Organization and Summary of Significant Accounting Policies

Description of the Company

Continental Resources, Inc. (the “Company”) was originally formed in 1967 and is incorporated under the laws of the State of Oklahoma. The Company's principal business is crude oil and natural gas exploration, development and production with properties primarily located in the North, South, and East regions of the United States. The North region consists of properties north of Kansas and west of the Mississippi River and includes North Dakota Bakken, Montana Bakken, and the Red River units. The South region includes all properties south of Kansas and west of the Mississippi River including various plays in the SCOOP (South Central Oklahoma Oil Province), STACK (Sooner Trend Anadarko Canadian Kingfisher), Northwest Cana and Arkoma Woodford areas of Oklahoma. The East region is comprised of undeveloped leasehold acreage east of the Mississippi River with no current drilling or production operations.

A substantial portion of the Company’s operations are concentrated in the North region, with that region comprising approximately 68% of the Company’s crude oil and natural gas production and approximately 77% of its crude oil and natural gas revenues for the year ended December 31, 2015. The Company's principal producing properties in the North region are located in the Bakken field of North Dakota and Montana. As of December 31, 2015, approximately 58% of the Company’s estimated proved reserves were located in the North region. In recent years, the Company has significantly expanded its activity in the South region with its discovery of the SCOOP play and its increased activity in the Northwest Cana and STACK plays. The South region comprised approximately 32% of the Company's crude oil and natural gas production, 23% of its crude oil and natural gas revenues, and 42% of its estimated proved reserves at December 31, 2015.

The Company has focused its operations on the exploration and development of crude oil since the 1980s. For the year ended December 31, 2015, crude oil accounted for approximately 66% of the Company’s total production and approximately 85% of its crude oil and natural gas revenues. Crude oil represents approximately 57% of the Company's estimated proved reserves as of December 31, 2015.

Basis of presentation of consolidated financial statements

The consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are 100% owned, after all significant intercompany accounts and transactions have been eliminated upon consolidation.

Use of estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure and estimation of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from those estimates. The most significant of the estimates and assumptions that affect reported results are the estimates of the Company’s crude oil and natural gas reserves, which are used to compute depreciation, depletion, amortization and impairment of proved crude oil and natural gas properties.

Revenue recognition

Crude oil and natural gas sales result from interests owned by the Company in crude oil and natural gas properties. Sales of crude oil and natural gas produced from crude oil and natural gas operations are recognized when the product is delivered to the purchaser and title transfers to the purchaser. Payment is generally received one to three months after the sale has occurred. The Company uses the sales method of accounting for natural gas imbalances in those circumstances where it has under-produced or over-produced its ownership percentage in a property. Under this method, a receivable or payable is recognized only to the extent an imbalance cannot be recouped from the reserves in the underlying properties. The Company’s aggregate imbalance positions at December 31, 2015 and 2014 were not material.

Cash and cash equivalents

The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The Company maintains its cash and cash equivalents in accounts that may not be federally insured. As of December 31, 2015, the Company had cash deposits in excess of federally insured amounts of approximately $10.7 million. The Company has not experienced any losses in such accounts and believes it is not exposed to significant credit risk in this area.

Accounts receivable

The Company operates exclusively in crude oil and natural gas exploration and production related activities. Receivables arising from crude oil and natural gas sales and joint interest receivables are generally unsecured. Accounts receivable are due within 30 days and are considered delinquent after 60 days. The Company determines its allowance for doubtful accounts by considering a number of factors, including the length of time accounts are past due, the Company’s history of losses, and the customer or working interest owner’s ability to pay. The Company writes off specific receivables when they become noncollectable and any payments subsequently received on those receivables are credited to the allowance for doubtful accounts. Write-offs of noncollectable receivables have historically not been material.

Concentration of credit risk

The Company is subject to credit risk resulting from the concentration of its crude oil and natural gas receivables with several significant purchasers. For the year ended December 31, 2015, sales to the Company’s largest purchaser accounted for approximately 11% of its total crude oil and natural gas sales. No other purchasers accounted for more than 10% of the Company’s total crude oil and natural gas sales for 2015. The Company does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers in various regions.

Inventories

Inventory is comprised of crude oil held in storage or as line fill in pipelines and tubular goods and equipment to be used in the Company's exploration and development activities. Crude oil inventories are valued at the lower of cost or market primarily using the first-in, first-out inventory method. Tubular goods and equipment are valued at the lower of cost or market, with cost determined primarily using a weighted average cost method applied to specific classes of inventory items.

The components of inventory as of December 31, 2015 and 2014 consisted of the following:



	December 31,
In thousands	2015		2014
Tubular goods and equipment	$	15,633	$	15,659
Crude oil	78,518		86,520
Total	$	94,151	$	102,179

Crude oil and natural gas properties

The Company uses the successful efforts method of accounting for crude oil and natural gas properties whereby costs incurred to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, to drill and equip development wells, and expenditures for enhanced recovery operations are capitalized. Geological and geophysical costs, seismic costs incurred for exploratory projects, lease rentals and costs associated with unsuccessful exploratory wells or projects are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. To the extent a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between capitalized development costs and exploration expense. Maintenance, repairs and costs of injection are expensed as incurred, except that the costs of replacements or renewals that expand capacity or improve production are capitalized.

Under the successful efforts method of accounting, the Company capitalizes exploratory drilling costs on the balance sheet pending determination of whether the well has found proved reserves in economically producible quantities. The Company capitalizes costs associated with the acquisition or construction of support equipment and facilities with the drilling and development costs to which they relate. If proved reserves are found by an exploratory well, the associated capitalized costs become part of well equipment and facilities. However, if proved reserves are not found, the capitalized costs associated with the well are expensed, net of any salvage value.

Production expenses are those costs incurred by the Company to operate and maintain its crude oil and natural gas properties and associated equipment and facilities. Production expenses include labor costs to operate the Company’s properties, repairs and maintenance, waste water disposal costs, and materials and supplies utilized in the Company’s operations.

Service property and equipment

Service property and equipment consist primarily of automobiles and aircraft; machinery and equipment; gathering systems; storage tanks; office and computer equipment, software, furniture and fixtures; and buildings and improvements. Major renewals and replacements are capitalized and stated at cost, while maintenance and repairs are expensed as incurred.

Depreciation and amortization of service property and equipment are provided in amounts sufficient to expense the cost of depreciable assets to operations over their estimated useful lives using the straight-line method. The estimated useful lives of service property and equipment are as follows:



Service property and equipment	Useful Lives In Years
Automobiles and aircraft	5-10
Machinery and equipment	6-10
Gathering systems	15-30
Storage tanks	10-30
Office and computer equipment, software, furniture and fixtures	3-10
Enterprise resource planning software	25
Buildings and improvements	10-40

Depreciation, depletion and amortization

Depreciation, depletion and amortization of capitalized drilling and development costs of producing crude oil and natural gas properties, including related support equipment and facilities, are computed using the unit-of-production method on a field basis based on total estimated proved developed reserves. Amortization of producing leaseholds is based on the unit-of-production method using total estimated proved reserves. In arriving at rates under the unit-of-production method, the quantities of recoverable crude oil and natural gas reserves are established based on estimates made by the Company’s internal geologists and engineers and external independent reserve engineers. Upon sale or retirement of properties, the cost and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss, if any, is recognized. Unit of production rates are revised whenever there is an indication of a need, but at least in conjunction with semi-annual reserve reports. Revisions are accounted for prospectively as changes in accounting estimates.

Asset retirement obligations

The Company accounts for its asset retirement obligations by recording the fair value of a liability for an asset retirement obligation in the period in which a legal obligation is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the capitalized asset retirement costs are charged to expense through the depreciation, depletion and amortization of crude oil and natural gas properties and the liability is accreted to the expected future abandonment cost ratably over the related asset’s life.

The Company’s primary asset retirement obligations relate to future plugging and abandonment costs on its crude oil and natural gas properties and related facilities disposal. The following table summarizes the changes in the Company’s future abandonment liabilities from January 1, 2013 through December 31, 2015:



In thousands	2015			2014			2013
Asset retirement obligations at January 1	$	76,708		$	55,787		$	47,171
Accretion expense	4,740			3,366			2,767
Revisions (1)	15,068			9,916			2,826
Plus: Additions for new assets	7,404			9,022			6,009
Less: Plugging costs and sold assets	(1,011		)	(1,383		)	(2,986		)
Total asset retirement obligations at December 31	$	102,909		$	76,708		$	55,787
Less: Current portion of asset retirement obligations at December 31 (2)	1,658			1,246			1,434
Non-current portion of asset retirement obligations at December 31	$	101,251		$	75,462		$	54,353


(1)	Revisions for the years ended December 31, 2015 and 2014 primarily represent an increase in the present value of liabilities from an acceleration in the estimated timing of abandonment prompted by decreases in commodity prices in 2015 and 2014 which shortened the economic lives of certain producing properties.


(2)	Balance is included in the caption "Accrued liabilities and other" in the consolidated balance sheets.

As of December 31, 2015 and 2014, net property and equipment on the consolidated balance sheets included $87.5 million and $64.7 million, respectively, of net asset retirement costs.

Asset impairment

Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value.

Non-producing crude oil and natural gas properties primarily consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Impairment losses for non-producing properties are recognized by amortizing the portion of the properties’ costs which management estimates will not be transferred to proved properties over the lives of the leases based on drilling plans, experience of successful drilling, and the average holding period. The Company’s impairment assessments are affected by economic factors such as the results of exploration activities, commodity price outlooks, anticipated drilling programs, remaining lease terms, and potential shifts in business strategy employed by management.

Debt issuance costs

Costs incurred in connection with the execution of the Company’s three-year term loan, note payable, and revolving credit facility and any amendments thereto are capitalized and amortized over the terms of the arrangements on a straight-line basis, the use of which approximates the effective interest method. Costs incurred upon the issuances of the Company's various senior notes (collectively, the “Notes”) were capitalized and are being amortized over the terms of the Notes using the effective interest method.

The Company had capitalized costs of $71.8 million and $76.1 million (net of accumulated amortization of $47.0 million and $38.1 million) relating to its long-term debt at December 31, 2015 and 2014, respectively. See the subsequent heading titled New accounting pronouncements for a discussion of the presentation of these costs on the consolidated balance sheets.

For the years ended December 31, 2015, 2014 and 2013, the Company recognized amortization expense associated with capitalized debt issuance costs of $8.9 million, $9.3 million and $8.6 million, respectively, which are reflected in “Interest expense” in the consolidated statements of comprehensive income (loss).

Derivative instruments

The Company recognizes its derivative instruments on the balance sheet as either assets or liabilities measured at fair value with such amounts classified as current or long-term based on contractual settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the changes in fair value in the consolidated statements of comprehensive income (loss) under the caption “Gain (loss) on derivative instruments, net.”

Fair value of financial instruments

The Company’s financial instruments consist primarily of cash, trade receivables, trade payables, derivative instruments and long-term debt. See Note 6. Fair Value Measurements for a discussion of the methods used to determine fair value for the Company's financial instruments and the quantification of fair value for its derivatives and long-term debt obligations at December 31, 2015 and 2014.

Income taxes

Income taxes are accounted for using the liability method under which deferred income taxes are recognized for the future tax effects of temporary differences between financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year-end. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. The Company’s policy is to recognize penalties and interest related to unrecognized tax benefits, if any, in income tax expense. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. The Company recorded valuation allowances of $13.5 million and $4.4 million for the years ended December 31, 2015 and 2014, respectively, against deferred tax assets associated with operating loss carryforwards generated by its Canadian subsidiary for which the Company does not expect to realize a benefit.

Earnings per share

Basic net income (loss) per share is computed by dividing net income (loss) by the weighted-average number of shares outstanding for the period. Diluted net income (loss) per share reflects the potential dilution of non-vested restricted stock awards, which are calculated using the treasury stock method. The following table presents the calculation of basic and diluted weighted average shares outstanding and net income (loss) per share for the years ended December 31, 2015, 2014 and 2013.



	Year ended December 31,
In thousands, except per share data	2015			2014		2013
Income (loss) (numerator):
Net income (loss) - basic and diluted	$	(353,668	)	$	977,341	$	764,219
Weighted average shares (denominator):
Weighted average shares - basic	369,540			368,829		368,150
Non-vested restricted stock (1)	—			1,929		1,548
Weighted average shares - diluted	369,540			370,758		369,698
Net income (loss) per share:
Basic	$	(0.96	)	$	2.65	$	2.08
Diluted	$	(0.96	)	$	2.64	$	2.07


(1)	During the year ended December 31, 2015, the Company had a net loss and therefore the potential dilutive effect of approximately 1,567,000 weighted average restricted shares were not included in the calculation of diluted net loss per share for 2015 because to do so would have been anti-dilutive to the computations.

Foreign currency translation

In 2014, the Company initiated exploratory drilling activities in Canada through a 100%-owned Canadian subsidiary. The Company has designated the Canadian dollar as the functional currency for its Canadian operations. Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in "Accumulated other comprehensive loss" within shareholders’ equity on the consolidated balance sheets.

New accounting pronouncements

In April 2015, the Financial Accounting Standards Board issued Accounting Standards Update ("ASU") 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs ("ASU 2015-03"). The new standard requires debt issuance costs related to a recognized term debt liability, such as the Company's senior notes, three-year term loan and note payable, be presented in the balance sheet as a direct deduction from the carrying amount of that term debt liability, consistent with the presentation of a debt discount. Under previous guidance, debt issuance costs were required to be presented in the balance sheet as an asset. The new standard does not affect the existing recognition and measurement guidance for debt issuance costs. The new standard is effective for annual and interim periods beginning after December 15, 2015, with early adoption permitted.

The Company early adopted ASU 2015-03 as of June 30, 2015 on a retrospective basis to all prior balance sheet periods presented. As a result of the adoption, the Company reclassified unamortized debt issuance costs associated with its senior notes and note payable, which totaled $65.7 million and $69.0 million as of June 30, 2015 and December 31, 2014, respectively, from "Other noncurrent assets" to a reduction of "Long-term debt, net of current portion" on the consolidated balance sheets. Unamortized debt issuance costs reflected as a reduction of long-term debt subsequently totaled $64.0 million as of December 31, 2015, inclusive of costs incurred upon execution of the Company's new term loan in November 2015 as discussed in Note 7. Long-Term Debt. Adoption of ASU 2015-03 had no impact on the Company's current and previously reported shareholders' equity, results of operations, or cash flows. The December 31, 2014 carrying amounts for the Company's senior notes and note payable presented throughout this report on Form 10-K have been adjusted to reflect the retroactive adoption of ASU 2015-03. Unamortized debt issuance costs associated with the Company's revolving credit facility, which amounted to $7.8 million and $7.0 million as of December 31, 2015 and 2014, respectively, were not reclassified and remain reflected in "Other noncurrent assets" on the consolidated balance sheets.

In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes, which requires entities with a classified balance sheet to present all deferred tax assets and deferred tax liabilities as noncurrent instead of separating deferred taxes into current and noncurrent amounts. The standard will be effective for public companies for annual and interim periods beginning after December 15, 2016, with early adoption permitted. The Company early adopted ASU 2015-17 as of December 31, 2015 on a retrospective basis to all prior balance sheet periods presented. As a result of the adoption, the Company reclassified $36.2 million and $145.3 million as of December 31, 2015 and 2014, respectively, from "Accrued liabilities and other" to “Deferred income tax liabilities, net” on the consolidated balance sheets. Adoption of ASU 2015-17 had no impact on the Company's current and previously reported shareholders' equity, results of operations, or cash flows. The affected prior period deferred income tax account balances presented throughout this report on Form 10-K have been adjusted to reflect the retroactive adoption of ASU 2015-17.