equipment is provided using the straight-line method based on estimated useful lives ranging from three to ten years.

Other property and equipment consists of the following, recorded at cost, as of March 31, 2011 and December 31, 2010:



		2011			2010

Computer equipment and software	$	158,776		$	150,852
Office equipment, furniture and fixtures		155,326			154,860
Vehicles		188,881			188,881
Office leasehold improvements		52,049			50,699
		555,032			545,292
Less accumulated depreciation and amortization		(296,499	)		(276,384	)
Net other property and equipment	$	258,533		$	268,908


6.	Deferred Financing Costs

Deferred financing costs consist of capitalized amounts for up-front facility fees, professional fees and other expenses related to the credit facilities described in Note D. Deferred financing costs of $834,052, net of $1,478,125 accumulated amortization, have been recorded at March 31, 2011 and will be amortized over the remaining term of the credit agreements using the effective interest method. Deferred financing costs at December 31, 2010 were $997,648, net of $1,314,529 accumulated amortization. Amortization of deferred financing costs is included in interest expense in the consolidated statements of operations. Amortization charged to interest expense over the remaining terms of the credit agreements is expected to be approximately $474,400 for the remainder of 2011; $331,000 in 2012; and $28,652 in 2013.


7.	Revenue Recognition

Oil and natural gas revenues are recorded using the sales method. Under this method, the Company recognizes revenues based on actual volumes of oil and natural gas sold to purchasers. The Company and other joint interest owners may sell more or less than their entitlement share of the oil and natural gas volumes produced. A liability is recorded and revenue is deferred if the Company's excess sales of oil and natural gas volumes exceed its estimated remaining recoverable reserves. Certain properties acquired in 2007 and 2010 by the Company had natural gas imbalances from natural gas sold prior to the effective date of the Company's acquisition of those properties in excess of estimated remaining recoverable reserves. The total recorded current and non-current liability attributable to the acquired interest in those wells was $1,659,189 at March 31, 2011 and December 31, 2010. Four of the wells acquired in 2010 with gas balancing liabilities have been plugged as of March 31, 2011. The Company expects to settle the imbalances on these four wells in 2011 and $219,083 has been recorded as a current liability at March 31, 2011 and December 31, 2010.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Unaudited Consolidated Financial Statements - continued

March 31, 2011 and 2010 and December 31, 2010

(unaudited)

The Company acquired an interest in two plugged wells in 2010 with a total under produced gas imbalance of approximately 441,000 Mcf. The Company expects to receive settlement for the imbalances in 2011 and has recorded a current gas balancing receivable of $1,103,607 at March 31, 2011 and December 31, 2010.


8.	Accounts Receivable

The Company sells oil and natural gas to various customers and participates with other parties in the drilling, completion and operation of oil and natural gas wells. Joint interest and oil and natural gas sales receivables related to these operations are generally unsecured. Accounts receivable for joint interest billings are recorded as amounts billed to joint interest owners less an allowance for doubtful accounts. Amounts are considered past due after 30 days. The Company determines joint interest operations accounts receivable allowances based on management's assessment of the creditworthiness of the joint interest owners and the Company's ability to realize the receivables through netting of anticipated future production revenues and other collection actions. The Company recorded an allowance for doubtful accounts at March 31, 2011 and December 31, 2010 of $115,848 and the related bad debt expense was included in general and administrative expenses in the consolidated statement of operations for the year ended December 31, 2009.

The Company has drilled multiple wells during the past several years in Oklahoma and Texas that qualify for certain production and severance tax exemptions and reduced tax rates. These tax incentives are realized through reduced rates on current production or the receipt of refunds for taxes previously paid. During the year ended December 31, 2010, the Company received Oklahoma production tax refunds attributable to its interest in qualifying wells totaling $550,113 for taxes previously paid on production through June 30, 2009. The Company expects additional Oklahoma production tax refunds totaling $897,143 to be paid to the Company for taxes previously paid on production from July 1, 2009 through December 31, 2010. During the three months ended March 31, 2011, the Company received Oklahoma production tax refunds of $108,341 and Texas severance tax refunds of $98,193 attributable to the Company's interest in qualifying wells. During the three months ended March 31, 2010, the Company received Oklahoma production tax refunds of $496,907 attributable to the Company's interest in qualifying wells.

At March 31, 2011, the Company has recorded a current and non-current receivable for production and severance tax refunds attributable to the Company's interest in qualifying wells of $447,620 and $449,523, respectively. At December 31, 2010, the Company recorded a current and non-current receivable for production and severance tax refunds attributable to the Company's interest in qualifying wells of $545,813 and $449,523, respectively. The current portions are included as a current asset in accounts receivable - joint operations and other, net in the consolidated balance sheets.


9.	General and Administrative Expense

The Company receives fees from third parties for the operation of jointly owned oil and natural gas properties and records such reimbursements as reductions of general and administrative expense. Such fees totaled approximately $195,200 and $140,700 for the three months ended March 31, 2011 and 2010, respectively.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Unaudited Consolidated Financial Statements - continued

March 31, 2011 and 2010 and December 31, 2010

(unaudited)


10.	Derivative Financial Instruments

Accounting and reporting standards require that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded as either an asset or liability measured at its fair value.

Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the statement of operations. Companies must formally document, designate and assess the effectiveness of transactions that receive hedge accounting.

The Company uses commodity derivatives (puts, costless collars and swaps) to manage its exposure to cash flow risk from oil and natural gas price fluctuations related to its production. The cash flows from such transactions are included in operating activities in the consolidated statements of cash flows.

The Company uses interest rate swaps to manage its exposure to cash flow risk from interest rate fluctuations on its variable rate debt. Gains or losses from interest rate swaps are recognized as an adjustment to interest expense when the related swap transactions are settled. Interest expense has increased by $233,004 and $1,484,311 related to the settlement of interest rate swaps for the three months ended March 31, 2011 and 2010, respectively. For the three months ended March 31, 2011 and 2010, the hedge ineffectiveness on the Company's interest rate swaps was determined to be immaterial.

As of March 31, 2011 and December 31, 2010, and for the three months ended March 31, 2011 and 2010, all of the Company's interest rate swaps outstanding were designated as hedges for financial statement purposes. None of the Company's commodity derivatives at March 31, 2011 or December 31, 2010 or during the three months ended March 31, 2011 and 2010 were accounted for as hedges for financial statement purposes.


11.	Income Taxes

The Company is a limited liability company. No provision for income taxes is included in the consolidated financial statements of the Company. Income taxes, if any, for the Company are generally payable by the individual members of the Company.

The Company evaluates uncertain tax positions for recognition and measurement in the financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax positions will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. The Company had no uncertain tax positions that required recognition in the financial statements at March 31, 2011 and December 31, 2010. Any interest or penalties would be recognized as a component of income tax expense. Open tax years are considered to be 2007 through 2010.


12.	Unit-Based Compensation

The cost of employee services received in exchange for equity instruments is measured based on the grant-date fair value of those instruments. That cost is recognized over the requisite service period (often the vesting period). Generally, no compensation cost is recognized for equity instruments that do not vest.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Unaudited Consolidated Financial Statements - continued

March 31, 2011 and 2010 and December 31, 2010

(unaudited)


13.	Concentration of Credit Risk

The Company's oil and natural gas production is sold to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. The Company's joint operations accounts receivable are from a large number of oil and gas companies, partnerships, individuals and others who own interests in the properties operated by the Company. Management believes that any credit risk imposed by a concentration in the oil and natural gas industry is offset by the creditworthiness of the Company's customer base.

The Company had three customers whose purchases accounted for 23%, 19% and 12% of total revenues for the three months ended March 31, 2011. The Company had four customers whose purchases accounted for 20%, 16%, 12% and 8% of total revenues for the three months ended March 31, 2010.

At March 31, 2011, three customers comprised a total of 21%, 14%, and 7% of the oil and natural gas receivable balance. At December 31, 2010, the Company had four customers who comprised a total of 15%, 11%, 12% and 15% of the oil and natural gas receivable balance.

The Company had significant derivative assets at March 31, 2011. Inherent in any such contract is the risk of loss as a result of nonperformance by the Company's counterparties. Although the Company does not obtain collateral or otherwise secure the fair value of its derivative instruments, management believes the associated credit risk is mitigated by creditworthiness of the counterparties. At March 31, 2011, the Company had four counterparties with gross derivative assets of $9,213,441, $3,788,505, $2,932,444 and $1,146,324.


14.	Environmental

The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable.

On September 26, 2008 the Company was notified of an acid spill that occurred during completion operations of an operated well located in Grady County, Oklahoma. The Company immediately notified its environmental consultant, the Oklahoma Corporation Commission and the landowner. Both the Company and landowner engaged legal counsel to settle the issue. At the landowner's request, the Company has not performed any remediation work on the spill area. On March 24, 2009, the Company received a letter from the landowner's attorney claiming damages related to the spill of approximately $92,000 for remediation and reclamation costs, consulting fees, and legal fees plus an undetermined amount for alleged damage to the landowner's livestock. On May 22, 2009 the landowner filed a lawsuit claiming damages in excess of $50,000 related to the spill. Following discovery in the case, mediation was held on August 23, 2010. As a result of the mediation, an agreement was signed to settle all claims under the lawsuit for a payment to the landowner in the amount of $70,000. The settlement payment was covered by the Company's insurance, subject to a $10,000 deductible. The lawsuit was dismissed on November 5, 2010.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Unaudited Consolidated Financial Statements - continued

March 31, 2011 and 2010 and December 31, 2010

(unaudited)


15.	Asset Retirement Obligations

Accounting standards require that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made and that the associated asset retirement costs be part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related long-lived asset is charged to expense through the depreciation of the asset. Changes in the liability due to passage of time are recognized as accretion expense in the consolidated statements of operations and a corresponding increase in the carrying amount of the liability. The Company recognizes asset retirement obligations for its oil and natural gas working interests associated with the retirement of long-lived assets that result from the acquisition and development of the assets. Such obligations consist of future costs, net of recoverable salvage value of tangible equipment, to plug and abandoned oil and natural gas wells when the wells permanently cease production.

The activity for the three months ended March 31, 2011 and 2010 are as follows:



		2010			2009
Asset retirement obligations, January 1	$	7,200,847		$	3,910,383
Liabilities incurred - drilled wells		186,811			4,503
Accretion expense		67,823			47,023
Disposition of wells		(52,720	)		—
Asset retirement obligations, March 31	$	7,402,761		$	3,961,909


16.	Fair Value of Financial Instruments

The carrying amounts reported in the balance sheet for cash, accounts receivable, and accounts payable approximate their fair values. The recorded values of the Company's credit facilities approximate fair value as the interest rate is variable and is repriced at a minimum of quarterly.

The Company accounts for its oil and natural gas commodity derivatives and interest rate swaps at fair value. The fair value of derivative financial instruments is determined utilizing pricing models for similar instruments. The models use a variety of techniques to arrive at fair value, including quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward curves generated from a compilation of data gathered from third parties.

The Company has categorized its financial instruments, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).

Financial assets and liabilities recorded in the consolidated balance sheets are categorized based on the inputs to the valuation techniques as follows:

Level 1 - Financial assets and liabilities for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access.

Level 2 - Financial assets and liabilities for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Unaudited Consolidated Financial Statements - continued

March 31, 2011 and 2010 and December 31, 2010

(unaudited)

Level 3 - Financial assets and liabilities for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability.

When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on an annual basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities.

The following presents the Company's fair value hierarchy for assets and liabilities measured at fair value on a recurring basis at March 31, 2011 and December 31, 2010. These items are included in “derivative financial instruments” in the consolidated balance sheets.



		March 31, 2011
		Level 1		Level 2		Level 3
Assets:
Commodity derivatives	$	—	$	17,389,963	$	—
Interest rate swaps	$	—	$	263,091	$	—

Liabilities:
Commodity derivatives	$	—	$	7,944,467	$	—
Interest rate swaps	$	—	$	627,842	$	—

		December 31, 2010
Assets:
Commodity derivatives	$	—	$	22,435,696	$	—
Interest rate swaps	$	—	$	339,519	$	—

Liabilities:
Commodity derivatives	$	—	$	4,168,640	$	—
Interest rate swaps	$	—	$	825,900	$	—

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are reported at fair value on a nonrecurring basis in the Company's consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Unaudited Consolidated Financial Statements - continued

March 31, 2011 and 2010 and December 31, 2010

(unaudited)

Impairments of Long-Lived Assets - The Company reviews its long-lived assets to be held and used, including oil and natural gas properties, whenever events or circumstances indicate that carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of expected discounted future net cash flows is less than the carrying amount of the assets. In this circumstance, the Company recognized an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset. The Company reviews its oil and natural gas properties included in the full cost pool or by individual well for those wells not constituting part of the full cost pool. If the total amortization base of the full cost pool is determined to be impaired, an impairment loss equal to the difference between the carrying value of the full cost pool and the estimated fair value (discounted future cash flows) of the properties would be recognized at that time. Estimating future cash flows involves the use of judgments, including estimation of the proved oil and natural gas reserves quantities, timing of development and production, capital expenditures and production cost. Estimating future cash flows for purposes of impairment loss recognition also involves future commodity price assumptions determined by the SEC.

Asset Retirement Obligations - The Company estimates the fair value of the asset retirement obligation (“ARO”) based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. See Note B.15 for a summary of changes in AROs.



				Significant
		Quoted Prices in		Other		Significant
		Active Markets for		Observable		Unobservable		Total
		Identical Assets		Inputs		Inputs		Impairment
		(Level 1)		(Level 2)		(Level 3)		Loss

Three Months Ended March 31, 2011:
Impairment of long-lived assets	$	—	$	—	$	427,749,125	$	—
Asset retirement obligations incurred
in current period		—		—		186,811		—
Three Months Ended March 31, 2010:
Impairment of long-lived assets	$	—	$	—	$	352,190,750	$	—
Asset retirement obligations incurred
in current period		—		—		4,503		—


17.	Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include the fair value of financial instruments, equity-based compensation, asset retirement obligations and depreciation, depletion and amortization of proved oil and natural gas properties. Oil and gas reserve estimates, which are the basis for units of production DD&A and the Full Cost Ceiling, are inherently imprecise and may change as future information becomes available.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Unaudited Consolidated Financial Statements - continued

March 31, 2011 and 2010 and December 31, 2010

(unaudited)

C - ACQUISITIONS AND DISPOSITION

On May 11, 2010, the Company entered into a purchase and sale agreement to acquire certain Mid-Continent Arkoma assets located in Arkansas from a group of partnerships affiliated with a private entity for a purchase price of $60.0 million, subject to customary adjustments. The Company made a deposit of $6.0 million upon signing the purchase and sale agreement. The transaction closed successfully on June 29, 2010 with an effective date of May 1, 2010. The acquisition was funded with a combination of debt and equity and included working interests in approximately 200 operated and non-operated natural gas properties and overriding royalty interests in approximately 125 additional natural gas properties. The Company assumed operations of approximately 100 of the acquired properties on June 29, 2010. The net income related to the acquired properties, including accrued revenue and expenses, from and after the effective date through the closing date, has been recorded as a reduction of the purchase price. Revenues and expenses from the acquired properties were recorded in the Company's consolidated statement of operations effective July 1, 2010. On December 16, 2010 the Company received payment from the seller of $787,798 for final post-closing adjustments, which has been included in oil and gas properties.

The following table represents the allocation of the total purchase price of the Mid-Continent Arkoma acquisition to the acquired assets and liabilities assumed. The allocation represents the fair value assigned to each of the assets acquired and liabilities assumed:



		Mid-Continent
		Arkoma
		Acquisition
Fair value of net assets:
Proved oil and natural gas properties	$	56,247,004
Unproved oil and natural gas properties		3,619,414
Gas balancing receivable		1,103,607
Total assets acquired		60,970,025
Revenue and royalties due to others		(1,024,400	)
Gas balancing liability		(741,237	)
Asset retirement obligations		(2,805,940	)
Other liabilities assumed		(92,170	)
Total liabilities assumed		(4,663,747	)
Total cash consideration	$	56,306,278

The Company participated in an auction held by the Bureau of Indian Affairs on August 31 and September 1, 2010, and was the successful bidder on multiple undeveloped oil and gas leases located on Cheyenne-Arapaho allotted and tribal lands in two Oklahoma counties. The total purchase price of approximately $12.8 million was funded with available cash and equity.

Effective November 4, 2010, the Company sold undeveloped leasehold in several sections of Ellis County, Oklahoma for sales proceeds totaling approximately $2.0 million.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Unaudited Consolidated Financial Statements - continued

March 31, 2011 and 2010 and December 31, 2010

(unaudited)

Effective January 1, 2011, the Company sold its interests in two outside-operated Oklahoma properties at an auction for net sales proceeds totaling approximately $2.7 million. Although the auction was held in December 2010, the sale did not close until after December 31, 2010. The effective date of the sale was January 1, 2011. The Company received the sales proceeds on January 14, 2011. No gain or loss was recognized on this sale, and the proceeds received were offset against the Company's oil and natural gas properties in the consolidated balance sheet upon sale.

D - DEBT

Long-term debt consisted of the following as of March 31, 2011 and December 31, 2010:



		March 31, 2011		December 31, 2010

Revolving credit facility	$	174,495,009	$	175,444,780
Term loan		32,000,000		32,000,000
Total debt		206,495,009		207,444,780
Less: current portion		—		—
Total long-term debt	$	206,495,009	$	207,444,780

At March 31, 2011, the Company had a $250.0 million revolving credit facility in place under a Credit Agreement dated June 29, 2007, as amended, entered into between the Company and Wachovia Bank, N.A. as Administrative Agent and certain other banks as named and defined therein (the “Banks”). The Credit Agreement established an initial borrowing base of $135.0 million, subject to semi-annual redeterminations based on the Administrative Agent's and the Banks' evaluation of the Company's oil and natural gas reserves. At December 31, 2008, the borrowing base was determined to be $144.85 million and was affirmed by the Banks effective June 24, 2009. Effective October 28, 2009, the borrowing base was decreased to $144.64 million in conjunction with the September 2009 sale of oil and natural gas properties. The $144.64 million borrowing base was affirmed by the Banks on December 22, 2009, effective January 1, 2010. In conjunction with the property acquisition that closed on June 29, 2010, the Credit Agreement was amended effective June 29, 2010 to increase the borrowing base to $200.0 million. The Banks re-determined the borrowing base effective December 22, 2010 to $250.0 million and subsequently reduced the borrowing base to $249.05 million effective January 14, 2011, in conjunction with the sale of properties effective January 1, 2011.

Also in conjunction with the property acquisition that closed on June 29, 2010, the Credit Agreement was amended to revise hedge requirements and restrictions and reallocate exposure under the facility between certain banks. The Company borrowed $6.0 million under the Credit Agreement on May 11, 2010 to fund the Mid-continent Arkoma property acquisition deposit and borrowed an additional $30.50 million to close the acquisition on June 29, 2010. As of March 31, 2011 and December 31, 2010, the Company had a total of $174.50 million and $175.44 million, respectively, outstanding under the Credit Agreement. All amounts outstanding under the Credit Agreement are due and payable on June 29, 2012.

Prior to June 24, 2009, outstanding advances under the Credit Agreement accrued interest payable at the Wachovia Bank Prime Rate, the Federal Funds Rate plus 1.00% or the Eurodollar rate (terms defined in the agreement), plus an applicable margin ranging from 0.00% to 1.75% based on the borrowing base usage at the time of the borrowing. On June 24, 2009, the Credit Agreement was amended to increase the applicable margin range from 1.00% to 2.75% based on the borrowing base utilization at the time of borrowing and to add the Eurodollar rate plus 1.00% to the Adjusted Base Rate definition. In addition, the Company must pay a commitment fee ranging from 0.250% to 0.375% per annum based on the unused portion of the Banks' commitment.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Unaudited Consolidated Financial Statements - continued

March 31, 2011 and 2010 and December 31, 2010

(unaudited)

The Credit Agreement also provides for the issuance of letters of credit, limited to the lesser of $25.0 million or availability under the Credit Agreement. There were no letters of credit outstanding at March 31, 2011 or December 31, 2010.

On June 29, 2007, the Company also entered into a six-year, $35.0 million Second Lien Term Loan Agreement (the “Term Loan Agreement”) with Wachovia Bank, N.A., as Administrative Agent and certain other banks as named and defined therein. The Term Loan Agreement was amended effective June 29, 2010 to change the hedge provisions to be consistent with the amendment to the Credit Agreement effective on the same date. As of March 31, 2011 and December 31, 2010 the Company had a total $32.0 million outstanding under the Term Loan Agreement. All amounts outstanding under the Term Loan Agreement are due and payable on June 29, 2013.

Outstanding advances under the Term Loan Agreement bear interest payable at the Wachovia Bank Prime Rate, the Federal Funds Rate plus 1.00% or the Eurodollar rate (terms defined in the agreement), plus a margin of 3.50%.

Aggregate amounts outstanding under the Credit Agreement and Term Loan Agreement at March 31, 2011 and December 31, 2010, were at a weighted average interest rate of approximately 2.70% and 2.71%, respectively.

The Company's borrowings under the Credit Agreement and the Term Loan Agreement are secured by the Company's oil and gas properties and are subject to various financial and non-financial covenants, including requirements and limitations related to oil and natural gas hedge transactions. Financial covenants include the maintenance of certain minimum working capital, interest coverage, debt leverage and collateral value ratios. At March 31, 2011 and December 31, 2010 the Company was in compliance with the covenants.

E - DRILLING ADVANCES

The Company periodically receives drilling advances from joint interest owners, which are applied toward the payment of drilling costs to be incurred in the future. The Company held drilling advances totaling $1,000,956 and $788,969 at March 31, 2011 and December 31, 2010, respectively, which are included in current liabilities.

F - RISK MANAGEMENT

The Company uses financial instruments to reduce its exposure to market fluctuation in the price of crude oil and gas and interest rates. The Company's general strategy is to mitigate oil and natural gas price risk with puts, costless collars and swaps and to hedge interest rate risk with swaps.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Unaudited Consolidated Financial Statements - continued

March 31, 2011 and 2010 and December 31, 2010

(unaudited)

The following table provides a balance sheet overview of the Company's derivative assets and liabilities as of March 31, 2011 and December 31, 2010:



		Fair Value of Derivative Instruments
		Asset Derivatives				Liability Derivatives
		3/31/2011		12/31/2010		3/31/2011			12/31/2010
Derivatives designated as hedging instruments:
Interest rate derivatives	$	263,091	$	339,519	$	(627,842	)	$	(825,900	)
Total derivatives designated as
hediging instruments		263,091		339,519		(627,842	)		(825,900	)
Derivatives not designated as hedging instruments:
Commodity derivatives		17,389,962		22,435,696		(7,944,467	)		(4,168,640	)
Total derivatives not designated as
hediging instruments		17,389,962		22,435,696		(7,944,467	)		(4,168,640	)
Total derivatives	$	17,653,053	$	22,775,215	$	(8,572,309	)	$	(4,994,540	)

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Unaudited Consolidated Financial Statements - continued

March 31, 2011 and 2010 and December 31, 2010

(unaudited)

The following tables detail the effect of the Company's derivative assets and liabilities in the consolidated statements of operations for the periods presented:



			Change in Value Recognized in Other Comprehensive
			Income on Derivatives (Effective Portion)
			Q1 2011			Q1 2010
Derivatives in cash flow hedging relationship
Interest rate derivatives		$	(111,374	)	$	(70,975	)
Total		$	(111,374	)	$	(70,975	)

	Location of Gain/(Loss)
	Reclassified from		Amount of Gain/(Loss) Reclassified from Accumulated Other
	AOCI into Income		Comprehensive Income ("AOCI") into Income (Effective Portion)
	(Effective Portion)		Q1 2011			Q1 2010
Derivatives in cash flow hedging relationship
Interest rate derivatives	Interest Expense	$	(233,004	)	$	(1,484,311	)
Total		$	(233,004	)	$	(1,484,311	)

	Location of Unrealized
	Gain/(Loss)		Amount of Unrealized Gain/(Loss) Recognized
	Recognized in Income		in Income on Derivatives
	on Derivatives		Q1 2011			Q1 2010
Derivatives not designated as hedging instruments:
	Unrealized gains and
	losses on commodity
	derivative financial
Commodity derivatives	instruments, net	$	(8,341,411	)	$	9,528,105
Total		$	(8,341,411	)	$	9,528,105

	Location of Realized
	Gain/(Loss)		Amount of Realized Gain/(Loss) Recognized
	Recognized in Income		in Income on Derivatives
	on Derivatives		Q1 2011			Q1 2010
Derivatives not designated as hedging instruments:
	Realized gains and
	losses on commodity
	derivative financial
Commodity derivatives	instruments, net	$	3,955,675		$	1,829,020
Total		$	3,955,675		$	1,829,020

The fair market value was based on quotes obtained from the counterparties to the derivative agreements and management estimates.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Unaudited Consolidated Financial Statements - continued

March 31, 2011 and 2010 and December 31, 2010

(unaudited)

The Company's derivative positions for crude oil and natural gas production as of March 31, 2011, are set forth in the following table for Barrels (Bbls) of oil and Million British Thermal Units (MMBtu) of natural gas. All of the natural gas positions are hedged to either the Panhandle, TX-OK Inside FERC index or the CenterPoint EGT Inside FERC index and the prices shown below represent NYMEX equivalent prices including the projected future basis.



		2011				2012				2013
		Bbls		MMBtu		Bbls		MMBtu		Bbls		MMBtu
Puts		72,000		1,320,000		—		—		—		—
Average Floor	$	55.00	$	5.60	$		$		$		$

Collars		90,000		1,470,000		144,000		3,030,000		99,000		3,540,000
Average Floor	$	81.50	$	6.18	$	72.22	$	5.05	$	74.85	$	5.15
Average Ceiling	$	112.71	$	7.93	$	104.31	$	6.39	$	104.57	$	5.79

Swaps		75,000		4,380,000		12,000		4,920,000		27,000		1,910,000
Average Fixed Price	$	61.60	$	6.04	$	81.50	$	5.93	$	81.95	$	5.78

The Company's interest rate hedges as of March 31, 2011, are set forth in the following table.



	Notional	Effective		Floating	Fixed
Swap	Amount	Date	Term	Rate	Rate

Floating for Fixed	$75,000,000	December 29, 2010	2 years	1M LIBOR	0.860%

Floating for Fixed	$50,000,000	December 29, 2010	2 years	1M LIBOR	0.860%

Floating for Fixed	$25,000,000	December 29, 2010	2 years	1M LIBOR	0.870%

The primary market risk related to the Company's commodity derivative contracts is the volatility in commodity prices. However, this market risk is offset by the gain or loss recognized upon the related physical sale of the Company's oil and natural gas.

To manage interest rate risk, in 2007 the Company entered into four different interest rate swap contracts with two major financial institutions to hedge a portion of its future variable rate interest costs. The contracts fixed the borrowing rate on portions of the floating rate debt to provide an economic hedge against rising interest rates. Two of the contracts, with notional values totaling $80.0 million at a weighted average fixed rate of 5.42%, expired as of June 29, 2010. The remaining 2007 contracts with notional values totaling $40.0 million at a fixed rate of 4.76% expired as of September 28, 2010. On August 3, 2010, the Company entered into new interest rate hedge transactions effective December 29, 2010, with a total notional value of $150.0 million at a weighted average fixed rate of 0.86%. All interest rate swap contracts have been designated as hedges for accounting purposes.

Based on interest rates in effect at March 31, 2011, approximately $618,311 is expected to reverse out of accumulated other comprehensive loss within the next twelve months.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Unaudited Consolidated Financial Statements - continued

March 31, 2011 and 2010 and December 31, 2010

(unaudited)

G - MEMBERS' EQUITY

On October 31, 2006, CCEII, NGP and certain members of the Company's executive management (“Management Subscribers”) entered into a Subscription and Contribution Agreement (“Contribution Agreement”) whereby members of CCEII committed $28.75 million in equity contributions for the issuance of 28.75 million units in CCEII. NGP committed $25.0 million with the remaining $3.75 million committed by the Management Subscribers. On May 17, 2007, the Contribution Agreement was amended to increase NGP's commitment by $145.0 million to a total new NGP commitment of $170.0 million to partially fund an acquisition of oil and natural gas assets from a former publicly traded partnership.

On June 25, 2010, the Contribution Agreement was amended to increase NGP's commitment by an additional $25.0 million to a new total NGP commitment of $195.0 million. In conjunction with closing the Mid-Continent Arkoma property acquisition, NGP contributed equity of approximately $25.33 million, including $12.50 million of the new $25.0 million commitment. The Company received the remaining $12.5 million of available equity from NGP on September 7, 2010, to fund the purchase of undeveloped oil and natural gas leases located on Cheyenne-Arapaho allotted and tribal lands in two Oklahoma counties.

At March 31, 2011 and December 31, 2010, the members had contributed a total of $196,774,992 under the Contribution Agreement, as amended, net of financing fees as described in Note I. The commitments of both the Management Subscribers and NGP have been fully funded at March 31, 2011 and December 31, 2010.

H - EQUITY COMPENSATION

The CCEII Amended and Restated Operating Agreement dated October 31, 2006, (the “Operating Agreement”) provided for the issuance of 6,155,357 Tier I Incentive Units (“Tier I Units”), of which 1,538,839 Incentive Units (“Tier I Subsequent Units”) may be granted to employees of the Company. The Operating Agreement also provided for the issuance of 2,051,786 Tier II Incentive Units (“Tier II Units”); 2,051,786 Tier III Incentive Units (“Tier III Units”); and 2,051,786 Tier IV Incentive Units (“Tier IV Units”). In each of Tier II, Tier III and Tier IV, 512,946 Incentive Units (“Tier II, III and IV Subsequent Units”) may be granted to employees of the Company. The four tiers of incentive units affect the amount of cash distributions received by unit holders in connection with any merger, sale or other transaction involving substantially all of the Company's assets, with Tier I receiving preferential payout over the remaining tiers.

Unit based compensation related to Tier I, II, III and IV Incentive Units and Subsequent Units grants is determined using an estimated value of the Company's proved oil and natural gas reserves less outstanding debt at the date of grant of such units and calculating the resulting payout, if any, to the grantee under the terms of the Operating Agreement. The compensation expense related to the units issued was immaterial.

There were no grants or forfeitures of Incentive Units during the three months ended March 31, 2011. All Tier I Incentive Units granted and outstanding at March 31, 2011, are fully vested as of March 31, 2011.

There were no grants or forfeitures of Subsequent Units during the three months ended March 31, 2011. Tier I Subsequent Units and Tier II, III and IV Subsequent Units totaling 520,939 and 291,346, respectively, remain unallocated at March 31, 2011 for grants to future employees of the Company or additional grants to current employees of the Company.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Unaudited Consolidated Financial Statements - continued

March 31, 2011 and 2010 and December 31, 2010

(unaudited)

The Tier I Units and Tier I Subsequent Units vest ratably over a three year period from the date of grant or will vest in full upon the occurrence of a Fundamental Change, as defined in the Operating Agreement. Tier II, III and IV Units and Tier II, III and IV Subsequent Units vest only upon the occurrence of the respective Tier Payout as defined in the Operating Agreement. Incentive Unit holders must forfeit all unvested Incentive Units upon termination and must forfeit all Incentive Units (vested and unvested) when the holder voluntarily terminates or is terminated with cause as defined in the Operating Agreement. The Incentive Units granted must be forfeited upon the fifth anniversary of the grant if the required Tier I, II, III and IV Payouts for the Tier I, II, III and IV Units, respectively, as defined in the Operating Agreement, have not yet occurred.

All Tier I Subsequent Units granted and outstanding at December 31, 2010 are fully vested as of December 31, 2010 except 62,500 and 10,000 Tier I Subsequent Units granted during the years ended December 31, 2010 and 2009, respectively. The weighted average remaining vesting period for the partially vested 72,500 Tier I Subsequent Units is approximately 25 months at March 31, 2011.

Pursuant to the Second Amendment to the Amended and Restated Operating Agreement effective January 1, 2009, Tier I Payout is computed as the distribution (in cash or marketable securities) to all of the Members equal to a stated dollar amount plus a compounding 10% return on any Additional Capital Contributions as defined therein. Tier II Payout is computed as the distribution (in cash or marketable securities) equal to two times NGP's capital contributions. Tier III Payout is computed as the distribution (in cash or marketable securities) equal to three times NGP's capital contributions. Tier IV Payout is computed as the distribution (in cash or marketable securities) equal to four times NGP's capital contributions.

Pursuant to the Third Amendment to the Amended and Restated Operating Agreement effective as of June 25, 2010, a Tier I Secondary Payout was defined related to the Additional Capital Contributions made in conjunction with the incremental $25.0 million NGP capital commitment and contribution made under the Second Amendment to the Contribution Agreement effective on the same date.

Any Incentive Units that have not been granted on or before the earlier of a Fundamental Change or a Tier I, II, III or IV Payout for the Tier I, II, III and IV Units, respectively, will not be included in the total Incentive Units held by the Tier I Members for purposes of allocating total Incentive Unit Payout in proportion to the total Incentive Units held by all Incentive Unit holders.

I - RELATED PARTY TRANSACTIONS

The Company pays annual fees in the amount of $30,000 to certain members of the Board of Managers who are directly affiliated with NGP, the Company's largest member. This amount is recorded in other expense in the consolidated statements of operations. The Company also pays advisory fees in the amount of $75,000 annually to NGP in addition to reimbursement of certain expenses, as provided for in the Advisory Services, Reimbursement and Indemnification Agreement. This amount is recorded in general and administrative expense in the consolidated statements of operations.

Additionally, NGP receives a financing fee equal to 1% of capital contributed, which is recorded as a reduction in the Company's total capital contributions.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Unaudited Consolidated Financial Statements - continued

March 31, 2011 and 2010 and December 31, 2010

(unaudited)

J - COMMITMENTS AND CONTINGENCIES


1.	Lease Commitments

The Company leases office space under an operating lease with a primary term expiring on January 31, 2015.

Rent expense was approximately $93,280 for the three months ended March 31, 2011 and 2010. Minimum annual lease commitments under the current office lease and other operating leases at March 31, 2011, for the following years are approximately $446,200 for the remainder of 2011; $394,200 in 2012; $377,100 in 2013 and 2014; and $31,400 in 2015. The office lease commitments are subject to annual adjustments based on the Consumer Price Index as published by the United States Bureau of Labor Statistics and annual operating cost adjustments. In conjunction with the sale of the Company (see Subsequent Events section below) the current office lease was terminated effective September 1, 2011 for an early lease termination payment of $365,000.


2.	Drilling Contracts

In September 2010, the Company entered into a two-year drilling contract, a three well drilling contract and a five well drilling contract, each committing a drilling rig for exclusive use by the Company at a stated day rate during the term of the contract. The five well contract term was completed before March 31, 2011. The minimum payments due under the remaining contracts at March 31, 2011 are approximately $5.8 million for the remainder of 2011 and $7.3 million in 2012. The Company has sufficient inventory of undeveloped acreage to keep the rigs active throughout the contracts terms and will recover a portion of the contract payments from third-party joint interest partners in the Company's operated wells drilled with the contracted rigs.


3.	Litigation

A legal suit was filed in March 2007 by two owners of surface and mineral rights in a Denton County, Texas natural gas field acquired by the Company from a former publicly traded partnership. The plaintiffs claim that the former owner did not develop the field in accordance with certain provisions of a Plan of Development that was agreed to for the purpose of protecting the value of the surface estate during natural gas development. Although the Company was never named in the lawsuit, the Plaintiffs made similar claims against the Company. The Company entered into a Settlement and Release Agreement dated April 10, 2008, with the plaintiffs to settle all claims and dismiss the lawsuit. Under the terms of the settlement, the Company was required to perform certain surface restoration projects before the end of 2009 at a total cost estimated to be approximately $265,000, net of salvage value recovered from removed equipment. The Company spent approximately $82,100 and $184,700 during the years ended December 31, 2010 and 2009, respectively, related to its obligations under the terms of the settlement. The Company expects to spend an additional $63,600 in 2011 to fully satisfy its obligations under the settlement.

On January 28, 2010, the Company filed a lawsuit against an Oklahoma oil and gas natural producer, a natural gas purchaser and an oil purchaser seeking quiet title in an oil and natural gas property located in Garfield County, Oklahoma. The defendant producer wrongfully claims an interest in the subject property, and the defendant purchasers have suspended production revenues owed to the Company. The Company sought actual and punitive damages, each in excess of $10,000. On December 13, 2010, the defendant producer filed a disclaimer wherein the producer disclaimed any right, title or interest in or to the subject property. The Company has received all production revenues from the oil and natural gas purchasers.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Unaudited Consolidated Financial Statements - continued

March 31, 2011 and 2010 and December 31, 2010

(unaudited)

On January 10, 2011, a lawsuit was filed against the Company and another party by the trustee of a liquidation trust claiming the Company and the other party owed the trust for certain unbilled lease acquisition costs. Legal counsel was hired to represent the Company and the case was recently dismissed pursuant to the filing of a joint stipulation. The parties agreed to allow the plaintiff to re-file the action in a proper venue. The action was re-filed and the Company has filed its answer. Another party to the lawsuit has filed their answer and has made a counter claim against the Company. Although, discovery in the lawsuit is ongoing, the Company does not believe it owes any money to the plaintiff and will vigorously defend that position.

On February 28, 2011, the Company was named as a Fourth Party Defendant in an action to quiet title to a certain interest in an oil and gas lease. The Company has hired legal counsel and filed a Special Entry of Appearance in the case. The Company does not plan to actively defend the lawsuit because the Company's investigation reveals that should the Fourth Party Plaintiff prevail, the Company would benefit from such outcome. The Company plans to file a motion to be dropped from the litigation.

On March 13, 2011, the Company received correspondence from an attorney representing a subcontractor placing the Company on notice that a lien claim for approximately $20,000 has been filed. The lien relates to nonpayment of invoices for labor and materials furnished by the subcontractor to a construction company. The construction company was hired by the Company to build drilling locations and the Company had paid the construction company in full for all work performed. The construction company had made additional payments to the subcontractor in an attempt to settle the liens. Until the Company in notified that the liens have been released, it will vigorously defend these claims.

K - DEFINED CONTRIBUTION PLAN

Effective January 1, 2010, the Company sponsors a safe harbor 401(k) defined contribution plan for the benefit of all employees who have completed three consecutive months of service. The plan allows eligible employees to make tax-deferred contributions up to 100% of their annual compensation, not to exceed annual limits established by the Internal Revenue Service. The Company makes safe harbor matching contributions of up to 4% of an employee's compensation and may make additional discretionary contributions for eligible employees. Employees are 100% vested in the Company's safe harbor matching contribution upon receipt. The Company's contributions to the plan were $27,861 and $20,316 during the three months ended March 31, 2011 and 2010, respectively. In conjunction with the sale of the Company discussed below, the 401(k) plan was terminated effective May 2, 2011. Distributions to participants and final wind-down of the plan will occur over the next several months.

L - SUBSEQUENT EVENTS

On May 3, 2011, the Company was acquired by Eagle Rock Energy Partners, L.P. (“EROC”) for total consideration of approximately $529.5 million, which consisted of (i) cash of $15.0 million, (ii) 28,753,174 EROC common units valued at $10.50 per unit (the ceiling price of an agreed upon collar) and (iii) the assumption of the Company's outstanding indebtedness of approximately $212.6 million.

Consolidated Financial Statements and Report of

Independent Certified Public Accountants

CC ENERGY II L.L.C. AND SUBSIDIARIES

December 31, 2010 and 2009

Report of Independent Certified Public Accountants

Board of Managers

CC Energy II L.L.C.

We have audited the accompanying consolidated balance sheets of CC Energy II L.L.C. (a

Delaware limited liability company) and subsidiaries as of December 31, 2010 and 2009, and the

related consolidated statements of operations, changes in members’ equity, and cash flows for

each of the three years in the period ended December 31, 2010. These financial statements are

the responsibility of the Company’s management. Our responsibility is to express an opinion

on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the

United States of America established by the American Institute of Certified Public

Accountants. Those standards require that we plan and perform the audit to obtain reasonable

assurance about whether the financial statements are free of material misstatement. An audit

includes consideration of internal control over financial reporting as a basis for designing audit

procedures that are appropriate in the circumstances, but not for the purpose of expressing an

opinion on the effectiveness of the Company’s internal control over financial reporting.

Accordingly, we express no such opinion. An audit also includes examining, on a test basis,

evidence supporting the amounts and disclosures in the financial statements, assessing the

accounting principles used and significant estimates made by management, as well as evaluating

the overall financial statement presentation. We believe that our audits provide a reasonable

basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all

material respects, the financial position of CC Energy II L.L.C. and subsidiaries as of December

31, 2010 and 2009, and the results of their operations and their cash flows for each of the three

years in the period ended December 31, 2010 in conformity with accounting principles

generally accepted in the United States of America.

/s/ GRANT THORNTON, LLP

Tulsa, Oklahoma

March 31, 2011

CC ENERGY II L.L.C. AND SUBSIDIARIES

Consolidated Balance Sheets

December 31, 2010 and 2009



		2010			2009
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	6,245,361		$	1,647,050
Accounts receivable-
Oil and natural gas sales		12,526,309			9,116,691
Joint operations and other, net		2,244,023			1,775,195
Prepaid well costs		2,791,642			1,433,711
Prepaid expenses and other current assets		2,743,911			1,848,888
Gas balancing receivable		1,103,607			—
Derivative financial instruments		15,382,726			10,045,139
Total current assets		43,037,579			25,866,674

PROPERTY AND EQUIPMENT, at cost:
Oil and natural gas properties, full cost method		601,547,602			455,909,414
Other		545,292			376,267
		602,092,894			456,285,681
Less- accumulated depreciation, depletion and amortization		259,696,598			240,519,821
Total property and equipment		342,396,296			215,765,860

PRODUCTION TAX REFUND RECEIVABLE		449,523			—

DEFERRED FINANCING COSTS, net of accumulated amortization		997,648			793,683

DERIVATIVE FINANCIAL INSTRUMENTS		7,392,489			4,701,145

Total assets	$	394,273,535		$	247,127,362

LIABILITIES AND MEMBERS' EQUITY

CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	18,332,680		$	5,240,361
Revenue and royalties due others		13,616,421			9,717,812
Derivative financial instruments		3,671,767			5,176,825
Drilling advances from partners		788,969			384,749
Gas balancing liability		219,083			—
Total current liabilities		36,628,920			20,519,747

GAS BALANCING LIABILITY		1,440,106			917,952

LONG-TERM DEBT		207,444,780			168,144,780

ASSET RETIREMENT OBLIGATIONS		7,200,847			3,910,383

DERIVATIVE FINANCIAL INSTRUMENTS		1,322,773			2,303,073

COMMITMENTS AND CONTINGENCIES (Note J)

Total liabilities		254,037,426			195,795,935

MEMBERS' EQUITY:
Members' equity interest		140,722,490			54,678,308
Accumulated other comprehensive loss		(486,381	)		(3,346,881	)
		140,236,109			51,331,427

Total liabilities and members' equity	$	394,273,535		$	247,127,362

The accompanying notes are an integral part of these consolidated financial statements.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Consolidated Statements of Operations

For the Years Ended December 31, 2010, 2009 and 2008



		2010			2009			2008

REVENUES:
Oil and natural gas sales	$	67,532,027		$	40,227,400		$	91,759,997

COSTS AND EXPENSES:
Lease operating and workover		6,528,709			6,375,847			8,494,666
Severance and ad valorem taxes		3,043,930			2,325,965			6,375,487
General and administrative		4,242,561			3,867,458			3,602,697
Depreciation, depletion and amortization		19,198,377			17,571,083			26,721,902
Reduction of carrying value of oil and natural
gas properties		—			58,462,020			126,359,509

OPERATING INCOME (LOSS)		34,518,450			(48,374,973	)		(79,794,264	)

NON-OPERATING INCOME (EXPENSE):
Professional services fees and other income		81,750			61,671			53,951
Realized gains and losses on commodity derivative
financial instruments, net		15,697,292			28,733,689			(847,118	)
Unrealized gains and losses on commodity derivative
financial instruments, net		8,296,390			(24,063,203	)		30,580,799
Interest expense		(9,564,240	)		(10,575,678	)		(9,829,036	)
Interest income		26,102			25,526			158,339
Successful acquisition expenses		(341,652	)		—			—
Unsuccessful acquisition expenses		(13,474	)		(472,674	)		—
Other expenses		(105,919	)		(83,754	)		(89,386	)

NET INCOME (LOSS)	$	48,594,699		$	(54,749,396	)	$	(59,766,715	)

The accompanying notes are an integral part of these consolidated financial statements.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Consolidated Statements of Changes in Members’ Equity

For the Years Ended December 31, 2010, 2009 and 2008



						Accumulated
						Other
	Equity					Comprehensive
	Units		Amount			Loss			Total

BALANCE, December 31, 2007	160,897,239	$	169,194,419		$	(4,119,089	)	$	165,075,330

Comprehensive loss:
Net loss	—		(59,766,715	)		—			(59,766,715	)
Reclassifications of derivative
settlements to net income	—		—			2,046,501			2,046,501
Current period change in fair
value of derivative
instruments used for
hedging purposes	—		—			(5,216,917	)		(5,216,917	)
Total comprehensive loss									(62,937,131	)

BALANCE, December 31, 2008	160,897,239	$	109,427,704		$	(7,289,505	)	$	102,138,199

Comprehensive loss:
Net loss	—		(54,749,396	)		—			(54,749,396	)
Reclassifications of derivative
settlements to net income	—		—			5,247,081			5,247,081
Current period change in fair
value of derivative
instruments used for
hedging purposes	—		—			(1,304,457	)		(1,304,457	)
Total comprehensive loss									(50,806,772	)

BALANCE, December 31, 2009	160,897,239	$	54,678,308		$	(3,346,881	)	$	51,331,427

Capital contributions	37,827,761		37,449,483			—			37,449,483

Comprehensive income:
Net income	—		48,594,699			—			48,594,699
Reclassifications of derivative
settlements to net income	—		—			3,405,181			3,405,181
Current period change in fair
value of derivative
instruments used for
hedging purposes	—		—			(544,681	)		(544,681	)
Total comprehensive income									51,455,199

BALANCE, December 31, 2010	198,725,000	$	140,722,490		$	(486,381	)	$	140,236,109

The accompanying notes are an integral part of these consolidated financial statements.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Consolidated Statements of Cash Flows

For Years Ended December 31, 2010, 2009 and 2008



		2010			2009			2008

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	48,594,699		$	(54,749,396	)	$	(59,766,715	)
Adjustments to reconcile net income (loss) to cash provided
by operating activities-
Depreciation, depletion and amortization		19,198,377			17,571,083			26,721,902
Reduction of carrying value of oil and natural gas properties		—			58,462,020			126,359,509
Amortization of deferred financing costs included in interest expense		469,357			335,361			335,390
Accretion of asset retirement obligation included in general and
administrative expense		259,301			177,044			178,382
Unrealized losses (gains) on commodity derivative financial instruments, net		(8,296,390	)		24,063,203			(30,580,799	)
Decrease in gas imbalance		—			—			(3,671	)
Changes in assets and liabilities-
Accounts receivable		(5,431,576	)		3,112,175			2,012,687
Prepaid expenses and other current assets		(2,252,954	)		(2,229,975	)		(699,122	)
Commodity derivative financial instruments		642,600			(267,000	)		911,700
Accounts payable and accrued liabilities		2,425,523			(9,668,780	)		1,548,636
Revenue and royalties due others		3,898,609			447,097			1,000,991
Drilling advances received from partners		404,220			(214,053	)		596,593
Net cash provided by operating activities		59,911,766			37,038,779			68,615,483

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures-
Acquisitions of oil and natural gas properties		(80,217,103	)		(6,334,981	)		(2,741,832	)
Drilling activities		(53,130,668	)		(37,479,120	)		(72,457,723	)
Purchase of other property and equipment		(190,626	)		(35,616	)		(161,907	)
Encore post-closing payment		—			—			(4,849,772	)
Proceeds from the sale of oil and natural gas properties and other assets		2,148,781			672,852			989,173
Net cash used in investing activities		(131,389,616	)		(43,176,865	)		(79,222,061	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Capital contributions, net of financing fee		37,449,483			—			—
Advances on lines of credit		54,000,000			14,000,000			12,500,000
Repayment of lines of credit		(14,700,000	)		(6,205,220	)		(5,150,000	)
Deferred financing costs		(673,322	)		(50,000	)		(50,000	)
Net cash provided by financing activities		76,076,161			7,744,780			7,300,000

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		4,598,311			1,606,694			(3,306,578	)

CASH AND CASH EQUIVALENTS, beginning of period		1,647,050			40,356			3,346,934

CASH AND CASH EQUIVALENTS, end of period	$	6,245,361		$	1,647,050		$	40,356

NON-CASH INVESTING AND FINANCING INFORMATION:

Accrued capital expenditures	$	13,343,544			1,935,511		$	11,615,947
Asset retirement obligations incurred	$	3,117,574		$	483,389		$	706,503
Asset retirement obligations on property dispositions	$	86,411		$	596,874		$	817,713

SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of $553,674, $66,681 and $550,788 capitalized	$	9,390,860		$	10,088,373		$	9,535,031

The accompanying notes are an integral part of these consolidated financial statements.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2010 and 2009

A - ORGANIZATION AND OPERATIONS

CC Energy II L.L.C. (“CCEII”), a Delaware limited liability company, was formed on June 7, 2006, by four

managing members, who currently serve as officers, for the purpose of acquiring, developing, producing,

exploring for and selling gas, crude oil and related hydrocarbon products. On October 31, 2006, the Operating

Agreement of CCEII and the Limited Liability Company Agreements of each of its two subsidiaries were

amended and restated to add Natural Gas Partners VIII, L.P. (“NGP”) as a managing member and primary

capital provider. Under the terms of the Operating Agreement, CCEII will be dissolved no later than

December 31, 2016 unless the Operating Agreement is amended before that date to extend the time period.

CCEII is the sole member of Crow Creek Energy II L.L.C. and Crow Creek Operating Company II L.L.C., its

wholly-owned subsidiaries. CCEII conducts business through its wholly-owned subsidiaries and sells natural gas and crude oil and related products to domestic pipelines and other markets primarily in the Mid-Continent region of the United States.

B - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

1. Principles of Consolidation

The consolidated financial statements include the accounts of CCEII and its two wholly-owned subsidiaries

(collectively, the “Company”). All significant intercompany accounts and transactions have been eliminated in

consolidation.

2. Cash and Cash Equivalents

The Company considers all investments purchased with initial maturities of three months or less to be cash

equivalents. Cash equivalents consist primarily of investments in highly liquid securities. The carrying amounts

of cash and cash equivalents reported in the balance sheets approximate their fair values.

The Company’s cash balances at December 31, 2010 are insured by the Federal Deposit Insurance Corporation

(“FDIC”) up to $250,000 per financial institution. At times, cash balances may be in excess of the FDIC

insurance limit. The Company had cash balances on deposit with one bank at December 31, 2010 which

exceeded the balance insured by the FDIC.

3. Oil and Natural Gas Properties

The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method,

all acquisition, exploration and development costs, including certain related employee costs, incurred for the

purpose of finding oil and natural gas are capitalized. Such amounts include the cost of drilling and equipping

productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities.

Costs, including related employee costs, associated with production and general corporate activities are expensed in the period incurred. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Consolidated Financial Statements - continued

December 31, 2010 and 2009

development costs and estimated future dismantlement, restoration and abandonment costs, net of estimated

salvage values. DD&A per equivalent Mcf of the Company’s oil and natural gas properties was $1.56, $1.90 and $2.62 for the years ended December 31, 2010, 2009 and 2008, respectively.

The Company excludes the costs directly associated with acquisition and evaluation of unproved properties from the DD&A calculation until it is determined whether or not proved reserves can be assigned to the properties. These properties are assessed at least annually to ascertain whether impairment has occurred. Such costs are transferred into the amortization base on an ongoing basis as projects are evaluated and proved reserves established or impairment determined. The Company excluded approximately $19,201,000, $1,691,000 and $1,997,000 related to undeveloped and unproved properties from the amortization base as of December 31, 2010, 2009 and 2008, respectively. The majority of the unproved properties excluded from the amortization base at December 31, 2010, 2009 and 2008 consist of costs incurred for oil and natural gas leases, plus capitalized interest, associated with probable reserves.

The Company capitalizes interest, if debt is outstanding, on expenditures for significant development projects

until such projects are ready for their intended use. During the years ended December 31, 2010, 2009 and 2008,

the Company had $553,674, $66,681 and $550,788, respectively, of capitalized interest related to the allocated

cost of acquired probable and possible reserves and other undeveloped prospect costs.

The Company’s unamortized costs of oil and natural gas properties are limited to the sum of the future net

revenues attributable to proved oil and natural gas reserves using unescalated prices determined under Security

Exchange Commission (“SEC”) rules, discounted at 10%, plus the lower of cost or fair value of any unproved

properties, as adjusted for related income tax effects (the “Full Cost Ceiling”). If the Company’s unamortized

costs of oil and natural gas properties exceed the Full Cost Ceiling, a provision for additional DD&A is required. The Company’s capitalized costs were not in excess of the Full Cost Ceiling at December 31, 2010.

At December 31, 2009, the Company’s capitalized costs were in excess of the Full Cost Ceiling by $58,462,020

which has been recorded in the consolidated statement of operations for the year then ended as a non-cash

reduction of carrying value of oil and natural gas properties and in the balance sheets as additional accumulated

DD&A. Application of the new SEC pricing rules, discussed at note B.4, resulted in the use of lower prices at

December 31, 2009 for both oil and natural gas than would have resulted under the previous rules. The reduction of carrying value results entirely from low crude oil and natural gas prices during 2009 and is not the result of a decrease in the quantity of the Company’s oil and natural gas reserves.

At December 31, 2008, the Company’s capitalized costs were in excess of the Full Cost Ceiling by $126,359,509, which has been recorded in the consolidated statement of operations for the year ended December 31, 2008 as a non-cash reduction of carrying value of oil and natural gas properties and in the December 31, 2008 balance sheet as additional accumulated DD&A. The reduction of carrying value results entirely from low crude oil and natural gas prices at December 31, 2008 and is not the result of a decrease in the quantity of the Company’s oil and natural gas reserves.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Consolidated Financial Statements - continued

December 31, 2010 and 2009

4. Reserve Estimation

In January 2010, the Financial Accounting Standards Board issued an update to the Oil and Gas topic, which

aligns the oil and natural gas reserve estimation and disclosure requirements with the requirements in the SEC’s

final rule, Modernization of the Oil and Gas Reporting Requirements (the “Final Rule”). The Final Rule permits the use of new technologies to determine proved reserves estimates if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volume estimates. The Final Rule will also allow inclusion of oil and natural gas extracted from nontraditional sources in reserve estimates. In addition, the new disclosure requirements require companies to report proved oil and natural gas reserves using an average price based upon the prior 12-month period rather than a year-end price.

The Final Rule changes the full cost accounting method by requiring the denominator used in the units-of production amortization method to conform to the proved reserves determined under the Final Rule. The Final

Rule also requires the full cost ceiling to be computed using the same pricing requirements (12-month average

price) that are used in determining reserve quantities.

The Company adopted the Final Rule effective December 31, 2009. The Company’s 2009 DD&A and

impairment calculations were based upon proved reserves that were determined using the new reserve rules,

whereas DD&A and impairment calculations prior to 2009 were based on the prior methodology. Adoption of

the Final Rule resulted in a decrease in DD&A expense of approximately $1,224,000 in 2009. The adoption of

the Final Rule also resulted in the Company’s $58,462,020 reduction of carrying value of oil and natural gas

properties at December 31, 2009. Without adopting the Final Rule effective December 31, 2009, there would be

no reduction of carrying value at December 31, 2009.

5. Other Property and Equipment

Other property and equipment consists of office furniture, fixtures and equipment, computer hardware and

software, leasehold improvements and Company owned vehicles. Depreciation of other property and equipment

is provided using the straight-line method based on estimated useful lives ranging from three to ten years.

Other property and equipment consists of the following, recorded at cost, as of December 31 2010 and 2009:



		2010			2009

Computer equipment and software	$	150,852		$	82,153
Office equipment, furniture and fixtures		154,860			137,686
Vehicles		188,881			105,729
Office leasehold improvements		50,699			50,699
		545,292			376,267
Less accumulated depreciation and amortization		(276,384	)		(180,695	)
Net other property and equipment	$	268,908		$	195,572

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Consolidated Financial Statements - continued

December 31, 2010 and 2009

6. Deferred Financing Costs

Deferred financing costs consist of capitalized amounts for up-front facility fees, professional fees and other

expenses related to the credit facilities described in Note D. Deferred financing costs of $997,648, net of

$1,314,529 accumulated amortization, have been recorded at December 31, 2010 and will be amortized over the

remaining term of the credit agreements using the effective interest method. Deferred financing costs at

December 31, 2009 were $793,683, net of $845,173 accumulated amortization. Amortization of deferred

financing costs is included in interest expense in the consolidated statements of operations. Amortization

charged to interest expense over the remaining terms of the credit agreements is expected to be approximately

$638,000 in 2011; $331,000 in 2012; and $28,648 in 2013.

7. Revenue Recognition

Oil and natural gas revenues are recorded using the sales method. Under this method, the Company recognizes

revenues based on actual volumes of oil and natural gas sold to purchasers. The Company and other joint

interest owners may sell more or less than their entitlement share of the oil and natural gas volumes produced. A

liability is recorded and revenue is deferred if the Company’s excess sales of oil and natural gas volumes exceed its estimated remaining recoverable reserves. Certain properties acquired in 2007 and 2010 by the Company had natural gas imbalances from natural gas sold prior to the effective date of the Company’s acquisition of those properties in excess of estimated remaining recoverable reserves. The total recorded current and non-current liability attributable to the acquired interest in those wells was $1,659,189 at December 31, 2010 and $917,952 at December 31, 2009 and 2008. Four of the wells acquired in 2010 with gas balancing liabilities were plugged as of December 2010, or will be plugged in 2011. The Company expects to settle the imbalances on these four wells in 2011 and $219,083 has been recorded as a current liability at December 31, 2010.

The Company acquired an interest in two plugged wells in 2010 with a total under produced gas imbalance of

approximately 441,000 Mcf. The Company expects to receive settlement for the imbalances in 2011 and has

recorded a current gas balancing receivable of $1,103,607 at December 31, 2010.

8. Accounts Receivable

The Company sells oil and natural gas to various customers and participates with other parties in the drilling,

completion and operation of oil and natural gas wells. Joint interest and oil and natural gas sales receivables

related to these operations are generally unsecured. Accounts receivable for joint interest billings are recorded as amounts billed to joint interest owners less an allowance for doubtful accounts. Amounts are considered past

due after 30 days. The Company determines joint interest operations accounts receivable allowances based on

management’s assessment of the creditworthiness of the joint interest owners and the Company’s ability to

realize the receivables through netting of anticipated future production revenues and other collection actions.

The Company recorded an allowance for doubtful accounts at December 31, 2010 and 2009 of $115,848 and the related bad debt expense was included in general and administrative expenses in the consolidated statement of operations for the year ended December 31, 2009. The Company did not record an allowance at December 31, 2008.

The Company has drilled multiple wells during the past several years in Oklahoma and Texas that qualify for

certain production and severance tax exemptions and reduced tax rates. These tax incentives are realized through reduced rates on current production or the receipt of refunds for taxes previously paid. During the year

ended December 31, 2010, the Company received Oklahoma production tax refunds attributable to its interest

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Consolidated Financial Statements - continued

December 31, 2010 and 2009

in qualifying wells totaling $550,113 for taxes previously paid on production through June 30, 2009. The Company expects additional Oklahoma production tax refunds totaling $897,143 to be paid to the Company for taxes previously paid on production from July 1, 2009 through December 31, 2010. Subsequent to December 31, 2010, the Company received Oklahoma production tax refunds of $108,341 and Texas severance tax refunds of $98,193 related to the Company's interest in qualifying wells.

At December 31, 2010, the Company has recorded a current and non-current receivable for production and

severance tax refunds attributable to the Company’s interest in qualifying wells of $545,813 and $449,523,

respectively. The current portion is included as a current asset in accounts receivable - joint operations and

other, net in the consolidated balance sheets. During the year ended December 31, 2010, severance and ad

valorem taxes have been reduced by $1,639,886 for production tax refunds received and receivable in the

consolidated statements of operations. The Company did not record a receivable for production tax refunds at

December 31, 2009.

9. General and Administrative Expense

The Company receives fees from third parties for operation of jointly owned oil and natural gas properties and

records such reimbursements as reductions of general and administrative expense. Such fees totaled

approximately $629,200, $558,200 and $644,000 for the years ended December 31, 2010, 2009 and 2008,

respectively.

10. Derivative Financial Instruments

Accounting and reporting standards require that every derivative instrument (including certain derivative

instruments embedded in other contracts) be recorded as either an asset or liability measured at its fair value.

Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of operations. Companies must formally document, designate and assess the effectiveness of transactions that receive hedge accounting.

expense when the related swap transactions are settled. Interest expense has increased by $3,405,181, $5,247,081 and $2,046,501 related to the settlement of interest rate swaps for the years ended December 31, 2010, 2009 and 2008, respectively. For the years ended December 31, 2010 and 2009, the hedge ineffectiveness on the Company’s interest rate swaps was determined to be immaterial.

As of December 31, 2010, 2009 and 2008, and for the years then ended, all of the Company’s interest rate swaps outstanding were designated as hedges for financial statement purposes. None of the Company’s commodity derivatives at December 31, 2010, 2009 or 2008, or during the years then ended were accounted for as hedges for financial statement purposes.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Consolidated Financial Statements - continued

December 31, 2010 and 2009

11. Income Taxes

The Company is a limited liability company. No provision for income taxes is included in the consolidated

financial statements of the Company. Income taxes, if any, for the Company are generally payable by the

individual members of the Company.

The Company evaluates uncertain tax positions for recognition and measurement in the financial statements. To

recognize a tax position, the Company determines whether it is more likely than not that the tax positions will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical

merits of the position. A tax position that meets the more likely than not threshold is measured to determine the

amount of benefit to be recognized in the financial statements. The amount of tax benefit recognized with

respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of

being realized upon settlement. The Company had no uncertain tax positions that required recognition in the

financial statements at December 31, 2010, 2009 and 2008. Any interest or penalties would be recognized as a

component of income tax expense. Open tax years are considered to be 2007 through 2010.

12. Unit-Based Compensation

The cost of employee services received in exchange for equity instruments is measured based on the grant-date

fair value of those instruments. That cost is recognized over the requisite service period (often the vesting

period). Generally, no compensation cost is recognized for equity instruments that do not vest.

13. Concentration of Credit Risk

The Company’s oil and natural gas production is sold to a variety of purchasers, including intrastate and

interstate pipelines or their marketing affiliates and independent marketing companies. The Company’s joint

operations accounts receivable are from a large number of oil and gas companies, partnerships, individuals and

others who own interests in the properties operated by the Company. Management believes that any credit risk

imposed by a concentration in the oil and natural gas industry is offset by the creditworthiness of the Company’s customer base.

The Company had three customers whose purchases accounted for 24%, 15% and 11% of total revenues for the

year ended December 31, 2010. At December 31, 2010, four customers comprised a total of 15%, 11%, 12%

and 15% of the oil and natural gas receivable balance.

The Company had four customers whose purchases accounted for 25%, 17%, 10% and 9% of total revenues for

the year ended December 31, 2009. At December 31, 2009, these four customers comprised a total of 16%,

23%, 8% and 6% of the oil and natural gas receivable balance.

The Company had three customers whose purchases accounted for 24%, 15% and 13% of total revenues for the

year ended December 31, 2008. At December 31, 2008, these three customers comprised a total of 14%, 24%

and 9% of the oil and natural gas receivable balance.

The Company had significant derivative assets at December 31, 2010. Inherent in any such contract is the risk of loss as a result of nonperformance by the Company’s counterparties. Although the Company does not obtain

collateral or otherwise secure the fair value of its derivative instruments, management believes the associated

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Consolidated Financial Statements - continued

December 31, 2010 and 2009

credit risk is mitigated by creditworthiness of the counterparties. At December 31, 2010, the Company had four

counterparties with gross derivative assets of $10,980,298, $5,020,477, $4,508,191 and $1,970,157.

14. Environmental

The Company is subject to extensive federal, state and local environmental laws and regulations. These laws,

which are often changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable.

consultant, the Oklahoma Corporation Commission and the landowner. Both the Company and landowner

engaged legal counsel to settle the issue. At the landowner’s request, the Company has not performed any

remediation work on the spill area. On March 24, 2009, the Company received a letter from the landowner’s

attorney claiming damages related to the spill of approximately $92,000 for remediation and reclamation costs,

consulting fees, and legal fees plus an undetermined amount for alleged damage to the landowner’s livestock. On May 22, 2009 the landowner filed a lawsuit claiming damages in excess of $50,000 related to the spill. Following discovery in the case, mediation was held on August 23, 2010. As a result of the mediation, an agreement was signed to settle all claims under the lawsuit for a payment to the landowner in the amount of $70,000. The settlement payment was covered by the Company’s insurance, subject to a $10,000 deductible. The lawsuit was dismissed on November 5, 2010.

On May 22, 2009, the landowner involved in the acid spill lawsuit filed a separate lawsuit against the Company

claiming total damages of less than $10,000 for unpaid water usage and livestock damage while drilling a well in Grady County, Oklahoma. Under a Release and Settlement Agreement dated July 8, 2009 the Company settled the claims and the lawsuit was dismissed on September 3, 2009.

15. Asset Retirement Obligations

Accounting standards require that the fair value of a liability for an asset retirement obligation be recognized in

the period in which it is incurred if a reasonable estimate of fair value can be made and that the associated asset

retirement costs be part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost

included in the carrying amount of the related long-lived asset is charged to expense through the depreciation of

the asset. Changes in the liability due to passage of time are recognized as accretion expense in the consolidated

statements of operations and a corresponding increase in the carrying amount of the liability. The Company

recognizes asset retirement obligations for its oil and natural gas working interests associated with the retirement of long-lived assets that result from the acquisition and development of the assets. Such obligations consist of future costs, net of recoverable salvage value of tangible equipment, to plug and abandoned oil and natural gas wells when the wells permanently cease production.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Consolidated Financial Statements - continued

December 31, 2010 and 2009

The activity for the years ended December 31, 2010, 2009 and 2008 are as follows:



		2010			2009			2008

Asset retirement obligations, beginning of period	$	3,910,383		$	3,846,824		$	3,779,652
Liabilities incurred - acquired wells		2,859,431			105,057			—
Liabilities incurred - drilled wells		258,143			378,332			706,503
Accretion expense		259,301			177,044			178,382
Disposition of wells		(86,411	)		(596,874	)		(817,713	)
Asset retirement obligations, end of period	$	7,200,847		$	3,910,383		$	3,846,824

16. Fair Value of Financial Instruments

The carrying amounts reported in the balance sheet for cash, accounts receivable, and accounts payable

approximate their fair values. The recorded values of the Company’s credit facilities approximate fair value as

the interest rate is variable and is repriced at a minimum of quarterly.

The Company accounts for its oil and natural gas commodity derivatives and interest rate swaps at fair value.

The fair value of derivative financial instruments is determined utilizing pricing models for similar instruments.

The models use a variety of techniques to arrive at fair value, including quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward curves generated from a compilation of data

gathered from third parties.

The Company has categorized its financial instruments, based on the priority of inputs to the valuation

technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted

prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs

(Level 3).

Financial assets and liabilities recorded in the consolidated balance sheets are categorized based on the inputs to

the valuation techniques as follows:

Level 1 - Financial assets and liabilities for which values are based on unadjusted quoted prices for identical

assets or liabilities in an active market that management has the ability to access.

Level 2 - Financial assets and liabilities for which values are based on quoted prices in markets that are not

active or model inputs that are observable either directly or indirectly for substantially the full term of

the asset or liability.

reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability.

When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment,

the level within which the fair value measurement is categorized is based on the lowest level input that is

significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Consolidated Financial Statements - continued

December 31, 2010 and 2009

classifications on an annual basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities.

The following presents the Company’s fair value hierarchy for assets and liabilities measured at fair value on a

recurring basis at December 31, 2010 and 2009. These items are included in “derivative financial instruments” in the consolidated balance sheets.



		December 31, 2010
		Level 1		Level 2		Level 3

Assets:
Commodity derivatives	$	—	$	22,435,696	$	—
Interest rate swaps	$	—	$	339,519	$	—

Liabilities:
Commodity derivatives	$	—	$	4,168,640	$	—
Interest rate swaps	$	—	$	825,900	$	—

		December 31, 2009

Assets:
Commodity derivatives	$	—	$	14,746,284	$	—

Liabilities:
Commodity derivatives	$	—	$	4,133,017	$	—
Interest rate swaps	$	—	$	3,346,881	$	—

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are reported at fair value on a nonrecurring basis in the Company’s consolidated

balance sheets. The following methods and assumptions were used to estimate the fair values:

Impairments of Long-Lived Assets – The Company reviews its long-lived assets to be held and used, including oil and natural gas properties, whenever events or circumstances indicate that carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of expected discounted future net cash flows is less than the carrying amount of the assets. In this circumstance, the Company recognized an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset. The Company reviews its oil and natural gas properties included in the full cost pool or by individual well for those wells not constituting part of the full cost pool. If the total amortization base of the full cost pool is determined to be impaired, an impairment loss equal to the difference between the carrying value of the full cost pool and the estimated fair value (discounted future cash flows) of the properties would be recognized at that time.

Estimating future cash flows involves the use of judgments, including estimation of the proved oil and natural

gas reserves quantities, timing of development and production, capital expenditures and production cost.

Estimating future cash flows for purposes of impairment loss recognition also involves future commodity price

assumptions determined by the SEC.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Consolidated Financial Statements - continued

December 31, 2010 and 2009

Asset Retirement Obligations – The Company estimates the fair value of the asset retirement obligation (“ARO”) based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. See Note B.15 for a summary of changes in AROs.



				Significant
		Quoted Prices in		Other		Significant
		Active Markets for		Observable		Unobservable		Total
		Identical Assets		Inputs		Inputs		Impairment
		(Level 1)		(Level 2)		(Level 3)		Loss

Year Ended December 31, 2010:
Impairment of long-lived assets	$	—	$	—	$	475,537,701	$	—
Asset retirement obligations incurred
in current period		—		—		3,117,574		—
Year ended December 31, 2009:
Impairment of long-lived assets	$	—	$	—	$	214,123,519	$	58,462,020
Asset retirement obligations incurred
in current period		—		—		483,389		—

17. Use of Estimates in the Preparation of Financial Statements

C - ACQUISITIONS AND DISPOSITION

During the year ended December 31, 2008, the Company sold one outside operated Texas property and 34

operated Oklahoma properties for net proceeds totaling approximately $617,000, in addition to undeveloped

leasehold and mineral acreage located primarily in Oklahoma, Texas and Arkansas for proceeds totaling

approximately $372,000.

On October 8, 2008, the Company signed a Trade Agreement with a public oil and gas company wherein the

Company agreed to exchange its interest in deep rights in certain leasehold acreage located in Hughes County,

Oklahoma for interests in certain undeveloped leasehold acreage located in Grady, Garvin and McClain counties, also located in Oklahoma. There was no cash consideration in the exchange transaction.

In a September 2009 auction, the Company sold 21 operated and 62 outside-operated marginal properties located in Oklahoma and 3 outside-operated marginal properties located in Texas for aggregate net proceeds of

approximately $647,800. The effective date of the sale was October 1, 2009.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Consolidated Financial Statements - continued

December 31, 2010 and 2009

In November 2009, the Company purchased additional interests in 5 Oklahoma properties for a purchase price

of $3.08 million, subject to customary purchase price adjustments. The acquisition was funded by an advance on the revolving credit facility. The Company owned the additional interests effective October 1, 2009 and took

over operations of the properties effective November 16, 2009.

On November 6, 2009, the Company submitted a bid for the acquisition of the stock of a reorganized bankrupt

oil and gas company. The Company’s bid was valued in excess of $248.5 million and was qualified under the

bankruptcy court-approved bid procedures with the Company’s deposit of $7.0 million into an earnest money

escrow account. An auction was held on November 13, 2009 among all qualified bidders, and the Company was

not the successful bidder. The successful bidder closed the acquisition before the end of 2009, and the Company

has no further obligations related to its unsuccessful bid. The $7.0 million deposit was returned to the Company

on December 24, 2009. The Company incurred costs of approximately $466,100 related to this acquisition

attempt which is recorded in unsuccessful acquisition expenses in the consolidated statement of operations for

the year ended December 31, 2009.

On May 11, 2010, the Company entered into a purchase and sale agreement to acquire certain Mid-Continent

Arkoma assets located in Arkansas from a group of partnerships affiliated with a private entity for a purchase

price of $60.0 million, subject to customary adjustments. The Company made a deposit of $6.0 million upon

signing the purchase and sale agreement. The transaction closed successfully on June 29, 2010 with an effective

date of May 1, 2010. The acquisition was funded with a combination of debt and equity and included working

interests in approximately 200 operated and non-operated natural gas properties and overriding royalty interests

in approximately 125 additional natural gas properties. The Company assumed operations of approximately 100

of the acquired properties on June 29, 2010. The net income related to the acquired properties, including

accrued revenue and expenses, from and after the effective date through the closing date, has been recorded as a

reduction of the purchase price. Revenues and expenses from the acquired properties were recorded in the

Company’s consolidated statement of operations effective July 1, 2010. On December 16, 2010 the Company

received payment from the seller of $787,798 for final post-closing adjustments, which has been included in oil

and gas properties.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Consolidated Financial Statements - continued

December 31, 2010 and 2009

The following table represents the allocation of the total purchase price of the Mid-Continent Arkoma

acquisition to the acquired assets and liabilities assumed. The allocation represents the fair value assigned to each of the assets acquired and liabilities assumed:



		Mid-Continent
		Arkoma
		Acquisition
Fair value of net assets:
Proved oil and natural gas properties	$	56,247,004
Unproved oil and natural gas properties		3,619,414
Gas balancing receivable		1,103,607
Total assets acquired		60,970,025
Revenue and royalties due to others		(1,024,400	)
Gas balancing liability		(741,237	)
Asset retirement obligations		(2,805,940	)
Other liabilities assumed		(92,170	)
Total liabilities assumed		(4,663,747	)
Total cash consideration	$	56,306,278

The Company participated in an auction held by the Bureau of Indian Affairs on August 31 and September 1,

2010, and was the successful bidder on multiple undeveloped oil and gas leases located on Cheyenne-Arapaho

allotted and tribal lands in two Oklahoma counties. The total purchase price of approximately $12.8 million was

funded with available cash and equity.

Effective November 4, 2010, the Company sold undeveloped leasehold in several sections of Ellis County,

Oklahoma for sales proceeds totaling approximately $2.0 million.

Effective January 1, 2011, the Company sold its interests in two outside-operated Oklahoma properties at an

auction for net sales proceeds totaling approximately $2.7 million. Although the auction was held in December

2010, the sale did not close until after December 31, 2010. The effective date of the sale was January 1, 2011.

The Company did not receive the proceeds until January 14, 2011. Accordingly, the sale has not been recorded

in the financial statements at December 31, 2010.

D - DEBT

Long-term debt consisted of the following as of December 31, 2010 and 2009:



		2010		2009

Revolving credit facility	$	175,444,780	$	136,144,780
Term loan		32,000,000		32,000,000
Total debt		207,444,780		168,144,780
Less: current portion		—		—
Total long-term debt	$	207,444,780	$	168,144,780

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Consolidated Financial Statements - continued

December 31, 2010 and 2009

At December 31, 2010, the Company had a $250.0 million revolving credit facility in place under a Credit

Agreement dated June 29, 2007, as amended, entered into between the Company and Wachovia Bank, N.A. as

Administrative Agent and certain other banks as named and defined therein (the “Banks”). The Credit

Agreement established an initial borrowing base of $135.0 million, subject to semi-annual redeterminations based

on the Administrative Agent’s and the Banks’ evaluation of the Company’s oil and natural gas reserves. At

December 31, 2008, the borrowing base was determined to be $144.85 million and was affirmed by the Banks

effective June 24, 2009. Effective October 28, 2009, the borrowing base was decreased to $144.64 million in

conjunction with the September 2009 sale of oil and natural gas properties. The $144.64 million borrowing base

was affirmed by the Banks on December 22, 2009, effective January 1, 2010. In conjunction with the property

acquisition that closed on June 29, 2010, the Credit Agreement was amended effective June 29, 2010 to increase

the borrowing base to $200.0 million. The Banks re-determined the borrowing base effective December 22,

2010 to $250.0 million and subsequently reduced the borrowing base to $249.05 million effective January 14,

2011, in conjunction with the sale of properties effective January 1, 2011.

Also in conjunction with the property acquisition that closed on June 29, 2010, the Credit Agreement was

amended to revise hedge requirements and restrictions and reallocate exposure under the facility between certain

banks. The Company borrowed $6.0 million under the Credit Agreement on May 11, 2010 to fund the Midcontinent

Arkoma property acquisition deposit and borrowed an additional $30.50 million to close the

acquisition on June 29, 2010. As of December 31, 2010 and 2009, the Company had a total of $175.44 million

and $136.14 million, respectively, outstanding under the Credit Agreement. All amounts outstanding under the

Credit Agreement are due and payable on June 29, 2012.

Prior to June 24, 2009, outstanding advances under the Credit Agreement accrued interest payable at the

Wachovia Bank Prime Rate, the Federal Funds Rate plus 1.00% or the Eurodollar rate (terms defined in the

agreement), plus an applicable margin ranging from 0.00% to 1.75% based on the borrowing base usage at the

time of the borrowing. On June 24, 2009, the Credit Agreement was amended to increase the applicable margin

range from 1.00% to 2.75% based on the borrowing base utilization at the time of borrowing and to add the

Eurodollar rate plus 1.00% to the Adjusted Base Rate definition. In addition, the Company must pay a

commitment fee ranging from 0.250% to 0.375% per annum based on the unused portion of the Banks’

commitment.

The Credit Agreement also provides for the issuance of letters of credit, limited to the lesser of $25.0 million or

availability under the Credit Agreement. There were no letters of credit outstanding at December 31, 2010 or

2009.

On June 29, 2007, the Company also entered into a six-year, $35.0 million Second Lien Term Loan Agreement

(the “Term Loan Agreement”) with Wachovia Bank, N.A., as Administrative Agent and certain other banks as

named and defined therein. The Term Loan Agreement was amended effective June 29, 2010 to change the

hedge provisions to be consistent with the amendment to the Credit Agreement effective on the same date. As

of December 31, 2010 and 2009, the Company had a total $32.0 million outstanding under the Term Loan

Agreement. All amounts outstanding under the Term Loan Agreement are due and payable on June 29, 2013.

Outstanding advances under the Term Loan Agreement bear interest payable at the Wachovia Bank Prime Rate,

the Federal Funds Rate plus 1.00% or the Eurodollar rate (terms defined in the agreement), plus a margin of

3.50%.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Consolidated Financial Statements - continued

December 31, 2010 and 2009

Aggregate amounts outstanding under the Credit Agreement and Term Loan Agreement at December 31, 2010

and 2009, were at a weighted average interest rate of approximately 2.71% and 3.10%, respectively.

The Company’s borrowings under the Credit Agreement and the Term Loan Agreement are secured by the

Company’s oil and gas properties and are subject to various financial and non-financial covenants, including

requirements and limitations related to oil and natural gas hedge transactions. Financial covenants include the

maintenance of certain minimum working capital, interest coverage, debt leverage and collateral value ratios. At

December 31, 2010 and 2009, the Company was in compliance with the covenants.

Scheduled maturities of long-term debt as of December 31, 2010, were as follows:



Year Ending		Principal Amount

December 31, 2011	$	—
December 31, 2012		175,444,780
December 31, 2013		32,000,000
December 31, 2014		—
December 31, 2015		—
	$	207,444,780

E - DRILLING ADVANCES

The Company periodically receives drilling advances from joint interest owners, which are applied toward the

payment of drilling costs to be incurred in the future. The Company held drilling advances totaling $788,969 and

$384,749 at December 31, 2010 and 2009, respectively, which are included in current liabilities.

F - RISK MANAGEMENT

The Company uses financial instruments to reduce its exposure to market fluctuation in the price of crude oil and

gas and interest rates. The Company’s general strategy is to mitigate oil and natural gas price risk with puts,

costless collars and swaps and to hedge interest rate risk with swaps.

The following table provides a balance sheet overview of the Company’s derivative assets and liabilities as of

December 31, 2010 and 2009:



		Fair Value of Derivative Instruments
		Asset Derivatives				Liability Derivatives
		2010		2009		2010			2009
Derivatives designated as hedging instruments:
Interest rate derivatives	$	339,519	$	—	$	(825,900	)	$	(3,346,881	)
Total derivatives designated as
hedging instruments		339,519		—		(825,900	)		(3,346,881	)

Derivatives not designated as hedging instruments:
Commodity derivatives		22,435,696		14,746,284		(4,168,640	)		(4,133,017	)
Total derivatives not designated as
hedging instruments		22,435,696		14,746,284		(4,168,640	)		(4,133,017	)

Total derivatives	$	22,775,215	$	14,746,284	$	(4,994,540	)	$	(7,479,898	)

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Consolidated Financial Statements - continued

December 31, 2010 and 2009

The following tables detail the effect of the Company’s derivative assets and liabilities in the consolidated

statements of operations for the periods presented:



			Change in Value Recognized in Other Comprehensive
			Income on Derivatives (Effective Portion)
			2010			2009			2008
Derivatives in cash flow hedging relationship
Interest rate derivatives		$	(544,681	)	$	(1,304,457	)	$	(5,216,917	)
Total		$	(544,681	)	$	(1,304,457	)	$	(5,216,917	)

	Location of Gain/(Loss)
	Reclassified from		Amount of Gain/(Loss) Reclassified from Accumulated Other
	AOCI into Income		Comprehensive Income ("AOCI") into Income (Effective Portion)
	(Effective Portion)		2010			2009			2008
Derivatives in cash flow hedging relationship
Interest rate derivatives	Interest Expense	$	(3,405,181	)	$	(5,247,081	)	$	(2,046,501	)
Total		$	(3,405,181	)	$	(5,247,081	)	$	(2,046,501	)

	Location of Unrealized
	Gain/(Loss)		Amount of Unrealized Gain/(Loss) Recognized
	Recognized in Income		in Income on Derivatives
	on Derivatives		2010			2009			2008
Derivatives not designated as hedging instruments:
	Unrealized gains and
	losses on commodity
	derivative financial
Commodity derivatives	instruments, net	$	8,296,390		$	(24,063,203	)	$	30,580,799
Total		$	8,296,390		$	(24,063,203	)	$	30,580,799

	Location of Realized
	Gain/(Loss)		Amount of Realized Gain/(Loss) Recognized
	Recognized in Income		in Income on Derivatives
	on Derivatives		2010			2009			2008
Derivatives not designated as hedging instruments:
	Realized gains and
	losses on commodity
	derivative financial
Commodity derivatives	instruments, net	$	15,697,292		$	28,733,689		$	(847,118	)
Total		$	15,697,292		$	28,733,689		$	(847,118	)

The fair market value was based on quotes obtained from the counterparties to the derivative agreements and

management estimates.

The Company’s derivative positions for crude oil and natural gas production as of December 31, 2010, are set

forth in the following table for Barrels (Bbls) of oil and Million British Thermal Units (MMBtu) of natural gas.

All of the natural gas positions are hedged to either the Panhandle, TX-OK Inside FERC index or the

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Consolidated Financial Statements - continued

December 31, 2010 and 2009

CenterPoint EGT Inside FERC index and the prices shown below represent NYMEX equivalent prices

including the projected future basis.



		2011					2012					2013
		Bbls			MMBtu		Bbls			MMBtu		Bbls		MMBtu
Puts		96,000			1,860,000		—			—		—		—
Average Floor	$	55.00		$	5.70	$	—		$	—	$	—	$	—

Collars		36,000			1,980,000		144,000			2,070,000		63,000		2,100,000
Average Floor	$	87.50		$	6.32	$	72.22		$	5.45	$	71.91	$	5.46
Average Ceiling	$	129.13		$	8.06	$	104.31		$	6.70	$	102.61	$	5.86

Swaps		90,000			4,440,000		12,000			4,920,000		27,000		1,910,000
Average Fixed Price	$	$	61.55	$	6.61	$	$	81.50	$	5.95	$	81.95	$	5.82

The Company’s interest rate hedges as of December 31, 2010, are set forth in the following table.



	Notional	Effective		Floating	Fixed
Swap	Amount	Date	Term	Rate	Rate

Floating for Fixed	$75,000,000	December 29, 2010	2 years	1M LIBOR	0.860%

Floating for Fixed	$50,000,000	December 29, 2010	2 years	1M LIBOR	0.860%

Floating for Fixed	$25,000,000	December 29, 2010	2 years	1M LIBOR	0.870%

The primary market risk related to the Company’s commodity derivative contracts is the volatility in commodity

prices. However, this market risk is offset by the gain or loss recognized upon the related physical sale of the

Company’s oil and natural gas.

To manage interest rate risk, in 2007 the Company entered into four different interest rate swap contracts with

two major financial institutions to hedge a portion of its future variable rate interest costs. The contracts fixed

the borrowing rate on portions of the floating rate debt to provide an economic hedge against rising interest

rates. Two of the contracts, with notional values totaling $80.0 million at a weighted average fixed rate of 5.42%,

expired as of June 29, 2010. The remaining 2007 contracts with notional values totaling $40.0 million at a fixed

rate of 4.76% expired as of September 28, 2010. On August 3, 2010, the Company entered into new interest rate

hedge transactions effective December 29, 2010, with a total notional value of $150.0 million at a weighted

average fixed rate of 0.86%. All interest rate swap contracts have been designated as hedges for accounting

purposes.

Based on interest rates in effect at December 31, 2010, approximately $757,787 is expected to reverse out of

accumulated other comprehensive loss within the next twelve months.

G - MEMBERS’ EQUITY

On October 31, 2006, CCEII, NGP and certain members of the Company’s executive management

(“Management Subscribers”) entered into a Subscription and Contribution Agreement (“Contribution

Agreement”) whereby members of CCEII committed $28.75 million in equity contributions for the issuance of

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Consolidated Financial Statements - continued

December 31, 2010 and 2009

28.75 million units in CCEII. NGP committed $25.0 million with the remaining $3.75 million committed by the

Management Subscribers. On May 17, 2007, the Contribution Agreement was amended to increase NGP’s

commitment by $145.0 million to a total new NGP commitment of $170.0 million to partially fund an acquisition

of oil and natural gas assets from a former publicly traded partnership.

On June 25, 2010, the Contribution Agreement was amended to increase NGP’s commitment by an additional

$25.0 million to a new total NGP commitment of $195.0 million. In conjunction with closing the Mid-continent

Arkoma property acquisition, NGP contributed equity of approximately $25.33 million, including $12.50 million

of the new $25.0 million commitment. The Company received the remaining $12.5 million of available equity

from NGP on September 7, 2010, to fund the purchase of undeveloped oil and natural gas leases located on

Cheyenne-Arapaho allotted and tribal lands in two Oklahoma counties.

At December 31, 2010, the members had contributed a total of $196,774,992 and at December 31, 2009, the

members had contributed $159,325,509 under the Contribution Agreement, as amended, net of financing fees as

described in Note I. The commitments of both the Management Subscribers and NGP have been fully funded at

December 31, 2010. The commitments of the Management Subscribers were also fully funded at December 31,

2009.

H - EQUITY COMPENSATION

The CCEII Amended and Restated Operating Agreement dated October 31, 2006, (the “Operating Agreement”)

provided for the issuance of 6,155,357 Tier I Incentive Units (“Tier I Units”), of which 1,538,839 Incentive Units

(“Tier I Subsequent Units”) may be granted to employees of the Company. The Operating Agreement also

provided for the issuance of 2,051,786 Tier II Incentive Units (“Tier II Units”); 2,051,786 Tier III Incentive

Units (“Tier III Units”); and 2,051,786 Tier IV Incentive Units (“Tier IV Units”). In each of Tier II, Tier III and

Tier IV, 512,946 Incentive Units (“Tier II, III and IV Subsequent Units”) may be granted to employees of the

Company. The four tiers of incentive units affect the amount of cash distributions received by unit holders in

connection with any merger, sale or other transaction involving substantially all of the Company’s assets, with

Tier I receiving preferential payout over the remaining tiers.

Unit based compensation related to Tier I, II, III and IV Incentive Units and Subsequent Units grants is

determined using an estimated value of the Company’s proved oil and natural gas reserves less outstanding debt

at the date of grant of such units and calculating the resulting payout, if any, to the grantee under the terms of the

Operating Agreement. The compensation expense related to the units issued was immaterial.

The following table sets forth the grants and forfeitures of Incentive Units during the years ended December 31,

2010:



	Incentive Units
	Tier I	Tier II	Tier III	Tier IV	Total
Outstanding at December 31, 2009	4,616,518	1,538,840	1,538,840	1,538,840	9,233,038
Granted	—	—	—	—	—
Vested	—	—	—	—	—
Forfeited	—	—	—	—	—
Outstanding at December 31, 2010	4,616,518	1,538,840	1,538,840	1,538,840	9,233,038

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Consolidated Financial Statements - continued

December 31, 2010 and 2009

All Tier I Incentive Units granted and outstanding at December 31, 2010, are fully vested as of December 31,

2010.

The following table sets forth grants and forfeitures of Subsequent Units during the years ended December 31,

2010:



	Subsequent Units
	Tier I		Tier II		Tier III		Tier IV		Total
Outstanding at December 31, 2009	1,055,400		292,100		292,100		292,100		1,931,700
Granted	72,500		5,500		5,500		5,500		89,000
Vested	—		—		—		—		—
Forfeited	(110,000	)	(76,000	)	(76,000	)	(76,000	)	(338,000	)
Outstanding at December 31, 2010	1,017,900		221,600		221,600		221,600		1,682,700

Tier I Subsequent Units and Tier II, III and IV Subsequent Units totaling 520,939 and 291,346, respectively,

remain unallocated at December 31, 2010 for grants to future employees of the Company or additional grants to

current employees of the Company.

The Tier I Units and Tier I Subsequent Units vest ratably over a three year period from the date of grant or will

vest in full upon the occurrence of a Fundamental Change, as defined in the Operating Agreement. Tier II, III

and IV Units and Tier II, III and IV Subsequent Units vest only upon the occurrence of the respective Tier

Payout as defined in the Operating Agreement. Incentive Unit holders must forfeit all unvested Incentive Units

upon termination and must forfeit all Incentive Units (vested and unvested) when the holder voluntarily

terminates or is terminated with cause as defined in the Operating Agreement. The Incentive Units granted must

be forfeited upon the fifth anniversary of the grant if the required Tier I, II, III and IV Payouts for the Tier I, II,

III and IV Units, respectively, as defined in the Operating Agreement, have not yet occurred.

All Tier I Subsequent Units granted and outstanding at December 31, 2010 are fully vested as of December 31,

2010 except 62,500 and 10,000 Tier I Subsequent Units granted during the years ended December 31, 2010 and

2009, respectively. The weighted average remaining vesting period for the partially vested 72,500 Tier I

Subsequent Units is approximately 28 months.

Pursuant to the Second Amendment to the Amended and Restated Operating Agreement effective January 1,

2009, Tier I Payout is computed as the distribution (in cash or marketable securities) to all of the Members equal

to a stated dollar amount plus a compounding 10% return on any Additional Capital Contributions as defined

therein. Tier II Payout is computed as the distribution (in cash or marketable securities) equal to two times

NGP’s capital contributions. Tier III Payout is computed as the distribution (in cash or marketable securities)

equal to three times NGP’s capital contributions. Tier IV Payout is computed as the distribution (in cash or

marketable securities) equal to four times NGP’s capital contributions.

Pursuant to the Third Amendment to the Amended and Restated Operating Agreement effective as of June 25,

2010, a Tier I Secondary Payout was defined related to the Additional Capital Contributions made in conjunction

with the incremental $25.0 million NGP capital commitment and contribution made under the Second

Amendment to the Contribution Agreement effective on the same date.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Consolidated Financial Statements - continued

December 31, 2010 and 2009

Any Incentive Units that have not been granted on or before the earlier of a Fundamental Change or a Tier I, II,

III or IV Payout for the Tier I, II, III and IV Units, respectively, will not be included in the total Incentive Units

held by the Tier I Members for purposes of allocating total Incentive Unit Payout in proportion to the total

Incentive Units held by all Incentive Unit holders.

I - RELATED PARTY TRANSACTIONS

The Company pays annual fees in the amount of $30,000 to certain members of the Board of Managers who are

directly affiliated with NGP, the Company’s largest member. This amount is recorded in other expense in the

consolidated statements of operations. The Company also pays advisory fees in the amount of $75,000 annually

to NGP in addition to reimbursement of certain expenses, as provided for in the Advisory Services,

Reimbursement and Indemnification Agreement. This amount is recorded in general and administrative expense

in the consolidated statements of operations.

Additionally, NGP receives a financing fee equal to 1% of capital contributed, which is recorded as a reduction in

the Company’s total capital contributions.

J - COMMITMENTS AND CONTINGENCIES

1. Lease Commitments

The Company leases office space under an operating lease with a primary term expiring on January 31, 2015.

Rent expense was approximately $373,900, $370,300 and $317,500 for the years ended December 31, 2010, 2009

and 2008, respectively. Minimum annual lease commitments under the current office lease and other operating

leases at December 31, 2010, for the following years are approximately $577,000 in 2011; $394,000 in 2012;

$377,000 in 2013 and 2014; and $31,000 in 2015. The office lease commitments are subject to annual

adjustments based on the Consumer Price Index as published by the United States Bureau of Labor Statistics and

annual operating cost adjustments.

2. Drilling Contracts

The Company assumed payment obligations under two long-term drilling contracts in conjunction with the

acquisition of oil and natural gas assets from a former publicly traded partnership in 2007. Each of the drilling

contracts commits one drilling rig for exclusive use by the Company at a stated day rate. One rig contract, with

a primary term that expired in June 2009, was temporarily extended with a reduced day rate until the rig was

permanently released on July 8, 2009. The second rig contract expired in November 2009. The Company kept

both of the contracted rigs active drilling its inventory of undeveloped acreage until the contracts expired.

In September 2010, the Company entered into a new two-year drilling contract, a three well drilling contract and

a five well drilling contract, each committing a drilling rig for exclusive use by the Company at a stated day rate

during the term of the contract. The minimum payments due under the contracts at December 31, 2010 are

approximately $10.4 million in 2011 and $7.3 million in 2012. The Company has sufficient inventory of

undeveloped acreage to keep the rigs active throughout the contracts terms and will recover a portion of the

contract payments from third-party joint interest partners in the Company’s operated wells drilled with the

contracted rigs.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Consolidated Financial Statements - continued

December 31, 2010 and 2009

3. Litigation

A legal suit was filed in March 2007 by two owners of surface and mineral rights in a Denton County, Texas

natural gas field acquired by the Company from a former publicly traded partnership. The plaintiffs claim that

the former owner did not develop the field in accordance with certain provisions of a Plan of Development that

was agreed to for the purpose of protecting the value of the surface estate during natural gas development.

Although the Company was never named in the lawsuit, the Plaintiffs made similar claims against the Company.

The Company entered into a Settlement and Release Agreement dated April 10, 2008, with the plaintiffs to settle

all claims and dismiss the lawsuit. Under the terms of the settlement, the Company was required to perform

certain surface restoration projects before the end of 2009 at a total cost estimated to be approximately $265,000,

net of salvage value recovered from removed equipment. The Company spent approximately $82,100 and

$184,700 during the years ended December 31, 2010 and 2009, respectively, related to its obligations under the

terms of the settlement. The Company expects to spend an additional $63,600 in 2011 to fully satisfy its

obligations under the settlement.

A legal suit was filed against the Company on November 7, 2008, alleging that the Company improperly operated

two wells located in Woodward County, Oklahoma after releasing the underlying leases because the wells did not

produce for an extended period of time. On January 15, 2009, the Company signed a Settlement Agreement with

the plaintiff in the suit. Under the terms of the settlement, the Company transferred operations of the wells to

the plaintiff, agreed to pay the plaintiff $140,000 for the cost to plug the wells (offset by the salvage value of the

equipment located on the leases), and assigned the leasehold rights outside the wellbore of a nearby producing

well. The estimate of the equipment salvage value exceeded the plugging costs by approximately $20,000, and

the plaintiff has refused to pay the excess as required under the terms of the settlement. On February 27, 2009,

the Company filed a counterclaim against the plaintiff in the original lawsuit for breach of the Settlement

Agreement, and on March 13, 2009, the Company filed a motion to enforce the Settlement Agreement. On

March 30, 2009, the plaintiff filed a response to the Company’s March 13, 2009 motion. Under a Settlement

Agreement dated July 1, 2009, the Company paid plaintiff approximately $38,000 to settle all claims. The lawsuit

was dismissed on July 22, 2009.

In December 2007, the Company experienced a casing failure during drilling operations of a well in Caddo

County, Oklahoma and incurred additional drilling costs to re-drill the well back to the point of the casing failure.

The casing failure was caused by defective steel. No lawsuit was filed, and under the terms of a Settlement and

Release Agreement dated March 23, 2009 between the Company, the steel manufacturer and other parties

involved, the Company received a payment of $3.0 million on May 8, 2009 for reimbursement of the additional

drilling costs incurred as a result of the failed casing. The receipt of the settlement payment and reduction of oil

and natural gas properties were recorded in the period ended December 31, 2009. The Company’s working

interest share of the settlement payment was approximately $2.3 million.

On January 28, 2010, the Company filed a lawsuit against an Oklahoma oil and gas natural producer, a natural gas

purchaser and an oil purchaser seeking quiet title in an oil and natural gas property located in Garfield County,

Oklahoma. The defendant producer wrongfully claims an interest in the subject property, and the defendant

purchasers have suspended production revenues owed to the Company. The Company sought actual and

punitive damages, each in excess of $10,000. On December 13, 2010, the defendant producer filed a disclaimer

wherein the producer disclaimed any right, title or interest in or to the subject property. The Company has

received all production revenues from the oil and natural gas purchasers.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Consolidated Financial Statements - continued

December 31, 2010 and 2009

On January 10, 2011, a lawsuit was filed against the Company and another party by the trustee of a liquidation

trust claiming the Company and the other party owed the trust for certain unbilled lease acquisition costs. Legal

counsel was hired to represent the Company and the case was recently dismissed pursuant to the filing of a joint

stipulation. The parties have agreed to allow the plaintiff to re-file the action in a proper venue. The Company

does not believe it owes any money to the plaintiff and will vigorously defend that position when, and if, the case

is re-filed.

On February 28, 2011, the Company was named as a Fourth Party Defendant in an action to quiet title to a

certain interest in an oil and gas lease. The Company has hired legal counsel and filed a Special Entry of

Appearance in the case. The Company does not plan to actively defend the lawsuit because the Company’s

investigation reveals that should the Fourth Party Plaintiff prevail, the Company would benefit from such

outcome.

On March 13, 2011, the Company received correspondence from an attorney representing a subcontractor

placing the Company on notice that a lien claim for approximately $20,000 has been filed. The lien relates to

nonpayment of invoices for labor and materials furnished by the subcontractor to a construction company. The

construction company was hired by the Company to build drilling locations and the Company had paid the

construction company in full for all work performed. The Company plans to vigorously defend these claims.

K - DEFINED CONTRIBUTION PLAN

Effective January 1, 2010, the Company sponsors a safe harbor 401(k) defined contribution plan for the benefit

of all employees who have completed three consecutive months of service. The plan allows eligible employees to

make tax-deferred contributions up to 100% of their annual compensation, not to exceed annual limits

established by the Internal Revenue Service. The Company makes safe harbor matching contributions of up to

4% of an employee’s compensation and may make additional discretionary contributions for eligible employees.

Employees are 100% vested in the Company’s safe harbor matching contribution upon receipt. The Company’s

contributions to the plan were $107,281 during the year ended December 31, 2010.

L - SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION (UNAUDITED)

Proved Oil and Natural Gas Reserves

The proved reserves of oil and natural gas of the Company have been prepared by the Company’s engineering

staff. In accordance with SEC regulations, reserves at December 31, 2010 and 2009 were estimated using the

average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month

price for each month. Reserves for all prior years were estimated using year-end prices in accordance with SEC

regulations in effect for those prior time periods.

The process of estimating quantities of proved oil and natural gas reserves is inherently complex and requires

significant subjective decisions in the evaluation of the available geological, engineering and economic data for

each reservoir. The data for a given reservoir may change substantially over time as a result of numerous factors

including, but not limited to, additional development activity, evolving production history and changing

operating and market conditions. As a result, revisions to existing reserve estimates will occur from time to time.

Although reasonable effort is made to ensure the reported reserve estimates represent the most accurate

assessments possible, the subjective decisions and variances in available data makes these estimates generally less

precise than other estimates included in the preparation of these financial statements and the notes thereto.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Consolidated Financial Statements - continued

December 31, 2010 and 2009

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the

future rates of production and timing of development expenditures. Reserve data represent management’s

estimates only and should not be construed as being exact. Moreover, the Standardized Measure of Oil and Gas

should not be construed as the current market value of the proved oil and natural gas reserves or the costs that

would be incurred to obtain equivalent reserves. A market value determination would consider many additional

factors including (a) anticipated future changes in crude oil and natural gas prices, production and development

costs; (b) an allowance for return on investment; (c) the value of additional reserves, not currently considered

proved, that may be recovered as a result of further exploration and development activities; and (d) other

business risks.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Consolidated Financial Statements - continued

December 31, 2010 and 2009

An analysis of the change in estimated quantities of proved oil and natural gas reserves, all of which are located in

the United States, is shown below:



	Oil (MBbls)		Gas (MMcf)
Proved reserves, January 1, 2008	2,966		142,252
Extensions, discoveries and other additions	758		60,639
Purchases and exchange of minerals in place	1,157		21,597
Production	(285	)	(8,474	)
Sales and exchange of minerals in place	(9	)	(5,407	)
Revision of previous estimates	(158	)	(11,423	)
Proved reserves, December 31, 2008	4,429		199,184

Proved developed reserves - producing, December 31, 2008	2,098		90,932
Proved developed reserves - not producing, December 31, 2008	547		16,399
Proved undeveloped reserves, December 31, 2008	1,784		91,853

	Oil (MBbls)		Gas (MMcf)
Proved reserves, January 1, 2009	4,429		199,184
Extensions, discoveries and other additions	66		5,164
Purchases of minerals in place	53		2,561
Production	(230	)	(7,811	)
Sales of minerals in place	(24	)	(754	)
Revision of previous estimates	311		(39,174	)
Proved reserves, December 31, 2009	4,605		159,170

Proved developed reserves - producing, December 31, 2009	2,192		91,975
Proved developed reserves - not producing, December 31, 2009	1,553		28,491
Proved undeveloped reserves, December 31, 2009	860		38,704

	Oil (MBbls)		Gas (MMcf)
Proved reserves, January 1, 2010	4,605		159,170
Extensions, discoveries and other additions	687		65,653
Purchases and exchange of minerals in place	786		179,110
Production	(294	)	(10,440	)
Sales of minerals in place	(35	)	(289	)
Revision of previous estimates	293		26,631
Proved reserves, December 31, 2010	6,042		419,835

Proved developed reserves - producing, December 31, 2010	2,862		152,229
Proved developed reserves - not producing, December 31, 2010	702		21,813
Proved undeveloped reserves, December 31, 2010	2,478		245,793

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Consolidated Financial Statements - continued

December 31, 2010 and 2009

The following table shows the total amount of capitalized costs related to oil and natural gas producing activities

and the total amount of related accumulated DD&A at December 31, 2010, 2009 and 2008:



		December 31,			December 31,			December 31,
($ in thousands)		2010			2009			2008
Evaluated Properties	$	575,761		$	450,663		$	407,217
Unevaluated Properties - excluded from depletion		19,201			1,691			1,997
Asset retirement cost		6,586			3,555			3,668
Gross oil and gas properties		601,548			455,909			412,882
Accumulated depreciation, depletion and amortization		(74,599	)		(55,518	)		(38,035	)
Reduction of carrying value of oil and gas properties		(184,821	)		(184,821	)		(126,360	)
Net oil and gas properties	$	342,128		$	215,570		$	248,487

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

Costs incurred in property acquisition, exploration and development activities were as follows for the years ended

December 31, 2010, 2009 and 2008:



($ in thousands)		2010		2009		2008
Property acquisition costs, proved	$	62,685	$	5,007	$	2,102
Property acquisition costs, unproved		17,532		1,328		640
Exploration and extension well costs		—		—		—
Development costs		53,131		37,479		72,458
Total costs	$	133,348	$	43,814	$	75,200

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas

Reserves

The following information has been developed utilizing authoritative guidance procedures and is based on oil

and natural gas reserves estimated by the Company’s reserve engineering staff. The information can be used for

some comparisons but should not be the only method used to evaluate the Company or its performance.

Further, the information in the following table may not represent realistic assessments of future cash flows, nor

should the Standardized Measure of Discounted Future Net Cash Flow be viewed as representative of the

current value of the Company.

The Company believes that the following factors should be taken into consideration when reviewing the

following information:

- future costs and selling prices will probably differ from those required to be used in these calculations;

- due to future market conditions and government regulations, actual rates of production in future years

may vary significantly from the rate of production assumed in the calculations; and

- a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future

net oil and natural gas revenues.

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Consolidated Financial Statements - continued

December 31, 2010 and 2009

Under the Standardized Measure calculations, future cash inflows were estimated by applying year-end oil and

natural gas prices to the estimated future production of year-end proved reserves and deducting estimated

development and production costs. The resulting cash flows are reduced to present value amounts by applying a

10% discount factor. There are no future income tax expenses because the Company is not subject to federal or

state income taxes. Although the Company is subject annually to franchise taxes in certain states, the amounts of

such franchise taxes are not material.

The Standardized Measure as of December 31, 2010, 2009 and 2008 is set forth in the table below:



($ in thousands)		2010			2009			2008
Future estimated revenues	$	2,371,497		$	831,073		$	1,259,669
Future estimated production costs		(484,368	)		(219,232	)		(321,541	)
Future estimated development costs		(391,115	)		(84,385	)		(218,642	)
Future net cash flows before income taxes	$	1,496,014		$	527,456		$	719,486
Future income tax benefit		—			—			—
Future net cash flows before 10% discount	$	1,496,014		$	527,456		$	719,486
10% annual discount for estimated timing of cash flows		(1,039,678	)		(315,023	)		(474,474	)
Standardized measure of discounted future net cash flows	$	456,336		$	212,433		$	245,012

Representative NYMEX prices, end of period:
Natural gas (MMBtu)	$	4.38		$	3.87		$	5.91
Oil (Bbl)	$	79.82		$	61.14		$	44.61

CC ENERGY II L.L.C. AND SUBSIDIARIES

Notes to Consolidated Financial Statements - continued

December 31, 2010 and 2009

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and

Gas Reserves

The following is a summary of the changes in the Standardized Measure of discounted future net cash flows for

the Company’s proved oil and natural gas reserves for the years ended December 31, 2010, 2009 and 2008:



		2010			2009			2008
($ in thousands)
Beginning of year	$	212,433		$	245,012		$	321,483
Sale of oil and gas produced, net of production costs		(57,959	)		(31,525	)		(76,890	)
Net changes in prices and production costs		62,313			(81,733	)		(119,032	)
Extensions, discoveries and other additions, less related
costs		46,083			1,271			23,565
Previously estimated development costs incurred during
the period		41,654			36,880			45,069
Net changes in future development costs		(20,444	)		12,226			(4,039	)
Revisions of previous quantity estimates		40,555			2,869			17,152
Purchases of minerals in place		110,760			3,905			8,629
Sales of minerals in place		(211	)		(1,303	)		(2,224	)
Accretion of discount		21,152			24,831			31,299
Net changes in income taxes		—			—			—
Other
End of year	$	456,336		$	212,433		$	245,012

Results of Operations

The following table sets forth the results of operations for the Company’s oil and natural gas producing activities

for the years ended December 31, 2010, 2009 and 2008:



		2010		2009			2008
($ in thousands)
Revenues, excluding commodity hedge gains and losses	$	67,532	$	40,227		$	91,760
Costs and expenses:
Production costs, including severance and
ad valorem tax		9,573		8,702			14,870
General and administrative		4,243		3,867			3,603
Depreciation, depletion, and amortization		19,081		17,483			26,639
Reduction of carrying value of oil and natural
gas properties		—		58,462			126,360
Total costs and expenses		32,897		88,514			171,472
Results of operations	$	34,635	$	(48,287	)	$	(79,712	)

M - SUBSEQUENT EVENTS

The Company has evaluated subsequent events through March 31, 2011, which is the date these financial

statements were available to be issued.

EAGLE ROCK ENERGY PARTNERS L P - FORM 8-K/A - EX-99.1 - EXHIBIT 99.1 CROW CREEK FINANCIAL STATEMENTS - May 17, 2011

Attached files

EAGLE ROCK ENERGY PARTNERS L P Reports