Audited Financial Statements of Hilcorp Energy GOM, LLC

EX-99.1 4 d430917dex991.htm AUDITED FINANCIAL STATEMENTS OF HILCORP ENERGY GOM, LLC Audited Financial Statements of Hilcorp Energy GOM, LLC

Exhibit 99.1

LOGO

Report of Independent Auditors

To the Member of Hilcorp Energy GOM, LLC

In our opinion, the accompanying balance sheets and the related statements of income, of member’s capital and of cash flows present fairly, in all material respects, the financial position of Hilcorp Energy GOM, LLC at December 31, 2011 and 2010, and the results of its operations and its cash flows for the years ended December 31, 2011 and 2010 in conformity with accounting principles generally accepted in the United States of America. 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 of these statements in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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.

LOGO

March 30, 2012

PricewaterhouseCoopers LLP, 1201 Louisiana, Suite 2900, Houston, TX 77002-5678

T: (713) 356 4000, F: (713) 356 4717, www.pwc.com/us

Hilcorp Energy GOM, LLC

Balance Sheet

December 31, 2011 and 2010


(in thousands of dollars)	2011		2010
Assets
Current assets:
Cash and cash equivalents	$	27	$	33
Accounts receivable from affiliates		104,126		32,336
Assets from risk management activities		10,270		11,108
Other current assets		2,382		1,478

Total current assets		116,805		44,955

Property and equipment, net		503,494		422,952
Assets from risk management activities		3,586		10,562

Total assets	$	623,885	$	478,469

Liabilities and Member’s Capital
Current liabilities:
Accounts payable and accrued liabilities	$	727	$	640
Accounts payable to affiliates		—		19,914
Deferred premiums on risk management activities		1,607		1,363
Liabilities for asset retirement obligations		17,749		22,000

Total current liabilities		20,083		43,917

Liabilities for asset retirement obligations		324,373		230,447
Deferred premiums on risk management activities		790		2,228
Commitments and contingencies
Member’s capital		278,639		201,877

Total liabilities and member’s capital	$	623,885	$	478,469

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

Hilcorp Energy GOM, LLC

Statement of Income

Years Ended December 31, 2011 and 2010


(in thousands of dollars)	2011			2010
Operating revenues:
Crude oil and products sales	$	161,458		$	64,167
Natural gas sales		61,383			63,305
Other		566			222

Total operating revenues		223,407			127,694

Operating expenses:
Oil and natural gas operating expenses		102,327			61,076
Transportation charges		692			690
Exploration expenses		78			39
Depletion, depreciation and amortization		90,844			87,130
Impairment of property and equipment		67,337			23,443
Accretion of asset retirement obligations		11,461			9,356
General and administrative expenses		18,303			11,147

Total operating expenses		291,042			192,881

Gain (loss) on sale of property and equipment		200			(14	)

Operating loss		(67,435	)		(65,201	)

Other income (expense):
Change in unrealized gain on commodity derivative contracts, net		(7,814	)		(7,544	)
Realized gain on commodity derivative contracts, net		12,011			16,410

Total other income		4,197			8,866

Net loss	$	(63,238	)	$	(56,335	)

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

Hilcorp Energy GOM, LLC

Statement of Member’s Capital

Years Ended December 31, 2011 and 2010


(in thousands of dollars)	Sole Member
Balance at December 31, 2009	$	187,712
Contributions		70,500
Comprehensive loss:
Net loss		(56,335	)

Total comprehensive loss		(56,335	)

Balance at December 31, 2010		201,877
Contributions		140,000
Comprehensive loss:
Net loss		(63,238	)

Total comprehensive loss		(63,238	)

Balance at December 31, 2011	$	278,639

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

Hilcorp Energy GOM, LLC

Statement of Cash Flows

Years Ended December 31, 2011 and 2010


(in thousands of dollars)	2011			2010
Cash flows from operating activities:
Net loss	$	(63,238	)	$	(56,335	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and amortization		90,844			87,130
Impairment of property and equipment		67,337			23,443
Accretion of asset retirement obligations		11,461			9,356
(Gain) loss on sale of property and equipment		(200	)		14
Unrealized loss on derivative contracts, net		7,814			7,544
Changes in assets and liabilities:
Account receivable from affiliate		(71,790	)		(19,457	)
Other current assets		128			745
Risk management activities		(1,194	)		(1,038	)
Accounts payable and accrued liabilities		87			(608	)
Accounts payable to affiliates		(24,005	)		1,832
Other		(7,007	)		(2,694	)

Net cash provided by operating activities		10,237			49,932

Cash flows from investing activities:
Acquisitions of oil and natural gas properties		(104,210	)		(191	)
Additions to oil and natural gas properties		(46,323	)		(126,567	)
Proceeds from insurance carriers		—			6,004
Proceeds from sale of property and equipment		290			289

Net cash used in investing activities		(150,243	)		(120,465	)

Cash flows from financing activities:
Contributions		140,000			70,500

Net cash provided by financing activities		140,000			70,500

Net change in cash and cash equivalents		(6	)		(33	)
Cash and cash equivalents at beginning of year		33			66

Cash and cash equivalents at end of year	$	27		$	33

Supplemental cashflow information:
Change in accrued capital expenditures	$	4,091		$	1,726

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

Hilcorp Energy GOM, LLC

Notes to Financial Statements

December 31, 2011 and 2010

(amounts in thousands, except volumes)

1. Organization and Summary of Significant Accounting Policies

Organization and Nature of Business

Hilcorp Energy GOM, LLC (the Company or HGOM) is primarily engaged in the production, development and exploration of oil and natural gas properties. The Company holds interests in oil and natural gas producing properties, located in the Gulf of Mexico, primarily offshore Louisiana and Texas. The Company has an agreement with Hilcorp Energy Company (HEC) to provide operating and other services to the Company.

The Company is a Texas limited liability company that was organized on March 6, 2008 by Hilcorp Energy GOM Holdings, LLC (HHGOM), its sole member. The Company shall continue until it is liquidated or dissolved in accordance with the limited liability agreement.

Basis of Presentation

The accompanying financial statements have been prepared on the accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America.

Cash and Cash Equivalents

The Company considers all highly liquid investments with an original maturity of three months or less when purchased to be cash and cash equivalents. Cash and cash equivalents are stated at cost which approximates market value.

Inventory

Hydrocarbon inventory, consisting of crude oil in tanks, is valued at the lower of average cost or market value and is included in other current assets on the balance sheet. Hydrocarbon inventory was $59 and $163 as of December 31, 2011 and 2010, respectively.

Property and Equipment

The Company uses the successful efforts method of accounting for its oil and natural gas properties. Under this method, all acquisition and development costs of proved properties are capitalized and amortized on the unit-of-production method over the remaining life of proved reserves and proved developed reserves, respectively. The cost of drilling an exploratory well is initially capitalized, but charged to expense if a well is determined to be unsuccessful. Unproved properties are excluded from the amortization computation until it is determined whether or not proved reserves can be assigned to the properties or whether impairment has occurred.

The Company evaluates the need for impairment of its oil and natural gas properties on a field-by-field basis, annually or whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. Property and equipment is reduced to fair value if the sum of the expected undiscounted future cash flows is less than the asset’s net book value. Cash flows are determined based upon proved reserves using prices and costs consistent with those used for internal decision making. Fair value is calculated by discounting the future cash flows. The discount factor used is based on rates utilized by market participants that are commensurate with the risks inherent in the development and production of the underlying natural gas and crude oil. The underlying commodity prices incorporated in the Company’s cash flow estimates are the result of a process that begins with the New York Mercantile Exchange (NYMEX) pricing, adjusted for location and quality differentials, as well as other factors that management believes will impact realizable prices.

During 2011 and 2010, the Company recognized non-cash charges of $67,337 and $23,443, respectively, related to the impairment of several fields. These impairments were related to downward revisions of previous estimates of proved oil and natural gas reserve quantities as a result of changes in the economic assumptions (including prices and costs) and production performance for these fields.

Costs of retired, sold or abandoned properties that constitute a part of an amortization base (partial field) are charged to accumulated depreciation, depletion and amortization if the unit-of-production rate is not significantly affected. Accordingly, a gain or loss, if any, is recognized only when a group of proved properties (entire field) that make up the amortization base has been retired, abandoned or sold, or a group of properties that comprise a significant portion of an amortization base has been retired, abandoned or sold and deferral of the gain or loss would significantly affect the unit-of-production rate.

Estimated dismantlement and abandonment costs for oil and natural gas properties are capitalized at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. Maintenance and repairs are charged as expense when incurred, and renewals and betterments which extend the useful life of an asset are capitalized.

Business Combinations

Business Combinations are accounted for in accordance with Accounting Standards Codification (ASC) 805, “Business Combinations.“ ASC 805 requires the assets and liabilities acquired to be recorded at their fair values at the date of the acquisition. 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. The Company uses a discounted cash flow model and market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as defined by ASC 820.

Asset Retirement Obligations

The Company records its asset retirement obligations (ARO) as a liability at its estimated net present value at the asset’s inception, with the offsetting charge to property and equipment. Periodic accretion of the discount of the estimated liability is recorded in the statement of income. The ARO represents the estimated present value of the amount the Company will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable laws. The Company has determined the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing, existence of a liability, as well as what constitutes adequate restoration. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the related asset.

Revenue Recognition

Oil and natural gas revenues from the Company’s interests in producing wells are recognized when production volumes are delivered and title transfers to the purchaser. Since there is a ready market for oil and natural gas, the Company sells the majority of its volumes produced soon after production at various locations at which time title and risk of loss passes to the buyer. As a result, the Company maintains a minimum amount of hydrocarbon inventory in storage.

Gas Imbalances

Revenues from natural gas production may result in more or less than the Company’s pro rata share of production from certain wells. The Company follows the sales method of accounting for natural gas sales and gas imbalances. When sales volumes exceed the Company’s entitled share and the overproduced balance exceeds the Company’s share of remaining estimated proved natural gas reserves for a given property, the Company records a liability. The Company had overproduced liabilities of $587 and $521, recorded in accounts payable and accrued liabilities on the balance sheet at December 31, 2011 and 2010, respectively.

At December 31, 2011, the Company’s underproduced natural gas position was approximately $74 (22.5 MMcf) at an average price of $3.26 per Mcf and its overproduced natural gas position was approximately $671 (124.5 MMcf) at an average price of $5.39 per Mcf. At December 31, 2010, the Company’s underproduced natural gas position was approximately $394 (93.4 MMcf) at an average price of $4.22 per Mcf and its overproduced natural gas position was approximately $746 (129.3 MMcf) at an average price of $4.21 per Mcf.

Environmental Costs

Expenditures for environmental remediation are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not have future economic benefit, are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and costs can be reasonably estimated. At December 31, 2011 and 2010, there were no environmental liabilities recorded on the balance sheet.

Income Taxes

The Company does not pay income taxes, as its profits or losses are reported directly to the taxing authorities by the sole member. Accordingly, no provision for income taxes has been included in the financial statements.

Contributions

During the years ended December 31, 2011 and 2010, the sole member made cash contributions of $140,000 and $70,500, respectively to the Company.

Concentrations of Credit Risk

Financial instruments which potentially subject the Company to credit risk consist principally of temporary cash balances, accounts receivable from affiliates and derivative financial instruments. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any losses from such investments. The Company attempts to limit the amount of credit exposure to any one financial institution or company. The Company’s customer base consists primarily of major integrated and international oil and gas companies, as well as smaller processors and gatherers. The Company believes the credit quality of its customers is high. In the normal course of business, letters of credit or parent guarantees are required for counterparties which management perceives to have a higher credit risk. Derivative instruments are with counterparties of high credit quality, therefore the risk of nonperformance by the counterparties is low (see Note 6).

Risk Management

The Company utilizes financial instruments to manage risks related to changes in commodity prices. During 2011 and 2010, the Company utilized financial instruments, including puts and collars to reduce the volatility of oil and natural gas prices on a portion of the Company’s future expected oil and natural gas production.

instrument prior to maturity, any cash paid or received upon settlement is recognized immediately and reported separately in other income (expense). Unrealized gains are included in current and noncurrent assets from risk management activities and unrealized losses are included in current and noncurrent liabilities from risk management activities on the balance sheet, respectively.

The Company’s risk management activities may prevent the Company from realizing the full benefits of price increases above the levels of the derivative instruments on a portion of its future oil and natural gas production.

Use of Estimates

The preparation of the financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting periods. Significant estimates made by management include oil and natural gas reserves, depletion, depreciation and amortization, purchase price allocations and valuations, asset retirement obligations, valuation of derivative instruments and accrued assets and liabilities.

Many of the Company’s significant financial estimates are based on remaining proved oil and natural gas reserves. Estimates of remaining proved reserves are a key component in determining the Company’s depletion rate for oil and natural gas properties and the Company’s asset retirement obligations. Estimation of the values of the Company’s remaining proved reserves is a key component in determining the need for impairment of the Company’s oil and natural gas asset base. These estimates require assumptions regarding future commodity prices and future costs and expenses as well as future production rates. Actual results could differ from these estimates.

Estimates of oil and natural gas reserves and their values, future production rates and future costs and expenses are inherently uncertain for numerous reasons, including many factors beyond the Company’s control. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploitation and development activities, prevailing commodity prices, operating costs and other factors. These revisions may be material and could materially affect future depletion, depreciation and amortization expense, asset retirement obligations and impairment expense.

Risk and Uncertainties

As an oil and natural gas producer, the Company’s revenue, profitability, and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, which are dependent upon numerous factors beyond its control such as economic, political and regulatory developments and competition from other energy sources. The energy markets have historically been very volatile and there can be no assurance that oil and natural gas prices will not be subject to wide fluctuations in the future. A substantial or extended decline in oil and natural gas prices could have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil and natural gas reserves that may be economically produced.

Fair Value of Financial Instruments

The Company has financial instruments such as cash and cash equivalents, accounts receivable from affiliates, accounts payable to affiliates and deferred premiums on risk management activities. These financial instruments are stated at cost which approximates market value. The Company has other financial instruments in the form of commodity derivative contracts which are used to reduce the impact of oil and natural gas price fluctuations (see Note 6). The fair value of commodity derivative instruments is based on the difference between the contractual fixed prices and forward market prices, discounted, on the contracted notional volumes and further discounted for counterparty nonperformance risk, if necessary.

Segment Information

All of the Company’s oil and natural gas properties and related operations are located in the United States of America and management has determined that the Company has one reportable segment.

2. Acquisitions and Dispositions of Oil and Natural Gas Properties

Acquisitions

On June 30, 2011, the Company acquired working and net revenue interests in oil and natural gas properties located in the federal outer continental shelf of the Gulf of Mexico for $104,795 and recorded a receivable from the seller of $1,032 for customary post closing adjustments. The Company used contributions from its sole member to fund this transaction. This acquisition had an effective date of July 1, 2011. The acquisition qualified as a business combination and the Company estimated the fair value of this property as of the June 30, 2011 closing date. The Company used a discounted cash flow model to arrive at its fair value estimate and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs as defined by ASC 820. The estimated fair value of these properties was assigned to the assets and liabilities acquired, which included $139,095 to proved properties and $35,332 for asset retirement obligations. Because the estimated fair value and purchase price were equivalent, the Company did not record goodwill or a bargain purchase gain related to this acquisition. The Company’s statement of income includes $32,010 of operating revenues and $11,174 of net income for the year ended December 31, 2011 related to the acquisition. The Company incurred acquisition costs of $216 related to this transaction, which are included in general and administrative expenses in the statement of income.

Summarized below are the results of operations for the years ended December 31, 2011 and 2010 on an unaudited pro forma basis as if the acquisition had occurred at the beginning of the period presented. This unaudited pro forma information has been prepared based on the Company’s historical statement of income and estimates based on information provided by the seller, with pro forma adjustments applied, as appropriate. This unaudited pro forma information is not necessarily indicative of the operating results that would have occurred at that date, nor are they necessarily indicative of future operating results.


	Year Ended December 31,
	2011			2010
Total operating revenues	$	267,266		$	196,146
Net loss		(45,547	)		(35,863	)

3. Related Party Transactions

The Company compensates HEC for providing these services. During 2011 and 2010, payments to HEC for these services are 7.5% of operating revenues on an annual basis plus certain permitted expenses and are included in general and administrative expenses in the statement of income. The Company paid $17,659 and $10,824 for the years ended December 31, 2011 and 2010, respectively, to HEC for providing these services. Additionally, the Company incurred $644 and $323 for the years ended December 31, 2011 and 2010, respectively, in permitted expenses as reimbursement to HEC for direct third-party charges for accounting, legal and engineering services.

Payments to Navitas Insurance Company, LLC

Navitas Insurance Company, LLC (Navitas), an affiliate of the Company, provides certain insurance coverage for HEC and its affiliates. During the year ended December 31, 2011, the Company paid HEC $9,443 in insurance expenses for oil lease property and well control coverage provided by Navitas, which are included in lease operating expenses in the statement of income.

Accounts receivable from and payable to affiliates were as follows:


	December 31,
	2011		2010
Accounts receivable from affiliates:
Receivables from oil and natural gas sales	$	37,669	$	32,336
Affiliate advances		66,457		—

	$	104,126	$	32,336

Accounts payable to affiliates:
Payables for operating and capital expenditures	$	—	$	19,914

4. Significant Concentrations

During the year ended December 31, 2011, approximately 74%, 8% and 8% of the Company’s oil and natural gas revenues were attributable to sales to Chevron USA Production Company, ConocoPhillips Company and Hess Corporation, respectively.

During the year ended December 31, 2010, approximately 62% and 19% of the Company’s oil and natural gas revenues were attributable to sales to Chevron USA Production Company and Hess Corporation, respectively.

5. Property and Equipment

Property and equipment consisted of the following:


	December 31,
	2011			2010
Unproved oil and natural gas properties	$	28,763		$	52,483
Proved oil and natural gas properties (successful efforts method)		825,096			562,653
Less accumulated depreciation, depletion and amortization		(350,365	)		(192,184	)

Property and equipment, net	$	503,494		$	422,952

During 2011, the Company transferred $23,720 of unproved properties to proved properties. During 2010, the Company transferred $18,391 of unproved properties to proved properties and received a credit of $11 related to exploration drilling.

The following table reflects the net changes in capitalized exploratory well costs:


	2011		2010
Balance of January 1,	$	—	$	—
Additions		—		(11	)
Transfers to proved properties		—		11
Charged to expense		—		—

Balance of December 31,	$	—	$	—

At December 31, 2011 and 2010, the Company had no suspended well costs related to wells that have been completed for more than one year.

6. Fair Value Measurements

The Company follows ASC 820, “Fair Value Measurements and Disclosures,” for financial and non financial assets and liabilities. ASC 820 requires disclosure that establishes a framework for measuring fair value and expands disclosure about fair value measurements. The statement characterizes inputs used in determining fair value using a hierarchy that prioritizes inputs depending on the degree to which they are observable.


Level 1:		Observable, unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2:		Observable inputs such as: (i) quoted prices for similar assets or liabilities in active markets; (ii) quoted prices for identical or similar assets or liabilities in markets that are not active; or (iii) valuations based on pricing models where significant inputs (e.g., interest rates, yield curves, etc.) are observable for the assets or liabilities, are derived principally from observable market data, or can be corroborated by observable market data.

Level 3:		Unobservable inputs, including valuations based on pricing models where significant inputs are not observable and not corroborated by market data. Unobservable inputs used to the extent that observable inputs are not available and reflect the Company’s own assumptions about the assumptions market participants would use in pricing the assets or liabilities. Unobservable inputs are based on the best information available in the circumstances, which might include the Company’s own data.

As required by ASC 820, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels.

Recurring Fair Value Measurements

The following table presents the valuation of the Company’s financial instruments by fair value hierarchy levels:


	Fair Value Measurements at Reporting Date Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Fair Value
December 31, 2011
Assets:
Derivative contracts
Crude oil and natural gas collars		—		—		8,263		8,263
Crude oil and natural gas puts		—		—		5,593		5,593

Total assets	$	—	$	—	$	13,856	$	13,856

December 31, 2010
Assets:
Derivative contracts
Crude oil and natural gas swaps	$	—	$	—		838		838
Crude oil and natural gas collars		—		—		13,746		13,746
Crude oil and natural gas puts		—		—		7,086		7,086

Total assets	$	—	$	—	$	21,670	$	21,670

The Company’s Level 3 instruments include commodity derivative instruments for which the Company does not have sufficient corroborative market evidence to support classifying the asset as Level 2, due to the limited market data available in the form of binding broker quotes or quoted prices for similar assets or liabilities in various markets. The commodity derivative instruments that the Company has categorized in Level 3 may later be reclassified to Level 2 if the Company is able to obtain additional observable market data to corroborate non-binding broker quotes or third-party pricing service inputs to models used to measure the fair value of these assets.

For liability positions, the Company has minimal risk of non-performance as all derivative contracts are secured by the Company’s oil and natural gas properties. The Company uses a third-party to value the derivative instruments it holds and compares these values against the counterparty’s valuations on a regular basis to confirm that the valuations reflected are appropriate and reasonable. For asset positions, the credit exposure by counterparty is assessed by reviewing each counterparty’s total position. The Company uses the credit default swap rate (or an equivalent rating) for the appropriate periods to calculate a credit risk adjustment. At December 31, 2011, the credit risk adjustment resulted in a $170 loss (or decrease in valuation). Changes in the fair value of derivatives affect the Company’s results of operations, but will not affect the Company’s cash flows until settled.

The following table sets forth a reconciliation of changes in the fair value of the Company’s derivatives classified as Level 3 in the fair value hierarchy:


	December 31,
	2011			2010
Balance at beginning of year	$	21,670		$	29,214
Total gains (realized or unrealized):
Included in earnings		4,197			8,866
Purchases, issuances and settlements
Purchases		—			—
Issuances		—			—
Sales		—			—
Settlements		(12,011	)		(16,410	)
Transfers in and out of Level 3		—			—

Balance at end of the year	$	13,856		$	21,670

Changes in unrealized gains relating to investments and derivatives still held as of December 31	$	3,293		$	4,884

Fair Value of Other Financial Instruments

Authoritative guidance on financial instruments requires certain fair value disclosures to be presented. The estimated fair value amounts have been determined using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

The carrying values of items comprising current assets and current liabilities approximate fair value due to the short-term maturities of these instruments. Derivative financial instruments included in the Company’s financial statements are stated at fair value; however, the Company’s oil and natural gas puts have a deferred premium. The deferred premium increases the derivative asset or reduces the derivative liability depending on the fair value of the derivative financial instruments.

The carrying amounts and fair value of the Company’s other financial instruments are as follows:


	December 31, 2011				December 31, 2010
	Carrying Value		Fair Value		Carrying Value		Fair Value
Current liability
Deferred premiums	$	1,607	$	1,607	$	1,363	$	1,363

Non-current liability
Deferred premiums	$	790	$	790	$	2,228	$	2,228

Nonrecurring Fair Value Measurements

The following table summarizes certain property and equipment measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition and their associated impairment:


	Year Ended December 31, 2011				Year Ended December 31, 2010
	Fair Value		Impairment		Fair Value		Impairment
Property and equipment	$	79,958	$	67,337	$	26,936	$	23,443

During 2011 and 2010, several fields were evaluated for impairment due to reductions in estimated reserves as a result of changes in economic assumptions (including prices and costs), drilling results and poorer than expected production performance results. The Company recorded impairments for several fields. The fair value of the property and equipment was measured as of the year ended December 31, 2011 and 2010 using an income approach based upon internal estimates of future production levels, prices and discount rate, which are Level 3 inputs.

7. Risk Management Activities

The Company utilizes financial instruments to manage risks related to changes in commodity prices. In 2011, the Company utilized financial instruments, including puts and collars, to reduce the volatility of oil and natural gas prices on a portion of the Company’s future expected oil and natural gas production. The Company has not designated any derivative instruments as hedges for accounting purposes. Realized gains and losses on the settlement of commodity derivative instruments and changes in unrealized gains and losses are reported separately in other income (expense) in the statement of income.

The Company’s commodity contracts outstanding at December 31, 2011 are summarized below:

Natural Gas Commodity Derivatives


Production Period	Transaction Type	Average Daily Volume (MMbtu)(1)		Weighted Average Swap/Floor Price ($/MMbtu)(2)		Weighted Average Ceiling Price ($/MMbtu)(2)		Weighted Average Net Floor Price ($/MMbtu)(2)(3)
2012	Collar		2,326	$	9.50	$	12.95	$	—
	Put		2,086		7.88		—		6.53
2013	Collar		656		10.00		12.40		—
	Put		1,366		7.07		—		5.64

(1)	MMbtu equals million British thermal units.

(2)	Reference price is NYMEX-Henry Hub.

(3)	Net floor price is the strike price less the deferred premium.

Crude Oil Commodity Derivatives


Production Period	Transaction Type	Average Daily Volume (Bbl)(1)		Weighted Average Swap/Floor Price ($/Bbl)(2)		Weighted Average Ceiling Price ($/Bbl)(2)		Weighted Average Net Floor/Ceiling Price ($/Bbl)(2)(3)
2012	Collar		119	$	120.00	$	166.25	$	—
	Put		54		120.00		—		99.26
2013	Collar		54		120.00		165.10		—
	Put		10		120.00		—		97.45

(1)	Bbl equals barrel of oil.

(2)	Reference price is NYMEX-WTI.

(3)	Net floor price is the strike price less the deferred premium.

Effect of Derivative Instruments on the Balance Sheet

At December 31, 2011 and 2010, the Company had the following outstanding commodity derivative contracts recorded on the balance sheet, none of which were designated as hedging instruments under ASC 815, “Derivatives and Hedging“:


		Estimated Fair Value
		December 31,
Instrument Type	Balance Sheet Location	2011		2010
Assets from risk management activities
Crude Oil Collars	Current assets	$	986	$	1,300
Crude Oil Puts	Current assets		474		609
Natural Gas Swaps	Current assets		—		838
Natural Gas Collars	Current assets		5,321		5,762
Natural Gas Puts	Current assets		3,489		2,599
Crude Oil Collars	Non-current assets		530		1,849
Crude Oil Puts	Non-current assets		96		697
Natural Gas Collars	Non-current assets		1,426		4,835
Natural Gas Puts	Non-current assets		1,534		3,181

Total assets from risk management activities			13,856		21,670

Fair value of risk management activities, net		$	13,856	$	21,670

The following table provides supplemental information to reconcile the fair value of the Company’s commodity derivative contracts to the balance sheet at December 31, 2011 and December 31, 2010:


	December 31,
	2011		2010
Assets from risk management activities—current asset	$	10,270	$	11,108
Assets from risk management activities—non-current assets		3,586		10,562

Fair value from risk management activities, net	$	13,856	$	21,670

The Company had $2,397 of derivative premiums payable recorded at December 31, 2011, of which $1,607 is classified as short-term and $790 is classified as long-term. At December 31, 2010, the Company had $3,591 of derivative premiums payable recorded, of which $1,363 is classified as short-term and $2,228 is classified as long-term. Derivative premiums are recorded as deferred premium on risk management activities on the balance sheet. The deferred premiums relate to various oil and natural gas price put contracts and are payable when the contracts settle.

Effect of Derivative Instruments on the Statement of Income

Below is a summary by type of the Company’s change in unrealized gain (loss) on commodity derivative contracts, net:


	Year Ended December 31, 2011			Year Ended December 31, 2010
Crude oil collars	$	(1,632	)	$	(3,358	)
Crude oil puts		(736	)		(1,182	)
Natural gas swaps		(839	)		787
Natural gas collars		(3,851	)		(3,212	)
Natural gas puts		(756	)		(579	)

	$	(7,814	)	$	(7,544	)

Below is a summary of the Company’s realized gain on commodity derivative contracts, net:


	Year Ended December 31, 2011		Year Ended December 31, 2010
Crude oil collars	$	1,146	$	2,763
Crude oil puts		599		849
Natural gas swaps		912		995
Natural gas collars		6,270		8,509
Natural gas puts		3,084		3,294

	$	12,011	$	16,410

8. Asset Retirement Obligations

The Company’s asset retirement obligations were $342,122 as of December 31, 2011, of which $17,749 are expected to be incurred over the next twelve months. Activity related to the Company’s asset retirement obligation during the years ended December 31, 2011 and 2010 is as follows:


	2011			2010
Balance at beginning of period	$	252,447		$	223,953
Accretion expense		11,461			9,356
Asset retirement costs incurred		(7,007	)		(2,694	)
Liabilities incurred during the period		35,965			—
Revisions in estimates(1)		49,256			21,832

Balance at end of period	$	342,122		$	252,447

(1)	In 2011 and 2010, the revisions in estimates relate to changes in estimates of the Company’s expected plugging and abandonment costs, facility removal costs and the life of several fields.

9. Commitments and Contingencies

The Company has a $644 commitment to use the services of an offshore drilling rig contractor which ends April 1, 2012.

Company believes that its ultimate liability with respect to any such matters will not have a significant impact or material adverse effect on its financial position, results of operations or cash flows. Results of operations and cash flows, however, could be significantly impacted in the reporting periods in which such matters are resolved.

10. Recent Accounting Pronouncements

In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs”. The amendments in ASU No. 2011-04 generally represent clarifications of Topic 820, but also include some instances where a particular principle or requirement for measuring fair value or disclosing information about fair value measurements has changed. ASU No. 2011-04 results in common principles and requirements for measuring fair value and for disclosing information about fair value measurements in accordance with U.S. GAAP and IFRS. The amendments in ASU No. 2011-04 are to be applied prospectively. The amendments are effective for interim and annual periods beginning after December 15, 2011. The Company does not expect this guidance to have a significant impact on its financial position, results of operations or cash flows.

In June 2011, the FASB issued ASU No. 2011-05, “Presentations of Comprehensive Income,” requiring most entities to present items of net income and other comprehensive income either in one continuous statement-referred to as the statement of comprehensive income-or in two separate, but consecutive, statements of net income and other comprehensive income. The new requirements are effective for fiscal years (including interim periods) beginning after December 15, 2011. The Company does not expect this guidance to have a significant impact on its financial position, results of operations or cash flows.

In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities,” requiring disclosure of gross information and net information about instruments and transactions eligible for offset arrangement. The guidance is effective for interim and annual periods beginning on or after January 1, 2013. The Company does not expect adoption of the additional disclosures about offsetting assets and liabilities to have a significant impact on its financial position, results of operations or cash flows.

11. Subsequent Events

These financial statements were published on March 30, 2012 and all subsequent events since December 31, 2011 through March 30, 2012 were considered by management for purposes of analysis and disclosure.

12. Oil and Natural Gas Activities (unaudited)

The Company follows the SEC’s final rule, Modernization of Oil and Gas Reporting, and the FASB’s authoritative guidance on extractive activities for oil and natural gas.

Costs Incurred

The Company’s oil and natural gas acquisition, exploration and development activities are conducted in the United States of America. The following table summarizes the costs incurred during the last two years for property acquisitions, exploration and development activities as follows:


	Year ended December 31, 2011		Year ended December 31, 2010
Acquisition costs
Unproved properties	$	—	$	—
Proved properties		104,210		191
Development costs		46,245		126,539
Exploration costs		78		28

Costs incurred	$	150,533	$	126,758

ARO is not included above. For further discussion of ARO see Note 8.

Supplemental Reserve Information

The following information summarizes the Company’s net proved crude oil, natural gas and natural gas liquids reserves and the present values thereof for the two years ended December 31, 2011. All of the Company’s reserves are located in the United States of America. In 2011 and 2010, the Company’s reserve reports were prepared by the independent petroleum engineers of W.D. Von Gonten & Co.

Management has reviewed the estimates presented herein and considers such estimates to be reasonable. However, there are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and the amount and timing of development expenditures, including many factors beyond the Company’s control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As all reserve estimates are subjective, the quantities of oil and natural gas that are ultimately recovered, producing and operating costs, the amount and timing of future development expenditures and future oil and natural gas sales prices may all differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. Therefore, the Standardized Measure shown below represents estimates only and should not be construed as the current market value of the estimated oil and natural gas reserve attributable to the Company’s properties. In this regard, the information set forth in the following tables includes revisions of reserve estimates attributable to proved properties included the preceding year’s estimates. Such revisions reflect additional information from subsequent development activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from change in product prices. Decreases in the price of oil and natural gas have had and could have in the future, an adverse effect on the carrying value of the Company’s proved reserves, reserve volume and operating revenues, profitability and cash flow.

The information may be useful for certain comparative purposes, but should not be solely relied upon in evaluating the Company or its performance. Furthermore, information contained in the following tables may not represent realistic assessments of future cash flows, nor should the Standardized Measure of discounted future net cash flows be viewed as representative of the current value of the Company. Management believes that the following factors should be considered when reviewing the following information:

•

Future commodity prices received for selling the Company’s net production will probably differ from those required to be used in these calculations.

•

Future operating and capital costs will probably differ from those required to be used in these calculations.

•

Future market conditions, government regulations and reservoir conditions may cause production rates in future years to vary significantly from those rates used in these calculations.

•

Future revenues may be subject to different production rates in the future.

•

The selection of a 10% discount rate is arbitrary and may not be a reasonable factor in adjusting for future economic conditions or in considering the risk that is part of realizing future net cash flows from the reserves.

Management generally does not use the Standardized Measure when making investment and operating decisions. Such decisions are based on a number of factors, including unproved reserves and estimates of future prices and costs which change from time to time but are considered to be more representative of the range of anticipated economic conditions at the time.

The following table summarizes the estimated quantities of the Company’s net proved reserves:


	Crude Oil (MBbls)			Natural Gas (MMcf)			NGL (MBbls)			Total Equivalent Reserves (MBOE)(1)
Proved reserves:
Reserves as of December 31, 2009		5,425			98,752			556			22,439
Production		(700	)		(14,089	)		(175	)		(3,223	)
Divestitures		—			—			—			—
Acquisitions		—			—			—			—
Extensions and discoveries		3,621			24,170			328			7,977
Revisions		(45	)		(19,834	)		821			(2,529	)

Reserves as of December 31, 2010		8,301			88,999			1,530			24,664

Production		(1,415	)		(14,613	)		(146	)		(3,997	)
Divestitures		—			—			—			—
Acquisitions		3,841			22,256			—			7,550
Extensions and discoveries		1,799			6,435			109			2,981
Revisions		1,151			(11,342	)		(191	)		(930	)

Reserves as of December 31, 2011		13,677			91,735			1,302			30,269

Proved developed reserves:
Reserves as of December 31, 2010		4,443			46,546			764			12,965
Reserves as of December 31, 2011		8,406			50,210			618			17,393
Proved undeveloped reserves:
Reserves as of December 31, 2010		3,858			42,453			766			11,699
Reserves as of December 31, 2011		5,271			41,525			684			12,876

(1)	Quantities are in thousands of barrel of oil equivalents. Natural gas quantities have been converted to barrel of oil equivalents using a factor of six million cubic feet per thousand barrels.

Standardized Measure of Discounted Future Net Cash Flows

The Standardized Measure of discounted future net cash flows relating to proved reserves is presented as follows:


	At December 31,
	2011			2010
Future cash inflows	$	1,931,319		$	1,098,959
Future production costs		(615,001	)		(300,094	)
Future development costs		(633,218	)		(476,346	)

Future net cash flows		683,100			322,519
Less 10% annual discount(1)		(128,294	)		(14,061	)

Standardized Measure of discounted future net cash flows	$	554,806		$	308,458

(1)	“Less 10% annual discount” reflects significant expected abandonment costs in future years that, when discounted, have the effect of causing the total discounted cash flows to be greater than the undiscounted cash flows, as it relates to these expected future abandonment costs.

The Standardized Measure of discounted future net cash flows (discounted at 10%) was developed as follows:

•

An estimate was made of the quantity of proved reserves and the future periods in which they are expected to be produced based on year end economic conditions.

•

In accordance with SEC guidelines, the engineers’ estimates of future net revenues from the Company’s proved properties and the present value thereof are made using the twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials. These prices are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. The Company used various derivative instruments to manage its exposure to commodity prices (see Note 7). The derivative instruments the Company had in place were not classified as hedges for accounting purposes. The realized sale prices used in the reserve reports, not including the effects of the Company’s commodity derivative contracts, as of December 31, 2011 and 2010, for crude oil ($ per Bbl) were $96.12 and $79.49, respectively, and for natural gas ($ per Mcf) were $4.12 and $4.37, respectively.

•

The future gross revenue streams were reduced by estimated future operating costs and future development and abandonment costs, all of which were based on current costs in effect at December 31 of the year presented and held constant throughout the life of the properties.

Changes in Standardized Measure of Discounted Future Net Cash Flows

The principal sources of the changes in the Standardized Measure of discounted future net cash flows for the years ended December 31, 2011 and 2010, are as follows:


	2011			2010
At beginning of period	$	308,458		$	77,500
Sales, net of production costs		(120,389	)		(65,928	)
Change in sales and transfer prices, net		114,092			161,729
Development costs incurred		23,707			41,819
Change in future development cost		12,247			10,649
Extensions and discoveries		74,041			177,125
Purchases of minerals in place		73,630			—
Revisions of quantity estimates		(11,630	)		(8,735	)
Accretion of discount		30,846			7,750
Changes in production rates and other(1)		49,804			(93,451	)

At December 31	$	554,806		$	308,458

(1)	“Changes in production rates and other” reflects significant expected abandonment costs in future years that, when discounted, have the effect of causing the total discounted cash flows to be greater than the undiscounted cash flows, as it relates to these expected future abandonment costs.

LOGO

Report of Independent Auditors

To the Member of Hilcorp Energy GOM, LLC:

In our opinion, the accompanying consolidated balance sheets and the related statements of income, of member’s capital and of cash flows present fairly, in all material respects, the financial position of Hilcorp Energy GOM, LLC at December 31, 2010 and 2009, and the results of their operations and their cash flows each of the years ended in conformity with accounting principles generally accepted in the United States of America. 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 of these statements in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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.

LOGO

March 31, 2011

PricewaterhouseCoopers LLP, 1201 Louisiana, Suite 2900, Houston, TX 77002-5678

T: (713) 356 4000, F: (713) 356 4717, www.pwc.com/us

Hilcorp Energy GOM, LLC

Balance Sheet


(in thousands of dollars)	December 31,
(in thousands of dollars)	2010		2009
Assets
Current assets:
Cash and cash equivalents	$	33	$	66
Accounts receivable from affiliates		32,336		18,883
Assets from risk management activities		11,108		12,485
Other current assets		1,478		2,223

Total current assets		44,955		33,657

Property and equipment, net		422,952		383,512
Assets from risk management activities		10,562		16,787

Total assets	$	478,469	$	433,956

Liabilities and Member’s Capital
Current liabilities:
Accounts payable and accrued liabilities	$	640	$	1,248
Liabilities from risk management activities		—		58
Accounts payable to affiliates		19,914		16,356
Deferred premiums on risk management activities		1,363		1,143
Liabilities for asset retirement obligations		22,000		7,640

Total current liabilities		43,917		26,445

Liabilities for asset retirement obligations		230,447		216,313
Deferred premiums on risk management activities		2,228		3,486
Commitments and contingencies
Member’s capital		201,877		187,712

Total liabilities and member’s capital	$	478,469	$	433,956

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

Hilcorp Energy GOM, LLC

Statement of Income


(in thousands of dollars)	Year Ended December 31,
(in thousands of dollars)	2010			2009
Operating revenues:
Natural gas sales	$	63,305		$	39,034
Crude oil and products sales		64,167			25,816
Other revenues		222			404

Total operating revenues		127,694			65,254

Operating expenses:
Oil and natural gas operating expenses		61,076			44,656
Transportation charges		690			623
Exploration expenses		39			34
Depletion, depreciation and amortization		87,130			43,766
Impairment of property and equipment		23,443			531
Accretion of asset retirement obligations		9,356			5,896
General and administrative expenses		11,147			7,139

Total operating expenses		192,881			102,645

Gain (loss) on sale of property and equipment, net		(14	)		107

Operating loss		(65,201	)		(37,284	)

Other income (expense):
Change in unrealized loss on commodity derivative contracts, net		(7,544	)		(25,983	)
Realized gain on commodity derivative contracts, net		16,410			33,579
Interest expense		—			(545	)
Loss on debt extinguishment		—			(838	)

Total other income		8,866			6,213

Net loss	$	(56,335	)	$	(31,071	)

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

Hilcorp Energy GOM, LLC

Statement of Member’s Capital


(in thousands of dollars)	Sole Member
Balance at December 31, 2008	$	75,318
Contributions		153,165
Distributions		(9,700	)
Comprehensive loss:
Net loss		(31,071	)

Total comprehensive loss		(31,071	)

Balance at December 31, 2009		187,712
Contributions		70,500
Comprehensive loss:
Net loss		(56,335	)

Total comprehensive loss		(56,335	)

Balance at December 31, 2010	$	201,877

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

Hilcorp Energy GOM, LLC

Statement of Cash Flows


(in thousands of dollars)	Year Ended December 31,
(in thousands of dollars)	2010			2009
Cash flows from operating activities:
Net loss	$	(56,335	)	$	(31,071	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Exploration expenses		—			7
Depletion, depreciation and amortization		87,130			43,766
Impairment of property and equipment		23,443			531
Accretion of asset retirement obligations		9,356			5,896
Amortization of deferred financing costs		—			86
Loss (gain) on sale of property and equipment, net		14			(107	)
Unrealized loss on derivative contracts, net		7,544			25,983
Loss on debt extinguishment		—			838
Changes in assets and liabilities:
Account receivable from affiliate		(19,457	)		(18,883	)
Other current assets		745			3,207
Risk management activities		(1,038	)		(1,303	)
Accounts payable and accrued liabilities		(608	)		472
Accounts payable to affiliates		1,832			(252	)
Other		(2,694	)		(1,279	)

Net cash provided by operating activities		49,932			27,891

Cash flows from investing activities:
Acquisitions of oil and natural gas properties		(191	)		(114,877	)
Additions to oil and natural gas properties		(126,567	)		(20,952	)
Proceeds from insurance carriers		6,004			—
Proceeds (payments) from sale of property and equipment		289			(17	)

Net cash provided by (used in) investing activities		(120,465	)		(135,846	)

Cash flows from financing activities:
Proceeds from long-term debt		—			12,000
Payments on long-term debt		—			(50,000	)
Payments of financing costs		—			(15	)
Distributions		—			(9,700	)
Contributions		70,500			153,165

Net cash provided by financing activities		70,500			105,450

Net change in cash and cash equivalents		(33	)		(2,505	)
Cash and cash equivalents at beginning of period		66			2,571

Cash and cash equivalents at end of period	$	33		$	66

Supplemental cash flow information:
Cash paid for interest	$	—		$	462
Accrued capital expenditures		1,726			401

Hilcorp Energy GOM, LLC

Notes to Financial Statements

(amounts in thousands, except volumes)

1. Organization and Summary of Significant Accounting Policies

Organization and Nature of Business

Hilcorp Energy GOM, LLC (the Company or HGOM) is primarily engaged in the production and development of oil and natural gas properties. The Company holds interests in oil and natural gas producing properties, located in the Gulf of Mexico, primarily offshore Louisiana and Texas. The Company has an agreement with Hilcorp Energy Company (HEC) to provide operating and other services to the Company.

The Company is a Texas limited liability company that was organized on March 6, 2008 (Inception) by Hilcorp Energy GOM Holdings, LLC (HHGOM), its sole member. The Company shall continue until it is liquidated or dissolved in accordance with the limited liability agreement.

Basis of Presentation

The accompanying financial statements have been prepared on the accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America.

Cash and Cash Equivalents

Inventory

Hydrocarbon inventory, consisting of crude oil in tanks, is valued at the lower of average cost or market value and is included in other current assets on the balance sheet. Hydrocarbon inventory was $163 and $82 as of December 31, 2010 and 2009, respectively.

Property and Equipment

The Company evaluates the need for impairment of its oil and natural gas properties on a field-by-field basis, annually or whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. Property and equipment is reduced to fair value if the sum of the expected undiscounted future cash flows is less than the asset’s net book value. Cash flows are determined based upon proved reserves using prices and costs consistent with those used for internal decision making. The underlying commodity prices incorporated in the Company’s cash flow estimates are the result of a process that begins with the New York Mercantile Exchange (NYMEX) pricing, adjusted for location and quality differentials, as well as other factors that management believes will impact realizable prices.

During 2010 and 2009, the Company recognized non-cash charges of $23,443 and $531, respectively, related to the impairment of several fields. These impairments were related to downward revisions of previous estimates of proved oil and natural gas reserve quantities as a result of changes in the economic assumptions (including prices and costs) and production performance for these fields.

Costs of retired, sold or abandoned properties that constitute a part of an amortization base (partial field) are charged to accumulated depreciation, depletion and amortization if the unit-of-production rate is not significantly affected. Accordingly, a gain or loss, if any, is recognized only when a group of proved properties (entire field) that make up the amortization base has been retired, abandoned or sold, or a group of properties that make up part of an amortization base has been retired, abandoned or sold and deferral of the gain or loss would significantly affect the unit-of-production rate.

Business Combinations

Asset Retirement Obligations

The Company records its asset retirement obligations (ARO) as a liability at its estimated net present value at the asset’s inception, with the offsetting charge to property and equipment. Periodic accretion of the discount of the estimated liability is recorded in the statement of income. The ARO represents the estimated present value of the amount the Company will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable federal laws. The Company has determined the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing, existence of a liability, as well as what constitutes adequate restoration. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the related asset.

Deferred Costs

The Company capitalizes costs incurred in connection with obtaining financing. These costs include fees paid to financial institutions, legal, accounting, engineering and other fees and are included in deferred financing costs on the balance sheet. These costs were being amortized over the remaining term of the related indebtedness using the straight-line method, which approximates the interest method. In May 2009, the Company’s credit facility was repaid and terminated and the associated deferred financing costs were expensed (see Note 7). Financing costs of $87 were amortized in the statement of income for the year ended December 31, 2009.

Revenue Recognition

Gas Imbalances

Revenues from natural gas production may result in more or less than the Company’s pro rata share of production from certain wells. The Company follows the sales method of accounting for natural gas sales and gas imbalances. When sales volumes exceed the Company’s entitled share and the overproduced balance exceeds the Company’s share of remaining estimated proved natural gas reserves for a given property, the Company records a liability. The Company had overproduced liabilities of $521 and $693, recorded in accounts payable and accrued liabilities on the balance sheet at December 31, 2010 and 2009, respectively.

At December 31, 2010, the Company’s underproduced natural gas position was approximately $394 (93.4 MMcf) at an average price of $4.22 per Mcf and its overproduced natural gas position was approximately $746 (129.3 MMcf) at an average price of $4.21 per Mcf. At December 31, 2009, the Company’s underproduced natural gas position was approximately $241 (51.6 MMcf) at an average price of $4.68 per Mcf and its overproduced natural gas position was approximately $1,083 (239.6 MMcf) at an average price of $4.52 per Mcf.

Environmental Costs

Expenditures for environmental remediation are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not have future economic benefit, are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and costs can be reasonably estimated. At December 31, 2010 and 2009, there were no environmental liabilities recorded on the balance sheet.

Income Taxes

Contributions and Distributions

During the year ended December 31, 2009, the Company made cash distributions of $9,700 to the sole member. During the years ended December 31, 2010 and 2009, the sole member made cash contributions of $70,500 and $153,165, respectively to the Company.

Concentrations of Credit Risk

Risk Management

The Company utilizes financial instruments to manage risks related to changes in commodity prices. During 2010 and 2009, the Company utilized financial instruments, including oil and natural gas fixed-price swaps, puts and collars to reduce the volatility of oil and natural gas prices on a portion of the Company’s future expected oil and natural gas production.

The Company records all derivative instruments on the balance sheet at their estimated fair value. The Company has not designated any derivative instruments as hedges for accounting purposes. Realized gains and losses on the settlement of commodity derivative instruments and changes in unrealized gains and losses are reported separately in other income (expense) in the statement of income. If the Company terminates a derivative instrument prior to maturity, any cash paid or received upon settlement is recognized immediately and reported separately in other income (expense). Unrealized gains are included in current and noncurrent assets from risk management activities and unrealized losses are included in current and noncurrent liabilities from risk management activities on the balance sheet, respectively.

Use of Estimates

Risk and Uncertainties

Fair Value of Financial Instruments

The Company has financial instruments such as cash and cash equivalents, accounts receivable from affiliates, accounts payable to affiliates and deferred premiums on risk management activities. These financial instruments are stated at cost which approximates market value. The Company has other financial instruments in the form of commodity derivative contracts which are used to reduce the impact of oil and natural gas price fluctuations (see Note 8). The fair value of commodity derivative instruments is based on the difference between the contractual fixed prices and forward market prices, discounted, on the contracted notional volumes and further discounted for counterparty nonperformance risk, if necessary.

Segment Information

All of the Company’s oil and natural gas properties and related operations are located in the United States of America and management has determined that the Company has one reportable segment.

2. Contribution of Hilcorp Energy GOM Holdings, LLC

In May 2009, the members of HHGOM, contributed their respective member interests in HHGOM to Hilcorp Energy I, LP (HEI) and HHGOM became a wholly owned subsidiary of HEI. HEI is a Texas limited liability company that was organized in February 1994. HEI is primarily engaged in the exploration, production and development of oil and natural gas properties located primarily onshore along the gulf coast of Louisiana and Texas and offshore in the federal outer continental shelf of the Gulf of Mexico.

After the contribution of the member interests, HEI contributed $38,061 to HHGOM which, in turn, contributed the funds to the Company to repay all of the outstanding borrowings under the credit facility.

3. Acquisitions and Dispositions of Oil and Natural Gas Properties

Acquisitions

On December 8, 2009, the Company acquired working and net revenue interests in oil and natural gas properties located in the federal outer continental shelf of the Gulf of Mexico for $60,314, subject to customary adjustments. The Company used contributions from its sole member to fund this transaction. This acquisition has an effective date of November 1, 2009. The acquisition qualifies as a business combination and the Company has estimated the fair value of this property as of December 8, 2009, the closing 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. The Partnership used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs as defined by ASC 820. The fair value of these properties was assigned to the assets and liabilities acquired, which included $98,401 to proved properties, $31,870 to unproved properties and $69,957 for asset retirement obligations. Because the estimated fair value and purchase price were equivalent, the Company did not record goodwill or a gain related to this acquisition. The Company’s statement of income includes $623 of net loss for the year ended December 31, 2009 related to the acquisition, which includes acquisition related expenses.

The Company has not presented any pro forma information for this acquisition as the properties have been idle since the 2008 hurricanes with no revenues and minimal expenses in 2009. Therefore, the pro forma effect was not material to the Company’s results of operations for the year ended December 31, 2009.

On July 16, 2009, the Company acquired working and net revenue interests in oil and natural gas properties located in the federal outer continental shelf of the Gulf of Mexico for $54,791, subject to customary adjustments. The Company used contributions from its sole member to fund this transaction. This acquisition has an effective date of July 1, 2009. The acquisition qualifies as a business combination and the Company has estimated the fair value of this property as of July 16, 2009, the closing 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. The Partnership used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs as defined by ASC 820. The fair value of these properties was assigned to the assets and liabilities acquired, which included $97,544 to proved properties, $32,579 to unproved properties and $75,332 for asset retirement obligations. Because the estimated fair value and purchase price were equivalent, the Company did not record goodwill or a gain related to this acquisition. The Company’s statement of income includes $14,448 of operating revenues for the year ended December 31, 2009 and $10,308 of net loss for the year ended December 31, 2009 related to the acquisition.

Summarized below are the consolidated results of operations for the year ended December 31, 2009 on an unaudited pro forma basis as if the acquisition had occurred at the beginning of the period presented. This unaudited pro forma information has been prepared based on the Company’s historical statement of income and estimates based on information provided by third-parties. This unaudited pro forma information was then adjusted to include estimated general and administrative expenses and depreciation and depletion expenses. This unaudited pro forma information is not necessarily indicative of the operating results that would have occurred at that date, nor are they necessarily indicative of future operating results.


	Year Ended December 31, 2009
Total operating revenues	$	85,236
Net income (loss)		(32,945	)

In May 2009, the Company acquired additional working and net revenue interests in oil and natural gas properties located in the federal outer continental shelf of the Gulf of Mexico for $5,790, subject to customary adjustments, and recorded asset retirement obligations of $7,724 associated with these interests. The Company used proceeds from its credit facility to fund this transaction.

4. Related Party Transactions

The Company compensates HEC for providing these services. During 2010 and 2009, payments to HEC for these services are 7.5% of operating revenues on an annual basis plus certain permitted expenses and are included in general and administrative expenses in the statement of income. The Company paid $10,824 and $6,326 for the years ended December 31, 2010 and 2009, respectively, to HEC for providing these services. Additionally, the Company incurred $323 and $813 for the years ended December 31, 2010 and 2009, respectively, in permitted expenses as reimbursement to HEC for direct third-party charges for accounting, legal and engineering services.

Accounts receivable from and payable to affiliates were as follows:


	December 31,
	2010		2009
Accounts receivable from affiliates:
Receivables from oil and natural gas sales	$	32,336	$	15,908
Receivable for insurance claims		—		2,975

	$	32,336	$	18,883

Accounts payable to affiliates:
Payables for operating and capital expenditures	$	19,914	$	16,356

5. Significant Concentrations

During the year ended December 31, 2009, approximately 63%, 11% and 10% of the Company’s oil and natural gas revenues were attributable to sales to Chevron USA Production Company, Hess Corporation and Enbridge Energy Partners L.P., respectively.

6. Property and Equipment

Property and equipment consisted of the following:


	December 31,
	2010			2009
Unproved oil and natural gas properties	$	52,483		$	70,885
Proved oil and natural gas properties (successful efforts method)		562,653			394,237
Less accumulated depreciation, depletion and amortization		(192,184	)		(81,610	)

Property and equipment, net	$	442,952		$	383,512

During 2010, the Company transferred $18,391 of unproved properties to proved properties and received a credit of $11 related to exploration drilling. During 2009, the Company added $67,335 to unproved properties related to the 2009 acquisitions, added $938 related to exploration drilling, transferred $39,739 of unproved properties to proved properties and expensed $7 of dry hole costs to exploration expense in the statement of income.

The following table reflects the net changes in capitalized exploratory well costs:


	2010			2009
Balance of January 1,	$	—		$	—
Additions		(11	)		938
Transfers to proved properties		11			(931	)
Charged to expense		—			(7	)

Balance of December 31,	$	—		$	—

At December 31, 2010 and 2009, the Company had no suspended well costs related to wells that have been completed for more than one year.

7. Long-term Debt

Credit Facility

In July 2008, the Company entered into a credit agreement with a group of financial institutions to finance a portion of the initial acquisition and provide for ongoing operating and general corporate needs. The credit facility had two components, a revolving credit and a term loan. The revolving credit had a final maturity of July 31, 2012 and the availability under it was governed by semi-annual borrowing base determinations. The credit facility was required to be secured by mortgages on at least 89% of the Company’s oil and natural gas properties while the term loan was outstanding and that requirement was reduced to 80% once the term loan was repaid in full. The credit agreement contained numerous covenants and restrictions including limitations on indebtedness, liens, nature of business, leases, gas imbalances, assets sales, derivative transactions, investments and distributions. Various covenants in the credit agreement required the Company to maintain a minimum interest coverage ratio, maintain a minimum current ratio, not exceed a maximum leverage ratio and limit the amount of general and administrative expenses that may be paid to HEC in any year to $2,500.

In May 2009, all outstanding borrowings under the credit facility were repaid through member contributions (see Note 2) and the credit facility was terminated. The Company recognized a loss on debt extinguishment of $838 related to the write-off of deferred financing costs associated with the credit agreement as of December 31, 2009.

The credit agreement required payment of interest at the U.S. prime rate or the Eurodollar rate plus an applicable margin. The applicable margin for the revolving credit portion was 0.00% to 0.75% over the U.S. prime rate or 1.50% to 2.25% over the rounded Eurodollar rate, depending on the ratio of the outstanding principal amount compared to the borrowing base on the interest rate determination date. The applicable margin for the term loan portion was 2.5% over the U.S. prime rate or 4% over the rounded Eurodollar rate. During 2009, the Company incurred financing costs of $15 related to the credit facility.

During the year ended December 31, 2009, the Company had interest expense related to its credit facility of $455.

8. Fair Value Measurements

The Company adopted ASC 820, “Fair Value Measurements and Disclosures,” for financial assets and liabilities measured on a recurring basis and as of January 1, 2009 adopted additional guidance for nonrecurring, nonfinancial assets and liabilities. ASC 820 requires disclosure that establishes a framework for measuring fair value and expands disclosure about fair value measurements. The statement characterizes inputs used in determining fair value using a hierarchy that prioritizes inputs depending on the degree to which they are observable.


Level 1:		Observable, unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2:		Observable inputs such as: (i) quoted prices for similar assets or liabilities in active markets; (ii) quoted prices for identical or similar assets or liabilities in markets that are not active; or (iii) valuations based on pricing models where significant inputs (e.g., interest rates, yield curves, etc.) are observable for the assets or liabilities, are derived principally from observable market data, or can be corroborated by observable market data.

Level 3:		Unobservable inputs, including valuations based on pricing models where significant inputs are not observable and not corroborated by market data. Unobservable inputs used to the extent that observable inputs are not available and reflect the Company’s own assumptions about the assumptions market participants would use in pricing the assets or liabilities. Unobservable inputs are based on the best information available in the circumstances, which might include the Company’s own data.

Recurring Fair Value Measurements

The following table presents the valuation of the Company’s financial instruments by fair value hierarchy levels:


	Fair Value Measurements at Reporting Date Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Fair Value
December 31, 2010
Assets:
Derivative contracts
Crude oil and natural gas swaps		—		—		838		838
Crude oil and natural gas collars		—		—		13,746		13,746
Crude oil and natural gas puts		—		—		7,086		7,086

Total assets	$	—	$	—	$	21,670	$	21,670

December 31, 2009
Assets:
Derivative contracts
Crude oil and natural gas swaps	$	—	$	—	$	109	$	109
Crude oil and natural gas collars		—		—		20,317		20,317
Crude oil and natural gas puts		—		—		8,846		8,846

Total assets	$	—	$	—	$	29,272	$	29,272

Liabilities:
Derivative Contracts
Crude oil and natural gas swaps	$	—	$	—	$	58	$	58

Total liabilities	$	—	$	—	$	58	$	58

For liability positions, the Company has minimal risk of non-performance as all derivative contracts are secured by the Company’s oil and natural gas properties. The Company uses a third-party to value the derivative instruments it holds and compares these values against the counterparty’s valuations on a regular basis to confirm that the valuations reflected are appropriate and reasonable. For asset positions, the credit exposure by counterparty is assessed by reviewing each counterparty’s total position. The Company uses the credit default swap rate (or an equivalent rating) for the appropriate periods to calculate a credit risk adjustment. At December 31, 2010, the credit risk adjustment resulted in a $114 loss (or decrease in valuation). Changes in the fair value of derivatives affect the Company’s results of operations, but will not affect the Company’s cash flows until settled.

The following table sets forth a reconciliation of changes in the fair value of the Company’s derivatives classified as Level 3 in the fair value hierarchy:


	2010			2009
Balance at beginning of period	$	29,214		$	53,524
Total gains or losses (realized or unrealized):
Included in earnings		8,866			7,596
Included in other comprehensive income		—			—
Purchases, issuances and settlements
Purchases		—			1,673
Issuances		—			—
Sales		—			—
Settlements		(16,410	)		(33,579	)
Transfers in and out of Level 3		—			—

Balance at end of the period	$	21,670		$	29,214

Changes in unrealized gains (losses) relating to investments and derivatives still held as of December 31	$	4,884		$	2,416

Fair Value of Other Financial Instruments

The carrying amounts and fair value of the Company’s other financial instruments are as follows:


	December 31, 2010				December 31, 2009
	Carrying Value		Fair Value		Carrying Value		Fair Value
Current liability
Deferred premiums	$	1,363	$	1,363	$	1,143	$	1,143

Non-current liability
Deferred premiums	$	2,228	$	2,228	$	3,486	$	3,486

Nonrecurring Fair Value Measurements

The following table summarizes certain property and equipment measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition and their associated impairment:


	Year Ended December 31, 2010				Year Ended December 31, 2009
	Fair Value		Impairment		Fair Value		Impairment
Property and equipment	$	26,936	$	23,443	$	2,037	$	531

During 2010 and 2009, several fields were evaluated for impairment due to reductions in estimated reserves. The fair value of the property and equipment was measured as of the year ended December 31, 2010 and 2009 using an income approach based upon internal estimates of future production levels, prices and discount rate, which are Level 3 inputs.

9. Risk Management Activities

The Company utilizes financial instruments to manage risks related to changes in commodity prices. In 2010, the Company utilized financial instruments, including oil and natural gas fixed-price swaps, puts and collars, to reduce the volatility of oil and natural gas prices on a portion of the Company’s future expected oil and natural gas production. The Company has not designated any derivative instruments as hedges for accounting purposes. Realized gains and losses on the settlement of commodity derivative instruments and changes in unrealized gains and losses are reported separately in other income (expense) in the statement of income.

The Company’s commodity contracts outstanding at December 31, 2010 are summarized below:

Natural Gas Commodity Derivatives


Production Period	Transaction Type	Average Daily Volume (MMbtu)(1)		Weighted Average Swap/Floor Price ($/MMbtu)(2)		Weighted Average Ceiling Price ($/MMbtu)(2)		Weighted Average Net Floor Price ($/MMbtu)(2)(3)
2011	Swap Collar Put		1,073 3,175 1,916	$	6.55 9.50 8.34	$	— 13.30 —	$	— — 7.15

2012	Collar Put		2,326 2,086		9.50 7.88		12.95 —		— 6.53

2013	Collar Put		656 1,366		10.00 7.07		12.40 —		— 5.64

(1)	MMbtu equals million British thermal units.

(2)	Reference price is NYMEX-Henry Hub.

(3)	The net floor price is the strike price less the deferred premium.

Crude Oil Commodity Derivatives


Production Period	Transaction Type	Average Daily Volume (Bbl)(1)		Weighted Average Swap/Floor Price ($/Bbl)(2)		Weighted Average Ceiling Price ($/Bbl)(2)		Weighted Average Net Floor/Ceiling Price ($/Bbl)(2)(3)
2011	Collar Put		131 61	$	120.00 120.00	$	167.35 —	$	— 100.85

2012	Collar Put		119 54		120.00 120.00		166.25 —		— 99.26

2013	Collar Put		54 10		120.00 120.00		165.10 —		— 97.45

(1)	Bbl equals barrel of oil.

(2)	Reference price is NYMEX-WTI.

(3)	Net floor price is the strike price less the deferred premium.

Effect of Derivative Instruments on the Balance Sheet

At December 31, 2010 and 2009, the Company had the following outstanding commodity derivative contracts recorded on the balance sheet, none of which were designated as hedging instruments under ASC 815, “Derivatives and Hedging“:


		Estimated Fair Value
		December 31,
Instrument Type	Balance Sheet Location	2010		2009
Assets from risk management activities
Crude Oil Collars	Current assets	$	1,300	$	2,612
Crude Oil Puts	Current assets		609		816
Natural Gas Swaps	Current assets		838		24
Natural Gas Collars	Current assets		5,762		6,615
Natural Gas Puts	Current assets		2,599		2,418
Crude Oil Collars	Non-current assets		1,849		3,894
Crude Oil Puts	Non-current assets		697		1,671
Natural Gas Swaps	Non-current assets		—		85
Natural Gas Collars	Non-current assets		4,835		7,196
Natural Gas Puts	Non-current assets		3,181		3,941

Total assets from risk management activities			21,670		29,272

Liabilities from risk management activities
Natural Gas Swaps	Current liabilities		—		58

Total liabilities from risk management activities			—		58

Fair value of risk management activities, net		$	21,670	$	29,214

The following table provides supplemental information to reconcile the fair value of the Company’s commodity derivative contracts to the balance sheet at December 31, 2010 and December 31, 2009:


	December 31,
	2010		2009
Assets from risk management activities—current asset	$	11,108	$	12,485
Assets from risk management activities—non-current assets		10,562		16,787
Liabilities from risk management activities—current liability		—		58

Fair value from risk management activities, net	$	21,670	$	29,214

The Company had $3,591 of derivative premiums payable recorded at December 31, 2010, of which $1,363 is classified as short-term and $2,228 is classified as long-term. At December 31, 2009, the Company had $4,629 of derivative premiums payable recorded, of which $1,143 is classified as short-term and $3,486 is classified as long-term. Derivative premiums are recorded as deferred premium on risk management activities on the balance sheet. The deferred premiums relate to various oil and natural gas price put contracts and are payable when the contracts settle.

Effect of Derivative Instruments on the Statement of Income

Below is a summary by type of the Company’s change in unrealized gain (loss) on commodity derivative contracts, net:


	Year Ended December 31, 2010			Year Ended December 31, 2009
Crude oil collars	$	(3,358	)	$	(10,174	)
Crude oil puts		(1,182	)		(3,189	)
Natural gas swaps		787			52
Natural gas collars		(3,212	)		(9,032	)
Natural gas puts		(579	)		(3,640	)

	$	(7,544	)	$	(25,983	)

Below is a summary of the Company’s realized gain on commodity derivative contracts, net:


	Year Ended December 31, 2010		Year Ended December 31, 2009
Crude oil collars	$	2,763	$	7,045
Crude oil puts		849		1,939
Natural gas swaps		995		122
Natural gas collars		8,509		17,917
Natural gas puts		3,294		6,556

	$	16,410	$	33,579

10. Asset Retirement Obligations

The Company’s asset retirement obligations were $252,447 as of December 31, 2010, of which $22,000 are expected to be incurred over the next twelve months. Activity related to the Company’s asset retirement obligation during the years ended December 31, 2010 and 2009 is as follows:


	2010			2009
Balance at beginning of period	$	223,953		$	66,435
Accretion expense		9,356			5,896
Asset retirement costs incurred		(2,694	)		(1,279	)
Liabilities incurred during the period		—			153,013
Liabilities reduced upon property sales		—			(112	)
Revisions in estimates(1)		21,832			—

Balance at end of period	$	252,447		$	223,953

(1)	In 2010, the revisions in estimates relate to changes in estimates of the Company’s expected plugging and abandonment costs and facility removal costs at several fields.

11. Commitments and Contingencies

The Company has a $644 commitment to use the services of an offshore drilling rig contractor which ends April 1, 2012.

From time to time the Company may be subject to various claims, title matters and legal proceedings arising in the ordinary course of business, including environmental contamination claims, personal injury and property damage claims, claims related to joint interest billings and other matters under oil and natural gas operating agreements and other contractual disputes. The Company maintains general liability and other insurance to cover some of these potential liabilities. All known liabilities are fully accrued based on the Company’s best estimate of the potential loss. While the outcome and impact on the Company cannot be predicted with certainty, the Company believes that its ultimate liability with respect to any such matters will not have a significant impact or material adverse effect on its financial position, results of operations or cash flows. Results of operations and cash flows, however, could be significantly impacted in the reporting periods in which such matters are resolved.

12. Impacts of Hurricanes

As of December 31, 2010, the Company has spent $7,654 to assess, remove, repair and rebuild facilities and equipment that were damaged by the hurricanes. The Company received $6,004 in payments from its insurance providers during 2010, as final settlement for these claims. As of December 31, 2010, insurance proceeds of $6,004 were collected and no receivable remained.

For the year ended December 31, 2010, oil and natural gas operating expenses in the statement of income include $863 of assessment, repair, removal and recovery costs as a result of the hurricanes. During this period, the Partnership’s oil and natural gas operating expenses were reduced by $3,030 associated with expected recoveries from insurance providers.

For the year ended December 31, 2009, oil and natural gas operating expenses in the statement of income include $5,516 of assessment, repair, removal and recovery costs as a result of the hurricanes. During this period, the Partnership’s oil and natural gas operating expenses were reduced by $2,975 associated with expected recoveries from insurance providers.

13. Recent Accounting Pronouncements

In December 2010, the Financial Accounting Standards Board issued authoritative guidance for ASC 805. This guidance clarifies the acquisition date that should be used for reporting the pro forma financial information disclosures when comparative financial statements are presented. The guidance also improves the usefulness of the pro forma revenue and earnings disclosures by requiring a description of the nature and amount of material, nonrecurring pro forma adjustments that are directly attributable to the business combination. The guidance is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. The Company has adopted this guidance in connection with its December 31, 2010 financial statements.

14. Subsequent Events

These financial statements were published on March 31, 2011 and all subsequent events since December 31, 2010 through March 31, 2011 were considered by management for purposes of analysis and disclosure.

15. Oil and Natural Gas Activities (unaudited)

The Company follows the SEC’s final rule, Modernization of Oil and Gas Reporting, and the FASB’s authoritative guidance on extractive activities for oil and natural gas.

Costs Incurred


	Year ended December 31, 2010		Year ended December 31, 2009
Acquisition costs
Unproved properties	$	—	$	67,335
Proved properties		191		47,542
Development costs		126,539		19,955
Exploration costs		28		964

Costs incurred	$	126,758	$	135,796

ARO is not included above. For further discussion of ARO see Note 10.

Supplemental Reserve Information

The following information summarizes the Company’s net proved crude oil, natural gas and natural gas liquids reserves and the present values thereof for the two years ended December 31, 2010. All of the Company’s reserves are located in the United States of America. In 2010 and 2009, the Company’s reserve reports were prepared by the independent petroleum engineers of W.D. Von Gonten & Co.

•

Future commodity prices received for selling the Company’s net production will probably differ from those required to be used in these calculations.

•

Future operating and capital costs will probably differ from those required to be used in these calculations.

•

Future market conditions, government regulations and reservoir conditions may cause production rates in future years to vary significantly from those rates used in these calculations.

•

Future revenues may be subject to different production rates in the future.

•

The following table summarizes the estimated quantities of the Company’s net proved reserves:


	Crude Oil (MBbls)			Natural Gas (MMcf)			NGL (MBbls)			Total Equivalent Reserves (MBOE)(1)
Proved reserves:
Reserves as of December 31, 2008		813			38,508			74			7,305
Production		(347	)		(10,055	)		(113	)		(2,136	)
Divestitures		—			—			—			—
Acquisitions		3,926			55,358			52			13,204
Extensions and discoveries		316			22,894			15			4,147
Revisions		717			(7,953	)		528			(81	)

Reserves as of December 31, 2009		5,425			98,752			556			22,439

Production		(700	)		(14,089	)		(175	)		(3,223	)
Divestitures		—			—			—			—
Acquisitions		—			—			—			—
Extensions and discoveries		3,621			24,170			328			7,977
Revisions		(45	)		(19,834	)		821			(2,529	)

Reserves as of December 31, 2010		8,301			88,999			1,530			24,664

Proved developed reserves:
Reserves as of December 31, 2009		4,382			57,973			198			14,243
Reserves as of December 31, 2010		4,443			46,546			764			12,965
Proved undeveloped reserves:
Reserves as of December 31, 2009		1,043			40,779			358			8,196
Reserves as of December 31, 2010		3,858			42,453			766			11,699

(1)	Quantities are in thousands of barrel of oil equivalents. Natural gas quantities have been converted to barrel of oil equivalents using a factor of six million cubic feet per thousand barrels.

Standardized Measure of Discounted Future Net Cash Flows

The Standardized Measure of discounted future net cash flows relating to proved reserves is presented as follows:


	At December 31,
	2010			2009
Future cash inflows	$	1,098,959		$	727,043
Future production costs		(300,094	)		(262,719	)
Future development costs		(476,346	)		(431,993	)

Future net cash flows		322,519			32,331
Less 10% annual discount(1)		(14,061	)		45,169

Standardized Measure of discounted future net cash flows	$	308,458		$	77,500

(1)	“Less 10% annual discount” reflects significant expected abandonment costs in future years that, when discounted, have the effect of causing the total discounted cash flows to be greater than the undiscounted cash flows, as it relates to these expected future abandonment costs.

The Standardized Measure of discounted future net cash flows (discounted at 10%) was developed as follows:

•

An estimate was made of the quantity of proved reserves and the future periods in which they are expected to be produced based on year end economic conditions.

•

In accordance with SEC guidelines, the engineers’ estimates of future net revenues from the Company’s proved properties and the present value thereof are made using the twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials. These prices are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. The Company used various derivative instruments to manage its exposure to commodity prices (see Note 9). The derivative instruments the Company had in place were not classified as hedges for accounting purposes. The realized sale prices used in the reserve reports, not including the effects of the Company’s commodity derivative contracts, as of December 31, 2010 and 2009, for crude oil ($ per Bbl) were $79.49 and $60.88, respectively, and for natural gas ($ per Mcf) were $4.37 and $3.87, respectively.

•

Changes in Standardized Measure of Discounted Future Net Cash Flows

The principal sources of the changes in the Standardized Measure of discounted future net cash flows for the years ended December 31, 2010 and 2009, are as follows:


	2010			2009
At beginning of period	$	77,500		$	64,094
Sales, net of production costs		(65,928	)		(19,975	)
Change in sales and transfer prices, net		161,729			(69,778	)
Development costs incurred		41,819			2,400
Change in future development cost		10,649			4,985
Extensions and discoveries		177,125			80,773
Purchases of minerals in place		—			39,282
Revisions of quantity estimates		(8,735	)		(700	)
Accretion of discount		7,750			2,407
Changes in production rates and other(1)		(93,451	)		(25,988	)

At December 31	$	308,458		$	77,500

(1)	“Changes in production rates and other” reflects significant expected abandonment costs in future years that, when discounted, have the effect of causing the total discounted cash flows to be greater than the undiscounted cash flows, as it relates to these expected future abandonment costs.

Hilcorp Energy GOM, LLC

Condensed Balance Sheet (Unaudited)

As of June 30, 2012


(in thousands of dollars)	June 30, 2012		December 31, 2011
Assets
Current assets:
Cash and cash equivalents	$	57	$	27
Accounts receivable from affiliates		141,494		104,126
Assets from risk management activities		8,583		10,270
Other current assets		1,216		2,382

Total current assets		151,350		116,805

Property and equipment, net		527,235		503,494
Assets from risk management activities		717		3,586

Total assets	$	679,302	$	623,885

Liabilities and Member’s Capital
Current liabilities:
Accounts payable and accrued liabilities	$	635	$	727
Liabilities for asset retirement obligations		6,400		17,749
Deferred premiums on risk management activities		1,436		1,607

Total current liabilities		8,471		20,083

Liabilities for asset retirement obligations		333,511		324,373
Deferred premiums on risk management activities		322		790
Commitments and contingencies
Member’s capital		336,998		278,639

Total liabilities and member’s capital	$	679,302	$	623,885

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

Hilcorp Energy GOM, LLC

Condensed Statement of Income (Unaudited)

Six Months Ended June 30, 2012


	Six Months Ended June 30,
(in thousands of dollars)	2012			2011
Operating revenues:
Crude oil and product sales	$	78,888		$	72,712
Natural gas sales		13,485			33,150
Other revenues		1,450			234

Total operating revenues		93,823			106,096

Operating expenses:
Oil and natural gas operating expenses		42,583			38,096
Transportation charges		224			392
Exploration expenses		43			69
Depletion, depreciation and amortization		35,412			43,334
Impairment of property and equipment		—			21,031
Accretion of asset retirement obligations		8,188			5,224
General and administrative expenses		5,690			8,844

Total operating expenses		92,140			116,990

Gain on sale of property and equipment		—			200

Operating income (loss)		1,683			(10,694	)

Other income (expense):
Change in unrealized loss on commodity derivative contracts, net		(4,556	)		(5,923	)
Realized gain on commodity derivative contracts		6,232			6,073

Total other income		1,676			150

Net income (loss)	$	3,359		$	(10,544	)

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

Hilcorp Energy GOM, LLC

Condensed Statement of Member’s Capital (Unaudited)

Six Months Ended June 30, 2012


(in thousands of dollars)
Balance at December 31, 2011	$	278,639
Contributions		55,000
Net income		3,359

Balance at June 30, 2012	$	336,998

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

Hilcorp Energy GOM, LLC

Condensed Statement of Cash Flows (Unaudited)

Six Months Ended June 30, 2012


	Six Months Ended June 30,
(in thousands of dollars)	2012			2011
Cash flows from operating activities:
Net income (loss)	$	3,359		$	(10,544	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization		35,412			43,334
Accretion of asset retirement obligations		8,188			5,224
Impairment of property and equipment		—			21,031
Gain on sale of property and equipment		—			(200	)
Unrealized loss on commodity derivative contracts, net		4,556			5,923
Changes in assets and liabilities:
Accounts receivable from affiliates		(39,117	)		(14,847	)
Advances from operator		—			3,435
Other current assets		134			269
Accounts payable and accrued liabilities		(92	)		138
Risk management activities		(639	)		(345	)
Accounts payable to affiliates		—			(23,434	)
Liabilities for asset retirement obligations		(11,789	)		(7,302	)

Net cash provided by operating activities		12			22,682

Cash flows from investing activities:
Acquisitions of oil and natural gas properties		(2,824	)		(108,167	)
Additions to oil and natural gas properties		(52,158	)		(24,058	)
Proceeds from sale of property and equipment		—			200

Net cash used in investing activities		(54,982	)		(132,025	)

Cash flows from financing activities:
Contributions		55,000			109,351

Net cash provided by financing activities		55,000			109,351

Net change in cash and cash equivalents		30			8
Cash and cash equivalents at beginning of period		27			33

Cash and cash equivalents at end of period	$	57		$	41

Supplemental cash flow information:
Change in accrued capital expenditures	$	1,749		$	3,520

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

Hilcorp Energy GOM, LLC

Notes to Condensed Financial Statements

Six Months Ended June 30, 2012

(amounts in thousands, except volumes)

1. Organization and Nature of Business

Hilcorp Energy GOM, LLC (the Company or HGOM) is primarily engaged in the production, development and exploration of oil and natural gas properties. The Company holds interests in oil and natural gas producing properties, located in the Gulf of Mexico, offshore Louisiana and Texas. The Company has an agreement with Hilcorp Energy Company (HEC) to provide operating and other services to the Company.

2. Summary of Significant Accounting Policies

Interim Condensed Financial Statements

The accompanying condensed financial statements of the Company have not been audited by independent accountants. In the opinion of management, the accompanying condensed financial statements reflect all adjustments necessary to fairly state the Company’s financial position at June 30, 2012 and December 31, 2011, its net income and cash flows for the six months ended June 30, 2012 and 2011 and its statement of member’s capital for the six months ended June 30, 2012. All such adjustments are of a normal recurring nature. The results for interim periods are not necessarily indicative of annual results.

Certain disclosures have been omitted from these condensed financial statements. Accordingly, these condensed financial statements should be read in conjunction with the audited financial statements and related notes for the year ended December 31, 2011.

Basis of Presentation

The accompanying condensed financial statements have been prepared on the accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America.

Use of Estimates

Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploitation and development activities, prevailing commodity prices, operating costs and other factors. These revisions may be material and could materially affect future depletion, depreciation and amortization expense, asset retirement obligations and impairment expense.

Recent Accounting Pronouncement

In May 2011, the Financial Accounting Standards Board (FASB) issued additional guidance regarding fair value measurement and disclosure requirements. The most significant changes require the Company, for Level 3 fair value measurements, to disclose quantitative information about unobservable inputs used, a description of the valuation processes used and a qualitative discussion about the sensitivity of the measurements. The guidance is effective for interim and annual periods beginning on or after December 15, 2011. Adopting the additional fair value measurement and disclosure requirements did not have a material impact on the Company’s financial position, results of operations or cash flows.

In December 2011, the FASB issued Accounting Standards Codification (ASU) No. 2011-11, “Disclosures about Offsetting Assets and Liabilities,” requiring disclosure of gross information and net information about instruments and transactions eligible for offset arrangement. The guidance is effective for interim and annual periods beginning on or after January 1, 2013. The Company does not expect adoption of the additional disclosures about offsetting assets and liabilities to have a significant impact on its financial position, results of operations or cash flows.

3. Income Taxes

4. Related Party Transactions

HEC manages the operations of the oil and natural gas properties and provides managerial, technical, professional and administrative services to the Company. In connection with the management of the oil and natural gas properties, HEC collects payments of revenues associated with the sale of oil and natural gas production and remits payments to royalty and other working interest owners and to vendors for operating and capital expenditures. HEC manages and operates the properties pursuant to joint operating agreements which allow HEC to charge the Company for labor and supervision, administrative overhead and insurance, as well as direct third party charges from vendors for operating expenses, capital expenditures and general and administrative services.

The Company compensates HEC for providing the general and administrative services through a management fee. The Company paid $5,431 and $8,412 for the six months ended June 30, 2012 and 2011, respectively to HEC for providing these services. Additionally, the Company incurred $259 and $432 for the six months ended June 30, 2012 and 2011, respectively, in permitted expenses as reimbursement to HEC for direct third-party charges for acquisition costs, accounting, legal and engineering services.

Accounts receivable from and payable to affiliates were as follows:


	June 30,		December 31,
	2012		2011
Accounts receivable from affiliates:
Receivables from oil and natural gas sales	$	27,867	$	37,669
Affiliate advances		113,627		66,457

	$	141,494	$	104,126

Navitas Insurance Company, LLC

Navitas Insurance Company, LLC (Navitas), an affiliate of the Company, provides certain insurance coverage for HEC and its affiliates. During the six months ended June 30, 2012, the Company incurred $4,068 in insurance expenses for oil lease property and well control coverage provided by Navitas, which are included in oil and natural gas operating expenses in the condensed statement of income.

Contributions

During the six months ended June 30, 2012 and 2011, the sole member made cash contributions of $55,000 and $109,351, respectively. The Company has relied on contributions from its sole member to fund acquisitions and capital expenditures.

5. Oil and Natural Gas Properties

Acquisitions

During the six months ended June 30, 2012, the Company acquired working and net revenue interests in oil and natural gas properties through various transactions totaling $2,824, subject to customary adjustments, and recorded asset retirement obligations totaling $1,390 associated with these interests. The Company used contributions from its sole member to fund these various transactions.

In June 2011, the Company acquired working and net revenue interests in oil and natural gas properties located in the Gulf of Mexico for $103,763, subject to customary adjustments. The Company used contributions from its sole member to fund this transaction, which had an effective date of July 1, 2011. The acquisition qualified as a business combination and the Company estimated the fair value of this property as of the June 30, 2011 closing date. The Company used a discounted cash flow model to arrive at its fair value estimate and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as defined by ASC 820. The estimated fair value of these properties was assigned to the assets acquired and liabilities assumed, which included $139,095 to proved properties and $35,332 for asset retirement obligations. Because the estimated fair value and purchase price were equivalent, the Company did not record goodwill or a bargain purchase gain related to this acquisition. This acquisition closed June 30, 2011, therefore there are no operating revenues or net income related to this acquisition included in the condensed statement of income for the six months ended June 30, 2011. The Company incurred acquisition costs of $303 related to this transaction, which are included in general and administrative expenses in the condensed statement of income.

Summarized below are the Company’s results of operations for the six months ended June 30, 2011, on an unaudited pro forma basis as if the acquisition had occurred at the beginning of the earliest period presented. This unaudited pro forma information has been prepared based on the Company’s historical statement of income and estimates based on information provided by the seller, with pro forma adjustments applied, as appropriate. This unaudited pro forma information is not necessarily indicative of the operating results that would have occurred at that date, nor are they necessarily indicative of future operating results.


	Six Months ended June 30, 2011
Total operating revenues	$	149,955
Net income	$	7,148

Additionally, during the six months ended June 30, 2011, the Company acquired working and net revenue interests in oil and natural gas properties and recorded post-closing adjustments on various transactions totaling $4,404, subject to customary adjustments, and recorded asset retirement obligations totaling $633 associated with these interests. The Company used contributions from its sole member to fund these transactions.

Impairment

During the six months ended June 30, 2011, the Company recognized non-cash charges of $21,031 related to the impairment of two fields due to downward revisions of previous estimates of proved oil and natural gas reserve quantities as a result of drilling results.

6. Fair Value Measurements

Authoritative guidance on fair value measurements defines fair value, establishes a framework for measuring fair value and stipulates the related disclosure requirements about fair value measurements. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value depending on the degree to which they are observable.

Recurring Fair Value Measurements

The following table presents the valuation of the Company’s financial instruments by fair value hierarchy levels:


	Fair Value Measurements at Reporting Date Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Fair Value
June 30, 2012
Assets:
Derivative contracts
Crude oil and natural gas collars		—		4,816		—		4,816
Crude oil and natural gas puts		—		4,484		—		4,484

Total assets	$	—	$	9,300	$	—	$	9,300

December 31, 2011
Assets:
Derivative contracts
Crude oil and natural gas collars		—		—		8,263		8,263
Crude oil and natural gas puts		—		—		5,593		5,593

Total assets	$	—	$	—	$	13,856	$	13,856

The Company’s Level 2 instruments include commodity derivative instruments for which the Company has sufficient corroborative market evidence. At December 31, 2011, the Company’s Level 3 instruments were commodity derivative instruments for which the Company did not have sufficient corroborative market evidence to support classifying the asset or liability as Level 2. Subsequent to December 31, 2011, the Company reclassified these derivatives to Level 2 upon receipt of sufficient corroborative market evidence.

The Company uses a third-party to value the derivative instruments it holds and compares these values against the counterparties’ valuations on a regular basis to confirm that the valuations reflected are appropriate and reasonable. Since the Company has netting provisions in the ISDA Master Agreements with all of its counterparties, credit exposure by counterparty is assessed by reviewing such net position. For asset positions, the Company uses the credit default swap rate of its counterparties (or an equivalent rating) for the appropriate periods to calculate a credit risk adjustment. At June 30, 2012, the credit risk adjustment resulted in a $25 loss (or decrease in the valuation). Changes in the fair value of derivatives affect the Company’s results of operations, but will not affect the Company’s cash flow until settled.

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:


	Six Months Ended
	June 30, 2012			June 30, 2011
	Derivatives			Derivatives
Balance at beginning of period	$	13,856		$	21,671
Total gains or losses (realized or unrealized):
Included in earnings		—			150
Included in other comprehensive income		—			—
Purchases, issuances and settlements
Purchases		—			—
Issuances		—			—
Sales
Settlements		—			(6,074	)
Transfers in and out of Level 3		(13,856	)		—

Balance at end of period	$	—		$	15,747

Changes in unrealized gains relating to Level 3 derivatives still held	$	—		$	125

Nonrecurring Fair Value Measurements

The following table summarizes certain property and equipment measured at fair value on a nonrecurring basis in periods subsequent to its initial recognition and the associated impairment:


	June 30, 2011
	Fair Value		Impairment
Property and equipment	$	33,304	$	21,031

During 2011, certain property and equipment was evaluated for impairment due to reductions in estimated reserves. During the six months ended June 30, 2011, the Company recorded impairments for two fields. The fair value of the property and equipment was measured at the time of impairment using an income approach based upon internal estimates of future production levels, prices and discount rate, which are Level 3 inputs.

Fair Value of Other Financial Instruments

The carrying values of items comprising current assets and current liabilities approximate fair value due to the short-term maturities of these instruments. Derivative financial instruments included in the Company’s condensed financial statements are stated at fair value; however, the Company’s oil and natural gas puts have a deferred premium. The deferred premium increases the derivative asset or reduces the derivative liability depending on the fair value of the derivative financial instruments.

The carrying amounts and fair value of the Company’s other financial instruments are as follows:


	June 30, 2012				December 31, 2011
	Carrying Value		Fair Value		Carrying Value		Fair Value
Current liability
Deferred premiums(1)	$	1,436	$	1,436	$	1,607	$	1,607

Non-current liability
Deferred premiums(1)	$	322	$	322	$	790	$	790

(1)	The Company’s deferred premiums on its commodity derivative contracts have been measured at fair value and are classified as Level 2 under the fair value hierarchy.

7. Risk Management Activities

The Company utilizes financial instruments to manage risks related to changes in commodity prices. As of June 30, 2012, the Company utilized financial instruments, including puts and collars, to reduce the volatility of oil and natural gas prices on a portion of the Company’s future expected oil and natural gas production. The Company has not designated any derivative instruments as hedges for accounting purposes. Realized gains and losses on the settlement of commodity derivative instruments and changes in unrealized gains and losses are reported separately in other income (expense) in the condensed statement of income.

The Company’s commodity derivative contracts outstanding at June 30, 2012 are summarized below:

Natural Gas Commodity Derivatives


Production Period	Transaction Type		Average Daily Volume (MMbtu)(1)		Weighted Average Floor Price ($/MMbtu)(2)		Weighted Average Ceiling Price ($/MMbtu)(2)		Weighted Average Net Floor Price ($/Mmbtu)(2)(3)
2012(4)		Collar Put		1,722 2,293	$	9.50 8.03	$	12.95 —	$	— 6.68

2013		Collar Put		656 1,366		10.00 7.07		12.40 —		— 5.64

(1)	MMbtu equals million British thermal units.

(2)	Reference Price for the Company’s collars and puts is NYMEX—Henry Hub.

(3)	The net floor price is the strike price less the deferred premium.

(4)	Reflects the remaining six months of 2012.

Crude Oil Commodity Derivatives


Production Period	Transaction Type		Average Daily Volume (Bbl)(1)		Weighted Average Floor Price ($/Bbl)(2)		Weighted Average Ceiling Price ($/Bbl)(2)		Weighted Average Net Floor/Ceiling Price ($/Bbl)(2)(3)
2012(4)		Collar Put		87 80	$	120.00 120.00	$	164.85 —	$	— 99.26

2013		Collar Put		54 10		120.00 120.00		165.10 —		— 97.45

(1)	Bbl equals barrel of oil.

(2)	Reference price for the Company’s puts and collars is NYMEX—WTI.

(3)	Net floor price is the strike price less the deferred premium.

(4)	Reflects the remaining six months of 2012.

Effect of Derivative Instruments on the Condensed Balance Sheet

At June 30, 2012 and December 31, 2011, the Company had the following outstanding commodity derivative contracts recorded on the condensed balance sheet, none of which were designated as a hedging instrument under ASC 815, “Derivatives and Hedging”:


		Estimated Fair Value
Instrument Type	Balance Sheet Location	June 30, 2012		December 31, 2011
Assets from risk management activities
Crude oil collars	Current assets	$	1,186	$	986
Crude oil puts	Current assets		616		474
Natural gas collars	Current assets		3,630		5,321
Natural gas puts	Current assets		3,151		3,489
Crude oil collars	Non-current assets		—		530
Crude oil puts	Non-current assets		—		96
Natural gas collars	Non-current assets		—		1,426
Natural gas puts	Non-current assets		717		1,534

Total assets from risk management activities			9,300		13,856

Fair value from risk management activities, net		$	9,300	$	13,856

The following table provides supplemental information to reconcile the fair value of the Company’s commodity derivative contracts to the condensed balance sheet at June 30, 2012 and December 31, 2011:


	June 30, 2012		December 31, 2011
Assets from risk management activities—current assets	$	8,583	$	10,270
Assets from risk management activities—non-current assets		717		3,586

Fair value from risk management activities, net	$	9,300	$	13,856

The Company had $1,758 of derivative premiums payable recorded at June 30, 2012, of which $1,436 is classified as short-term and $322 is classified as long-term. The Company had $2,397 of derivative premiums payable recorded at December 31, 2011, of which $1,607 is classified as short-term and $790 is classified as long-term. Derivative premiums are recorded as deferred premiums on risk management activities on the condensed balance sheet. The deferred premiums relate to various oil and natural gas price put contracts and are payable when the contracts settle. The Company paid $639 and $345 in deferred premiums for the six months ended June 30, 2012 and 2011, respectively.

Effect of Derivative Instruments on the Condensed Statement of Income

Below is a summary by type of the Company’s change in unrealized gain (loss) on commodity derivative contracts, net:


	Six Months Ended June 30,
	2012			2011
Crude oil collars	$	(330	)	$	(1,244	)
Crude oil puts		47			(339	)
Natural gas swaps		—			(771	)
Natural gas collars		(3,117	)		(3,122	)
Natural gas puts		(1,156	)		(447	)

	$	(4,556	)	$	(5,923	)

Below is a summary of the Company’s realized gain on commodity derivative contracts, net:


	Six Months Ended June 30,
	2012		2011
Crude oil collars	$	598	$	668
Crude oil puts		105		118
Natural gas swaps		—		844
Natural gas collars		3,746		3,646
Natural gas puts		1,783		797

	$	6,232	$	6,073

8. Asset Retirement Obligations

The Company’s asset retirement obligations were $339,911 as of June 30, 2012, of which $6,400 are expected to be incurred over the next twelve months. Activity related to the Company’s asset retirement obligations during the six months ended June 30, 2012 and 2011 is as follows:


	Six Months Ended June 30,
	2012			2011
Balance at beginning of period	$	342,122		$	252,447
Accretion expense		8,188			5,224
Asset retirement costs incurred		(11,789	)		(7,302	)
Liabilities incurred during period		1,390			35,965
Liabilities reduced upon property sales		—			—

Balance at end of period	$	339,911		$	286,334

9. Commitments and Contingencies

The Company is subject to various claims, title matters and legal proceedings arising in the ordinary course of business, including personal injury claims, claims related to joint interest billings and other matters under oil and natural gas operating agreements and other contractual disputes. The Company maintains general liability and other insurance to cover some of these potential liabilities. All known liabilities are fully accrued based on the Company’s best estimate of the potential loss. While the outcome and impact on the Company cannot be predicted with certainty, the Company believes that its ultimate liability with respect to these matters will not have a significant impact or material adverse effect on its financial position, results of operations or cash flows.

10. Subsequent Events

Management has evaluated subsequent events through September 26, 2012, which was the date the condensed financial statements were available to be issued and has determined that there were no subsequent events to be reported other than those reported below.

Pending Divestiture

In September 2012, HHGOM, the Company’s sole member, entered into a purchase and sale agreement with an unaffiliated third party to divest all of its issued and outstanding member interests of the Company for a purchase price of $550,000, subject to customary adjustments. HHGOM received a deposit of $55,000 in September and expects to close this transaction in the fourth quarter of 2012. As a requirement of the purchase and sale agreement, the Company terminated its insurance policies in place with its affiliate, Navitas Insurance Company, LLC on September 14, 2012 (see Note 4). In addition, in September 2012 the Company novated all of its commodity derivative contracts in place to an affiliate and subsequently entered into commodity derivative contracts with trade dates beginning November 2012 through December 2013.

The Company’s commodity derivative contracts outstanding at September 26, 2012 are summarized below:

Natural Gas Commodity Derivatives


Production Period	Transaction Type		Average Daily Volume (MMbtu)(1)		Weighted Average Swap Price ($/MMbtu)(2)
2012(3)		Swap		14,492	$	3.13

2013		Swap		8,562		3.51

(1)	MMbtu equals million British thermal units.

(2)	Reference price for the Company’s swaps is NYMEX—Henry Hub.

(3)	Reflects the remaining two months of 2012.

Crude Oil Commodity Derivatives


Production Period	Transaction Type		Average Daily Volume (Bbl)(1)		Weighted Average Floor Price ($/Bbl)(2)
2012(3)		Swap-Brent		3,500	$	111.75

2013		Swap-Brent		2,662		108.60

(1)	Bbl equals barrels of oil.

(2)	Reference price for the Company’s swaps is “Brent Crude Oil” as traded on the ICE (IPE) exchange.

(3)	Reflects the remaining two months of 2012.