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Continental Resources, Inc. (CLR) (“Continental” or the “Company”) today announced third quarter 2014 operating and financial results.  Net income for the quarter ended September 30, 2014 was $534 million, or $1.44 per diluted share.  Excluding items typically excluded from published analyst estimates, adjusted net income for third quarter 2014 was $301 million, or $0.81 per diluted share.

EBITDAX for third quarter 2014 was $948 million, a 9% increase over EBITDAX of $868 million for second quarter 2014 and 19% above EBITDAX for third quarter 2013.  Definitions and reconciliations of adjusted net income, adjusted earnings per share and EBITDAX to the most directly comparable U.S. generally accepted accounting principles (“GAAP”) financial measures can be found in the supporting tables at the conclusion of this press release.

Harold G. Hamm, Chairman and Chief Executive Officer, commented, “We are well positioned with a world-class asset portfolio, strong balance sheet and a track record of operational execution. In the third quarter, our teams delivered yet another solid quarter of production growth, and delineation and development in our two key assets, the Bakken and SCOOP.”

Mr. Hamm added, “We view the recent downdraft in oil prices as unsustainable given the lack of fundamental change in supply and demand. Accordingly, we have elected to monetize nearly all of our outstanding oil hedges, allowing us to fully participate in what we anticipate will be an oil price recovery.  While awaiting this recovery, we have elected to maintain our current level of activity and plan to defer adding rigs in 2015.  This translates to a $600 million reduction in our 2015 capex budget, resulting in a revised 2015 capex budget of $4.6 billion, with 23% to 29% production growth.”

Third Quarter 2014 Production

Third quarter 2014 net production totaled 16.8 million barrels of oil equivalent (“Boe”), or 182,335 Boe per day, a sequential increase of 9% from second quarter 2014 and 29% higher than third quarter 2013.  Third quarter 2014 net production included 127,788 barrels of oil per day (70% of production) and approximately 327 million cubic feet of natural gas (“MMcf”) per day (30% of production).  Continental’s October production averaged in excess of 187,000 Boe per day.

The following table provides the Company’s average daily production by region for the periods presented.

3Q

2Q

3Q

Boe per day

2014

2014

2013

North Region:

North Dakota Bakken

106,224

94,702

81,545

Montana Bakken

15,380

13,871

12,957

Red River Units

13,749

14,125

14,703

Other

725

961

408

South Region:

SCOOP

36,346

34,265

20,070

NW Cana

4,957

5,223

6,985

Arkoma

2,494

2,599

3,004

Other

2,460

2,207

2,201

Total

182,335

167,953

141,873

Jack H. Stark, President and Chief Operating Officer, commented, “This is our second consecutive quarter to grow production over 14,000 Boe per day.  This sustained growth underscores our high-quality assets and the excellent execution by our teams.”

SCOOP Production Continues to Climb

Continental’s South Central Oklahoma Oil Province (“SCOOP”) position has expanded vertically to include its most recent discovery, the Springer oil play.  Located in the heart of SCOOP, the Company’s Springer position augments its Woodford leasehold and expands the Company’s net resource potential and inventory.  Continental’s SCOOP leasehold position of approximately 471,000 net acres has productive potential in multiple formations.

In third quarter 2014, SCOOP net production averaged 36,346 Boe per day, an increase of 6% sequentially from the second quarter of 2014 and 81% above third quarter 2013.  The Company completed a total of 18 net (23 gross) operated and 2 net (27 gross) non-operated wells during third quarter 2014 in SCOOP. The Company is currently running 27 operated rigs in SCOOP, with 10 in the Springer formation and 17 in the Woodford formation.  The Company concluded third quarter 2014 with an inventory of approximately 18 net (28 gross) operated SCOOP (Springer and Woodford) wells drilled, but not yet producing.

Springer Discovery Delivering Strong Results in SCOOP

Continental has announced 15 producing wells in the oil fairway of the Springer with an average 24-hour initial production (IP) rate of 1,230 Boe per day and an average 30-day IP of 830 Boe per day.  These are all approximately 4,500′ lateral wells. The Company’s estimated ultimate recovery (“EUR”) model for a 4,500′ lateral Springer well is 940,000 Boe, with 67% oil and 17% natural gas liquids, at an average completed well cost of $9.7 million.  To further improve recoveries and enhance economics per well, the Company will begin drilling its first 7,500′ extended lateral in the Springer in fourth quarter 2014.  Continental estimates a 7,500′ extended lateral well will recover 1.6 million Boe with a cost of approximately $12.1 million.

Bakken Development: EUR Increasing With Enhanced Completions

Continental’s Bakken production totaled 121,604 Boe per day in third quarter 2014, an increase of 12% compared to second quarter 2014 and an increase of 29% compared to third quarter 2013.  The Company completed 77 net (256 gross) wells in the Bakken during third quarter 2014.  The Company concluded third quarter 2014 with an inventory of approximately 71 net (99 gross) operated Bakken wells drilled, but not yet producing.

The Company has been testing various enhanced completion technologies and monitoring results throughout its Bakken leasehold seeking the optimal method for future development.  Recently the Company expanded its assessment to include industrywide enhanced completion results.  The combined results show that the early time uplift in production can be sustained in certain areas which translates to a higher EUR per well. In particular, where the Company has its most complete data set, an average production uplift of approximately 45% over the first 90 days and an average EUR increase of approximately 30% has been observed. The Company plans to focus a majority of its 2015 Bakken capital expenditures in areas where improved recoveries are anticipated.  The Company’s average projected EUR per well for its 2015 Bakken drilling program now stands at approximately 700,000 Boe.  Average anticipated well costs have been reduced by $400,000 from $10 million to $9.6 million.

Financial Update

Continental’s average realized sales price excluding the effects of derivative positions was $85.49 per barrel of oil and $5.10 per thousand cubic feet of natural gas (“Mcf”), or $69.08 per Boe for third quarter 2014.  Settlements of matured commodity derivative positions generated a $0.37 loss per barrel of oil and $0.15 gain per Mcf of natural gas, resulting in a net gain on matured derivatives of $0.2 million, or $0.01 per Boe for the third quarter 2014.  Based on realizations without the effect of derivatives, the Company’s third quarter 2014 oil differential was $11.77 per barrel below the NYMEX daily average for the period.  The realized natural gas price differential for third quarter 2014 was a positive $1.04 per Mcf.

The cash margin for third quarter 2014 totaled 74% or $51.26 per Boe. Production expense per Boe was $5.80 for third quarter 2014.  Other select operating costs and expenses for third quarter 2014 included production taxes of 8.3% of oil and natural gas sales; DD&A of $21.65 per Boe; and G&A (cash and non-cash) of $2.62 per Boe.

Non-acquisition capital expenditures for third quarter 2014 totaled approximately $1.3 billion, including approximately $1.2 billion in exploration and development drilling, $66 million in leasehold and seismic and $55 million in facilities, workovers, recompletions and other.  Acquisition capital expenditures totaled approximately $72 million for third quarter 2014.

As of September 30, 2014, Continental’s balance sheet included approximately $152 million in cash and cash equivalents and no borrowings outstanding on the Company’s $1.75 billion revolving credit facility.  In third quarter 2014 the Company booked a $24.5 million loss due to the early redemption of $300 million of 8.25% senior notes.

Hedge Position and Guidance Update

Recently the Company monetized substantially all of its crude oil hedge positions for 2014, 2015 and 2016, generating proceeds of $433 million.  The Company has approximately one-third of its natural gas production hedged in 2015 at an average price of $4.34.  A complete listing of the Company’s hedge positions can be found in the Company’s quarterly filing for the third quarter of 2014 with the Securities and Exchange Commission.

The Company has reduced its 2015 non-acquisition capital expenditures to $4.6 billion, 12% lower than the previous forecast of $5.2 billion and flat with current 2014 activity levels.  This level of capital expenditures is projected to yield 23% to 29% production growth in 2015 compared to estimated 2014 levels.  This budget is based on approximately 245 net wells in the Bakken at $9.6 million per well and approximately 105 net wells for the SCOOP area at an average well cost of $11 million. An updated table of the Company’s guidance can be found at the conclusion of this release.

John D. Hart, Chief Financial Officer, commented, “Our portfolio and capital structure allow us to be nimble and adapt to market conditions.  We are choosing not to accelerate development next year and will instead maintain our current pace.  This change better aligns our development efforts with our cash flow generation capabilities.  Our balance sheet remains very strong, bolstered by approximately $520 million of cash from our recent NW Cana transaction and monetization of hedge positions.  We remain committed to capital discipline and protecting our investment grade rating.”

The following table provides the Company’s production results, average sales prices, per-unit operating costs, results of operations and certain non-GAAP financial measures for the periods presented. Average sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.

 

3Q 2014

2Q 2014

3Q 2013

Average daily production:

Crude oil (Bbl per day)

127,788

116,441

100,684

Natural gas (Mcf per day)

327,287

309,074

247,135

Crude oil equivalents (Boe per day)

182,335

167,953

141,873

Average sales prices, excluding effect from derivatives:

Crude oil ($/Bbl)

$85.49

$92.31

$98.02

Natural gas ($/Mcf)

$5.10

$5.43

$4.84

Crude oil equivalents ($/Boe)

$69.08

$74.09

$77.86

Production expenses ($/Boe) 

$5.80

$5.50

$5.17

Production taxes (% of oil and gas revenues)

8.3%

8.3%

8.3%

DD&A ($/Boe)

$21.65

$21.28

$18.87

General and administrative expenses ($/Boe) 

$1.82

$2.08

$1.81

Non-cash equity compensation ($/Boe)

$0.80

$0.98

$0.81

Net income (in thousands) 

$533,521

$103,538

$167,498

Diluted net income per share (1)

$1.44

$0.28

$0.45

Adjusted net income (in thousands) (2) 

$300,961

$277,143

$296,879

Adjusted diluted net income per share (1) (2) 

$0.81

$0.75

$0.80

EBITDAX (in thousands) (2)

$947,635

$867,938

$797,575

 

(1)

Net income per share amounts for the second quarter of 2014 and third quarter of 2013 have been retroactively adjusted to reflect the Company’s 2-for-1 stock split in September 2014.

(2)

Adjusted net income, adjusted diluted net income per share, and EBITDAX represent non-GAAP financial measures. These measures should not be considered as an alternative to, or more meaningful than, net income, diluted net income per share, or operating cash flows as determined in accordance with U.S. GAAP. Further information about these non-GAAP financial measures as well as reconciliations of adjusted net income, adjusted diluted net income per share, and EBITDAX to the most directly comparable U.S. GAAP financial measures are provided subsequently under the header Non-GAAP Financial Measures.

Conference Call Information and Summary Presentation

Continental Resources plans to host a conference call to discuss third quarter 2014 results on Thursday, November 6, 2014 at 12:00 p.m. ET (11:00 a.m. CT). Those wishing to listen to the conference call may do so via the Company’s website at www.CLR.com or by phone:

Time and date:

12:00 p.m. ET, Thursday, November 6, 2014

Dial in:

888-895-5271

Intl. dial in:

847-619-6547 

Pass code:

38251665

A replay of the call will be available for 30 days on the Company’s website or by dialing:

Replay number:

888-843-7419

Intl. replay:

630-652-3042

Pass code:

38251665

Upcoming Conferences

Members of Continental’s management team will be participating in the following upcoming investment conferences:

November 13, 2014

Bank of America Merrill Lynch 2014 Global Energy Conference; Miami, FL

January 7, 2015

Goldman Sachs Global Energy Conference; Miami, FL

Conference materials for both of the above-referenced conferences will be available on the Company’s website at www.CLR.com on or prior to the day of the presentation at each conference.  The Company’s presentation at the Bank of America Merrill Lynch 2014 Global Energy Conference will be available to the public via internet webcast at www.CLR.com.  A link to the webcast will be accessible from the Company’s website on the date of the event.

About Continental Resources

Continental Resources (CLR) is a Top 10 independent oil producer in the United States. Based in Oklahoma City, Continental is the largest leaseholder and producer in the nation’s premier oil field, the Bakken play of North Dakota and Montana. The Company also has significant positions in Oklahoma, including its SCOOP discovery and the Northwest Cana play. With a focus on the exploration and production of oil, Continental is on a mission to unlock the technology and resources vital to American energy independence. In 2014, the Company celebrated 47 years of operation. For more information, please visit www.CLR.com.

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

This press release includes “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 included in this press release other than statements of historical fact, including, but not limited to, statements or information concerning the Company’s future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, returns, budgets, costs, business strategy, objectives, and cash flow, are forward-looking statements. When used in this press release, 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 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 the expectations reflected in the forward-looking statements are reasonable and based on reasonable assumptions, no assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. When considering forward-looking statements, readers should keep in mind the risk factors and other cautionary statements described under Part I, Item 1A. Risk Factors included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013, registration statements and other reports filed from time to time with the Securities and Exchange Commission (“SEC”), and other announcements the Company makes from time to time.

The Company cautions readers these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company’s control, incident to the exploration for, and development, production, and sale of, crude oil and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling, completion and production equipment and services and transportation infrastructure, environmental risks, drilling and other operating risks, lack of availability and security of computer-based systems, regulatory changes, the uncertainty inherent in estimating crude oil and natural gas reserves and in projecting future rates of production, cash flows and access to capital, the timing of development expenditures, and the other risks described under Part I, Item 1A. Risk Factors in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. Should one or more of the risks or uncertainties described in this press release 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. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that the Company, or persons acting on its behalf, may make.

Except as otherwise required by applicable law, the Company disclaims any duty to update any forward-looking statements to reflect events or circumstances after the date of this press release.

Investor Contact:

Media Contact:

John J. Kilgallon

Kristin Miskovsky

Vice President, Investor Relations

Vice President, Public Relations

405-234-9330

405-234-9480

John.Kilgallon@CLR.com 

Kristin.Miskovsky@CLR.com

 

Continental Resources, Inc.

Unaudited Condensed Consolidated Statements of Income

Three months ended September 30,

Nine months ended September 30,

2014

2013

2014

2013

Revenues:

In thousands, except per share data

Crude oil and natural gas sales

$

1,160,281

$

1,009,836

$

3,300,699

$

2,670,259

Gain (loss) on derivative instruments, net

473,999

(203,774)

171,801

(89,548)

Crude oil and natural gas service operations

11,048

8,825

31,418

29,876

Total revenues

1,645,328

814,887

3,503,918

2,610,587

Operating costs and expenses:

Production expenses

97,374

67,050

258,781

202,305

Production taxes and other expenses

97,399

84,334

272,726

223,718

Exploration expenses

13,514

8,173

29,532

29,138

Crude oil and natural gas service operations

4,337

6,654

18,390

22,567

Depreciation, depletion, amortization and accretion

363,677

244,721

963,409

695,189

Property impairments

85,561

42,167

223,085

161,960

General and administrative expenses 

43,980

34,070

134,435

103,761

(Gain) loss on sale of assets, net

(5,411)

(325)

952

(112)

Total operating costs and expenses

700,431

486,844

1,901,310

1,438,526

Income from operations

944,897

328,043

1,602,608

1,172,061

Other income (expense):

Interest expense

(73,912)

(62,756)

(209,728)

(171,609)

Loss on extinguishment of debt

(24,517)

(24,517)

Other 

393

584

1,945

1,765

(98,036)

(62,172)

(232,300)

(169,844)

Income before income taxes

846,861

265,871

1,370,308

1,002,217

Provision for income taxes

313,340

98,373

507,015

370,822

Net income

$

533,521

$

167,498

$

863,293

$

631,395

Basic net income per share(1)

$

1.45

$

0.45

$

2.34

$

1.72

Diluted net income per share(1)

$

1.44

$

0.45

$

2.33

$

1.71

 

(1)

Net income per share amounts for the three and nine months ended September 30, 2013 have been retroactively adjusted to reflect the Company’s 2-for-1 stock split in September 2014.  

 

 

Continental Resources, Inc.

Unaudited Condensed Consolidated Balance Sheets

September 30, 2014

December 31, 2013

Assets

In thousands

Current assets

$

1,598,876

$

1,147,266

Net property and equipment (1)

12,993,789

10,721,272

Other noncurrent assets

119,422

72,644

Total assets

$

14,712,087

$

11,941,182

Liabilities and shareholders’ equity

Current liabilities 

$

1,804,517

$

1,473,156

Long-term debt

5,831,860

4,713,821

Other noncurrent liabilities

2,227,500

1,801,087

Total shareholders’ equity

4,848,210

3,953,118

Total liabilities and shareholders’ equity

$

14,712,087

$

11,941,182

 

(1)

Balance is net of accumulated depreciation, depletion and amortization of $4.05 billion and $3.12 billion as of September 30, 2014 and December 31, 2013, respectively.

 

 

Continental Resources, Inc.

Unaudited Condensed Consolidated Statements of Cash Flows

Three months ended September 30, 

Nine months ended September 30, 

In thousands

2014

2013

2014

2013

Net income 

$

533,521

$

167,498

$

863,293

$

631,395

Adjustments to reconcile net income to net cash provided by operating activities:

Non-cash expenses

328,395

558,759

1,509,093

1,297,762

Changes in assets and liabilities

(16,518)

95,251

(94,535)

49,296

Net cash provided by operating activities

845,398

821,508

2,277,851

1,978,453

Net cash used in investing activities

(1,148,973)

(949,211)

(3,226,260)

(2,799,388)

Net cash (used in) provided by financing activities

(321,098)

(1,203)

1,072,217

876,713

Net change in cash and cash equivalents

(624,673)

(128,906)

123,808

55,778

Cash and cash equivalents at beginning of period

776,963

220,413

28,482

35,729

Cash and cash equivalents at end of period

$

152,290

$

91,507

$

152,290

$

91,507

Non-GAAP Financial Measures

EBITDAX

We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX. EBITDAX represents earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, non-cash equity compensation expense, and losses on extinguishment of debt. EBITDAX is not a measure of net income or operating cash flows as determined by U.S. GAAP.

Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. Further, we believe EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. We exclude the items listed above from net income and operating cash flows in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.

EBITDAX should not be considered as an alternative to, or more meaningful than, net income or operating cash flows as determined in accordance with U.S. GAAP or as an indicator of a company’s operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies.

The following table provides a reconciliation of our net income to EBITDAX for the periods presented.

In thousands

3Q 2014

2Q 2014

3Q 2013

Net income

$

533,521

$

103,538

$

167,498

Interest expense

73,912

72,841

62,756

Provision for income taxes

313,340

60,808

98,373

Depreciation, depletion, amortization and accretion

363,677

326,871

244,721

Property impairments

85,561

79,316

42,167

Exploration expenses

13,514

11,205

8,173

Impact from derivative instruments:

Total (gain) loss on derivatives, net

(473,999)

262,524

203,774

Total cash (paid) received on derivatives, net

190

(64,143)

(40,349)

Non-cash (gain) loss on derivatives, net

(473,809)

198,381

163,425

Non-cash equity compensation

13,402

14,978

10,462

Loss on extinguishment of debt

24,517

EBITDAX

$

947,635

$

867,938

$

797,575

The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented.

In thousands

3Q 2014

2Q 2014

3Q 2013

Net cash provided by operating activities

$

845,398

$

741,791

$

821,508

Current income tax provision (benefit)

(826)

1,552

4,393

Interest expense

73,912

72,841

62,756

Exploration expenses, excluding dry hole costs

8,755

6,822

7,055

Gain on sale of assets, net

5,411

2,135

325

Other, net

(1,533)

(1,309)

(3,211)

Changes in assets and liabilities

16,518

44,106

(95,251)

EBITDAX

$

947,635

$

867,938

$

797,575

Adjusted earnings and adjusted earnings per share

Our presentation of adjusted earnings and adjusted earnings per share that exclude the effect of certain items are non-GAAP financial measures. Adjusted earnings and adjusted earnings per share represent earnings and diluted earnings per share determined under U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments, gains and losses on asset sales, corporate relocation expenses, and losses on extinguishment of debt. Management believes these measures provide useful information to analysts and investors for analysis of our operating results on a recurring, comparable basis from period to period. In addition, management believes these measures are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to an entity’s specific derivative portfolio, impairment methodologies, and nonrecurring transactions. Adjusted earnings and adjusted earnings per share should not be considered in isolation or as a substitute for earnings or diluted earnings per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following table reconciles earnings and diluted earnings per share as determined under U.S. GAAP to adjusted earnings and adjusted diluted earnings per share for the periods presented. Net income per share amounts for the second quarter of 2014 and third quarter of 2013 have been retroactively adjusted to reflect the Company’s 2-for-1 stock split in September 2014.

 

3Q 2014

2Q 2014

3Q 2013

In thousands, except per share data

After-Tax $

Diluted EPS

After-Tax $

Diluted EPS

After-Tax $

Diluted EPS

Net income (GAAP)

$ 533,521

$1.44

$ 103,538

$0.28

$ 167,498

$0.45

Adjustments, net of tax:

Non-cash (gain) loss on derivatives, net

(298,500)

(0.81)

124,981

0.34

102,958

0.28

Property impairments

53,903

0.15

49,969

0.13

26,565

0.07

Gain on sale of assets, net

(3,409)

(0.01)

(1,345)

(205)

Loss on extinguishment of debt

15,446

0.04

Corporate relocation expenses

63

Adjusted net income (Non-GAAP)

$ 300,961

$0.81

$ 277,143

$0.75

$ 296,879

$0.80

Weighted average diluted shares outstanding

370,528

370,334

369,761

Adjusted diluted net income per share (Non-GAAP)

$      0.81

$      0.75

$      0.80

 

Continental Resources, Inc.

2014 and 2015 Guidance

As of November 5, 2014(1)

2014

2015

Production growth (YOY)

27% to 30%

23% to 29%

Capital expenditures (non-acquisition, in $ billions)

$4.55

$4.6

Operating Expenses:

     Production expense per Boe

$5.60 to $6.00

$5.50 to $6.00

     Production tax (% of oil & gas revenue)

8% to 8.5%

7.5% to 8.5%

     G&A expense per Boe

$2.00 to $2.50

$2.25 to $2.75

     Non-cash equity compensation per Boe

$0.70 to $0.90

$0.75 to $0.95

      DD&A per Boe

$20.00 to $22.50

   $20.00 to $22.50

Average Price Differentials:

     NYMEX WTI crude oil (per barrel of oil)

 ($8.00) to ($11.00)

($9.00) to ($11.00)

     Henry Hub natural gas (per Mcf)

+$1.00 to $1.50 

+$1.00 to $1.50

Income tax rate

37%

37%

Deferred taxes

 90% to 95%

 90% to 95%

 

(1)

Bold items above in guidance denote a change from the previous disclosure.

 

Continental Resources, Inc.

2015 Non-Acquisition Capital Expenditures and

Associated Operated Rig Activity

The following table provides changes in 2015 non-acquisition capital expenditures and associated operated rig activity as compared to guidance previously disclosed on September 17, 2014.

($MM)

Bakken

SCOOP

Other Drilling(1)

Land

Other

Total

Capex

Rigs

Capex

Rigs

Capex

Rigs

Capex

Capex

Capex

Rigs

Original 2015 Budget

$3,030

22

$1,450

29

$180

2

$300

$240

$5,200

53

Adjusted 2015 Budget

$2,591

19

$1,325

26

$114

5

$300

$270

$4,600

50

Change

($439)

(3)

($125)

(3)

($66)

3

0

$30

($600)

(3)

(1)

Includes NW Cana JV