Exhibit 99.4

Report of Independent Auditors

The Board of Directors and Members of

Eagle Energy Company of Oklahoma, LLC

We have audited the accompanying consolidated balance sheets of Eagle Energy Company of Oklahoma, LLC as of December 31, 2011 and 2010, and the related consolidated statements of income, changes in members’ equity, and cash flows for the years ended December 31, 2011, and 2010, and the period from December 11, 2009 (Inception) to December 31, 2009. 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. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no 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, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Eagle Energy Company of Oklahoma, LLC at December 31, 2011 and

2010, and the consolidated results of its operations and its cash flows for the years ended December 31,

2011, and 2010, and the period from December 11, 2009 (Inception) to December 31, 2009, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

April 13, 2012

 

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Eagle Energy Company of Oklahoma, LLC

Consolidated Balance Sheets

 

		December 31
		2011				2010
		(In Thousands)
Assets
Cash		$	9,986			$	3,675
Accounts receivable			20,052				13,674
Derivative assets, net			6,435				3,163
Prepaid expenses and other current assets			778				818
Total current assets			37,251				21,330
Properties and equipment, net—successful efforts method			205,198				140,347
Noncurrent derivative assets, net			28				2,643
Other noncurrent assets			3,960				2,115
Total assets		$	246,437			$	166,435
Liabilities and members’ equity
Current liabilities:
Accounts payable and accrued liabilities			21,717				8,235
Total current liabilities			21,717				8,235
Long-term debt			114,000				86,500
Asset retirement obligations			1,545				780
Contingent liabilities and commitments (Note 8)
Members’ equity			109,175				70,920
Total liabilities and members’ equity		$	246,437			$	166,435

See accompanying notes.

 

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Eagle Energy Company of Oklahoma, LLC

Consolidated Statement of Income

 

		Years Ended December 31,								For the Period
		2011				2010				December 11, 2009 (Inception) to December 31, 2009
		(In Thousands)
Revenues:
Oil and gas sales		$	73,446			$	30,340			$	945
Realized and unrealized gains (losses) on derivatives			4,240				9,893				(354	)
Total revenues			77,686				40,233				591
Expenses:
Lease operating			12,130				9,173				83
Production taxes			3,090				2,195				67
Depletion, depreciation, and amortization			18,889				9,739				80
Impairment of oil and gas properties			6,338				2,188				—
Exploration			804				—				—
General and administrative			5,074				3,441				1,919
Other			813				31				30
Total expenses			47,138				26,767				2,179
Operating income (loss)			30,548				13,466				(1,588	)
Other income (expenses):
Interest expense			(6,965	)			(4,021	)			(83	)
Other			(27	)			(258	)			(8	)
Total other income (expenses)			(6,992	)			(4,279	)			(91	)
Net income (loss)		$	23,556			$	9,187			$	(1,679	)

See accompanying notes.

 

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Eagle Energy Company of Oklahoma, LLC

 

		Total Members’ Equity
		(In Thousands)
Members’ equity at December 11, 2009 (Inception)		$	—
Contributions			35,000
Distributions			(1,048	)
Net income			(1,679	)
Members’ equity at December 31, 2009		$	32,273
Contributions			30,000
Distributions			(540	)
Net income			9,187
Members’ equity at December 31, 2010		$	70,920
Contributions			15,000
Distributions			(301	)
Net income			23,556
Members’ equity at December 31, 2011		$	109,175

See accompanying notes.

 

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Eagle Energy Company of Oklahoma, LLC

Consolidated Statement of Cash Flows

 

		For the Years Ended December 31,								For the period
		2011				2010				December 11, 2009 (Inception) to December 31, 2009
		(In Thousands)
Operating activities
Net income (loss)		$	23,556			$	9,187			$	(1,679	)
Adjustments to reconcile to cash provided by operations:
Depletion, depreciation and amortization			18,889				9,739				80
Amortization of debt financing costs			1,182				934				30
Impairment of oil and gas properties			6,338				2,188				—
Cash provided (used) by changes in current assets and liabilities:
Accounts receivable			(6,378	)			(11,680	)			(4,082	)
Prepaid expenses and other current assets			37				(787	)			(31	)
Accounts payable			5,797				2,918				790
Changes in current and noncurrent derivative assets, net			(657	)			(6,160	)			354
Net cash provided by operating activities			48,764				6,339				(4,538	)
Investing activities
Acquisitions of oil and gas properties			(7,600	)			(33,566	)			(61,565	)
Capital expenditures			(74,890	)			(46,760	)			—
Other			—				(8	)			—
Net cash used in investing activities			(82,490	)			(80,334	)			(61,565	)
Financing activities
Borrowings under credit agreements			27,500				43,500				43,000
Debt financing costs			(2,163	)			(650	)			(2,429	)
Contributions by members			15,000				27,000				35,000
Distributions			(300	)			(600	)			(1,048	)
Net cash provided by financing activities			40,037				69,250				74,523
Increase (decrease) in cash			6,311				(4,745	)			8,420
Cash at the beginning of the year			3,675				8,420				—
Cash at the end of the year		$	9,986			$	3,675			$	8,420
Supplemental non-cash transactions:
Change in accrued capital expenditures		$	1,829			$	4,587			$	—
Change in asset retirement obligations		$	765			$	484			$	—
Noncash property contribution		$	—			$	3,000			$	—

See accompanying notes.

 

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Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

1. Organization, Operations and Basis of Presentation

Organization and Operations

Unless otherwise noted, the terms “we,” “us,” “our,” “management” and other similar terms refer to Eagle Energy Company of Oklahoma, LLC (the Company), an Oklahoma limited liability company. We were formed on December 11, 2009 (Inception) with a focus on the acquisition, exploration, development, and production of natural gas and crude oil in the Mid-Continent region of the United States. Our wholly owned subsidiary, Eagle Energy Operating GP, LLC is the general partner (0.01%) of Eagle Energy Operating Company, LLC in which we own a substantial majority interest (99.99%). Eagle Energy Operating Company operates its wholly owned subsidiary, Eagle Energy Production, LLC.

The Company is headquartered in Tulsa, Oklahoma. The Company’s operations are primarily in Oklahoma, in the counties of Woods, Alfalfa and Lincoln, with drilling efforts primarily focused in the Mississippian Limestone geological formations.

2. Summary of Significant Accounting Policies

Basis of Presentation

We prepared the consolidated financial statements in accordance with accounting principles generally accepted in the United States and included the accounts of the Company and our wholly owned, controlled subsidiaries. We eliminated intercompany accounts and transactions.

Use of Estimates

The preparation of our consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

Areas requiring the use of assumptions, judgments and estimates relate to volumes of oil and natural gas reserves used in calculating depreciation, depletion and amortization (DD&A); the amount of expected future cash flows used in determining possible impairments of oil and gas properties and the amount of future capital costs used in these calculations; future asset retirement obligations; impairments of undeveloped properties; and valuations of derivatives. These estimates are discussed further throughout these notes.

Cash and Cash Equivalents

All highly liquid investments purchased with an original maturity of three months or less are considered cash equivalents.

Product Revenues

Revenues from sales of crude oil, natural gas and other hydrocarbons are recognized when the product is sold and delivered. Production revenue from properties in which we have an interest with other producers is recognized based on actual volumes sold (the sales method) during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, that are determined to be non-recoverable through remaining production are recognized as accounts receivable or accounts payable, as appropriate. The Company has no material imbalances at December 31, 2011 or 2010.

 

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Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

 

Accounts Receivable

The Company sells oil, natural gas and related products to various customers and participates with other parties in the drilling, completion and operation of oil and natural gas wells. Accounts receivable are carried on a gross basis, with no discounting, less the allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial conditions of the customers and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. A portion of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. The Company had no allowance for doubtful accounts at December 31, 2011 or 2010; and there was no provision for bad debt expense for any period presented.

Accounts receivable is comprised of the following at December 31, 2011 and 2010:

 

		December 31,
		2011				2010
		(In Thousands)
Receivables by product or service:
Sale of oil, natural gas and related products		$	10,197			$	5,169
Joint interest owners			9,682				8,118
Other			173				387
Accounts receivable		$	20,052			$	13,674

Inventory

Inventory, which is included in Prepaid expenses and other current assets, consists principally of tubular goods, spare parts and equipment that is used in the Company’s drilling operations. Inventory is stated at the lower of cost or market and is relieved using the specific identification method. The inventory balance was $515 thousand and $562 thousand at December 31, 2011 and 2010, respectively. There were no provisions related to obsolete or slow-moving inventory for either year.

Properties and Equipment

The Company’s oil and gas exploration and production activities are accounted for using the successful efforts method. Costs incurred in connection with the drilling and equipping of exploratory wells are capitalized as incurred. If proved reserves are not found, such costs are charged to exploration expense. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred whether productive or nonproductive.

Properties and Equipment

Capitalized exploratory and developmental drilling costs, including lease and well equipment and intangible development costs are depreciated and amortized using the unit-of-production method based on estimated proved developed oil and gas reserves on a field basis. Depletion of producing leasehold costs is based on the unit-of-production method using estimated proved oil and gas reserves on a field basis. The rates we utilize under the units-of-production methodology are based on our estimates of proved oil and gas reserves.

 

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Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

 

Unproved properties consist of costs incurred to acquire unproved leases. Unproved lease acquisition costs are capitalized until the leases expire or when the Company specifically identifies leases that will revert to the lessor, at which time the Company expenses the associated unproved lease acquisition costs. The expensing of the unproved lease acquisition costs is recorded as Impairment of oil and gas properties in the Consolidated Statement of Operations. Unproved oil and gas property costs are transferred to proved oil and gas properties if the properties are subsequently determined to be productive or are assigned proved reserves. Unproved oil and gas properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, future plans to develop acreage and other relevant factors.

Other exploration costs, including geological and geophysical costs and lease delay rentals are charged to expense as incurred and are included in Exploration expenses.

We record other property and equipment at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repairs are expensed as incurred. Depreciation for these assets is computed using the straight-line method over estimated useful lives. Upon retirement or disposition of assets, the costs and related accumulated depreciation are removed from the accounts with the resulting gain or losses, if any, reflected in results of operations.

Impairment of Long-lived Assets

The Company reviews its proved oil and gas properties for impairment whenever events or changes in circumstances indicate, in our management’s judgment, that a decline in the recoverability of their carrying value may have occurred. Assets are grouped for impairment purposes at the field level. When an indicator of impairment has occurred, we compare our estimate of undiscounted cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

Judgment’s and assumptions are inherent in our estimate of undiscounted future cash flows and an asset’s fair value. These judgments and assumptions include such matters as the estimation of oil and gas reserve quantities, risks associated with the different categories of oil and gas reserves, the timing of development and production, expected future commodity prices, capital expenditures, production costs and appropriate discount rates.

Debt Placement Costs

Costs incurred for debt borrowings are capitalized as paid and amortized over the life of the associated debt instrument using the effective interest method. When debt is retired prior to scheduled maturity, remaining placement costs associated with that debt are expensed. Unamortized debt financing costs were $3.01 million and $2.12 million as of December 31, 2011 and 2010, respectively, and are included in Other non-current assets.

Asset Retirement Obligations

The Company has obligations under its lease agreements and federal regulations to remove equipment and restore land at the end of oil and natural gas production operations. These asset retirement obligations (ARO) primarily relate to costs necessary to plug and abandon wells. We record an asset and a liability upon incurrence equal to the present value of each expected future ARO. These estimates include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market risk premium.

 

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Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

 

The ARO asset is depreciated in a manner consistent with the depreciation or depletion of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense in Depletion, depreciation and amortization expenses.

A roll forward of our asset retirement obligation liability is presented below:

 

		December 31,
		2011				2010
		(In Thousands)
Beginning balance		$	780			$	296
Liabilities incurred during the period			165				475
Revisions in cost estimates			545				—
Accretion expense			55				9
Ending balance		$	1,545			$	780

Derivatives

In addition to requirements under our credit agreements, the Company utilizes commodity derivative financial instruments, including swaps and collars, to manage risks related to changes in oil, natural gas and NGL prices. See Note 10—Derivative Instruments for further discussion. The Company records all derivative instruments as either assets or liabilities measured at their estimated fair value. We do not hedge volumes in excess of our expected oil, natural gas and NGL production (i.e. we do not enter into speculative trading positions). We have not designated our derivative instruments as cash flow hedges for accounting purposes, but they do serve as economic hedges of our production. All realized gains and losses from the settlement of commodity derivative instruments and unrealized gains and losses from valuation changes in the remaining unsettled commodity derivative instruments are reported in Realized and unrealized gains (losses) on derivatives revenues. Unrealized gains are included in current and noncurrent assets and unrealized losses are included in current and noncurrent liabilities on the Consolidated Balance Sheet, respectively.

Our derivatives are presented on a net basis, as those with both gain and loss positions are held by a single counterparty and are subject to a master netting arrangement. We determine current and noncurrent classification based on the timing of expected future cash flows of individual trades.

Under the terms of our credit facility, we are required to execute all hedge transactions with an approved counterparty. All of our derivative financial instruments are currently executed with the agent bank of our senior credit facility. The creditworthiness of our counterparty is subject to continual review by our management and we believe the risk of non-performance to be low.

The Company’s derivative contracts are documented with industry standard contracts known as a Schedule to the Master Agreement and International Swaps and Derivatives Association, Inc. Master Agreement. We are not required to provide any collateral support to our counterparty other than cross collateralization with the properties securing our credit facility. Under the terms of our credit facility, new hedge positions are limited to 85% of projected future production for three years and 75% of projected production for the fourth year following the date of the hedge transaction.

Reclassifications

Prior year amortization of debt placement costs have been reclassified from Depreciation, depletion and amortization expense to conform to current year presentation in Other income (expense).

 

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Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

 

3. Property and Equipment

Acquisitions

In December of 2009, we closed on our purchase of proved and unproved properties from Special Exploration Co., Inc. (Special) located in Lincoln, Alfalfa and Woods counties in Oklahoma. The purchase had an effective date of September 1, 2009, on which date Special conveyed all of its right, title and interest in the properties to Eagle Energy Production, LLC along with related operating contracts. The purchase price was $61.28 million (which is net of a purchase price adjustment of $2.71 million that was received during 2010) and the purchase price was allocated to the oil and gas properties acquired on a property-by-property basis.

At December 31, 2009, these wells were externally managed by Special. In February 2010, the Company took over operatorship of all properties purchased from Special. During 2010, we completed additional purchases of incremental ownership interests in these properties from nine separate parties.

During 2010, we acquired ownership interests in certain oil and gas property in Haskell County, Oklahoma, for $3 million from HISAW partners, a related party. This acquisition was in addition to the related assets, as discussed in Note 4.

During 2011, we closed on an agreement with an unrelated party to acquire additional ownership interests in certain oil and gas property leases in northwest Oklahoma for a purchase price of $7.6 million. This consisted of $1.6 million of proved property and $6 million of unproved property.

These acquisitions qualify as business combinations, and as such, the Company estimated the fair value as of each acquisition date. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements also utilize assumptions of market participants. To estimate the fair value of proved properties, the Company used a discounted cash flow model and made market assumptions for future commodity prices, projections of estimated quantities of reserves, expectations for timing and amount of future development and operating costs, and projections of future rates of production, and expected recovery rates. Due to the unobservable nature of the inputs, these estimates of the proved and unproved oil and gas properties are considered Level 3 fair value measurements; see further discussion in Note 9—Fair Value Measurements.

Properties and equipment

Properties and equipment are carried at cost and include the following at December 31, 2011 and 2010:

 

		Estimated Useful Life		2011				2010
		(In Thousands)
Proved properties		(a)		$	189,886			$	145,351
Unproved properties		(b)			27,359				3,351
Construction in progress		(b)			15,939				391
Office and other equipment		36-60 months			690				1,097
Total at cost					233,874				150,191
Accumulated depletion, depreciation, and amortization					(28,676	)			(9,843	)
Properties and equipment, net					205,198				140,347

 

(a)	Proved properties are depreciated, depleted and amortized using the units-of-production method (see Note 1).

(b)	Unproved properties and construction in progress are not yet subject to depreciation and depletion.

 

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Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

 

During 2011, the Company recognized an impairment of $1.4 million on its well and equipment costs located in Haskell County, Oklahoma. These wells have not produced commercially. Management evaluated the estimated future cash flows of the field and determined that required significant infrastructure investments in the area render the wells uneconomic. We recognized additional impairment charges of $3.9 million on remaining undeveloped acreage located in Haskell County, Oklahoma and $1 million related to undeveloped acreage in Lincoln County, Oklahoma and Northwest Oklahoma expiring in 2012. During 2010, the Company recognized an impairment charge of $2.2 million related to undeveloped acreage held by leases expiring in Haskell County.

4. Related Party Transactions

In March of 2010, the Company’s CEO, Steve Antry, contributed undeveloped acreage to the Company for consideration of three million Series A units. As disclosed in Note 3, we have recognized non-cash impairment charges related to this acreage during 2011 and 2010.

The Company paid for goods and services in the amount of $899 thousand and $989 thousand in 2011 and 2010, respectively, from certain well servicing companies in which Mr. Antry directly and indirectly holds a controlling interest.

The Company is required to pay R/C IV Eagle Holdings, L.P. (“Riverstone”, its largest Series A Unitholder) an annual monitoring fee equal to $250 thousand. When Riverstone’s total capital contributions to the Company equal $100 million, the annual monitoring fee is equal to 1% of the aggregate amount of its capital contributions. We paid $250 thousand and $258 thousand in 2011 and 2010, respectively, to Riverstone related to this monitoring fee, which is recorded in Other income (expense).

The Company is obligated to pay a commitment fee promptly upon the funding of any Series A Unit capital contribution. The amount of such commitment fee is equal to 2% of each capital contribution made by Series A members. During 2011 and 2010, respectively, we received contributions of $14.2 million and $26.6 million from R/V IV Eagle Holdings, LP and $789 thousand and $421 thousand from Mr. Antry and we distributed 2% of such contributions back to each party. We accounted for the contributions and distributions as increases and decreases in equity.

5. Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities are comprised of the following at December 31, 2011 and 2010:

 

		December 31,
		2011				2010
		(In Thousands)
Accounts payable, trade		$	8,525			$	38
Accrued capital costs—gross			11,035				7,343
Accrued lease operating expenses			999				724
Accrued general and administrative expenses			497				34
Accrued interest payable			478				68
Other			183				28
Total		$	21,717			$	8,235

 

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Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

 

6. Debt

In 2009, the Company entered into a senior revolving credit agreement with a syndication of banks (the Lenders), totaling $150 million (the Credit Facility). During 2011, we amended and restated the Credit Facility which included an increase to $250 million. Borrowings under the Credit Facility are secured by the assets of Eagle Energy Production, LLC (which represents virtually all of the Company’s assets), including its oil and gas properties. Twice annually, the participating lenders determine the maximum amount of the $250 million which will be available for borrowings and letters of credit (Borrowing Base). The calculation is based on the lenders’ customary practices and standards, which focus on the value and nature of the assets which secure the facility. As of December 31, 2011, the Borrowing Base was $105 million. Borrowings under the Credit Facility incur interest at a LIBOR-based rate plus a margin which increases based on increases in the amount of the Borrowing Base (ranging from 2 to 3 percent) which is due and payable monthly and the principal balance is due August 2014. Issued letters of credit incur a standby fee ranging from 2 to 3 percent (also based on increases in the amount of the Borrowing Base). A commitment fee is assessed at a rate of 0.5%, dependent on the unused portion of the Credit Facility. As of December 31, 2011 and 2010, borrowings of $79 million and $74 million, respectively, were outstanding under this facility. Our letter of credit facility had total capacity of $10 million as of December 31, 2011 and 2010, respectively, of which $302 thousand and $262 thousand was outstanding, respectively. Amounts obligated for letters of credit are not reflected as debt on our consolidated balance sheet. The annual weighted-average interest rate on borrowings outstanding under the facility at December 31, 2011 and 2010 was 4.80% and 5.01%, respectively.

Our Credit Facility requires the Company to maintain certain specific financial ratios. The ratio of consolidated EBITDAX (generally defined as earnings before interest, taxes, depreciation, depletion, amortization, exploration expenses, and non-cash items which affect net income) to total interest expense may not be less than 2.75 to 1.00, the ratio of consolidated funded senior indebtedness to EBITDAX may not be greater than 4.00 to 1.00, the consolidated current ratio may not be less than 1.00 to 1.00, and the ratio of consolidated funded total indebtedness to EBITDAX may not be greater than 4.50 to 1.00. Further, the ratio of total proved reserves (discounted at 9%) to total consolidated funded indebtedness must be greater than 1.50 to 1.00.

In addition, the Credit Facility contains covenants that limit the Company’s ability to, among other things, incur indebtedness secured by certain liens or encumber its assets, engage in certain sale-leaseback transactions, and consolidate, merge or dispose of all or substantially all of its assets. As of December 31, 2011, we were in compliance with all financial covenants. If an event of default occurs and is continuing, the Lenders may declare all amounts due under the Credit Facility to be immediately due and payable.

In August of 2011, Eagle Energy Production, LLC entered into a second lien credit agreement with Citibank, as agent and issuer for the participating lenders, totaling $50 million (the “Second Facility”) which retired the existing $12.5 million second lien in place executed December 2010. The Second Facility includes cross-default provisions with the Credit Facility. Prepayment of principal of borrowings under the Second Facility is not permitted without the consent of the Credit Facility lenders.

Borrowings under the Second Facility are secured by the Company’s oil and gas properties and incur interest at a LIBOR-based rate plus a margin of 9 percent. Such interest is due and payable on a monthly basis and the principal balance is due February 2015. As of December 31, 2011 and 2010, $35 million and $12.5 million, respectively, were outstanding under our second lien facilities. The annual weighted-average interest rate on borrowings outstanding under these facilities at December 31, 2011 and 2010 was 10.06% and 9.47%, respectively.

We paid cash interest of $5.8 million, $3.1 million and $83 thousand during the years ended December 31, 2011, 2010 and the period ended 2009, respectively.

 

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Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

 

The amounts of required future principal payments as of December 31, 2011 are as follows:

 

		(In Thousands)
2012		$	—
2013			—
2014			79,000
2015			35,000
2016			—
		$	114,000

7. Concentration of Credit Risk

Financial instruments, which potentially subject the Company to concentrations of credit risk, consist primarily of cash, accounts receivable and derivative instruments. The Company maintains cash and cash equivalents in bank deposit accounts which may at times exceed federally insured limits.

We have not experienced any significant losses from uncollectible receivables. The Company believes the creditworthiness of its customer base is high and has not experienced any significant write-downs in its account receivable balances. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly.

Sales to purchasers of greater than ten percent of operating revenues consist of the following:

 

		For the years ended December 31,
Purchaser		2011				2010				2009
SemGas, L.P.			22	%			29	%			0.0	%
ConocoPhillips			46	%			9	%			0.0	%
DCP Midstream LLC			14	%			29	%			0.0	%
Scissor Tail Energy, LLC			10	%			25	%			0.0	%

If we were to lose any one of our customers, the loss could temporarily delay production and sale of oil and natural gas in our producing area, however, management believes that a substitute customer to purchase the impacted production volumes could be identified.

8. Commitments and Contingencies

The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. We are unable to estimate the costs of asset additions or modifications which may be necessary to comply with any new regulations due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance.

We are involved in various legal actions and claims arising in the ordinary course of our business. While the outcome of these lawsuits cannot be predicted with certainty, we do not expect these matters to have a material adverse effect on our financial position, cash flows or results of operations.

Commitments

Total rental charges incurred were $7.6 million, $3.7 million and $3 thousand in 2011, 2010 and 2009, respectively. Rent charges incurred for drilling rigs are capitalized under the successful efforts method of accounting.

 

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Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

 

9. Fair Value Disclosures

The Company’s derivative financial assets and liabilities are measured at fair value on a recurring basis. The Company discloses its recognized non-financial assets and liabilities at fair value on a non-recurring basis. As defined in the authoritative guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants (an exit price) at the measurement date. To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique.

These inputs can be readily observable, market corroborated or generally unobservable. The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value, giving the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The Company classifies fair value balances based on the observability of those inputs.

The three levels of the fair value hierarchy are as follows:

Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed equities and U.S. government treasury securities.

Level 2—Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives, such as over-the-counter forwards and options.

Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

The following table summarizes by level the Company’s financial assets that were accounted for at fair value on a recurring basis as of December 31, 2011 and 2010, based on the fair value hierarchy:

 

		Fair Value Measurements at December 31, 2011 Using:
		Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Total Carrying Value as of December 31, 2011
Energy derivative assets		$	—			$	6,463			$	—			$	6,463

 

		Fair Value Measurements at December 31, 2010 Using:
		Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Total Carrying Value as of December 31, 2010
Energy derivative assets		$	—			$	5,806			$	—			$	5,806

 

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Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

 

The Level 2 instruments presented in the table above consist of oil, liquids and natural gas collars and swaps. The Company utilizes the mark-to-market valuation reports provided by our counterparty for monthly settlement purposes to determine the valuation of our derivative instruments. The determination of the fair values presented above also incorporates a credit adjustment for non-performance risk, as required in the authoritative guidance. The Company calculated the credit adjustment for derivatives in an asset position using the credit default swap rate for our counterparty. Based on this computation the adjustment for credit risk is not significant. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. The determination of the fair value of our liabilities does not consider noncash collateral credit enhancements.

During 2011, we recorded an impairment charge on our Haskell County oil and gas well and equipment costs based on our estimate of fair value on a nonrecurring basis. Significant assumptions used in our assessment include estimates of future reserve quantities, estimates of future prices using a forward NYMEX curve adjusted for locational differences, expected capital costs including infrastructure costs required to produce the wells and a discount rate of ten percent. Based on the capital costs required to produce and ultimately market production from the wells we determined them to be uneconomic and fully impaired the costs.

10. Derivative Instruments

All derivative instruments are recorded on the balance sheet as either assets or liabilities measured at their estimated fair value, see Note 9—Fair Value Measurements. We do not enter into these arrangements for speculative trading purposes.

 

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Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

 

As of December 31, 2011, the table on the following page sets forth our outstanding commodity derivative contracts, all of which settle monthly, and none of which were designated as hedges.

 

Period		Contract		Quantity Type		Notional Volume				Range of Hedge Prices
Natural Gas
2012		Swap		MMBtu			2,114,100			$	6.51
2013		Swap		MMBtu			176,700			$	6.52
2012		Collar		MMBtu			492,000			$	4.50-5.15
2013		Collar		MMBtu			1,524,000			$	4.00-5.61
2014		Collar		MMBtu			1,189,500			$	4.38-5.38
2015		Collar		MMBtu			25,500			$	4.00-4.92
Crude oil
2012		Swap		Bbls			38,814				86.63
2013		Swap		Bbls			18,647				86.19
2014		Swap		Bbls			1,500				86.30
2012		Collar		Bbls			209,000			$	90.47-$103.24
2013		Collar		Bbls			145,500			$	84.01-$97.43
2014		Collar		Bbls			118,500			$	87.62-$95.76
2015		Collar		Bbls			9,400			$	85.00- $95.25
NGLs
2012		Swap		Gallons			9,874,200			$	1.64
2013		Swap		Gallons			7,543,200			$	1.50
2014		Swap		Gallons			4,956,000			$	1.46
Natural gas basis
2012		Swap		MMBtu			2,114,100				(0.46	)
2013		Swap		MMBtu			176,700				(0.46	)

The combined fair value of derivatives included in our consolidated balance sheet as of December 31, 2011 and 2010 is summarized below. We conduct derivative activities with only one financial institution, who is the agent of our Credit Facility. This may result in a concentration of credit risk. Our derivative assets and liabilities are presented in our consolidated balance sheets on a net basis, as our derivatives with both gain and loss positions are held by a single counterparty and are subject to a master netting arrangement. The fair value amounts in the table below are presented on a gross basis:

 

		December 31,
		2011				2010
		(In Thousands)
Derivatives not designated as hedging instruments:
Derivative assets:
Natural gas—derivatives		$	9,412			$	7,596
NGLs—derivatives		$	758			$	—
Derivative liabilities:
Crude Oil—derivatives		$	1,703			$	1,791
Natural gas—derivatives		$	714			$	—
NGLs—derivatives		$	1,290			$	—

 

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Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

 

The following table summarizes the effect of the Company’s derivative contracts on the accompanying consolidated statements of operations for the years ended December 31, 2011 and 2010 (in thousands):

 

Type of Contract		Location of Gain Recognized in Income		December 31,
				2011				2010
Energy derivatives		Realized and unrealized gain on derivatives		$	4,240			$	9,893

The following table summarizes the cash settlements and valuation gains and losses from our commodity derivative contracts for the years ended December 31, 2011 and 2010 (in thousands):

 

		December 31,
Oil and Natural Gas Derivatives		2011				2010
Realized gain		$	3,583			$	3,421
Unrealized gain			657				6,472
Realized and unrealized gains on derivatives			4,240				9,893

11. Members’ Equity and Distributions

The Company was initially funded through (i) a $35 million contribution from its affiliate R/V IV Eagle Holdings, LP (in exchange for Series A Units in the Company) and (ii) a $3 million contribution from S&L Antry, LLC (beneficially owned by Steve and Lisa Antry) and Steve Antry relating to the purchase of HISAW undeveloped acreage. During 2011 and 2010, respectively, an additional $15 million and $27 million was contributed by the initial Series A Unit holders.

The Company’s Series A Unit holders have the right, among other things, to appoint a Board of Directors. Pursuant to the Company’s operating agreement, Riverstone has the right to appoint three directors, and the Company’s management has the right to appoint two directors.

The following items require approval of the Board of Directors and two thirds of the Series A Units.

 

•

making capital calls to fund capital contributions

 

•

making distributions other than cash distributions (cash distributions only require Board of Director approval)

 

•

removing any member of the Company’s management team

 

•

effecting a liquidation event of the Company and

 

•

changing the Company’s experts on technical matters

The Company is authorized to issue Series B Units as an incentive to its management team, employees and key advisors. These units constitute “profits interests” and have an initial threshold value of $0. The recipients of the Series B Units are not required to contribute capital upon receipt of the B units. However, under certain circumstances, the Series B Unitholders may be allocated items of income or loss for Federal Income Tax purposes. Further, the Series B Unitholders may participate in distributions from the Company based upon a contractual formula. The Series B Units have limited voting rights, are subject to various performance and forfeiture provisions, and are subject to a vesting schedule based on length of service with the Company. As of December 31, 2011 and 2010, respectively, there were 119,149 and 117,000 outstanding Series B Units.

 

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Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

 

The Series B Units vest according to the following schedule: 20% on each of the first three grant anniversary dates, and 40% upon a liquidation event. Management has evaluated the terms of the awards and, in particular, the fact that the value of the units is contingent upon certain liquidity events which have not yet occurred, and has determined that related compensation expense for 2011 and 2010 is $0.

For purposes of determining capital account balances, the Company allocates net income to its unit holders based on contractually determined profit and loss sharing arrangements and actual cash or property contributions and distributions. Distributions are made pursuant to what is commonly referred to as a “waterfall” whereby the Series B Units increase their share of the distributions as the Series A Units achieve certain cash returns.

12. Income Taxes

The Company is organized as a limited liability company and is classified as a partnership for federal income tax purposes. Due to its partnership classification, the Company is not subject to federal income tax. Similarly, most states treat entities classified as partnerships for federal income tax purposes as partnerships for state purposes. As such, income tax liabilities are passed through to the members.

13. Subsequent Events

We evaluated subsequent events through April 13, 2012, which is the day the financial statements were issued.

On March 19, 2011 a fire began at the Company operated Buckles 1H-3 during drilling which resulted in damage to the drilling rig on location, other equipment in the area and some adjacent property. We incurred charges during the year related to clean up and site remediation. We filed suit against our insurer for specific performance under our policy and ultimately entered mediation. On March 29, 2012, a tentative settlement agreement was reached under which we anticipate that we will recover approximately $600,000 for charges incurred.

Information Subsequent to Initial Date of Report of Independent Auditors (Unaudited)

On August 11, 2012, the Company entered into an Asset Purchase Agreement (the “Agreement”) with Midstates Petroleum Company, LLC (“Midstates”), pursuant to which the Company has agreed to sell substantially all of its producing oil and natural gas assets, unevaluated leasehold acreage in Oklahoma and Kansas and related hedging instruments. The aggregate purchase price, subject to adjustment as provided in the Agreement, consists of (a) $325 million in cash and (b) 325,000 shares of Series A Preferred Stock of the Company with an initial liquidation preference of $1,000 per share.

The Company and Midstates have made customary representations, warranties and covenants in the Agreement. Midstates has agreed not to take certain specified actions without the Company’s consent during the time between execution of the Agreement and the closing of the sale. The Company has made certain additional customary covenants, including, among others, covenants to conduct its business in the ordinary course between the execution of the Agreement and the closing and not to engage in certain kinds of transactions during that period, subject to certain exceptions.

Consummation of the sale is subject to various conditions, including, among others, (1) the accuracy of representations and warranties of the parties as of the closing date, including the absence of any material adverse effect with respect to each of the Company’s business and Midstates’s business, (2) the release of certain liens in connection with the repayment of our indebtedness, (3) the execution of certain ancillary documents and (4) other customary closing conditions. The sale will be effective June 1, 2012 and closing is expected to occur on or about October 1, 2012. The Agreement may be terminated under customary circumstances.

Amounts outstanding under our credit facilities will be retired with the proceeds received at closing.

 

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Eagle Energy Company of Oklahoma, LLC

Supplemental Oil and Gas Disclosures

(Unaudited)

14. Supplemental Oil and Gas Disclosures—(Unaudited)

The supplemental data presented herein reflects information for all of the Company’s oil and natural gas producing activities.

Capitalized Costs

The following table sets forth the capitalized costs related to the Company’s oil and natural gas producing activities at December 31, 2011 and 2010:

 

		2011				2010
		(In Thousands)
Proved properties		$	205,825			$	145,742
Unproved Properties			27,359				3,351
Total at cost			233,184				149,093
Less: Accumulated depletion, depreciation, and amortization			(28,367	)			(9,718	)
Total oil and gas properties, net			204,817				139,375

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

The following table sets forth costs incurred related to the Company’s oil and natural gas activities for the years ended December 31, 2011 and 2010 and for the period from December 11, 2009 (Inception) to December 31, 2009:

 

		December 31,
		2011				2010				2009
		(In Thousands)
Acquisition
Proved		$	1,565			$	32,652			$	59,935
Unproved			24,008				1,843				1,508
Exploration			804				—				—
Development			57,753				52,374				—
Asset retirement obligations			765				485				296
Total costs incurred		$	84,895			$	87,354			$	61,739

 

•

Costs incurred include capitalized and expensed items

 

•

Exploration costs include the costs incurred for geological and geophysical activity

Estimated Quantities of Proved Oil and Natural Gas Reserves

The reserve estimates presented in the following table at December 31, 2011 are based on reports prepared by Netherland, Sewell & Associates, Inc., independent reserve engineers. The reserve report was prepared in accordance with the FASB’s authoritative guidance on oil and gas reserve estimation and disclosures. All of the Company’s oil and natural gas producing activities are conducted within the continental United States.

 

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Eagle Energy Company of Oklahoma, LLC

Supplemental Oil and Gas Disclosures

(Unaudited)

 

The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made. Proved developed oil and natural gas reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made.

The following table sets forth the Company’s net proved, proved developed and proved undeveloped reserves at December 31, 2011, 2010 and 2009:

 

		Oil (MBbl)				Gas (MMcf)				NGL (MBbl) (1)				MBoe
2009
Proved reserves
Beginning balance			—				—				—				—
Acquisition of reserves			1,651				123,324				—				22,206
Production			—				(143	)			—				(24	)
Net proved reserves at December 31, 2009			1,651				123,181				—				22,182
Proved developed reserves, December 31, 2009			168				33,583				—				5,766
Proved undeveloped reserves, December 31, 2009			1,483				89,598				—				16,416
2010
Proved reserves
Beginning balance			1,651				123,181				—				22,182
Revisions of previous estimates			342				(90,150	)			—				(14,684	)
Extensions and discoveries			1,097				24,658				—				5,207
Acquisition of reserves			222				9,248				—				1,764
Production			(77	)			(4,593	)			—				(843	)
Net proved reserves at December 31, 2010			3,235				62,344				—				13,626
Proved developed reserves, December 31, 2010			1,358				38,430				—				7,763
Proved undeveloped reserves, December 31, 2010			1,877				23,914				—				5,863
2011
Proved reserves
Beginning balance			3,235				62,344				—				13,626
Revisions of previous estimates			(460	)			(31,248	)			2,482				(3,185	)
Extensions and discoveries			6,721				34,625				3,669				16,160
Production			(424	)			(4,023	)			(422	)			(1,517	)
Net proved reserves at December 31, 2011			9,072				61,698				5,729				25,084
Proved developed reserves, December 31, 2011			2,989				28,121				2,809				10,486
Proved undeveloped reserves, December 31, 2011			6,083				33,577				2,920				14,598

 

(1)	Prior to 2011, the Company’s reserve estimates were prepared based on wet gas volumes. Beginning in 2011, NGLs reserve volumes have been estimated separately.

 

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Eagle Energy Company of Oklahoma, LLC

Supplemental Oil and Gas Disclosures

(Unaudited)

 

Revisions of previous estimates

Revisions in 2011 and 2010 primarily relate to the reclassification of reserves from proved to probable locations not expected to be developed within five years. Beginning in mid-2010 through the end of 2011, the Company devoted substantially all of its capital spending to its Mississippian Limestone properties. As such, negative reserve revisions relate primarily to reserves related to the Hunton formation not expected to be developed within five years.

Extensions and discoveries

Extensions and discoveries in 2011 and 2010 relate primarily to drilling activity in our Mississippian Limestone properties.

Acquisition of Reserves

Acquired reserves for 2009 are comprised entirely of the mineral interests acquired from Special. Reserves acquired in 2010 consist primarily of incremental working interests in existing wells previously acquired from Special.

Standardized Measure of Discounted Future Net Cash Flows

The Standardized Measure represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows. Production costs do not include depreciation, depletion and amortization of capitalized acquisition, exploration and development costs.

Our estimated proved reserves and related future net revenues and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The un-weighted arithmetic average first-day-of-the-month prices for the prior 12 months were $60.94/Bbl WTI posted price for oil and $3.87/MMBtu Platt’s Gas Daily Henry Hub for natural gas at December 31, 2009, $79.79/Bbl WTI posted price for oil and $4.39/MMBtu Platt’s Gas Daily Henry Hub for natural gas at December 31, 2010, and $92.71/Bbl WTI posted price for oil and $4.118/MMBtu Platt’s Gas Daily Henry Hub for natural gas at December 31, 2011. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

The discount rate of 10 percent is as prescribed by authoritative guidance. Continuation of year-end economic conditions also is assumed. The calculation is based on estimates of proved reserves, which are revised over time as new data becomes available. Probable or possible reserves, which may become proved in the future, are not considered. The calculation also requires assumptions as to the timing of future production of proved reserves, and the timing and amount of future development and production costs.

Numerous uncertainties are inherent in estimating volumes and the value of proved reserves and in projecting future production rates and timing of development expenditures. Such reserve estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production may be substantially different from the reserve estimates.

 

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Eagle Energy Company of Oklahoma, LLC

Supplemental Oil and Gas Disclosures

(Unaudited)

 

The following table sets forth the Standardized Measure of discounted future net cash flows from projected production of the Company’s oil and natural gas reserves at December 31, 2011, 2010 and 2009.

 

		December 31,
		2011				2010				2009
Future cash inflows		$	1,323,470			$	531,864			$	577,347
Future production costs			(335,130	)			(174,464	)			(164,944	)
Future development costs			(132,396	)			(57,382	)			(150,999	)
Future income tax expense (1)			—				—				—
Future net cash flows			855,944				300,018				261,404
10% annual discount for estimated timing of cash flows			(419,693	)			(139,487	)			(124,132	)
Standardized measure of discounted future net cash flows		$	436,251			$	160,531			$	137,272

 

(1)

Does not include the effects of income taxes on future revenues because as of December 31, 2011, 2010 and 2009, the Company was a limited liability company not subject to entity-level taxation. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income was passed through to the Company’s equity holders. If the Company were subject to entity-level taxation, the unaudited pro forma future income tax expense at December 31, 2011, 2010 and 2009 would have been $279,032, $74,620 and $79,269, respectively. The unaudited pro forma Standardized Measure at December 31, 2011, 2010 and 2009 would have been $291,472, $121,533 and $95,645, respectively.

Sources of Change in Standardized Measure of Discounted Future Net Cash Flows

The following table sets forth the changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves for the periods presented.

 

		2011				2010				2009
		(in thousands)
January 1,		$	160,531			$	137,272			$	—
Net changes in prices and production costs			84,297				44,838				—
Net changes in future development costs			(25,413	)			(8,289	)			—
Sales of oil and natural gas, net			(59,896	)			(20,839	)			(864	)
Extensions			296,677				47,957				—
Discoveries			—				—				—
Purchases of reserves in place			—				23,302				138,136
Revisions of previous quantity estimates			(37,532	)			(90,867	)			—
Previously estimated development costs incurred			31,500				112				—
Accretion of discount			16,053				13,727				—
Net change in income taxes			—				—				—
Changes in timing, other			(29,966	)			13,318				—
Period End		$	436,251			$	160,531			$	137,272

 

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