SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

(State or other jurisdiction of

incorporation or organization)

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, ~~or a~~ smaller reporting company, or an emerging growth company. See the definitions of “large accelerated ~~filer”,~~filer,” “accelerated ~~filer”~~filer,” “smaller reporting company,” and ~~“smaller reporting~~“emerging growth company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

~~374,571,874~~375,190,967 shares of our $0.01 par value common stock were outstanding on April ~~29, 2016~~.30, 2017.

When we refer to “us,” “we,” “our,” “Company,” or “Continental” we are describing Continental Resources, Inc. and our subsidiaries.

Glossary of Crude Oil and Natural Gas Terms

The terms defined in this section may be used throughout this report:

“Bbl” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.

“Boe” Barrels of crude oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of crude oil based on the average equivalent energy content of the two commodities.

“Btu” British thermal unit, which represents the amount of energy needed to heat one pound of water by one degree Fahrenheit and can be used to describe the energy content of fuels.

“completion” The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil and/or natural gas.

“DD&A” Depreciation, depletion, amortization and accretion.

“developed acreage” The number of acres allocated or assignable to productive wells or wells capable of production.

“development well” A well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

“dry hole” Exploratory or development well that does not produce crude oil and/or natural gas in economically producible quantities.

“enhanced recovery” The recovery of crude oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Enhanced recovery methods are sometimes applied when production slows due to depletion of the natural pressure.

“exploratory well” A well drilled to find crude oil or natural gas in an unproved area, to find a new reservoir in an existing field previously found to be productive of crude oil or natural gas in another reservoir, or to extend a known reservoir beyond the proved area.

“field” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

“formation” A layer of rock which has distinct characteristics that differs from nearby rock.

"gross acres" or "gross wells" Refers to the total acres or wells in which a working interest is owned.

“horizontal drilling” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled horizontally within a specified interval.

“MBbl” One thousand barrels of crude oil, condensate or natural gas liquids.

“MBoe” One thousand Boe.

“Mcf” One thousand cubic feet of natural gas.

“MMBoe” One million Boe.

“MMBtu” One million British thermal units.

“MMcf” One million cubic feet of natural gas.

“net acres” or "net wells" Refers to the sum of the fractional working interests owned in gross acres or gross wells.

“NYMEX” The New York Mercantile Exchange.

“play” A portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential crude oil and natural gas reserves.

“productive well” A well found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

“prospect” A potential geological feature or formation which geologists and geophysicists believe may contain hydrocarbons. A prospect can be in various stages of evaluation, ranging from a prospect that has been fully evaluated and is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation.

“proved reserves” The quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain.

“reservoir” A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“royalty interest” Refers to the ownership of a percentage of the resources or revenues produced from a crude oil or natural gas property. A royalty interest owner does not bear exploration, development, or operating expenses associated with drilling and producing a crude oil or natural gas property.

“SCOOP” Refers to the South Central Oklahoma Oil Province, a term ~~we use~~used to describe ~~an area of crude oil and liquids-rich natural gas~~ properties located in the Anadarko basin of Oklahoma in which we operate. Our SCOOP acreage extends across portions of Garvin, Grady, Stephens, Carter, McClain and Love counties of Oklahoma and has the potential to contain hydrocarbons from a variety of conventional and unconventional reservoirs overlying and underlying the Woodford formation.

"STACK" Refers to Sooner Trend Anadarko Canadian Kingfisher, a term used to describe ~~properties~~a resource play located in the Anadarko Basin of Oklahoma characterized by stacked geologic formations with major targets in ~~which we operate.~~the Meramec, Osage and Woodford formations. A significant portion of our STACK acreage is located in over-pressured portions of Blaine, Dewey and Custer counties of Oklahoma.

“undeveloped acreage” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and/or natural gas.

“unit” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

“working interest” The right granted to the lessee of a property to explore for and to produce and own crude oil, natural gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995

This report and information incorporated by reference in this report include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company's business and statements or information concerning the Company’s future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows, included in this report are forward-looking statements. The words “could,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “budget,” “plan,” “continue,” “potential,” “guidance,” “strategy” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

Forward-looking statements may include, but are not limited to, statements about:

Forward-looking statements are based on the Company’s current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate or will not change over time. The risks and uncertainties that may affect the operations, performance and results of the business and forward-looking statements include, but are not limited to, those risk factors and other cautionary statements described under Part II, Item 1A. Risk Factors and elsewhere in this report, if any, our Annual Report on Form 10-K for the year ended December 31, ~~2015,~~2016, registration statements we file from time to time with the Securities and Exchange Commission, and other announcements we make from time to time.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this report occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement.

Except as expressly stated above or otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.

PART I. Financial Information

Continental Resources, Inc. and Subsidiaries

Note 1. Organization and Nature of Business

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~~Nebraska 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 primarily comprised of undeveloped leasehold acreage east of the Mississippi River with no ~~current~~significant drilling or production operations.

A substantial portion of the Company’s operations are ~~concentrated~~located in the North region, with that region comprising approximately ~~66%~~56% of the Company’s crude oil and natural gas production and approximately ~~72%~~65% of its crude oil and natural gas revenues for the three months ended March 31, ~~2016.~~2017. The Company's principal producing properties in the North region are located in the Bakken field of North Dakota and Montana. In recent years, the Company has significantly expanded its ~~activity~~operations in the South region with its ~~discovery of the SCOOP play and its~~ increased activity in the ~~Northwest Cana~~SCOOP and STACK plays. The South region comprised approximately ~~34%~~44% of the Company's crude oil and natural gas production and approximately ~~28%~~35% of its crude oil and natural gas revenues for the three months ended March 31, ~~2016.~~2017.

~~The Company has focused its operations on the exploration and development of crude oil since the 1980s.~~ For the three months ended March 31, ~~2016,~~2017, crude oil accounted for approximately ~~63%~~56% of the Company’s total production and approximately ~~85%~~76% of its crude oil and natural gas revenues.

Note 2. Basis of Presentation and Significant Accounting Policies

Basis of presentation

The condensed 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.

This report has been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”) applicable to interim financial information. Because this is an interim period filing presented using a condensed format, it does not include all disclosures required by accounting principles generally accepted in the United States (“U.S. GAAP”), although the Company believes the disclosures are adequate to make the information not misleading. You should read this Quarterly Report on Form 10-Q ("Form 10-Q") together with the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2015~~2016 (“~~2015~~2016 Form 10-K”), which includes a summary of the Company’s significant accounting policies and other disclosures.

The condensed consolidated financial statements as of March 31, ~~2016~~2017 and for the three month periods ended March 31, ~~2016~~2017 and ~~2015~~2016 are unaudited. The condensed consolidated balance sheet as of December 31, ~~2015~~2016 was derived from the audited balance sheet included in the ~~2015~~2016 Form 10-K. The Company has evaluated events or transactions through the date this report on Form 10-Q was filed with the SEC in conjunction with its preparation of these condensed consolidated financial statements.

The preparation of financial statements in conformity with 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 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 unaudited interim condensed consolidated financial statements. The results of operations for any interim period are not necessarily indicative of the results of operations that may be expected for any other interim period or for an entire year.

~~Net loss~~Earnings per share

Basic ~~and diluted~~ net ~~loss~~income (loss) per share is computed by dividing net ~~loss~~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-~~non-vested restricted stock awards, which are calculated using the treasury stock method. The following table

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

~~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 ~~loss~~income (loss) per share for the three months ended March 31, ~~2016~~2017 and ~~2015.~~2016.

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 March 31, ~~2016~~2017 and December 31, ~~2015~~2016 consisted of the following:

~~Income taxes are accounted for using the liability method under which deferred income taxes are recognized for the future tax effects~~Adoption 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 period-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 $0.1 million and $11.1 million for the three months ended March 31, 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.

~~New~~new accounting pronouncements ~~not yet adopted~~

Stock-based compensation – In ~~February~~March 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ~~2016-02,~~("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 $3.3 million ($0.01 per share) of tax deficiencies from stock-based compensation as income tax expense in the first quarter of 2017 under the new standard, which is reflected in “(Provision) benefit for income taxes" in the unaudited condensed consolidated statements of comprehensive income (loss).

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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, if applicable, will not be 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, rather than accounting for forfeitures as they occur. 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 three months ended March 31, 2017.

New accounting pronouncements not yet adopted

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 ~~is currently evaluating~~continues to evaluate the impact of ASU 2016-02 and is in the process of developing systems and processes to identify, classify, and account for leases within the scope of the new ~~standard~~guidance. Based on ~~its financial statements~~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 ~~disclosures.~~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.

Revenue recognition and presentation – In ~~March 2016,~~May 2014, the FASB issued ~~Accounting Standards Update 2016-09,~~ASU 2014-09, ~~Compensation—Stock Compensation~~Revenue from Contracts with Customers (Topic ~~718): Improvements to Employee Share-Based Payment Accounting~~606), which ~~changes how companies account~~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 has 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 will be 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 plans to adopt the standard on January 1, 2018 using a modified retrospective approach. 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 is expected to impact the presentation of future 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 is expected to result in future revenues and associated transportation expenses for certain ~~aspects~~ of ~~share-based payment awards, including~~ the ~~accounting for~~Company's operated properties being reported on a gross basis. The Company expects 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, ~~taxes, forfeitures, and statutory tax withholding~~or cash flows. For the three months ended March 31, 2017, the

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

~~requirements, as well as classification~~Company estimates it had approximately $50 million of transportation-related charges on operated properties included in "Crude oil and natural gas sales" on the unaudited condensed consolidated statements of comprehensive income (loss). The Company is not currently 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 ~~statement~~nature, timing, and extent of ~~cash flows.~~its arrangements from period to period.

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 ~~reporting~~ periods beginning after December 15, ~~2016~~2019 and shall be ~~adopted~~ ~~either prospectively, retrospectively or~~applied using a modified retrospective ~~transition~~ approach ~~depending on the topic covered~~resulting in ~~the standard.~~ a cumulative effect adjustment to retained earnings upon adoption. The Company is currently evaluating the ~~impact of the~~ new standard onand is unable to estimate its financial ~~statements and related disclosures.~~statement impact at this time.

Note 3. Supplemental Cash Flow Information

The following table discloses supplemental cash flow information about cash paid for interest and income tax payments and refunds. Also disclosed is information about investing activities that affects recognized assets and liabilities but ~~has~~does not ~~yet resulted~~result in cash receipts or payments.

As of March 31, ~~2016~~2017 and December 31, ~~2015,~~2016, the Company had ~~$246.0~~$268.0 million and ~~$282.8~~$223.6 million, respectively, of accrued capital expenditures included in "Net property and equipment" and "Accounts payable trade" in the condensed consolidated balance sheets. ~~As of March 31, 2015 and December 31, 2014, the Company had $537.3 million and $797.5 million, respectively, of accrued capital expenditures.~~

Note 4. Derivative Instruments

Crude oil and natural gas derivatives

The Company may utilize crude oil and natural gas swap and collar derivative contracts to economically hedge against the variability in cash flows associated with future sales of crude oil and natural gas production. While the use of these derivative instruments limits the downside risk of adverse price movements, their use also limits future revenues from upward price movements.

The Company recognizes all ~~crude oil and natural gas~~ derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The Company has not designated its crude oil and natural gas derivative instruments as hedges for accounting purposes and, as a result, marks such derivative instruments to fair value and recognizes the changes in fair value in the unaudited condensed consolidated statements of comprehensive ~~loss~~income (loss) under the caption “Gain on crude oil and natural gas derivatives, net”~~, which is a component of "Total revenues"~~.

The estimated fair value of derivative contracts is based upon various factors, including commodity exchange prices, over-the-counter quotations, and, in the case of collars and written call options, volatility, the risk-free interest rate, and the time to expiration. The calculation of the fair value of collars and written call options requires the use of an option-pricing model. See Note 5. Fair Value Measurements.

With respect to a crude oil or natural gas fixed price swap contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swap price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. For a crude oil or natural gas collar contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price, and the Company is required to make a payment to the counterparty if the settlement

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

price for any settlement period is above the ceiling price. Neither party is required to make a payment to the other party if the settlement price for any settlement period is between the floor price and the ceiling price.

~~The Company’s crude oil and~~At March 31, 2017, the Company had outstanding natural gas derivative contracts are settled based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on Inter-Continental Exchange (“ICE”) pricing for Brent crude oil and natural gas derivative settlements based on NYMEX Henry Hub pricing. The estimated fair value of derivative contracts is based upon various factors, including commodity exchange prices, over-the-counter quotations, and, in the case of collars and written call options, volatility, the risk-free interest rate, and the time to expiration. The calculation of the fair value of collars and written call options requires the use of an option-pricing model. See ~~Note 5. Fair Value Measurements~~.

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

~~At March 31, 2016, the Company had outstanding crude oil and natural gas derivative contracts with respect to future production~~ as set forth in the ~~tables~~table below. The ~~hedged~~ volumes reflected below represent an aggregation of multiple derivative contracts having similar remaining durations that ~~have varying durations and may not~~are expected to be realized ~~on a ratable basis~~ratably over ~~a calendar year.~~the respective 2017 and 2018 periods. At March 31, 2017 the Company had no outstanding crude oil derivative contracts.

Crude Oil - ICE Brent

Period and Type of Contract Bbls Ceiling Price
April 2016 - December 2016
Written call options - ICE Brent (1) 1,100,000
$ 107.70

(1) Written call options represent the ceiling positions remaining from the Company's previous crude oil collar contracts. The floor positions of the collars were liquidated in the fourth quarter of 2014. For these written call options, the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price.

Crude oil and natural gas derivative gains and losses

The following table presents cash settlements on matured crude oil and natural gas derivative instruments and non-cash gains and losses on open crude oil and natural gas derivative instruments for the periods presented. Cash receipts and payments ~~below~~in the following table reflect the gain or loss on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash gains and losses below represent the change in fair value of derivative instruments which continue to be held at period end and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period.

Diesel fuel derivatives

In March 2016, the Company entered into diesel fuel swap derivative contracts to economically hedge against the variability in cash flows associated with future purchases of diesel fuel for use in drilling activities. The Company has hedged approximately 19nine million gallons of diesel fuel over the period from ~~July 2016~~April 2017 to December 2017 at a weighted average price of ~~$1.41~~$1.45 per gallon. With respect to these diesel fuel swap contracts, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is greater than the swap price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is less than the swap price. The diesel fuel swap contracts are settled based upon reported NYMEX settlement prices for New York Harbor ultra-low sulfur diesel fuel.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

The Company recognizes its diesel fuel derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The estimated fair value is based upon various factors, including commodity exchange prices, over-the-counter quotations, the risk-free interest rate, and time to expiration. The Company has not designated its diesel fuel derivative instruments as hedges for accounting purposes and, as a result, marks the derivative instruments to fair value and recognizes the changes in fair value in the unaudited condensed consolidated statements of comprehensive ~~loss~~income (loss) under the caption “Operating costs and expenses—~~Other.~~Net loss on sale of assets and other.” For the three months ended March 31, 2017, the Company recognized cash gains of $0.7 million on its matured diesel fuel derivatives. For the three months ended March 31, 2017 and March 31, 2016, the Company recognized a non-cash ~~loss~~losses of $2.6 million and $1.1 million, ~~associated with its~~respectively, on diesel fuel ~~derivatives.~~derivatives that continued to be held at the end of those respective periods.

Balance sheet offsetting of derivative assets and liabilities

The Company’s derivative contracts are recorded at fair value in the condensed consolidated balance sheets under the captions “Derivative assets”, “Noncurrent derivative assets”, “Derivative liabilities”, and “Noncurrent derivative liabilities”., as applicable. Derivative assets and liabilities with the same counterparty that are subject to contractual terms which provide for net settlement are reported on a net basis in the condensed consolidated balance sheets.

The following table presents the gross amounts of recognized crude oil, natural gas, and diesel fuel derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the condensed consolidated balance sheets for the periods presented, all at fair value.

The following table reconciles the net amounts disclosed above to the individual financial statement line items in the condensed consolidated balance sheets.

Note 5. Fair Value Measurements

The Company follows a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

A financial instrument’s categorization within the hierarchy is based upon the lowest level of input that is significant to the fair value measurement. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the hierarchy. As Level 1 inputs generally provide the most reliable evidence of fair value, the Company uses Level 1 inputs when available. The Company’s policy is to recognize transfers between the hierarchy levels as of the beginning of the reporting period in which the event or change in circumstances caused the transfer.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Company's derivative instruments are reported at fair value on a recurring basis. In determining the fair values of swap contracts, a discounted cash flow method is used due to the unavailability of relevant comparable market data for the Company’s exact contracts. The discounted cash flow method estimates future cash flows based on quoted market prices for forward commodity prices and a risk-adjusted discount rate. The fair values of swap contracts are calculated mainly using significant observable inputs (Level 2). Calculation of the fair values of collars ~~and written call options~~ requires the use of an industry-standard option pricing model that considers various inputs including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. These assumptions are observable in the marketplace or can be corroborated by active markets or broker quotes and are therefore designated as Level 2 within the valuation hierarchy. The Company’s calculation of fair value for each of its derivative positions is compared to the counterparty valuation for reasonableness.

The following tables summarize the valuation of financial instruments by pricing levels that were accounted for at fair value on a recurring basis as of March 31, ~~2016~~2017 and December 31, ~~2015.~~2016.

Assets Measured at Fair Value on a Nonrecurring Basis

Certain assets are reported at fair value on a nonrecurring basis in the condensed consolidated financial statements. The following methods and assumptions were used to estimate the fair values for those assets.

Asset Impairments – 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. 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 the Company's estimates of future crude oil and natural gas production, commodity prices based on commodity futures price strips adjusted for differentials, operating costs, and a risk-adjusted discount rate. The fair value of proved crude oil and natural gas properties is calculated using significant unobservable inputs (Level 3). The

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

following table sets forth quantitative information about the significant unobservable inputs used by the Company to calculate the fair value of proved crude oil and natural gas properties using a discounted cash flow method.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Unobservable inputs to the fair value assessment are reviewed quarterly and are revised as warranted based on a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Fair value measurements of proved properties are reviewed and approved by certain members of the Company’s management.

~~Proved~~For the three months ended March 31, 2017 the Company determined the carrying amounts of certain proved properties were ~~reviewed~~not recoverable from future cash flows, and therefore, were impaired. Impairments of proved properties amounted to $0.9 million for ~~impairment at~~the period, primarily for properties in a non-core area of the North region. The impaired properties were written down to their estimated fair value of approximately $3.4 million as of March 31, ~~2016 and March 31, 2015.~~ 2017.

For the three months ended March 31, 2016, estimated future net cash flows were determined to be in excess of cost basis, therefore no impairment was recorded for the Company’s proved crude oil and natural gas properties. For the three months ended March 31, 2015, the Company determined the carrying amounts of certain proved properties were not recoverable from future cash flows at that time and, therefore, were impaired. Impairments of proved properties for the first quarter of 2015 totaled $70.0 million, which were primarily concentrated in an emerging area with minimal production and costly reserve additions ($36.1 million), the Medicine Pole Hills units ($14.7 million), various legacy areas in the South region ($11.1 million), and non-Bakken areas of North Dakota and Montana ($8.1 million). The impaired properties were written down to their estimated fair value totaling approximately $38.2 million as of March 31, 2015.

Certain unproved crude oil and natural gas properties were impaired during the three months ended March 31, ~~2016~~2017 and ~~2015,~~2016, reflecting recurring amortization of undeveloped leasehold costs on properties the Company expects 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 following table sets forth the non-cash impairments of both proved and unproved properties for the indicated periods. Proved and unproved property impairments are recorded under the caption “Property impairments” in the unaudited condensed consolidated statements of comprehensive ~~loss.~~income (loss).

Three months ended March 31,
In thousands 2016 2015
Proved property impairments $ —
$ 70,016
Unproved property impairments 78,927
77,545
Total $ 78,927
$ 147,561

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~



	Three months ended March 31,
In thousands	2017		2016
Proved property impairments	$	871	$	—
Unproved property impairments	50,501		78,927
Total	$	51,372	$	78,927

Financial Instruments Not Recorded at Fair Value

The following table sets forth the estimated fair values of financial instruments that are not recorded at fair value in the condensed consolidated financial statements.

The fair values of revolving credit facility borrowings and the term loan approximate ~~face~~carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and are classified as Level 2 in the fair value hierarchy.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

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 the note payable is significantly influenced by the discount rate assumption, which is derived by the Company and is unobservable. Accordingly, the fair value of the note payable is classified as Level 3 in the fair value hierarchy.

The fair values of the ~~7.375% Senior Notes due 2020 (“2020 Notes”), the 7.125% Senior Notes due 2021 (“2021 Notes”), the~~ 5% Senior Notes due 2022 (“2022 Notes”), the 4.5% Senior Notes due 2023 ("(“2023 ~~Notes"~~Notes”), the 3.8% Senior Notes due 2024 ("(“2024 ~~Notes"~~Notes”), and the 4.9% Senior Notes due 2044 ("(“2044 ~~Notes"~~Notes”) are based on quoted market prices and, accordingly, are classified as Level 1 in the fair value hierarchy.

The carrying values of all classes of cash and cash equivalents, trade receivables, and trade payables are considered to be representative of their respective fair values due to the short term maturities of those instruments.

Note 6. Long-Term Debt

Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling ~~$48.2~~$36.2 million and ~~$49.6~~$37.3 million at March 31, ~~2016~~2017 and December 31, ~~2015,~~2016, respectively, consists of the following.

In thousands March 31, 2016 December 31, 2015
Revolving credit facility $ 940,000
$ 853,000
Term loan 498,401
498,274
Note payable 13,781
14,309
7.375% Senior Notes due 2020 196,724
196,574
7.125% Senior Notes due 2021 395,547
395,365
5% Senior Notes due 2022 1,996,917
1,996,831
4.5% Senior Notes due 2023 1,482,958
1,482,451
3.8% Senior Notes due 2024 990,186
989,932
4.9% Senior Notes due 2044 691,088
691,052
Total debt $ 7,205,602
$ 7,117,788
Less: Current portion of long-term debt 2,162
2,144
Long-term debt, net of current portion $ 7,203,440
$ 7,115,644

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~



In thousands	March 31, 2017		December 31, 2016
Revolving credit facility	$	835,000	$	905,000
Term loan	499,020		498,865
Note payable	11,631		12,176
5% Senior Notes due 2022	1,997,280		1,997,188
4.5% Senior Notes due 2023	1,485,049		1,484,524
3.8% Senior Notes due 2024	991,228		990,964
4.9% Senior Notes due 2044	691,237		691,199
Total debt	$	6,510,445	$	6,579,916
Less: Current portion of long-term debt	2,236		2,219
Long-term debt, net of current portion	$	6,508,209	$	6,577,697

Revolving Credit Facility

The Company has an unsecured revolving credit facility, maturing on May 16, 2019, with aggregate commitments totaling $2.75 billion at March 31, ~~2016,~~2017, which may be increased up to a total of $4.0 billion upon agreement between the Company and participating lenders.

~~The Company had $940 million and $853 million of outstanding~~Credit facility borrowings ~~on its revolving credit facility at March 31, 2016 and December 31, 2015, respectively. Borrowings~~ bear interest at market-based interest rates plus a margin based on the terms of the borrowing and the credit ratings assigned to the Company's senior, unsecured, long-term indebtedness. The weighted-average interest rate on outstanding credit facility borrowings at March 31, ~~2016~~2017 was ~~2.2%~~2.60%.

The Company had approximately ~~$1.81~~$1.91 billion of borrowing availability on its revolving credit facility at March 31, ~~2016~~2017 and incurs commitment fees based on currently assigned credit ratings of 0.30% per annum on the daily average amount of unused borrowing availability under its revolving credit facility.

The revolving credit facility contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. This ratio represents the ratio of net debt ~~(total~~(calculated as total face value of debt plus outstanding letters of credit less cash and cash equivalents) divided by the sum of net debt plus total shareholders' equity plus, to the extent resulting in a reduction of total shareholders’ equity, the amount of any non-cash impairment charges incurred, net of any tax effect, after June 30, 2014. The Company was in compliance with the revolving credit facility covenants at March 31, ~~2016.~~2017.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

The following table summarizes the face values, maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding senior note obligations at March 31, ~~2016.~~2017.

The Company’s senior notes are not subject to any mandatory redemption or sinking fund requirements.

The indentures governing the Company's senior notes contain covenants that, among other things, limit the Company's ability to create liens securing certain indebtedness, enter into certain sale-leaseback transactions, and consolidate, merge or transfer certain assets. The senior note covenants are subject to a number of important exceptions and qualifications. The Company was in compliance with these covenants at March 31, ~~2016. Two~~2017. Three of the Company’s subsidiaries, Banner Pipeline Company, L.L.C. ~~and~~, CLR Asset Holdings, LLC, and The Mineral Resources Company, which have no material assets or operations, fully and unconditionally guarantee the senior notes on a joint and several basis. The Company’s other subsidiaries, the value of whose assets and operations are minor, do not guarantee the senior notes.

In November 2015, the Company borrowed $500 million under a three-year term loan agreement, the proceeds of which were used to repay a portion of the borrowings then outstanding on the Company's revolving credit facility. The term loan matures in full on November 4, 2018 and bears interest at a variable market-based interest rate plus a margin based on the

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

terms of the borrowing and the credit ratings assigned to the Company's senior, unsecured, long-term indebtedness. The interest rate on the term loan at March 31, ~~2016~~2017 was ~~1.95%~~2.35%.

The term loan contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.0, consistent with the covenant requirement in the Company's revolving credit facility. The Company was in compliance with the term loan covenants at March 31, ~~2016.~~2017.

In February 2012, 20 Broadway Associates LLC, a 100% owned subsidiary of the Company, borrowed $22 million under a 10-year amortizing term loan secured by the Company’s corporate office building in Oklahoma City, Oklahoma. The loan bears interest at a fixed rate of 3.14% per annum. Principal and interest are payable monthly through the loan’s maturity date of February 26, 2022. Accordingly, approximately $2.2 million is reflected as a current liability under the caption “Current portion of long-term debt” in the condensed consolidated balance sheets as of March 31, ~~2016.~~2017.

Note 7. Commitments and Contingencies

Included below is a discussion of various future commitments of the Company as of March 31, ~~2016.~~2017. The commitments under these arrangements are not recorded in the accompanying condensed consolidated balance sheets.

Drilling commitments – As of March 31, ~~2016,~~2017, the Company ~~had~~has drilling rig contracts with various terms extending to ~~year-end 2019~~February 2020 to ensure rig availability in its key operating areas. Future commitments as of March 31, ~~2016~~2017 total approximately ~~$367~~$183 million, of which ~~$145~~$94 million is expected to be incurred in the remainder of ~~2016, $136 million in~~ 2017, ~~$62~~$59 million in 2018, ~~and $24~~$29 million in ~~2019.~~2019, and $1 million in 2020.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

~~Pipeline transportation~~Transportation and processing commitments – The Company has entered into ~~firm~~ transportation and processing commitments to guarantee ~~pipeline access~~ capacity on ~~operational~~ crude oil and natural gas ~~pipelines.~~pipelines and natural gas processing facilities. The commitments, which have varying terms extending as far as 2027, require the Company to pay per-unit transportation or processing charges regardless of the amount of ~~pipeline~~ capacity used. Future commitments remaining as of March 31, ~~2016~~2017 under the ~~operational pipeline transportation~~ arrangements amount to approximately ~~$952~~$839 million, of which ~~$161~~$169 million is expected to be incurred in the remainder of ~~2016, $212 million in~~ 2017, ~~$208~~$217 million in 2018, ~~$154~~$191 million in 2019, $59 million in 2020, $47 million in ~~2020,~~2021, and ~~$170~~$156 million thereafter.

~~The Company’s pipeline commitments are for production primarily~~ Additionally, in April 2017 the ~~North region.~~Company entered into a natural gas firm transportation agreement that commits the Company to pay transportation charges totaling approximately $380 million over a 10-year period anticipated to begin in April 2018 regardless of the transportation capacity used. The Company is not committed under ~~these~~the above contracts to deliver fixed and determinable quantities of crude oil or natural gas in the future.

~~Fuel purchase commitment~~– The Company has a forward purchase contract with a third party to purchase specified quantities of diesel fuel at specified prices each month through June 2016 for use in drilling operations. Over the remaining contract term, the Company has committed to purchase approximately 5 million gallons of diesel fuel at varying prices depending on the grade of diesel fuel purchased and the timing and location of delivery. The contract satisfies a significant portion of the Company's anticipated diesel fuel needs and provides for physical delivery to desired locations. Future commitments under the arrangement as of March 31, 2016 total approximately $14 million, all of which is expected to be incurred in the second quarter of 2016.

Litigation –In November 2010, a putative class action was filed in the District Court of Blaine ~~County,~~county, Oklahoma by Billy J. Strack and Daniela A. Renner as trustees of certain named trusts and on behalf of other similarly situated parties against the Company. The Petition alleged the Company improperly deducted post-production costs from royalties paid to plaintiffs and other royalty interest owners from crude oil and natural gas wells located in Oklahoma. The plaintiffs alleged a number of claims, including breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the proposed class. On November 3, 2014, plaintiffs filed an Amended Petition that did not add any substantive claims, but sought a “hybrid class action” in which they sought certification of certain claims for injunctive relief, reserving the right to seek a further class certification on money damages in the future. Plaintiffs filed an Amended Motion for Class Certification on January 9, 2015, that modified the proposed class to royalty owners in Oklahoma production from July 1, 1993, to the present (instead of 1980 to the present) and sought certification of over 45 separate “issues” for injunctive or declaratory relief, again, reserving the right to seek a further class certification of money damages in the future. The Company responded to the petition, its amendment, and the motions for class certification denying the allegations and raising a number of affirmative defenses and legal arguments to each of the claims and filings. Certain discovery was undertaken and the “hybrid” motion was briefed by plaintiffs and the Company. A hearing on the “hybrid” class certification was held on June ~~1st~~1 and ~~2nd,~~2, 2015. On June 11, 2015, the trial court certified a “hybrid” class as requested by plaintiffs. The Company ~~has~~ appealed the trial court’s class certification ~~order,~~order. On February 8, 2017, the Oklahoma Court of Civil Appeals reversed the trial court’s ruling on certification and remanded the case for further proceedings. The plaintiffs filed a Petition for Rehearing which ~~will be reviewed de novo by~~is pending before the ~~appellate court. The appeal briefing is complete and ready for determination by the court. An~~

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

~~unsuccessful mediation was conducted on December 7, 2015.~~Oklahoma Court of Civil Appeals. The Company is not currently able to estimate a reasonably possible loss or range of loss or what impact, if any, the ultimate resolution of the action will have on its financial condition, results of operations or cash flows due to the preliminary status of the matter, the complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among other things, the nature of the claims and defenses, the potential size of the class, the scope and types of the properties and agreements involved, the production years involved, and the ultimate potential outcome of the matter. ~~Although not currently at issue~~It is reasonably possible one or more events may occur in the ~~“hybrid” certification, plaintiffs~~near term that could impact the Company’s ability to estimate the potential effect this matter could have, if any, on its financial condition, results of operations or cash flows. Plaintiffs have alleged underpayments in excess of $200 million that they may claim as damages, which may increase with the passage of time, a majority of which would be comprised of interest. The Company disputes plaintiffs’ claims, disputes ~~that~~ the case meets the requirements for a class action and iscontinues to vigorously ~~defending~~defend the case. An unsuccessful mediation was conducted on December 7, 2015. The parties continue to negotiate a possible resolution to the case. However, it is unclear and unforeseeable whether the parties' efforts will result in settlement and the Company will continue to ~~assert its defenses to~~defend the case ~~as certified as well as any future attempt~~on all merits and certification issues and, absent settlement, intends to ~~certify~~defend the case to a ~~money damages class.~~final judgment.

The Company is involved in various other legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, disputes with tax authorities and other matters. While the outcome of these legal matters cannot be predicted with certainty, the Company does not expect them to have a material effect on its financial condition, results of operations or cash flows. As of March 31, ~~2016~~2017 and December 31, ~~2015,~~2016, the Company had recorded a liability in the condensed consolidated balance sheets under the caption “Other noncurrent liabilities” of ~~$6.4~~$6.7 million and ~~$6.1~~$6.5 million, respectively, for various matters, none of which are believed to be individually significant.

Environmental risk – Due to the nature of the crude oil and natural gas business, the Company is exposed to possible environmental risks. The Company is not aware of any material environmental issues or claims.

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Note 8. Stock-Based Compensation

On January 1, 2017, the Company adopted ASU 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. See Note 2. Basis of Presentation and Significant Accounting Policies—Adoption of new accounting pronouncements for a discussion of the impact of adoption.

The Company has granted restricted stock to employees and directors pursuant to the Continental Resources, Inc. 2013 Long-Term Incentive Plan ("2013 Plan") as discussed below. The Company’s associated compensation expense, which is included in the caption “General and administrative expenses” in the unaudited condensed consolidated statements of comprehensive ~~loss,~~income (loss), was ~~$9.2~~$11.4 million and ~~$11.3~~$9.2 million for the three months ended March 31, ~~2016~~2017 and ~~2015,~~2016, respectively.

In May 2013, the Company adopted the 2013 Plan and reserved 19,680,072 shares of common stock that may be issued pursuant to the plan. As of March 31, ~~2016,~~2017, the Company had ~~15,175,243~~14,437,178 shares of ~~restricted~~common stock available for long-term incentive awards to ~~grant to officers,~~employees and directors ~~and employees~~ under the 2013 Plan.

Restricted stock is awarded in the name of the recipient and constitutes issued and outstanding shares of the Company’s common stock for all corporate purposes during the period of restriction and, except as otherwise provided under the 2013 Plan or agreement relevant to a given award, includes the right to vote the restricted stock or to receive dividends, subject to forfeiture. Restricted stock grants generally vest over periods ranging from one to three years.

A summary of changes in non-vested restricted shares outstanding for the three months ended March 31, ~~2016~~2017 is presented below.


	Number of non-vested shares		Weighted average grant-date fair value		Number of non-vested shares		Weighted average grant-date fair value
Non-vested restricted shares outstanding at December 31, 2015	3,249,611		$	48.20
Non-vested restricted shares outstanding at December 31, 2016					3,913,634		$	37.12
Granted	1,927,889		20.75		1,151,041		46.21
Vested	(958,965	)	38.59		(715,222	)	58.48
Forfeited	(40,899	)	50.27		(109,987	)	33.71
Non-vested restricted shares outstanding at March 31, 2016	4,177,636		$	37.72
Non-vested restricted shares outstanding at March 31, 2017					4,239,466		$	36.08

The grant date fair value of restricted stock represents the closing market price of the Company’s common stock on the date of grant. Compensation expense for a restricted stock grant is ~~a fixed amount~~ determined at the grant date fair value and is recognized ~~ratably~~ over the vesting period as services are rendered by employees and directors. The Company estimates the number of forfeitures expected to occur in determining the amount of stock-based compensation expense to recognize. There are no post-vesting restrictions related to the Company’s restricted stock. The fair value at the vesting date of restricted stock that vested during the three months ended March 31, ~~2016~~2017 was approximately ~~$18.5~~$33.1 million. As of March 31, ~~2016,~~2017, there was approximately $93 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized ~~ratably~~ over a weighted average period of ~~2.1~~1.8 years.

~~Continental Resources, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

Note 9. Accumulated Other Comprehensive Loss

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 condensed consolidated balance sheets. The following table summarizes the change in accumulated other comprehensive loss for the three months ended March 31, ~~2016~~2017 and ~~2015:~~2016:


							Three months ended March 31,
In thousands	Three months ended March 31, 2016			Three months ended March 31, 2015			2017			2016
Beginning accumulated other comprehensive loss, net of tax	$	(3,354	)	$	(385	)	$	(260	)	$	(3,354	)
Foreign currency translation adjustments	426			(3,105		)	138			426
Income taxes (1)	—			—			—			—
Other comprehensive income (loss), net of tax	426			(3,105		)
Other comprehensive income, net of tax							138			426
Ending accumulated other comprehensive loss, net of tax	$	(2,928	)	$	(3,490	)	$	(122	)	$	(2,928	)

Continental Resources, Inc. and Subsidiaries

Notes to Unaudited Condensed Consolidated Financial Statements

Note 10. ~~Subsequent Event~~Income Taxes

~~On April 27, 2016,~~Income taxes are accounted for using the ~~Company sold certain non-core undeveloped leasehold acreage located~~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 ~~Wyoming to~~effect at period-end. The effect on deferred taxes for a ~~third party for cash proceeds of $110 million.~~change in tax rates is recognized in income in the period that includes the enactment date. The ~~proceeds were used to pay down a portion of outstanding borrowings on the Company's revolving credit facility. In connection with the transaction, the Company expects~~Company’s policy is to recognize ~~a pre-tax gain of approximately $95 million.~~ 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 ~~disposed properties represented an immaterial portion~~Company's (provision) benefit for income taxes totaled ($6.0) million and $121.3 million for the three months ended March 31, 2017 and 2016, respectively. These amounts differ from the amounts computed by applying the United States statutory federal income tax rate to income (loss) before income taxes. The sources and tax effects of the ~~Company’s total acreage and included no production or proved reserves.~~differences are reflected in the table below:



	Three months ended March 31,
$ in thousands	2017			Tax rate %		2016			Tax rate %
Expected income tax (provision) benefit based on US statutory tax rate of 35%	$	(2,272	)	35	%	$	111,885		35	%
State income taxes, net of federal benefit	(195		)	3	%	9,590			3	%
Tax deficiency from stock-based compensation (1)	(3,300		)	51	%	—			—	%
Canadian valuation allowance (2)	(145		)	2	%	(77		)	—	%
Effect of differing statutory tax rate in Canada	(67		)	1	%	(34		)	—	%
Other, net	(43		)	1	%	(18		)	—	%
(Provision) benefit for income taxes	$	(6,022	)	93	%	$	121,346		38	%


(1)	The Company recognized $3.3 million of tax deficiencies from stock-based compensation as income tax expense in accordance with ASU 2016-09 as discussed in Note 2. Basis of Presentation and Significant Accounting Policies–Adoption of new accounting pronouncements.


(2)	Represents valuation allowances recognized against all deferred tax assets associated with operating loss carryforwards generated by the Company's Canadian operations during the respective periods for which the Company does not expect to realize a benefit.


ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with the unaudited condensed consolidated financial statements and notes thereto included elsewhere in this report and our historical consolidated financial statements and notes included in our Annual Report on Form 10-K for the year ended December 31, ~~2015~~2016. Our operating results for the periods discussed below may not be indicative of future performance. The following discussion and analysis includes forward-looking statements and should be read in conjunction with the risk factors described in Part II, Item 1A. Risk Factors included in this report, if any, and in our Annual Report on Form 10-K for the year ended December 31, ~~2015~~2016, along with Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995 at the beginning of this report, for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

Overview

We are an independent crude oil and natural gas company engaged in the exploration, development and production of crude oil and natural gas. We derive the majority of our operating income and cash flows from the sale of crude oil and natural gas and expect this to continue in the future. Our operations are primarily focused on exploration and development activities in the Bakken field of North Dakota and Montana and the SCOOP ~~STACK,~~ and ~~Northwest Cana~~STACK areas of Oklahoma.

Business Environment and Outlook

~~Crude oil~~Commodity prices ~~experienced significant downward pressure in the first quarter of 2016~~remain volatile and unpredictable due to domestic and global supply and demand factors, with prices dropping below $27 per barrel in February 2016, a level not seen since 2003. Crude oil prices have showed signs of stabilization and recovery in April 2016; however, prices remain volatile and unpredictable.

factors. In light of the challenges facing our industry, our primary business strategies for ~~2016 continue to~~2017 will focus on: (1) ~~optimizing cash flows through operating efficiencies and cost reductions, (2)~~ high-grading investments based on rates of return and opportunities to work down our large inventory of drilled but uncompleted wells and convert undeveloped acreage to acreage held by production, (2) improving cash flows through operating efficiencies, cost reductions, and optimized completions, (3) ~~working to balance~~managing capital spending ~~with cash flows~~ to minimize the incurrence of new ~~borrowings~~debt and maintain ample ~~liquidity.~~liquidity and financial flexibility, and (4) further reducing debt using proceeds from potential sales of non-strategic assets.

~~2016~~2017 Highlights

Production

~~Production~~Crude oil and natural gas production for the first quarter of ~~2016~~2017 averaged ~~230,802~~213,755 Boe per day, an increase of 3%2% from the fourth quarter of ~~2015~~2016 and ~~12% higher~~7% lower than the first quarter of ~~2015.~~2016.

~~North Dakota Bakken~~Average daily crude oil production ~~averaged 129,168 Boe per day for~~decreased 19% in the first quarter of 2017 compared to the first quarter of 2016, ~~a 3% increase from~~while average daily natural gas production increased 12%. First quarter 2017 average daily crude oil production increased 2% compared to the fourth quarter of ~~2015 and 7% higher than~~2016, while average daily natural gas production increased 1%.

Crude oil represented 56% of our production for the 2017 first quarter ~~of 2015.~~

~~SCOOP production averaged 64,616 Boe per day~~compared to 55% for the ~~first quarter of~~ 2016 ~~in line with the~~ fourth quarter ~~of 2015~~ and ~~30% higher than~~63% for the 2016 first ~~quarter of 2015.~~quarter.

~~SCOOP~~The South region comprised ~~28%~~44% of our total production for the ~~2016~~2017 first quarter compared to ~~24%~~43% for the ~~2015~~2016 fourth quarter and 34% for the 2016 first quarter.

The following table summarizes the changes in our average daily Boe production by major operating area.



Boe production per day	1Q 2017	1Q 2016	% Change from 1Q 2016		4Q 2016	% Change from 4Q 2016
Bakken	108,992	139,602	(22	%)	104,524	4	%
SCOOP	62,178	64,616	(4	%)	63,490	(2	%)
STACK	29,216	11,127	163	%	24,426	20	%
All other	13,369	15,457	(14	%)	17,421	(23	%)
Total	213,755	230,802	(7	%)	209,861	2	%

Revenues

Crude oil and natural gas revenues for the ~~2016~~2017 first quarter ~~decreased 31%~~increased 57% compared to the ~~2015~~2016 first quarter driven by a ~~39% decrease~~71% increase in realized commodity prices ~~the effect of which was~~ partially offset by ~~a 14% increase~~an 8% decrease in total sales volumes.

Average crude oil sales prices for the ~~2016~~2017 first quarter ~~decreased 33%~~increased 74% compared to the ~~2015~~2016 first quarter.

Crude oil sales volumes for the ~~2016~~ first quarter ~~increased 4% compared to~~of 2017 decreased 19% from the ~~2015~~2016 first quarter.

Average natural gas sales prices for the ~~2016~~ first quarter ~~decreased 50%~~of 2017 increased 121% compared to the ~~2015~~2016 first quarter.

Natural gas sales volumes for the first quarter of 2017 increased 11% compared to the 2016 first quarter.

Operating cash flows

Cash flows from operating activities totaled $470.2 million for the first quarter of 2017, an increase of 79% compared to $262.0 million for the 2016 fourth quarter and 69% higher than 2016 first quarter ~~increased 35% compared to the 2015 first quarter.~~operating cash flows of $278.9 million.

Capital expenditures and drilling activity

Non-acquisition capital expenditures totaled ~~approximately $319.9~~$427.0 million for the first quarter of ~~2016~~2017 compared to ~~$394.0~~$306.3 million for the ~~2015~~2016 fourth quarter and ~~$983.8~~$319.9 million for the ~~2015~~2016 first quarter.

For the first quarter of ~~2016~~2017 we participated in the drilling and completion of 9094 gross ~~(19~~(31 net) wells.

~~Our inventory of drilled but uncompleted ("DUC") wells in North Dakota increased from 135 gross (107 net) operated wells~~Debt and liquidity

Total debt decreased $69.5 million to $6.51 billion at March 31, 2017 compared to $6.58 billion at December 31, ~~2015 to 142 gross (114 net) operated wells at March 31,~~ 2016. Our DUC inventory in Oklahoma increased from 35 gross (25 net) operated wells at December 31, 2015 to 42 gross (26 net) operated wells at March 31, 2016. Due to market conditions we have chosen to defer completions on certain wells until commodity prices improve.

~~Credit facility and liquidity~~

At March 31, ~~2016,~~2017, we had ~~$12.9~~$17.2 million of cash and cash equivalents and ~~approximately $1.81~~$1.91 billion of borrowing availability on our credit facility after considering outstanding borrowings and letters of credit. We had ~~$940~~$835 million of outstanding borrowings on our credit facility at March 31, ~~2016~~2017 compared to ~~$853~~$905 million at December 31, ~~2015.~~2016. At April 30, 2017, outstanding credit facility borrowings totaled $885 million, leaving approximately $1.86 billion of borrowing availability at that date.

Financial and operating highlights

We use a variety of financial and operating measures to assess our performance. Among these measures are:

Volumes of crude oil and natural gas ~~produced,~~produced;

Crude oil and natural gas prices ~~realized,~~realized; and

Per unit operating and administrative ~~costs, and~~

~~EBITDAX (a non-GAAP financial measure).~~costs.

The following table contains financial and operating highlights for the periods presented. Average sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.


	Three months ended March 31,						Three months ended March 31,
	2016			2015			2017			2016
Average daily production:
Crude oil (Bbl per day)	146,469			143,511			119,201			146,469
Natural gas (Mcf per day)	505,998			379,906			567,328			505,998
Crude oil equivalents (Boe per day)	230,802			206,829			213,755			230,802
Average sales prices:
Crude oil ($/Bbl)	$	25.72		$	38.56		$	44.69		$	25.72
Natural gas ($/Mcf)	$	1.36		$	2.70		$	3.00		$	1.36
Crude oil equivalents ($/Boe)	$	19.27		$	31.65		$	32.90		$	19.27
Crude oil sales price discount to NYMEX ($/Bbl)	$	(7.78	)	$	(10.01	)	$	(7.09	)	$	(7.78	)
Natural gas sales price discount to NYMEX ($/Mcf)	$	(0.73	)	$	(0.28	)	$	(0.29	)	$	(0.73	)
Production expenses ($/Boe)	$	3.76		$	5.05		$	3.78		$	3.76
Production taxes (% of oil and gas revenues)	7.6		%	8.2		%	6.5		%	7.6		%
DD&A ($/Boe)	$	22.16		$	21.00		$	19.84		$	22.16
General and administrative expenses ($/Boe) (1)	$	1.11		$	1.85
Non-cash equity compensation ($/Boe)	$	0.44		$	0.61
Net loss (in thousands)	$	(198,326	)	$	(131,971	)
Diluted net loss per share	$	(0.54	)	$	(0.36	)
EBITDAX (in thousands) (2)	$	314,609		$	439,427
Total general and administrative expenses ($/Boe) (1)							$	2.45		$	1.55
Net income (loss) (in thousands)							$	469		$	(198,326	)
Diluted net income (loss) per share							$	—		$	(0.54	)

~~We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization~~Represents cash general and ~~accretion, property impairments, exploration~~administrative expenses ~~non-cash gains and losses resulting from the requirements of accounting for derivatives,~~per Boe and non-cash equity compensation ~~expense. EBITDAX is not a measure~~expenses per Boe. See Operating Costs and Expenses—General and Administrative Expenses below for additional discussion of ~~net income (loss) or operating cash flows as determined by U.S. GAAP. Reconciliations of net loss and operating cash flows to EBITDAX are provided below under the heading~~ ~~Non-GAAP Financial Measures~~.these components.

Three months ended March 31, ~~2016~~2017 compared to the three months ended March 31, ~~2015~~2016

Results of Operations

The following table presents selected financial and operating information for the periods presented.

The following tables reflect our production by product and region for the periods presented.

The ~~3% increase~~20% decrease in crude oil production for the first quarter was driven by ~~increased~~decreased production from our North region properties in ~~SCOOP, STACK/Northwest Cana, and~~ North Dakota ~~Bakken. SCOOP~~Bakken, Montana Bakken, and the Red River units due to natural declines in production coupled with reduced drilling and completion activities throughout 2016 in response to low crude oil prices. North Dakota Bakken crude oil production ~~increased 358~~decreased 2,237 MBbls, or 24%, and ~~STACK/Northwest Cana~~Montana Bakken production ~~increased 222~~decreased 203 MBbls, or ~~740%~~26%, while production in ~~North Dakota Bakken increased 376~~the Red River units decreased 112 MBbls, or 4%12%, over the prior year first quarter. ~~Production growth~~Additionally, crude oil production in ~~these areas was primarily due to additional drilling and completion activity~~SCOOP decreased 318 MBbls, or 17%, resulting from a shift in our 2016 drilling ~~programs.~~activities to liquids-rich natural gas areas of that play offering higher rates of return and opportunities to convert undeveloped acreage to acreage held by production. These ~~increases~~decreases were partially offset by ~~a decrease~~an increase of 285 MBbls in crude oil production from our properties in Montana Bakken and the Red River units totaling 494 MBbls, or 22%, compared to the prior year first quarter due to a combination of natural declines in production and reduced drilling activity.STACK

properties due to additional wells being completed and producing as a result of a shift in our drilling and completion activities to high rate-of-return opportunities in that area.

The ~~35%~~11% increase in natural gas production for the first quarter was driven by increased production from our properties in the STACK and SCOOP ~~STACK/Northwest Cana, and North Dakota Bakken areas~~plays due to additional wells being completed and producing subsequent to March 31, ~~2015.~~2016. Natural gas production in ~~SCOOP~~STACK increased ~~6,194~~7,988 MMcf, or ~~34%~~175%, and SCOOP natural gas production increased 202 MMcf, or 1%, over the prior year first ~~quarter, and STACK/Northwest Cana production increased 2,890 MMcf, or 173%, while North Dakota Bakken production increased 2,953 MMcf, or 27%.~~quarter. These increases were partially offset by decreases of 2,559 MMcf, or 18%, in ~~production from various areas~~North Dakota Bakken and 173 MMcf, or 18%, in ~~our North and South regions primarily~~Montana Bakken due to natural declines in ~~production.~~production and reduced drilling and completion activities in those areas throughout 2016.

The increase in natural gas production as a percentage of our total production from ~~31% in the first quarter of 2015 to~~ 37% in the first quarter of 2016 to 44% in the first quarter of 2017 primarily resulted from ~~significant~~ increases in ~~SCOOP,~~ STACK and ~~Northwest Cana~~SCOOP natural gas production over the past year due ~~in part~~ to a shift in our well completion activities away from the Bakken to ~~higher rate-of-return~~ areas in Oklahoma. ~~Our properties~~Certain areas in ~~SCOOP,~~ STACK and ~~Northwest Cana typically~~SCOOP produce a higher concentration of liquids-rich natural gas compared to oil-weighted properties in the Bakken. ~~For~~Our crude oil production is expected to grow in relative significance throughout 2017, particularly in the ~~remainder~~second half of the year, as we execute our plan to work down our inventory of uncompleted wells in the Bakken.

In conjunction with our planned increase in capital spending for 2017 relative to 2016, we expect to continue focusing our well completion activities on our Oklahoma properties. Accordingly, we expect our natural gas production may increase to approximately 40% of our total production for the full year of 2016. As crude oil prices recover, we expect to increase our completion activities in the Bakken and shift our production ~~back to a higher proportion of crude oil.~~

Our reduction in capital spending and deferral of well completion activities throughout 2015, which has continued into 2016, has adversely impacted our production growth and our 13% growth in production realized in the 2016 first quarter compared to the 2015 first quarter is not expected to be sustained for the remainder of 2016. We expect our production maywill average between ~~205,000~~220,000 and ~~215,000~~230,000 Boe per day for the full year of ~~2016~~2017 compared to average daily production of ~~221,715~~216,912 Boe per day for ~~full year 2015.~~2016.

Our revenues primarily consist of sales of crude oil and natural gas and gains and losses resulting from changes in the fair value of our crude oil and natural gas derivative instruments.

Crude Oil and Natural Gas Sales. Crude oil and natural gas sales for the first quarter of ~~2016~~2017 were ~~$403.6~~$633.9 million, a ~~31% decrease~~57% increase from sales of ~~$582.6~~$403.6 million for the ~~2015~~2016 first quarter ~~primarily~~ due to ~~a significant decrease~~increases in commodity prices partially offset by ana decrease in total sales volumes. If commodity prices remain at current levels or increase, ~~in sales volumes.~~we expect our 2017 crude oil and natural gas revenues will continue to be higher than 2016 levels, the extent of which is uncertain due to the unpredictable nature of commodity prices.

Our crude oil sales prices averaged ~~$25.72~~$44.69 per barrel in the 2017 first quarter, an increase of 74% compared to $25.72 per barrel for the 2016 first quarter ~~a decrease of 33% compared~~due to ~~$38.56 for the 2015 first quarter. The downward pressure on~~higher crude oil prices arising from domestic and global supply and demand factors intensified in early 2016, with prices dropping below $27 per barrel in February 2016 which resulted in significantly lower realized sales prices compared to the prior year period.market prices. The differential between NYMEX West Texas Intermediate calendar month crude oil prices and our realized crude oil prices averaged ~~$7.78~~$7.09 per barrel for the ~~2016~~2017 first quarter compared to ~~$10.01~~$7.78 for the ~~2015~~2016 first quarter. The improved differential was due to increased ~~availability and~~ use of pipeline transportation to move our North region crude oil to market with less dependence on more costly rail transportation, along with significant growth in our South region production which typically has lower transportation costs compared to the Bakken due to its relatively close proximity to regional refineries and the crude oil trading hub in Cushing, Oklahoma.



Oklahoma		73-0767549
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

20 N. Broadway, Oklahoma City, Oklahoma		73102
(Address of principal executive offices)		(Zip Code)



Large accelerated filer	x	Accelerated filer	¨

Non-accelerated filer	¨ (Do not check if a smaller reporting company)	Smaller reporting company	¨

		Emerging growth company	¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨




PART I. Financial Information
Item 1.	Financial Statements	1
	Condensed Consolidated Balance Sheets	1
	Unaudited Condensed Consolidated Statements of Comprehensive ~~Loss~~Income (Loss)	2
	Condensed Consolidated Statement of Shareholders’ Equity	3
	Unaudited Condensed Consolidated Statements of Cash Flows	4
	Notes to Unaudited Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	1718
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	2827
Item 4.	Controls and Procedures	29

PART II. Other Information
Item 1.	Legal Proceedings	30
Item 1A.	Risk Factors	30
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	30
Item 3.	Defaults Upon Senior Securities	30
Item 4.	Mine Safety Disclosures	30
Item 5.	Other Information	3130
Item 6.	Exhibits	3130
	Signature	3231


	March 31, 2016			December 31, 2015			March 31, 2017			December 31, 2016
In thousands, except par values and share data	(Unaudited)						(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	12,927		$	11,463		$	17,188		$	16,643
Receivables:
Crude oil and natural gas sales	327,083			378,622			414,841			404,750
Affiliated parties	97			122			52			99
Joint interest and other, net	217,435			232,293			376,259			364,850
Derivative assets	94,720			93,922			7,524			4,061
Inventories	92,832			94,151			98,690			111,987
Prepaid taxes	68			94
Prepaid expenses and other	15,019			11,672			14,952			10,843
Total current assets	760,181			822,339			929,506			913,233
Net property and equipment, based on successful efforts method of accounting	13,843,132			14,063,328			12,880,357			12,881,227
Noncurrent derivative assets	12,549			14,560
Other noncurrent assets	17,527			19,581			16,197			17,316
Total assets	$	14,633,389		$	14,919,808		$	13,826,060		$	13,811,776

Liabilities and shareholders’ equity
Current liabilities:
Accounts payable trade	$	484,901		$	553,285		$	582,565		$	476,342
Revenues and royalties payable	169,620			187,000			237,967			217,425
Payables to affiliated parties	149			69			62			148
Accrued liabilities and other	206,769			176,947			164,694			176,770
Derivative liabilities	1,757			3,583			17,797			59,489
Current portion of long-term debt	2,162			2,144			2,236			2,219
Total current liabilities	865,358			923,028			1,005,321			932,393
Long-term debt, net of current portion	7,203,440			7,115,644			6,508,209			6,577,697
Other noncurrent liabilities:
Deferred income tax liabilities, net	1,968,876			2,090,228			1,891,177			1,890,305
Asset retirement obligations, net of current portion	103,249			101,251			97,151			94,436
Noncurrent derivative liabilities	2,456			3,706
Other noncurrent liabilities	14,890			17,051			14,848			14,949
Total other noncurrent liabilities	2,089,471			2,212,236			2,003,176			1,999,690
Commitments and contingencies (Note 7)
Shareholders’ equity:
Preferred stock, $0.01 par value; 25,000,000 shares authorized; no shares issued and outstanding	—			—			—			—
Common stock, $0.01 par value; 1,000,000,000 shares authorized; 374,583,066 shares issued and outstanding at March 31, 2016; 372,959,080 shares issued and outstanding at December 31, 2015	3,746			3,730
Common stock, $0.01 par value; 1,000,000,000 shares authorized; 375,321,131 shares issued and outstanding at March 31, 2017; 374,492,357 shares issued and outstanding at December 31, 2016							3,753			3,745
Additional paid-in capital	1,349,728			1,345,624			1,376,883			1,375,290
Accumulated other comprehensive loss	(2,928		)	(3,354		)	(122		)	(260		)
Retained earnings	3,124,574			3,322,900			2,928,840			2,923,221
Total shareholders’ equity	4,475,120			4,668,900			4,309,354			4,301,996
Total liabilities and shareholders’ equity	$	14,633,389		$	14,919,808		$	13,826,060		$	13,811,776


	Three months ended March 31,						Three months ended March 31,
In thousands, except per share data	2016			2015			2017			2016
Revenues
Revenues:
Crude oil and natural gas sales	$	403,592		$	581,192		$	633,850		$	403,592
Crude oil and natural gas sales to affiliates	—			1,400
Gain on crude oil and natural gas derivatives, net	42,112			32,755			46,858			42,112
Crude oil and natural gas service operations	7,470			10,297			4,719			7,470
Total revenues	453,174			625,644			685,427			453,174

Operating costs and expenses
Operating costs and expenses:
Production expenses	78,640			91,355			72,854			78,640
Production expenses to affiliates	—			1,586
Production taxes and other expenses	30,493			48,362
Production taxes							41,234			30,493
Exploration expenses	3,066			14,340			4,998			3,066
Crude oil and natural gas service operations	3,043			3,894			2,837			3,043
Depreciation, depletion, amortization and accretion	463,992			386,512			382,156			463,992
Property impairments	78,927			147,561			51,372			78,927
General and administrative expenses	32,407			45,380			47,220			32,407
Other	1,709			(2,070		)
Net loss on sale of assets and other							5,535			1,709
Total operating costs and expenses	692,277			736,920			608,206			692,277
Loss from operations	(239,103		)	(111,276		)
Income (loss) from operations							77,221			(239,103		)
Other income (expense):
Interest expense	(80,953		)	(75,063		)	(71,172		)	(80,953		)
Other	384			347			442			384
	(80,569		)	(74,716		)	(70,730		)	(80,569		)
Loss before income taxes	(319,672		)	(185,992		)
Benefit for income taxes	(121,346		)	(54,021		)
Net loss	$	(198,326	)	$	(131,971	)
Basic net loss per share	$	(0.54	)	$	(0.36	)
Diluted net loss per share	$	(0.54	)	$	(0.36	)
Income (loss) before income taxes							6,491			(319,672		)
(Provision) benefit for income taxes							(6,022		)	121,346
Net income (loss)							$	469		$	(198,326	)
Basic net income (loss) per share							$	—		$	(0.54	)
Diluted net income (loss) per share							$	—		$	(0.54	)

Comprehensive loss:
Net loss	$	(198,326	)	$	(131,971	)
Other comprehensive income (loss), net of tax:
Comprehensive income (loss):
Net income (loss)							$	469		$	(198,326	)
Other comprehensive income, net of tax:
Foreign currency translation adjustments	426			(3,105		)	138			426
Total other comprehensive income (loss), net of tax	426			(3,105		)
Comprehensive loss	$	(197,900	)	$	(135,076	)
Total other comprehensive income, net of tax							138			426
Comprehensive income (loss)							$	607		$	(197,900	)


In thousands, except share data	Shares outstanding		Common stock			Additional paid-in capital			Accumulated other comprehensive loss			Retained earnings			Total shareholders’ equity			Shares outstanding		Common stock			Additional paid-in capital			Accumulated other comprehensive loss			Retained earnings		Total shareholders’ equity
Balance at December 31, 2015	372,959,080		$	3,730		$	1,345,624		$	(3,354	)	$	3,322,900		$	4,668,900
Net loss (unaudited)	—		—			—			—			(198,326		)	(198,326		)
Balance at December 31, 2016																		374,492,357		$	3,745		$	1,375,290		$	(260	)	$	2,923,221	$	4,301,996
Cumulative effect adjustment from adoption of ASU 2016-09 (unaudited) (see Note 2)																		—		—			—			—			5,150		5,150
Net income (unaudited)																		—		—			—			—			469		469
Other comprehensive income, net of tax (unaudited)	—		—			—			426			—			426			—		—			—			138			—		138
Stock-based compensation (unaudited)	—		—			9,189			—			—			9,189			—		—			11,428			—			—		11,428
Restricted stock:
Granted (unaudited)	1,927,889		19			—			—			—			19			1,151,041		11			—			—			—		11
Repurchased and canceled (unaudited)	(263,004	)	(3		)	(5,085		)	—			—			(5,088		)	(212,280	)	(2		)	(9,835		)	—			—		(9,837		)
Forfeited (unaudited)	(40,899	)	—			—			—			—			—			(109,987	)	(1		)	—			—			—		(1		)
Balance at March 31, 2016 (unaudited)	374,583,066		$	3,746		$	1,349,728		$	(2,928	)	$	3,124,574		$	4,475,120
Balance at March 31, 2017 (unaudited)																		375,321,131		$	3,753		$	1,376,883		$	(122	)	$	2,928,840	$	4,309,354


(1)	~~During~~For the three months ended March 31, 2016 ~~and 2015,~~ the Company had a net loss and therefore the potential dilutive effect of approximately 42,000 ~~and 925,000~~ weighted average non-vested restricted shares were not included in the calculation of diluted net loss per share because to do so would have been anti-dilutive to the computations.



Crude Oil - ICE Brent

Period and Type of Contract	Bbls	Ceiling Price
April 2016 - December 2016
Written call options - ICE Brent (1)	1,100,000	$	107.70


							Collars												Collars
Natural Gas - NYMEX Henry Hub	Natural Gas - NYMEX Henry Hub		Swaps Weighted Average Price				Floors				Ceilings			Natural Gas - NYMEX Henry Hub		Swaps Weighted Average Price			Floors				Ceilings
						Weighted Average Price				Weighted Average Price								Weighted Average Price				Weighted Average Price
Period and Type of Contract		MMBtus						Range				Range		MMBtus						Range				Range
April 2016 - December 2016
Swaps - Henry Hub		112,780,000		$	3.03
January 2017 - December 2017
April 2017 - December 2017
Swaps - Henry Hub		25,550,000	$	3.35											99,000,000	$	3.39
Collars - Henry Hub		65,700,000					$2.40 - $3.00	$	2.47		$2.92 - $3.88	$	3.08		49,500,000				$2.40 - $3.00	$	2.47		$2.92 - $3.88	$	3.08
January 2018 - March 2018
Swaps - Henry Hub															6,300,000	$	3.28


	Fair value measurements at March 31, 2016 using:										Fair value measurements at March 31, 2017 using:
In thousands	Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Derivative assets (liabilities):
Swaps	$	—	$	105,759		$	—	$	105,759		$	—	$	7,968		$	—	$	7,968
Collars	—		(2,697		)	—		(2,697		)	—		(18,241		)	—		(18,241		)
Written call options	—		(6		)	—		(6		)
Total	$	—	$	103,056		$	—	$	103,056		$	—	$	(10,273	)	$	—	$	(10,273	)

	Fair value measurements at December 31, 2015 using:										Fair value measurements at December 31, 2016 using:
In thousands	Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Derivative assets (liabilities):
Derivative liabilities:
Swaps	$	—	$	104,426		$	—	$	104,426		$	—	$	(12,297	)	$	—	$	(12,297	)
Collars	—		(3,195		)	—		(3,195		)	—		(43,131		)	—		(43,131		)
Written call options	—		(38		)	—		(38		)
Total	$	—	$	101,193		$	—	$	101,193		$	—	$	(55,428	)	$	—	$	(55,428	)



Unobservable Input		Assumption
Future production		Future production estimates for each property
Forward commodity prices		Forward NYMEX strip prices through ~~2020~~2021 (adjusted for differentials), escalating 3% per year thereafter
Operating costs		Estimated costs for the current year, escalating 3% per year thereafter
Productive life of field		Ranging from 0 to 3439 years
Discount rate		10%


(1)	~~On or after these dates, the~~The Company has the option to redeem all or a portion of its ~~senior notes of the applicable series~~2022 Notes at the decreasing redemption prices specified in the ~~respective senior note indentures (together,~~indenture related to the ~~“Indentures”)~~2022 Notes plus any accrued and unpaid interest to the date of redemption.


(1)	A valuation allowance has been recognized against all deferred tax assets associated with losses generated by the Company's Canadian operations, thereby resulting in no income taxes on other comprehensive ~~income (loss).~~income.


	Three months ended March 31,						Three months ended March 31,
In thousands, except sales price data	2016			2015			2017			2016
Crude oil and natural gas sales	$	403,592		$	582,592		$	633,850		$	403,592
Gain on crude oil and natural gas derivatives, net	42,112			32,755			46,858			42,112
Crude oil and natural gas service operations	7,470			10,297			4,719			7,470
Total revenues	453,174			625,644			685,427			453,174
Operating costs and expenses	(692,277		)	(736,920		)	(608,206		)	(692,277		)
Other expenses, net	(80,569		)	(74,716		)	(70,730		)	(80,569		)
Loss before income taxes	(319,672		)	(185,992		)
Benefit for income taxes	121,346			54,021
Net loss	$	(198,326	)	$	(131,971	)
Income (loss) before income taxes							6,491			(319,672		)
(Provision) benefit for income taxes							(6,022		)	121,346
Net income (loss)							$	469		$	(198,326	)
Production volumes:
Crude oil (MBbl)	13,329			12,916			10,728			13,329
Natural gas (MMcf)	46,046			34,192			51,059			46,046
Crude oil equivalents (MBoe)	21,003			18,615			19,238			21,003
Sales volumes:
Crude oil (MBbl)	13,266			12,711			10,754			13,266
Natural gas (MMcf)	46,046			34,192			51,059			46,046
Crude oil equivalents (MBoe)	20,940			18,409			19,264			20,940
Average sales prices:
Crude oil ($/Bbl)	$	25.72		$	38.56		$	44.69		$	25.72
Natural gas ($/Mcf)	1.36			2.70			3.00			1.36
Crude oil equivalents ($/Boe)	19.27			31.65			32.90			19.27


	Three months ended March 31,						Volume increase	Volume percent increase		Three months ended March 31,						Volume increase (decrease)		Volume percent increase (decrease)
	2016			2015						2017			2016
	Volume	Percent		Volume	Percent					Volume	Percent		Volume	Percent
Crude oil (MBbl)	13,329	63	%	12,916	69	%	413	3	%	10,728	56	%	13,329	63	%	(2,601	)	(20	%)
Natural gas (MMcf)	46,046	37	%	34,192	31	%	11,854	35	%	51,059	44	%	46,046	37	%	5,013		11	%
Total (MBoe)	21,003	100	%	18,615	100	%	2,388	13	%	19,238	100	%	21,003	100	%	(1,765	)	(8	%)

	Three months ended March 31,						Volume increase	Volume percent increase		Three months ended March 31,						Volume increase (decrease)		Volume percent increase (decrease)
	2016			2015						2017			2016
	MBoe	Percent		MBoe	Percent					MBoe	Percent		MBoe	Percent
North Region	13,791	66	%	13,426	72	%	365	3	%	10,747	56	%	13,791	66	%	(3,044	)	(22	%)
South Region	7,212	34	%	5,189	28	%	2,023	39	%	8,491	44	%	7,212	34	%	1,279		18	%
Total	21,003	100	%	18,615	100	%	2,388	13	%	19,238	100	%	21,003	100	%	(1,765	)	(8	%)


	Three months ended March 31,				Three months ended March 31,
$/Boe	2016		2015		2017		2016
Crude oil and natural gas	$	21.73	$	20.59	$	19.43	$	21.73
Other equipment	0.36		0.35		0.34		0.36
Asset retirement obligation accretion	0.07		0.06		0.07		0.07
Depreciation, depletion, amortization and accretion	$	22.16	$	21.00	$	19.84	$	22.16


In millions	Amount		Amount
Exploration and development drilling	$	784	$	1,720
Land costs	78		115
Capital facilities, workovers and other corporate assets	55		105
Seismic	3		10
Total 2016 capital budget, excluding acquisitions	$	920
Total 2017 capital budget, excluding acquisitions			$	1,950


(a)	Recent Sales of Unregistered Securities – Not applicable.



Period	Total number of shares purchased (1)	Average price paid per share (2)		Total number of shares purchased as part of publicly announced plans or programs	Maximum number of shares that may yet be purchased under the plans or programs (3)
January 1, 2016 to January 31, 2016	—	—		—	—
February 1, 2016 to February 29, 2016	262,613	$	19.34	—	—
March 1, 2016 to March 31, 2016	391	22.98		—	—
Total	263,004	$	19.34	—	—



Period	Total number of shares purchased		Average price paid per share			Total number of shares purchased as part of publicly announced plans or programs	Maximum number of shares that may yet be purchased under the plans or programs
January 1, 2017 to January 31, 2017	808	(1)	$	51.78	(2)	—	—
February 1, 2017 to February 28, 2017	211,472	(1)	$	46.32	(2)	—	—
March 1, 2017 to March 31, 2017	74,983	(3)	$	42.60	(3)	—	—
Total	287,263		$	45.36		—	—


(2)	The price paid per share was the closing price of our common stock on the date the restrictions lapsed on such shares.



		CONTINENTAL RESOURCES, INC.

Date:	May ~~4, 2016~~3, 2017	By:	/s/ John D. Hart
			John D. Hart
			Sr. Vice President, Chief Financial Officer and Treasurer (Duly Authorized Officer and Principal Financial Officer)



3.1	Conformed version of Third Amended and Restated Certificate of Incorporation of Continental Resources, Inc. as amended by amendment filed on June 15, 2015filed as Exhibit 3.1 to the Company’s Form 10-Q for the ~~quarter~~quarterly period ended June 30, 2015 (Commission File No. 001-32886) filed August 5, 2015 and incorporated herein by reference.

3.2	Third Amended and Restated Bylaws of Continental Resources, Inc. filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-32886) filed November 6, 2012 and incorporated herein by reference.

4.1***	Registration Rights Agreement dated as of May 18, 2007 by and among Continental Resources, Inc., the Revocable Inter Vivos Trust of Harold G. Hamm, the Harold Hamm DST Trust and the Harold Hamm HJ Trust.

4.2***	Indenture dated as of March 8, 2012 among Continental Resources, Inc., Banner Pipeline Company, L.L.C. and Wilmington Trust, National Association, as trustee.

10.1*†	Description of Cash Bonus Plan updated as of March 20, 2017.

31.1*	Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (15 U.S.C. Section 7241).

31.2*	Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (15 U.S.C. Section 7241).

32**	Certification of the Company’s Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).

101.INS**	XBRL Instance Document

101.SCH**	XBRL Taxonomy Extension Schema Document

101.CAL**	XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF**	XBRL Taxonomy Extension Definition Linkbase Document

101.LAB**	XBRL Taxonomy Extension Label Linkbase Document

101.PRE**	XBRL Taxonomy Extension Presentation Linkbase Document


***	Re-filed herewith pursuant to Item 10(d) of Regulation S-K.


†	Management contract or compensatory plan or arrangement filed pursuant to Item 601(b)(10)(iii) of Regulation S-K.