Continental Resources, Inc.

has added a news release to its Investor Relations website. Title: Continental Resources Reports Third Quarter 2013 Results Date(s): 6-Nov-2013 6:13 PM For a complete listing of our news releases, please click here Hawkinson Unit Density Test Produces at an Initial Combined Rate of 14,850 Boe per Day from Middle Bakken and Three Forks Benches One, Two and Three Adjusted Net Income for Third Quarter 2013 of $297 Million, or $1.61 per Diluted Share Record EBITDAX of $798 Million, an Increase of 13% Compared to Second Quarter 2013 and 62% Compared to Third Quarter 2012 Record Production Totaling 141,900 Boe per Day for Third Quarter 2013, an Increase of 5% Sequentially and 38% Compared to Third Quarter 2012
OKLAHOMA CITY, Nov.

6, 2013 /PRNewswire/ -- Continental Resources, Inc.

(NYSE: CLR) ("Continental" or the "Company") announced third quarter 2013 operating and financial results, reporting net income of $167 million, or $0.91 per diluted share.� Adjusted net income, which excludes items typically excluded from published analyst estimates, totaled $297 million, or $1.61 per diluted share, an increase of $51 million compared to second quarter 2013.� The Company achieved record EBITDAX of $798 million, an increase of $89 million or 13% compared to second quarter 2013.� Definitions and reconciliations of adjusted net income, adjusted earnings per share and EBITDAX to the most directly comparable U.S.

GAAP financial measures can be found in the supporting tables at the conclusion of this release. (Logo: http://photos.prnewswire.com/prnh/20120327/DA76602LOGO) Third quarter 2013 production highlights include:
Record net production of approximately 141,900 barrels of oil equivalent ("Boe") per day in third quarter 2013, of which 71% was crude oil; Net Bakken production increased 7% from second quarter 2013 to approximately 94,500 Boe per day for third quarter 2013, representing 67% of total production, highlighted by Montana production growth of 17% compared to second quarter 2013; and� Net production from South Central Oklahoma Oil Province ("SCOOP") play increased to approximately 20,100 Boe per day for third quarter 2013, up 14% from second quarter 2013. Harold G.

Hamm, Continentals Chairman and Chief Executive Officer commented, "The Continental team performed at an exceptional level in the third quarter of this year, increasing production, generating record EBITDAX and delivering on budget.� In addition, we completed our first density test in the Hawkinson spacing unit, demonstrating very strong initial production in the Middle Bakken and the first three benches of the Three Forks.� Once again, Continental is pioneering the expansion and improved recoveries in the world-class Bakken oil play, demonstrating the productive potential of four to five stacked zones with multiple wells in each." Bakken Delivers Oil Growth � Net production from the Companys industry-leading activity in the Bakken play in North Dakota and Montana increased to approximately 94,500 Boe per day in third quarter 2013, an increase of 7% sequentially and 51% above third quarter 2012.

The Companys gross operated�Bakken production averaged approximately 119,000 Boe per day in third quarter 2013.� In the third quarter 2013, Continental operated an average of 20 rigs across its leasehold position of approximately 1.2 million net acres in the Bakken play.

� The Company participated in completing 75 net (203 gross) wells in third quarter 2013.� Given the companys increased activity on large drilling pads, the amount of gross operated wells drilled, but not yet completed increased in third quarter 2013 and is currently 85 wells. Drilling and completion costs continued to improve in the Bakken in the third quarter.

Continentals average operated completed well cost in North Dakota is now $8.0 million per well, achieving its revised year-end target two months ahead of schedule.� The Companys original operated well cost target for 2013 was $8.2 million per well, which was later reduced to $8.0 million per well.

� Bakken Downspacing Activity: The Hawkinson Unit In October 2013 and one month ahead of schedule, Continental successfully completed the first of four pilot density projects it has under way.� The Hawkinson unit initially tested at a combined rate of 14,850 Boe per day from 14 wells.� This included 13,400 Boe per day from 11 new wells drilled this year and combined current rates of 1,450 Boe per day from three existing wells in the unit, which to-date have cumulative production of 1.3 million Boe since 2010.� The Hawkinson density project includes four Middle Bakken, three TF1 (Three Forks 1), four TF2 and three TF3 wells, which all were spaced 1,320 feet apart in the same zone and offset 660 feet in the adjacent zones.� This is the industrys first density drilling program in the basin to include all of these lower benches.�� W.

F.

"Rick" Bott, Continentals President and Chief Operating Officer, commented, "The Hawkinson project is a milestone event for CLR and further validates our vision for full field development of the Bakken -Three Forks reservoirs in this world class oil field.

�Clearly there is more oil to be recovered than previously perceived and projects like the Hawkinson are leading the way to defining the optimum drilling density and pattern to maximize oil recovery.� The news in the Bakken just keeps getting better." In addition to the Hawkinson project, Continental has three other density pilot tests in North Dakota underway, with results expected in the first half of 2014.� The Tangsrud project in Divide County involves 12 new wells and the Rollefstad project in McKenzie County involves 11 new wells drilled with 1,320 foot same zone inter-well spacing, similar to the Hawkinson.� The Wahpeton project in McKenzie County involves 13 new wells configured in four zones at tighter spacing, which is 660 foot same zone inter-well spacing.��During 2014, Continental plans to conduct three additional density pilots to test 660 foot inter-well spacing, further defining the density spacing across a very large portion of Continentals acreage in the Bakken.�� The Company plans to complete approximately 282 net (761 gross) wells in the Bakken in 2013, including both operated and non-operated wells.� The Company estimates its operated rig activity will average 20 rigs throughout the balance of 2013, down from 22 rigs as earlier expected due to realized efficiencies.� This activity level should deliver the planned production growth and stay within capital expenditure guidance.�
Full Development Planned for Antelope - "Ears Back"�Program The Antelope prospect area in McKenzie and Williams Counties, North Dakota will be the first area Continental will execute full field development activities in the Bakken as part of the 2013-2014 planned capital program.� The Company currently has 40 gross existing producing wells in this area, which includes the recently completed prolific Angus wells and legacy activity at the Rollefstad density pilot.� The Company plans to drill an additional 350 wells over the course of the next four to five years focusing on drilling pads with 20 to 30 wells per location.� Continentals "Ears Back" project in Antelope will dedicate four rigs in 2014 for full field development with plans to drill Middle Bakken, TF1, TF2 and TF3 wells with 1,320 foot inter-well spacing.� �� Hamm added, "Antelope is a high-impact area where we have been eager to expand our activity, however, we needed to allow regional infrastructure to catch up to support our goal of limited natural gas flaring.� We are already leveraging on the success of the Hawkinson project in Antelope with well placement, completion design and facility planning for up to 30 wells on a single location.

�This area�will be the first in the field to see full field development including the deeper TF benches." Growth in SCOOP Continues ��� Continental continues to deliver excellent, repeatable results from its drilling activity in the SCOOP.� The play, discovered by Continental and announced in October 2012, currently extends approximately 3,300 square miles across several counties in Oklahoma and contains defined oil and condensate-rich fairways as delineated by more than 290 gross wells in the area.� Continental currently has approximately 320,000 net acres of leasehold in the play.� In third quarter 2013, SCOOP net production averaged approximately 20,100 Boe per day, an increase of 14% sequentially and 293% above third quarter 2012.� The recent growth was driven by the addition of 11 net (22 gross) operated and non-operated wells in the play during the third quarter 2013, as per the Companys capital plan.� The Company is currently operating 12 rigs in the play with plans to increase to 15 by year-end 2013.� The Company plans to complete a total of approximately 41 net (77 gross) wells in the SCOOP play in 2013, including both operated and non-operated wells.� These wells will focus on expanding the proved productive extent of the play and de-risking the Companys leasehold.� Expected net and gross well count activity has been adjusted to account for recent increased cross-unit activity. Production Third quarter 2013 Company net production totaled 13.1 million Boe, or approximately 141,900 Boe per day, a sequential increase of 5% from second quarter 2013.� Total net production included approximately 100,700 barrels of oil per day (71% of production) and approximately 247 million cubic feet of natural gas per day (29% of production).� In the third quarter 2013, the Company sold its natural gas prior to processing based upon pricing provisions in its natural gas contracts.� The Company estimates that if it had sold its natural gas liquids after processing, the combined natural gas liquids and oil would account for approximately 80% of total production. The following table provides the Companys average daily production by region for the periods presented.
3Q
2Q
3Q
Boe per day
2013
2013
2012
North Region:
North Dakota Bakken
81,545
76,909
55,918
Montana Bakken
12,957
11,081
6,535
Red River Units�
14,703
14,886
14,916
Other
408
2,141
1,343
South Region:
SCOOP
20,070
17,547
5,108
NW Cana
6,985
7,763
11,395
Arkoma
3,004
3,064
4,061
Other�
2,201
2,309
2,590
East Region
-
-
1,098
Total
141,873
135,700
102,964
Financial Update� Continentals average realized sales price excluding the effects of derivative positions was $98.02 per barrel of oil and $5.23 per thousand cubic feet ("Mcf") of natural gas, or $78.55 per Boe for third quarter 2013.

�Realized settlements of commodity derivative positions generated a $5.92 loss per barrel of oil and $0.62 gain per Mcf of natural gas resulting in a net realized hedging loss of $40.3 million, or $3.11 per Boe for the third quarter 2013.

�Based on realizations without the effect of derivatives, the Companys third quarter 2013 oil differential was $7.80 per barrel below the NYMEX daily average for the period.� The realized natural gas price differential for third quarter 2013 was a positive $1.65 per Mcf. Production expense per Boe was $5.17 for third quarter 2013, an improvement of $0.69 per Boe compared to second quarter 2013.�� Other select operating costs and expenses for third quarter 2013 included production taxes of 8.2% of oil and natural gas sales; DD&A of $18.87 per Boe; and G&A (cash and non-cash, excluding relocation expenses) of $2.62 per Boe.� The Companys 2013 and 2014 guidance can be found at the conclusion of this release. As of September 30, 2013, Continentals balance sheet included approximately $92 million in cash and cash equivalents and an undrawn $1.5 billion revolving credit facility.� During third quarter 2013, the Companys long-term corporate credit rating and senior unsecured debt was increased by Standard & Poors to BBB-, which is investment grade status.� As of September 30, 2013, the Companys Net Debt-to-EBITDAX ratio for the trailing four quarters and third quarter 2013 annualized was 1.6 and 1.4 times, respectively.�� Non-acquisition capital expenditures for third quarter 2013 totaled $910 million, including $770 million in exploration and development drilling, $100 million in leasehold and seismic and $40 million in workovers, recompletions and other.� Acquisition capital expenditures totaled approximately $74 million for third quarter 2013, and are excluded from the Companys capital expenditure guidance for 2013 of $3.6 billion.� The following table provides the Companys 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
2Q
3Q
2013
2013
2012
Average daily production:
Crude oil (Bbl per day)
100,684
96,029
72,235
Natural gas (Mcf per day)
247,135
238,028
184,377
Crude oil equivalents (Boe per day)
141,873
135,700
102,964
Average sales prices, excluding effect from derivatives:
Crude oil ($/Bbl)
$98.02
$87.22
$82.87
Natural gas ($/Mcf)
$5.23
$5.22
$4.00
Crude oil equivalents ($/Boe)
$78.55
$71.13
$65.62
Production expenses ($/Boe)
$5.17
$5.86
$5.62
Production taxes (% of oil and gas revenues)
8.2%
8.3%
8.4%
DD&A ($/Boe)
$18.87
$18.88
$19.62
General and administrative expenses ($/Boe) (1)
$1.81
$2.03
$2.29
Non-cash equity compensation ($/Boe)
$0.81
$0.78
$0.78
Net income (in thousands)�
$167,498
$323,270
$44,096
Diluted net income per share
$0.91
$1.75
$0.24
Adjusted net income (in thousands) (2)�
$296,879
$245,728
$159,511
Adjusted diluted net income per share (2)�
$1.61
$1.33
$0.87
EBITDAX (in thousands) (2)�
$797,575
$708,107
$492,279
(1)
General and administrative expenses ($/Boe) exclude non-recurring corporate relocation expenses of $0.1 million ($0.01 per Boe) for the three months ended September 30, 2013, $0.7 million ($0.05 per Boe) for the three months ended June 30, 2013, and $2.3 million ($0.24 per Boe) for the three months ended September 30, 2012.
(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 2013 results on Thursday, November 7, 2013 at 11 a.m.

ET (10 a.m.

CT).

Those wishing to listen to the conference call may do so via the Companys website at www.CLR.com or by phone:
Time and date:
11 a.m.

ET, Thursday, November 7, 2013
Dial in:
888 679 8033
Intl.

dial in:
617 213 4846
Pass code:
15871985
A replay of the call will be available for 30 days on the Companys website or by dialing:
Replay number:
888 286 8010
Intl.

replay:
617 801 6888
Pass code:
59553466
Callers who wish to pre-register for the call may go to: https://www.theconferencingservice.com/prereg/key.process?key=PUDQ6BJKE Continental plans to publish a third quarter 2013 summary presentation to its website at www.CLR.com prior to the start of its earnings conference call on November 7, 2013.� Upcoming Conferences Members of Continentals management team will be participating in the following upcoming investment conferences:
November 13, 2013
Jefferies 2013 Global Energy Conference: Houston
November 22, 2013
Bank of America Merrill Lynch 2013 Global Energy Conference: Miami
December 4, 2013
Cowen and Company Ultimate Energy Conference:� New York City
December 12, 2013
Capital One Southcoast 2013 Energy Conference: New Orleans
The Companys presentations at the above conferences will be available via webcast.� Instructions regarding how to access the webcasts and�presentation materials will be available on the Companys website at www.CLR.com on or prior to the day of the presentations. About Continental Resources Continental Resources (NYSE: 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 nations premier oil field, the Bakken play of North Dakota and Montana.

The company also has significant positions in Oklahoma, including its recently discovered SCOOP play 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 2013, the company will celebrate 46 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 Companys 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 Companys 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 Companys Annual Report on Form 10-K for the year ended December 31, 2012, 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 Companys 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 and production equipment and services, environmental risks, drilling and other operating risks, 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 Companys Annual Report on Form 10-K for the year ended December 31, 2012, 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 Companys 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.
CONTACTS: Continental Resources, Inc.
Investors
Media
Warren Henry
Kristin Miskovsky
VP, Investor Relations
VP, Public Relations
405-234-9127
405-234-9480
�
John J.

Kilgallon
Director, Investor Relations
405-234-9330
�
Continental Resources, Inc.
Unaudited Condensed Consolidated Statements of Income
Three months ended September 30,
Nine months ended September 30,
2013
2012
2013
2012
Revenues:
In thousands, except per share data
Crude oil and natural gas sales
$
1,018,784
$
633,344
$
2,694,488
$
1,708,995
Gain (loss) on derivative instruments, net
(203,774)
(158,294)
(89,548)
144,377
Crude oil and natural gas service operations
8,825
8,679
29,876
30,176
Total revenues
823,835
483,729
2,634,816
1,883,548
Operating costs and expenses:
Production expenses
67,050
54,210
202,305
138,041
Production taxes and other expenses
93,282
62,913
247,947
162,880
Exploration expenses
8,173
4,899
29,138
17,752
Crude oil and natural gas service operations
6,654
7,626
22,567
24,723
Depreciation, depletion, amortization and accretion
244,721
189,374
695,189
499,847
Property impairments
42,167
27,375
161,960
93,153
General and administrative expenses�
34,070
31,925
103,761
86,704
Gain on sale of assets, net
(325)
(115)
(112)
(67,139)
Total operating costs and expenses
495,792
378,207
1,462,755
955,961
Income from operations
328,043
105,522
1,172,061
927,587
Other income (expense):
Interest expense
(62,756)
(39,205)
(171,609)
(95,174)
Other�
584
710
1,765
2,280
(62,172)
(38,495)
(169,844)
(92,894)
Income before income taxes
265,871
67,027
1,002,217
834,693
Provision for income taxes
98,373
22,931
370,822
315,819
Net income
$
167,498
$
44,096
$
631,395
$
518,874
Basic net income per share
$
0.91
$
0.24
$
3.43
$
2.88
Diluted net income per share
$
0.91
$
0.24
$
3.42
$
2.86
�
Continental Resources, Inc.
Unaudited Condensed Consolidated Balance Sheets
September 30,
December 31,
2013
2012
Assets
In thousands
Current assets
$
1,213,181
$
946,783
Net property and equipment (1)
10,112,506
8,105,269
Other noncurrent assets
94,601
87,957
Total assets
$
11,420,288
$
9,140,009
Liabilities and shareholders equity
Current liabilities
$
1,468,071
$
1,125,865
Long-term debt
4,439,825
3,537,771
Other noncurrent liabilities
1,691,779
1,312,674
Total shareholders equity
3,820,613
3,163,699
Total liabilities and shareholders equity
$
11,420,288
$
9,140,009
(1)
Balance is net of accumulated depreciation, depletion and amortization of $2.84 billion and $2.12 billion as of September 30, 2013 and December 31, 2012, respectively.
�
Continental Resources, Inc.
Unaudited Condensed Consolidated Statements of Cash Flows
Three months ended September 30,�
Nine months ended September 30,�
2013
2012
2013
2012
In thousands
Net income�
$
167,498
$
44,096
$
631,395
$
518,874
Adjustments to reconcile net income to net cash provided by operating activities:
Non-cash expenses
558,759
412,006
1,297,762
681,891
Changes in assets and liabilities
95,251
(79,035)
49,296
(52,868)
Net cash provided by operating activities
821,508
377,067
1,978,453
1,147,897
Net cash used in investing activities
(949,211)
(817,635)
(2,799,388)
(2,591,127)
Net cash (used in) provided by financing activities
(1,203)
670,876
876,713
1,649,131
Net change in cash and cash equivalents
(128,906)
230,308
55,778
205,901
Cash and cash equivalents at beginning of period
220,413
29,137
35,729
53,544
Cash and cash equivalents at end of period
$
91,507
$
259,445
$
91,507
$
259,445
Non-GAAP Financial Measures 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, and non-cash equity compensation expense.

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.

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 companys operating performance or liquidity.

Certain items excluded from EBITDAX are significant components in understanding and assessing a companys financial performance, such as a companys 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. 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.

Our credit facility requires that we maintain a total funded debt to EBITDAX ratio of no greater than 4.0 to 1.0 on a rolling four-quarter basis.

This ratio represents the sum of outstanding borrowings and the letters of credit under our credit facility plus our note payable and Senior Note obligations, divided by total EBITDAX for the most recent four quarters.

Our credit facility defines EBITDAX consistent with the presentation below.

The following table provides a reconciliation of our net income to EBITDAX for the periods presented.
3Q 2013
2Q 2013
3Q 2012
in thousands
Net income
$
167,498
$
323,270
$
44,096
Interest expense
62,756
61,378
39,205
Provision for income taxes
98,373
189,858
22,931
Depreciation, depletion, amortization and accretion
244,721
236,790
189,374
Property impairments
42,167
79,712
27,375
Exploration expenses
8,173
11,151
4,899
Impact from derivative instruments:
Total (gain) loss on derivatives, net
203,774
(199,056)
158,294
Total cash paid on derivatives, net
(40,349)
(4,752)
(1,394)
Non-cash (gain) loss on derivatives, net
163,425
(203,808)
156,900
Non-cash equity compensation
10,462
9,756
7,499
EBITDAX
$
797,575
$
708,107
$
492,279
The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented.
3Q 2013
2Q 2013
3Q 2012
in thousands
Net cash provided by operating activities
$
821,508
$
698,834
$
377,067
Current income tax provision (benefit)
4,393
5,830
(9,874)
Interest expense
62,756
61,378
39,205
Exploration expenses, excluding dry hole costs
7,055
5,349
4,678
Gain (loss) on sale of assets, net
325
(349)
115
Other, net
(3,211)
2,539
2,053
Changes in assets and liabilities
(95,251)
(65,474)
79,035
EBITDAX
$
797,575
$
708,107
$
492,279
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, and corporate relocation expenses.

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 entitys 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.
3Q 2013
2Q 2013
3Q 2012
In thousands, except per share data
After-Tax $
Diluted EPS
After-Tax $
Diluted EPS
After-Tax $
Diluted EPS
Net income (GAAP)
$ 167,498
$ � � � �0.91
$ 323,270
$ � � � �1.75
$ �44,096
$ � � � �0.24
Adjustments, net of tax:
Non-cash (gain) loss on derivatives, net
102,958
$ � � � �0.56
(128,399)
$ � � � (0.69)
97,121
0.53
Property impairments
26,565
$ � � � �0.14
50,219
$ � � � �0.27
16,945
0.09
(Gain) loss on sale of assets, net
(205)
-
220
-
(71)
-
Corporate relocation expenses
63
-
418
-
1,420
0.01
Adjusted net income (Non-GAAP)
$ 296,879
$ � � � �1.61
$ 245,728
$ � � � �1.33
$ 159,511
$ � � � �0.87
Weighted average diluted shares outstanding
184,880
184,739
182,537
Adjusted diluted net income per share (Non-GAAP)
$ � � �1.61
$ � � �1.33
$ � � �0.87
� � �
Continental Resources, Inc.�
2013 and 2014 Guidance Outlook
As of November 6, 2013*
2013
2014
Production growth (YOY)
38% to 40%
26% to 32%
Capital expenditures (non-acquisition)
$3.6B
$4.05B
Operating Expenses:
���� Production expense per Boe
$5.60 to $6.00
$5.60 to $6.10
���� Production tax (% of oil & gas revenue)**
8% to 9%
8% to 9%
���� DD&A per Boe
$18.50 to $19.50
$17.50 to $19.50
���� G&A expense per Boe
�$2.00 to $2.50
$2.00 to $2.50
���� Non-cash equity compensation per Boe
�$0.70 to $0.80
$0.70 to $0.90
Average Price Differentials:
���� NYMEX WTI crude oil (per barrel of oil)
($6.00) to ($8.00)
($8.00) 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%
*��� No change from previously announced 2013 and 2014 Guidance Outlook on September 10, 2013
**� Does not include other expenses which could represent an additional 1%
SOURCE Continental Resources
------------------------------------------------------------ If you are unable to click on the link above, please copy and paste the URL below into a web browser http://phx.corporate-ir.net/phoenix.zhtml?c=197380&p=IROL-news&nyo=0 ------------------------------------------------------------ 20 N.

Broadway, OKC, OK 73102 Click Here to unsubscribe from this JoinMail list.
-----