Note 1. Organization and Summary of Significant Accounting Policies

Description of the Company

Continental Resources, Inc. (the “Company”) is incorporated under the laws of the State of Oklahoma. The Company was originally formed in 1967 to explore for, develop and produce crude oil and natural gas. Continental’s properties are 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 Kansas and all properties south of Kansas and west of the Mississippi River including the South Central Oklahoma Oil Province, Northwest Cana, and Arkoma Woodford plays in Oklahoma. In December 2012, the Company sold its producing properties in the East region. See Note 13. Property Acquisitions and Dispositions for further discussion. The Company’s remaining East region properties are comprised of undeveloped leasehold acreage east of the Mississippi River.

The Company’s operations are geographically concentrated in the North region, with that region comprising approximately 76% of the Company’s crude oil and natural gas production for the year ended December 31, 2012. Additionally, as of December 31, 2012 approximately 82% of the Company’s estimated proved reserves were located in the North region.

The Company has focused its operations on the exploration and development of crude oil since the 1980s. For the year ended December 31, 2012, crude oil accounted for approximately 70% of the Company’s crude oil and natural gas production and approximately 89% of its crude oil and natural gas revenues.

Basis of presentation of consolidated financial statements

The consolidated financial statements include the accounts of Continental Resources, Inc. and its subsidiaries. All significant intercompany balances 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 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. In the opinion of management, all adjustments (consisting only of normal recurring adjustments) necessary for a fair presentation in accordance with U.S. GAAP have been included in these consolidated financial statements.

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. Each month the Company estimates the volumes sold and the price at which they were sold to record revenue. The following table shows the amounts of estimated crude oil and natural gas sales recorded as of December 31 for each indicated year.


	December 31,
	2012		2011		2010
	In thousands
Estimated crude oil and natural gas revenues	$	530,601	$	491,585	$	263,075

Variances between estimated revenues and actual amounts received are recorded in the month payment is received and are included in the consolidated statements of income under the caption “Revenues—Crude Oil and Natural Gas Sales”. These variances have historically not been material. 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, 2012 and 2011 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, 2012, the Company had cash deposits in excess of federally insured amounts of approximately $35.2 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 uncollectible and any payments subsequently received on those receivables are credited to the allowance for doubtful accounts. Write-offs of uncollectible 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 years ended December 31, 2012, 2011 and 2010, crude oil and natural gas sales to the Company’s largest purchaser accounted for approximately 21%, 41% and 57% of total crude oil and natural gas sales, respectively. Additionally, for the year ended December 31, 2012 the Company’s second 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 those three years. 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 the Company’s operating regions.

Inventories

Inventories are stated at the lower of cost or market and consist of the following:


	December 31,
	2012		2011
	In thousands
Tubular goods and equipment	$	13,590	$	15,665
Crude oil		33,153		25,605

Total	$	46,743	$	41,270

Crude oil inventories are valued at the lower of cost or market using the first-in, first-out inventory method. Crude oil inventories consist of the following volumes:


	December 31,
MBbls	2012		2011
Crude oil line fill requirements		391		283
Temporarily stored crude oil		211		152

Total		602		435

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. Total capitalized exploratory drilling costs pending the determination of proved reserves were $92.7 million and $128.1 million as of December 31, 2012 and 2011, respectively. As of December 31, 2012, exploratory drilling costs of $8.1 million, representing 6 wells, were suspended one year beyond the completion of drilling and are expected to be fully evaluated in 2013. Of the suspended costs, $0.3 million was incurred in 2012, $6.6 million was incurred in 2011, $0.1 million was incurred in 2010 and $1.1 million was incurred in 2009.

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, and materials and supplies utilized in the Company’s operations.

Service property and equipment

Service property and equipment consist primarily of furniture and fixtures, automobiles, machinery and equipment, office equipment, computer equipment and software, 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
Furniture and fixtures		10
Automobiles		5
Machinery and equipment		10-20
Office equipment, computer equipment and software		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 crude oil and natural gas 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, 2010 through December 31, 2012:


	2012			2011			2010
	In thousands
Asset retirement obligations at January 1	$	62,625		$	56,320		$	50,167
Accretion expense		3,105			3,163			2,665
Revisions		(2,871	)		1,947			2,564
Plus: Additions for new assets		6,679			3,559			2,794
Less: Plugging costs and sold assets (1)		(22,367	)		(2,364	)		(1,870	)

Total asset retirement obligations at December 31	$	47,171		$	62,625		$	56,320
Less: Current portion of asset retirement obligations at December 31		2,227			2,287			2,241

Non-current portion of asset retirement obligations at December 31	$	44,944		$	60,338		$	54,079

(1)	As a result of asset dispositions during the year ended December 31, 2012, the Company removed $20.0 million of its previously recognized asset retirement obligations that were assumed by the buyers. See Note 13. Property Acquisitions and Dispositions for further discussion.

As of December 31, 2012 and 2011, net property and equipment on the consolidated balance sheets included $36.6 million and $43.8 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, or when events and circumstances indicate a possible decline in the recoverability of the carrying value of such field. 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. Due to the unavailability of relevant comparable market data, a discounted cash flow method is used to determine the fair value of proved properties. The discounted cash flow method estimates future cash flows based on managementâ€™s estimates of future crude oil and natural gas production, commodity prices based on commodity futures price strips, operating and development costs, and a risk-adjusted discount rate.

Non-producing crude oil and natural gas properties primarily consist of undeveloped leasehold costs and costs associated with the purchase of proved undeveloped reserves. Individually significant non-producing properties, if any, are assessed for impairment on a property-by-property basis and, if the assessment indicates an impairment, a loss is recognized by providing a valuation allowance consistent with the level at which impairment was assessed. For individually insignificant non-producing properties, impairment losses 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 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 revolving credit facility and amendments thereto were capitalized and are being amortized over the term of the facility on a straight-line basis, the use of which approximates the effective interest method. Costs incurred upon the issuance of the 8 1/4% Senior Notes due 2019, the 7 3/8% Senior Notes due 2020, the 7 1/8% Senior Notes due 2021, and the 5% Senior Notes due 2022 (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 $55.3 million and $23.9 million (net of accumulated amortization of $20.2 million and $14.6 million) relating to its long-term debt at December 31, 2012 and 2011, respectively. The increase in 2012 resulted from the capitalization of costs incurred in connection with the Company’s issuances of 5% Senior Notes due 2022 as discussed in Note 7. Long-Term Debt. During the years ended December 31, 2012, 2011 and 2010, the Company recognized associated amortization expense of $5.6 million, $3.3 million and $3.5 million, respectively, which are reflected in “Interest expense” in the consolidated statements of income.

Derivative instruments

The Company is required to recognize 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 anticipated 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 realized and unrealized changes in fair value in the consolidated statements of income 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. The carrying values of cash, trade receivables and trade payables are considered to be representative of their respective fair values due to the short term maturity of those instruments. The fair value of derivative contracts is based upon various factors, including commodity exchange prices, over-the-counter quotations, and, in the case of collars, volatility, the risk-free interest rate, and the time to expiration. See Note 5. Derivative Instruments for quantification of the fair value of the Company’s derivative instruments at December 31, 2012 and 2011.

Long-term debt consists of the Company’s Notes, its note payable, and borrowings on its revolving credit facility. The fair values of the Notes are based on quoted market prices. The fair value of the note payable is determined using a discounted cash flow approach based on the interest rate and payment terms of the note payable and an assumed discount rate. The fair value of credit facility borrowings approximates carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities. See Note 6. Fair Value Measurements for quantification of the fair value of the Company’s long-term debt obligations at December 31, 2012 and 2011.

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. 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’s policy is to recognize penalties and interest related to unrecognized tax benefits, if any, in income tax expense.

Earnings per share

Basic net income per share is computed by dividing net income by the weighted-average number of shares outstanding for the period. Diluted net income per share reflects the potential dilution of non-vested restricted stock awards and stock options, which are calculated using the treasury stock method as if the awards and options were exercised. The following table presents the calculation of basic and diluted weighted average shares outstanding and net income per share for the years ended December 31, 2012, 2011 and 2010:


	Year ended December 31,
	2012		2011		2010
	In thousands, except per share data
Income (numerator):
Net income - basic and diluted	$	739,385	$	429,072	$	168,255
Weighted average shares (denominator):
Weighted average shares - basic		181,340		177,590		168,985
Non-vested restricted stock		490		544		546
Stock options		16		96		248

Weighted average shares - diluted		181,846		178,230		169,779
Net income per share:
Basic	$	4.08	$	2.42	$	1.00
Diluted	$	4.07	$	2.41	$	0.99