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 Nebraska and west of the Mississippi River including various plays in the SCOOP (South Central Oklahoma Oil Province) and STACK (Sooner Trend Anadarko Canadian Kingfisher) areas of Oklahoma. The East region is primarily comprised of undeveloped leasehold acreage east of the Mississippi River with no significant drilling or production operations.

A substantial portion of the Company’s operations is located in the North region, with that region comprising approximately 59% of the Company’s crude oil and natural gas production and approximately 69% of its crude oil and natural gas revenues for the year ended December 31, 2017. 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, 2017, approximately 50% of the Company’s estimated proved reserves were located in the North region. In recent years, the Company has significantly expanded its operations in the South region with its increased activity in the SCOOP and STACK plays. The South region comprised approximately 41% of the Company’s crude oil and natural gas production, 31% of its crude oil and natural gas revenues, and 50% of its estimated proved reserves as of and for the year ended December 31, 2017.

For the year ended December 31, 2017, crude oil accounted for approximately 57% of the Company’s total production and approximately 78% of its crude oil and natural gas revenues. Crude oil represents approximately 48% of the Company’s estimated proved reserves as of December 31, 2017.

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 periods. Actual results may differ from those estimates. The most significant estimates and assumptions impacting reported results are 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, 2017 and 2016 were not material.

New accounting rules governing the recognition and presentation of revenues went into effect on January 1, 2018. See the subsequent section titled "New accounting pronouncements not yet adopted at December 31, 2017–Revenue recognition and presentation" for discussion of the expected impact of the new rules on the Company's future financial statements.

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, 2017, the Company had cash deposits in excess of federally insured amounts of approximately $42.5 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. The Company’s allowance for doubtful accounts totaled $2.2 million and $3.0 million as of December 31, 2017 and 2016, respectively, which is included in “Receivables—Joint interest and other, net” on the consolidated balance sheets.

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, 2017, sales to the Company’s two largest purchasers accounted for approximately 11% and 11%, respectively, of the Company’s total crude oil and natural gas sales. No other purchaser accounted for more than 10% of the Company’s total crude oil and natural gas sales for 2017. 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 primarily using a weighted average cost method applied to specific classes of inventory items.

The components of inventory as of December 31, 2017 and 2016 consisted of the following:



	December 31,
In thousands	2017		2016
Tubular goods and equipment	$	14,946	$	15,243
Crude oil	82,460		96,744
Total	$	97,406	$	111,987

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 but are not limited to labor costs to operate the Company’s properties, repairs and maintenance, waste water disposal costs, utility costs, certain workover-related 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 and recycling 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 and recycling systems	15-30
Storage tanks	10-30
Office and computer equipment, software, furniture and fixtures	3-25
Buildings and improvements	4-40

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 and related disposal of facilities on its crude oil and natural gas properties. The following table summarizes the changes in the Company’s future abandonment liabilities from January 1, 2015 through December 31, 2017:



In thousands	2017			2016			2015
Asset retirement obligations at January 1	$	96,178		$	102,909		$	76,708
Accretion expense	5,886			6,086			4,740
Revisions (1)	7,801			(12,755		)	15,068
Plus: Additions for new assets	6,884			2,692			7,404
Less: Plugging costs and sold assets	(2,343		)	(2,754		)	(1,011		)
Total asset retirement obligations at December 31	$	114,406		$	96,178		$	102,909
Less: Current portion of asset retirement obligations at December 31 (2)	2,612			1,742			1,658
Non-current portion of asset retirement obligations at December 31	$	111,794		$	94,436		$	101,251


(1)	Revisions primarily represent changes in the present value of liabilities resulting from changes in estimated costs and economic lives of producing properties.


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

As of December 31, 2017 and 2016, net property and equipment on the consolidated balance sheets included $40.3 million and $34.0 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 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 aggregate capitalized costs of $58.2 million and $55.9 million (net of accumulated amortization of $65.9 million and $56.8 million) relating to its long-term debt at December 31, 2017 and 2016, respectively. Unamortized capitalized costs associated with the Company’s Notes and note payable totaled $55.0 million and $50.4 million at December 31, 2017 and 2016, respectively, and are reflected as a reduction of “Long-term debt, net of current portion” on the consolidated balance sheets. The increase in 2017 resulted from the capitalization of costs incurred in connection with the Company’s issuance of 4.375% Senior Notes due 2028 as discussed in Note 7. Long-Term Debt. Unamortized capitalized costs associated with the Company’s revolving credit facility totaled $3.2 million and $5.5 million at December 31, 2017 and 2016, respectively, and are reflected in “Other noncurrent assets” on the consolidated balance sheets.

For the years ended December 31, 2017, 2016 and 2015, the Company recognized amortization expense associated with capitalized debt issuance costs of $9.1 million, $9.8 million and $8.9 million, respectively, which are reflected in “Interest expense” on 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). Gains and losses on crude oil and natural gas derivatives are reflected in the caption “Gain (loss) on crude oil and natural gas derivatives, net.” Gains and losses on diesel fuel derivatives are reflected in the caption “Operating costs and expenses—Net gain on sale of assets and other.”

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, 2017 and 2016.

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. On December 22, 2017, the Tax Cuts and Jobs Act (the "Tax Reform Act") was signed into law, which among other things reduces the federal corporate income tax rate from 35% to 21% effective January 1, 2018. In accordance with U.S. GAAP, the Company remeasured its deferred income tax assets and liabilities as of December 31, 2017 to reflect the reduced tax rate. See Note 8. Income Taxes for further discussion of the Tax Reform Act and its impact on the Company's financial statements as of and for the year ended December 31, 2017.

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 $0.4 million, $1.0 million, and $13.5 million for the years ended December 31, 2017, 2016, and 2015, 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. In periods where the Company has net income, diluted earnings 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, 2017, 2016 and 2015.



	Year ended December 31,
In thousands, except per share data	2017		2016			2015
Net income (loss) (numerator) (1)	$	789,447	$	(399,679	)	$	(353,668	)
Weighted average shares (denominator):
Weighted average shares - basic	371,066		370,380			369,540
Non-vested restricted stock (2)	2,702		—			—
Weighted average shares - diluted	373,768		370,380			369,540
Net income (loss) per share: (1)
Basic	$	2.13	$	(1.08	)	$	(0.96	)
Diluted	$	2.11	$	(1.08	)	$	(0.96	)

(1)

The Company’s remeasurement of its deferred income tax assets and liabilities in response to the enactment of the Tax Reform Act in December 2017 resulted in a one-time decrease in income tax expense and corresponding increase in net income of approximately $713.7 million ($1.92 per basic share and $1.91 per diluted share) for the year ended December 31, 2017. See Note 8. Income Taxes for further discussion. Additionally, 2017 results include a $59.6 million pre-tax loss accrual recognized in conjunction with a litigation settlement as discussed in Note 10. Commitments and Contingencies, which resulted in an after-tax decrease in 2017 net income of $37.0 million ($0.10 per basic and diluted share).


(2)	For the years ended December 31, 2016 and 2015, the Company had a net loss and therefore the potential dilutive effect of approximately 2,303,000 and 1,567,000 weighted average non-vested restricted shares, respectively, were not included in the calculation of diluted net loss per share 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’s operations in Canada are currently immaterial. 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 income (loss)” within shareholders’ equity on the consolidated balance sheets.

Adoption of new accounting pronouncements

Stock-based compensation – In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, which changes how companies account for certain aspects of share-based payment awards, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The Company adopted the new standard on January 1, 2017 as required. The impact of adoption is described below.

ASU 2016-09 removes the requirement to delay recognition of an excess tax benefit until it reduces current taxes payable. An excess tax benefit (tax deficiency) arises when stock-based compensation expense recognized in an entity’s tax return exceeds (is less than) the expense recognized in an entity’s financial statements. Under the new standard, effective January 1, 2017 excess tax benefits are recorded when they arise. This change was required to be applied on a modified retrospective basis by recording a cumulative effect adjustment to opening retained earnings upon adoption to account for previously unrecognized excess tax benefits. The Company’s cumulative effect adjustment recorded under the new standard resulted in a $5.2 million increase in retained earnings and corresponding decrease in deferred income tax liabilities at January 1, 2017.

Additionally, under ASU 2016-09 companies no longer record excess tax benefits and deficiencies in additional paid-in capital. Instead, excess tax benefits and deficiencies are recognized as income tax benefit or expense in the income statement, effective January 1, 2017 on a prospective basis. This is expected to result in increased volatility in income tax expense/benefit and corresponding variations in the relationship between income tax expense/benefit and pre-tax income/loss from period to period. The Company recognized $3.9 million ($0.01 per basic and diluted share) of tax deficiencies from stock-based compensation as income tax expense for the year ended December 31, 2017 under the new standard, which is reflected in “Benefit for income taxes” in the consolidated statements of comprehensive income (loss).

ASU 2016-09 also removed the requirement that entities present excess tax benefits and deficiencies as offsetting cash flows from financing and operating activities in the statement of cash flows. Instead, ASU 2016-09 requires cash flows related to excess tax benefits and deficiencies be classified as operating activities in the same manner as other cash flows related to income taxes. The Company has elected to apply this guidance on a prospective basis. Accordingly, the cash flow presentation of excess tax benefits and deficiencies in periods prior to January 1, 2017 has not been adjusted to conform to current period presentation.

The Company has elected to continue its historical accounting practice of estimating forfeitures in determining the amount of stock-based compensation expense to recognize. Therefore, the adoption of ASU 2016-09 does not have an impact on the amount of stock-based compensation expense to be recognized by the Company on non-vested restricted stock awards.

Business combinations – In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business, which changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities is deemed to be a business. Determining whether a transferred set constitutes a business is important because the accounting for a business combination differs from that of an asset acquisition. The definition of a business also affects the accounting for dispositions. Under the new standard, when substantially all of the fair value of assets acquired is concentrated in a single asset, or a group of similar assets, the assets acquired would not represent a business and business combination accounting would not be required. The new standard may result in more transactions being accounted for as asset acquisitions rather than business combinations. The standard is effective for interim and annual periods beginning after December 15, 2017 and shall be applied prospectively. The Company early adopted ASU 2017-01 as of January 1, 2017, which had no significant impact on the Company’s financial statements as of and for the year ended December 31, 2017.

New accounting pronouncements not yet adopted at December 31, 2017

Revenue recognition and presentation – In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which generally requires an entity to identify performance obligations in its contracts, estimate the amount of consideration to be received in the transaction price, allocate the transaction price to each separate performance obligation, and recognize revenue as obligations are satisfied. Additionally, the standard requires expanded disclosures related to revenue recognition.

Subsequent to the issuance of ASU 2014-09, the FASB issued various clarifications and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. Under this guidance, an entity generally shall record revenue on a gross basis if it controls a promised good or service before transferring it to a customer, whereas an entity shall record revenue on a net basis if its role is to arrange for another entity to provide the goods or services to a customer. Significant judgment may be required in some circumstances to determine whether gross or net presentation is appropriate.

ASU 2014-09 and related interpretive guidance is effective for interim and annual periods beginning after December 15, 2017 and allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. The Company adopted the standard on January 1, 2018 using the modified retrospective approach, which had no cumulative effect impact on retained earnings upon adoption. The standard is not expected to have a material effect on the timing of the Company’s revenue recognition or its financial position, results of operations, net income, or cash flows, but will impact the Company’s revenue-related disclosures and internal controls over financial reporting beginning January 1, 2018. Additionally, the standard will impact the Company's future presentation of revenues and expenses under the gross-versus-net presentation guidance. Historically, the Company has generally presented its revenues net of transportation costs. The new guidance will result in future revenues and associated transportation expenses for certain of the Company’s operated properties being reported on a gross basis beginning January 1, 2018. The changes from net to gross presentation will result in an increase in revenues and a corresponding increase in separately reported transportation expenses, with no net effect on the Company’s results of operations, net income, or cash flows. For the year ended December 31, 2017, the Company had approximately $201.5 million of transportation–related charges on operated properties included in “Crude oil and natural gas sales” on the consolidated statements of comprehensive income (loss). This amount is not necessarily indicative of amounts to be expected in future periods. The Company is not able to estimate the impact on the presentation of its future revenues and expenses under the new guidance due to uncertainties with respect to future sales volumes, service costs, locations of producing properties, sales destinations, transportation methods utilized, and changes in the nature, timing, and extent of its arrangements from period to period.

Leases – In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires companies to recognize a right of use asset and related liability on the balance sheet for the rights and obligations arising from leases with durations greater than 12 months. The standard is effective for interim and annual reporting periods beginning after December 15, 2018 and requires adoption by application of a modified retrospective transition approach.

The Company continues to evaluate the impact of ASU 2016-02 on its financial statements, accounting policies and internal controls and is in the process of developing systems and processes to identify, classify, and account for leases within the scope of the new guidance and to comply with the related disclosure requirements. Standard setting guidance and interpretations continue to evolve and are being monitored for applicability and impact to the Company’s business and industry. Based on an initial review of the new guidance and the Company’s current commitments, the Company anticipates it may be required to recognize lease assets and liabilities related to drilling rig commitments, certain equipment rentals and leases, certain surface use agreements, and potentially certain firm transportation agreements, as well as other arrangements, the effect of which cannot be estimated at this time.

Credit losses – In June 2016, the FASB issued ASU 2016-13, Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. This standard changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. The standard is effective for interim and annual periods beginning after December 15, 2019 and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Company continues to evaluate the new standard and is unable to estimate its financial statement impact at this time. Historically, the Company’s credit losses on crude oil and natural gas sales receivables and joint interest receivables have been immaterial.