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Continental Resources Reports Third Quarter 2013 Results

           Continental Resources Reports Third Quarter 2013 Results

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

PR Newswire

OKLAHOMA CITY, Nov. 6, 2013

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:

  oRecord net production of approximately 141,900 barrels of oil equivalent
    ("Boe") per day in third quarter 2013, of which 71% was crude oil;
  oNet 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
  oNet 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, Continental's 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 Company's 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 Company's gross operatedBakken 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 company's 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. Continental's 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 Company's 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 industry's first density drilling program in the basin to include all
of these lower benches.

W. F. "Rick" Bott, Continental's 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 Continental's 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. Continental's "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 areawill 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 Company's 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 Company's 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 Company's 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

Continental's 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 Company's
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 Company's 2013 and 2014
guidance can be found at the conclusion of this release.

As of September 30, 2013, Continental's 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 Company's long-term corporate
credit rating and senior unsecured debt was increased by Standard & Poor's to
BBB-, which is investment grade status. As of September 30, 2013, the
Company's 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 Company's capital
expenditure guidance for 2013 of $3.6 billion.

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        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

    General and administrative expenses ($/Boe) exclude non-recurring
    corporate relocation expenses of $0.1 million ($0.01 per Boe) for the
(1) 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.
    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
(2) 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 Company's 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 Company's 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 Continental's 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 Company's presentations at the above conferences will be available via
webcast. Instructions regarding how to access the webcasts andpresentation
materials will be available on the Company's 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 nation's 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 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, 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 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 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 Company's 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 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.

CONTACTS: Continental Resources, Inc.
Investors                             Media
Warren Henry                          Kristin Miskovsky
VP, Investor Relations                VP, Public Relations
405-234-9127                          405-234-9480
Warren.Henry@CLR.com                 Kristin.Miskovsky@CLR.com
John J. Kilgallon
Director, Investor Relations
405-234-9330
John.Kilgallon@CLR.com



Continental Resources, Inc.
Unaudited Condensed Consolidated Statements of Income
                    Three months ended September  Nine months ended September
                    30,                           30,
                    2013            2012          2013            2012
Revenues:           In thousands, except per share data
Crude oil and       $  1,018,784    $  633,344    $  2,694,488    $ 1,708,995
natural gas sales
Gain (loss) on
derivative             (203,774)       (158,294)     (89,548)       144,377
instruments, net
Crude oil and
natural gas service    8,825           8,679         29,876         30,176
operations
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       93,282          62,913        247,947        162,880
and other expenses
Exploration            8,173           4,899         29,138         17,752
expenses
Crude oil and
natural gas service    6,654           7,626         22,567         24,723
operations
Depreciation,
depletion,             244,721         189,374       695,189        499,847
amortization and
accretion
Property               42,167          27,375        161,960        93,153
impairments
General and
administrative         34,070          31,925        103,761        86,704
expenses
Gain on sale of        (325)           (115)         (112)          (67,139)
assets, net
Total operating        495,792         378,207       1,462,755      955,961
costs and expenses
Income from            328,043         105,522       1,172,061      927,587
operations
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          265,871         67,027        1,002,217      834,693
income taxes
Provision for          98,373          22,931        370,822        315,819
income taxes
Net income          $  167,498      $  44,096     $  631,395      $ 518,874
Basic net income    $  0.91         $  0.24       $  3.43         $ 2.88
per share
Diluted net income  $  0.91         $  0.24       $  3.42         $ 2.86
per share



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

    Balance is net of accumulated depreciation, depletion and amortization of
(1) $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    Nine months ended September
                   30,                            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     95,251          (79,035)     49,296          (52,868)
and liabilities
Net cash provided
by operating          821,508         377,067      1,978,453       1,147,897
activities
Net cash used in
investing             (949,211)       (817,635)    (2,799,388)     (2,591,127)
activities
Net cash (used in)
provided by           (1,203)         670,876      876,713         1,649,131
financing
activities
Net change in cash
and cash              (128,906)       230,308      55,778          205,901
equivalents
Cash and cash
equivalents at        220,413         29,137       35,729          53,544
beginning of
period
Cash and cash
equivalents at end $  91,507       $  259,445    $ 91,507        $ 259,445
of period

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 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.

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     244,721     236,790      189,374
accretion
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       7,055       5,349       4,678
costs
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 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.

                    3Q 2013             2Q 2013             3Q 2012
In thousands,       After-Tax  Diluted  After-Tax  Diluted  After-Tax  Diluted
except per share    $          EPS      $          EPS      $          EPS
data
Net income (GAAP)   $ 167,498  $     $ 323,270  $     $ 44,096  $   
                               0.91               1.75               0.24
Adjustments, net
of tax:
 Non-cash (gain)               $                $   
 loss on            102,958    0.56    (128,399)  (0.69)   97,121     0.53
 derivatives, net
 Property           26,565     $     50,219     $     16,945     0.09
 impairments                   0.14               0.27
 (Gain) loss on
 sale of assets,    (205)      -        220        -        (71)       -
 net
 Corporate
 relocation         63         -        418        -        1,420      0.01
 expenses
  Adjusted net                 $                $                $   
  income            $ 296,879  1.61    $ 245,728  1.33    $ 159,511  0.87
  (Non-GAAP)
  Weighted average
  diluted shares    184,880             184,739             182,537
  outstanding
  Adjusted diluted  $                 $                 $  
  net income per    1.61               1.33               0.87
  share (Non-GAAP)







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    8% to 9%            8% to 9%
revenue)**
 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  $0.70 to $0.80     $0.70 to $0.90
Boe
Average Price Differentials:
 NYMEX WTI crude oil (per barrel   ($6.00) to ($8.00)  ($8.00) to ($11.00)
of oil)
 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

Website: http://www.clr.com
 
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