NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The consolidated financial statements include the accounts of the Company and its majority–owned subsidiaries (“we,” “our” or “us”). All significant intercompany accounts and transactions have been eliminated in consolidation. In the Notes to Consolidated Financial Statements, all dollar and share amounts in tabulations are in thousands of dollars and shares, respectively, unless otherwise indicated.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and judgments that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We base our estimates and judgments on historical experience and on various other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. While we believe that the estimates and assumptions used in the preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.

Cash and Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less at the time of purchase to be cash equivalents. All of our cash and cash equivalents are maintained with several major financial institutions in the United States. Deposits with these financial institutions may exceed the amount of insurance provided on such deposits; however, we regularly monitor the financial stability of these financial institutions and believe that we are not exposed to any significant default risk.

Restricted Cash

Restricted cash serves as collateral for certain of our obligations. These restricted funds are invested in interest–bearing accounts.

Joint Interest and Other Receivables

Joint interest receivables result from billing shared costs under the respective operating agreements to our partners. Accounts receivable from oil, natural gas and natural gas liquids sales are recorded at the invoiced amount and do not bear interest. We routinely assess the financial strength of our customers and partners and bad debts are recorded based on an account–by–account review after all means of collection have been exhausted, and the potential recovery is considered remote.

As of December 31, 2016, we have a $159.1 million receivable from Sonangol Pesquisa e Produção, S.A. (“Sonangol P&P”) related to its share of costs incurred under the Block 21 Risk Services Agreement. Although this amount has been outstanding for over one year, Sonangol P&P has acknowledged that this amount is owed to us. We continue to work with them on resolution of this issue and have determined that we did not need to set up a reserve for doubtful accounts as of December 31, 2016.

As of December 31, 2016 and 2015, we did not have any reserves for doubtful accounts. We also did not have any off–balance sheet credit exposure related to our customers.

Investments

We have investments in marketable debt securities that are classified as held–to–maturity as we have the positive intent and ability to hold the investments until they mature. We classify investments with original maturities of greater than three months and remaining maturities of less than one year as short–term investments, and investments with maturities beyond one year as long–term investments.

Our debt securities are carried at amortized cost and the carrying value of these securities is adjusted for amortization of premiums and accretion of discounts to maturity over the life of the securities. As the estimated fair value of each investment approximates its amortized cost, there were no significant unrecognized holding gains or losses as of December 31, 2016 and 2015. Income related to these securities is reported as a component of interest income in our consolidated statements of operations.

Investments are considered to be impaired when a decline in fair value is determined to be other–than–temporary. We conduct a regular assessment of our debt securities with unrealized losses to determine whether these securities have other–than-temporary impairment (“OTTI”). This assessment considers, among other factors, the nature of the securities, credit rating or financial condition of the issuer, the extent and duration of the unrealized loss, market conditions and whether we intend to sell or whether it is more likely than not that we will be required to sell the debt securities. As of December 31, 2016 and 2015, we have no OTTI in our debt securities.

Property and Depreciation, Depletion and Amortization

Our oil, natural gas and natural gas liquids producing activities are accounted for under the successful efforts method of accounting. Under this method, costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs and costs of carrying and retaining unproved properties are charged to expense as incurred. For 2016, 2015 and 2014, we recorded dry hole costs of $213.5 million, $188.0 million and $165.5 million, respectively, to expense costs associated with the drilling of exploratory wells that did not find proved reserves.

Costs for unproved leasehold properties and exploratory wells that find reserves that cannot yet be classified as proved are capitalized if the well has found a sufficient quantity of reserves to justify its completion as a producing well and we are making sufficient progress assessing the reserves and the economic and operating viability of the project. Often, the ability to move into the development phase and record proved reserves is dependent on obtaining permits and government or partner approvals, the timing of which is ultimately beyond our control. Exploratory well costs remain suspended as long as we are actively pursuing such approvals and permits, and believe they will be obtained. For complex exploratory projects, it is not unusual to have exploratory wells remain suspended on the balance sheet for several years while additional appraisal drilling and seismic work is performed on the field or while we seek government or partner approval of development plans. Our assessment of suspended exploratory well costs is continuous until a determination is made to either sanction the project or to expense the well costs as dry hole costs as sufficient progress has not been made in assessing the reserves and the economic and operating viability of the project. In 2016, we recorded dry hole costs of $1,276.4 million to expense costs associated with our Angolan exploratory wells (see Note 3).

The capitalized costs of our producing oil and natural gas properties are depreciated and depleted by the units–of–production method based on the ratio of current production to estimated total net proved reserves as estimated by independent petroleum engineers. Proved developed reserves are used in computing unit rates for drilling and development costs and total proved reserves are used for depletion rates of leasehold costs.

Other property is stated at cost less accumulated depreciation, which is computed using the straight–line method based on estimated economic lives ranging from three to ten years. We expense costs for maintenance and repairs in the period incurred. Significant improvements and betterments are capitalized if they extend the useful life of the asset.

Impairment of Oil and Natural Gas Properties

We evaluate our proved oil and natural gas properties and related equipment and facilities for impairment whenever events or changes in circumstances indicate that the carrying amounts of such properties may not be recoverable. The determination of recoverability is made based upon estimated undiscounted future net cash flows. The amount of impairment loss, if any, is determined by comparing the fair value, as determined by a discounted cash flow analysis, with the carrying value of the related asset. For 2015, we recorded impairment charges of $256.8 million related to our proved oil and natural gas properties as the carrying amounts of such properties were determined not to be recoverable (see Note 5).

Oil and natural gas leases for unproved properties with a carrying value greater than $1.0 million are assessed individually for impairment based on our current exploration plans and an allowance for impairment is provided if impairment is indicated. Leases that are individually less than $1.0 million in carrying value or are near expiration are amortized over the terms of the leases at rates that provide for full amortization of leases upon lease expiration. These leases have expiration dates ranging from 2017 through 2026. For 2016, 2015 and 2014, we recorded impairment charges of $66.6 million, $26.9 million and $70.5 million, respectively, related to our leases for unproved oil and natural gas properties. In 2016, we also recorded an impairment charge of $353.4 million related to our Angolan leases in conjunction with the write-off of our Angolan exploratory well costs (see Note 3).

Asset Retirement Obligations

An asset retirement obligation (“ARO”) represents the future abandonment costs of tangible assets, such as wells, service assets, and other facilities. We record an ARO and capitalize the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit–of–production basis. If the ARO is settled for an amount other than the recorded amount, a gain or loss is recognized.

Embedded Derivatives

Our first lien senior secured notes due (the “First Lien Notes”) and our second lien senior secured notes due 2023 (the “Second Lien Notes”) include features which were determined to be embedded derivatives requiring bifurcation and accounting as separate financial instruments. The embedded derivatives were initially recorded at fair value and are subject to remeasurement as of each balance sheet date. We have elected not to designate our embedded derivatives as hedging instruments. Changes in the fair value of these embedded derivatives are recorded immediately to earnings in “Other (expense) income” in our consolidated statements of operations.

Revenue Recognition

Oil, natural gas and natural gas liquids revenues are recognized when production is sold to a purchaser at fixed or determinable prices, when delivery has occurred and title has transferred and collectability of the revenue is reasonably assured. We follow the sales method of accounting for natural gas revenues. Under this method of accounting, revenues are recognized based on volumes sold, which may differ from the volume to which we are entitled based on our working interest. An imbalance is recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the under–produced owner(s) to recoup its entitled share through future production. Under the sales method, no receivables are recorded where we have taken less than our share of production. There were no significant natural gas imbalances at December 31, 2016.

Income Taxes

We use the liability method to determine our income tax provisions, under which current and deferred tax liabilities and assets are recorded in accordance with enacted tax laws and rates. Under this method, the amounts of deferred tax liabilities and assets at the end of each period are determined using the tax rate expected to be in effect when taxes are actually paid or recovered. Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized.

Concentration of Credit Risk

Our oil, natural gas and natural gas liquids revenues are derived principally from uncollateralized sales to customers in the oil and natural gas industry; therefore, our customers may be similarly affected by changes in economic and other conditions within the industry. We have experienced no credit losses on such sales in the past.

In 2016, one customer accounted for 96.5% of our consolidated oil, natural gas and natural gas liquids revenues. We believe that the loss of this customer would have a temporary effect on our revenues but, that over time, we would be able to replace this customer.

Recently Issued Accounting Standards

In May 2014, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2014–09, Revenue from Contracts with Customers. This ASU superseded virtually all of the revenue recognition guidance in generally accepted accounting principles in the United States. The core principle of the five–step model is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. Entities can choose to apply the standard using either the full retrospective approach or a modified retrospective approach. The provisions of ASU 2014–09 are applicable to annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. We plan to adopt ASU 2014-09 as of January 1, 2018 using the modified retrospective method with the cumulative effect, if any, of initial adoption to be recognized at the date of initial application. We are in the initial stages of our evaluation of the impact of adopting ASU 2014–09, but we do not expect the adoption to have a material impact on our consolidated financial statements.

In August 2014, the FASB issued ASU No. 2014–15, Presentation of Financial Statements – Going Concern. This ASU amends the accounting guidance for the presentation and disclosure of uncertainties about an entity’s ability to continue as a going concern. It requires management to evaluate and disclose whether there is substantial doubt about its ability to continue as a going concern. Management should consider relevant conditions or events that are known or reasonably known on the date the financial statements are issued. The provisions of ASU 2014–15 are applicable to the annual reporting period ending after December 15, 2016 and for annual periods and interim periods thereafter. We adopted ASU 2014–15 on December 31, 2016 (see Note 1).

In April 2015, the FASB issued ASU No. 2015–03, Interest—Imputation of Interest. This ASU changes the presentation of debt issuance costs in financial statements. Under ASU 2015–03, an entity presents such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. We adopted ASU 2015–03 on March 31, 2016, which required that we apply the guidance on a retrospective basis, wherein our consolidated balance sheets for all periods presented were adjusted to reflect the effects of applying the guidance. Accordingly, as of December 31, 2015, we reclassified $32.9 million of unamortized debt issuance costs previously reported in “Other assets” to “Long–term debt, net” on our consolidated balance sheet.

In July 2015, the FASB issued ASU No. 2015–11, Accounting for Inventory. This ASU requires entities to measure most inventory at lower of cost or net realizable value, which is defined as "the estimated selling prices in the ordinary course of business, less reasonably predictable cost of completion, disposal and transportation." We adopted ASU No. 2015–11 on December 31, 2016, and the adoption did not have a material impact on our consolidated financial statements.

In February 2016, the FASB issued ASU No. 2016-02, Leases. Under the new guidance, a lessee will be required to recognize assets and liabilities for leases with lease terms of more than 12 months. Consistent with current accounting guidance, the recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee primarily depends on its classification as a finance or operating lease. However, unlike current accounting guidance, which requires only capital leases to be recognized on the balance sheet, ASU 2016–02 will require both types of leases to be recognized on the balance sheet. ASU 2016-02 will also require disclosures to help investors and other financial statement users to better understand the amount, timing and uncertainty of cash flows arising from leases. Although ASU 2016–02 does not apply to leases for oil and natural gas properties, it does apply to equipment used to explore and develop oil and natural gas resources. ASU 2016–02 is effective for annual and interim periods beginning after December 15, 2018 and is to be applied using the modified retrospective approach. We have not yet fully determined the effect that adopting ASU 2016-02 will have on our consolidated financial statements.

In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Subtopic 718). This ASU simplifies several aspects of the accounting for employee share–based payment transactions, including the accounting for income taxes, forfeitures and statutory withholding requirements, as well as classification in the statement of cash flows. The provision of ASU 2016–09 are applicable to annual reporting periods beginning after December 15, 2016 and interim period within those annual periods. Early adoption is permitted for financial statements that have not yet been previously issued. We have not yet fully determined or quantified the effect ASU 2016–09 will have on our consolidated financial statements.

In June 2016, the FASB issued ASU 2016–13, Financial Instruments – Credit Losses, which requires the measurement of expected credit losses for financial instruments held at the reporting date based on historical experience, current conditions and reasonable forecasts. The main objective of ASU 2016–13 is to provide financial statement users with more decision-useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. The provisions of ASU 2016–13 are effective for annual and interim periods beginning after December 15, 2019. Early adoption is permitted for annual and interim periods beginning after December 15, 2018. We have not yet fully determined the effect that adopting ASU 2016–13 will have on our consolidated financial statements.

In November 2016, the FASB issued ASU 2016–18, Statement of Cash Flows, which requires that amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning–of–period and end–of–period total amounts shown on the statement of cash flows. The provisions of ASU 2016–18 are effective for annual and interim periods beginning after December 15, 2017. We elected to early adopt the provisions of ASU 2016–18 on December 31, 2016, which required that we apply the guidance on a retrospective basis, wherein our consolidated statements of cash flows for all periods presented were adjusted to reflect the effects of applying the guidance. The following table shows the effects of applying the guidance:

	Prior to Adoption ⁽¹⁾			As Adjusted
Year ended December 31, 2015:
(Accretion of discount) amortization of premium on investments	$	14,207		$	14,483
Accrued liabilities		22,453			272,065
Net cash flows used in operating activities		(251,942	)		(1,646	)
Change in restricted funds		(3,856	)		—
Proceeds from maturity of investment securities		1,894,562			1,999,421
Purchase of investment securities		(892,577	)		(1,192,873	)
Net cash flows provided by (used in) investing activities		77,460			(114,121	)
Increase (decrease) in cash, cash equivalents and restricted cash		(178,550	)		(119,835	)
Cash, cash equivalents and restricted cash, end of year		80,171			138,886

Year ended December 31, 2014:
(Accretion of discount) amortization of premium on investments		18,159			20,925
Net cash flows used in operating activities		(64,526	)		(61,760	)
Change in restricted funds		43,667			—
Proceeds from maturity of investment securities		1,700,123			2,350,705
Purchase of investment securities		(2,129,453	)		(2,739,134	)
Net cash flows provided by (used in) investing activities		(1,138,393	)		(1,141,159	)

⁽¹⁾	Amounts are after reclassification of Angolan operations to no longer reflect these operations as discontinued.

No other new accounting pronouncements issued or effective during 2016 have had or are expected to have a material impact on our consolidated financial statements.