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.

 

2


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.

 

3


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.

 

4


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.

 

5


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.

 

6


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.

 

7


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.

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

 

8


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.

 

9


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

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.

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.

 

10


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.

 

11


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   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

12


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.

 

13


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.

 

14


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.

 

15


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.

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

 

16


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.

 

17


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.

 

18


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.

 

19


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.

 

20


 

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

 

21


Hilcorp Energy GOM, LLC

Balance Sheet

 

(in thousands of dollars)

   December 31,  
   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.

 

22


Hilcorp Energy GOM, LLC

Statement of Income

 

(in thousands of dollars)

   Year Ended
December 31,
 
   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.

 

23


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.

 

24


Hilcorp Energy GOM, LLC

Statement of Cash Flows

 

(in thousands of dollars)

   Year Ended
December 31,
 
   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   

 

 

25


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

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 $163 and $82 as of December 31, 2010 and 2009, 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. 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.

 

26


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.

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 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

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.

 

27


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

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 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

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 8).

 

28


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.

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.

 

29


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.

 

30


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

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.

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.

 

31


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, 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.

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.

 

32


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.

 

33


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. The following table summarizes the valuation of the Company’s financial instruments by ASC 820 pricing 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, 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   
  

 

 

    

 

 

    

 

 

    

 

 

 

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, 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.

 

34


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

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, 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   

 

 

35


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.

 

36


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.

 

37


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.

 

38


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.

 

39


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,
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.

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.

 

 

40


   

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, 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.

 

41


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.

 

   

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.

 

42


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.

 

43


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.

 

44


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.

 

45


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.

 

46


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.

 

47


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.

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.

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

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.

 

48


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

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 condensed financial statements.

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.

 

49


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.

 

50


     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   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

51


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

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.

 

52


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.

 

53


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.

 

54


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.

 

55


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.

 

56