Continental Resources Reports Fourth Quarter 2013 And Full-Year Results

   Continental Resources Reports Fourth Quarter 2013 And Full-Year Results

Fourth Quarter Adjusted Net Income Totals $228.1 Million, or $1.23 per Diluted
Share

Fourth Quarter EBITDAX of $712 Million Brings Full-Year 2013 EBITDAX to Record
$2.84 Billion

Strong Early Performance of Hawkinson Density Pilot Wells

2014 Production on Track for 26% to 32% Growth in 2014

PR Newswire

OKLAHOMA CITY, Feb. 26, 2014

OKLAHOMA CITY, Feb. 26, 2014 /PRNewswire/ -- Continental Resources, Inc.
(NYSE: CLR) ("Continental" or the "Company") today announced fourth quarter
and full-year 2013 operating and financial results. Net income for the
quarter ended December 31, 2013 was $132.8 million, or $0.72 per diluted
share, compared with net income of $220.5 million, or $1.19 per diluted share,
for the fourth quarter of 2012. Excluding items typically excluded from
published analyst estimates, adjusted net income for the fourth quarter of
2013 was $228.1 million, or $1.23 per diluted share, a 19% increase over
adjusted net income of $191.8 million, or $1.04 per diluted share, for the
fourth quarter of 2012.

(Logo: http://photos.prnewswire.com/prnh/20120327/DA76602LOGO)

Net income for full-year 2013 was $764.2 million, or $4.13 per diluted share,
compared with net income of $739.4 million, or $4.07 per diluted share, for
full-year 2012. Excluding items typically excluded from published analyst
estimates, adjusted net income for full-year 2013 was $986.1 million, or $5.33
per diluted share, a 61% increase over adjusted net income of $611.9 million,
or $3.36 per diluted share, for full-year 2012.

EBITDAX for the fourth quarter of 2013 was $712 million, a 20% increase over
EBITDAX of $595 million for the fourth quarter of 2012. Full-year 2013
EBITDAX was a record $2.84 billion, a 45% increase over EBITDAX of $1.96
billion for full-year 2012. 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.

"Our teams performed at an exceptional level in 2013, achieving our key growth
targets for the initial year in our five-year plan to triple production and
proved reserves," said Harold G. Hamm, Chairman and Chief Executive Officer.
"The foundation of our plan is an unmatched inventory of oil and liquid-rich
assets in the Bakken play of North Dakota and Montana and in the South Central
Oklahoma Oil Province, or SCOOP. Our goal is to deliver exceptional
production growth and cash margins, while maintaining a strong, conservative
balance sheet. Both S&P and Moody's upgraded the Company to investment grade
in the second half of 2013, clear evidence we are generating growth while
maintaining financial strength and discipline."

Fourth quarter and full-year 2013 highlights included:

  oAchieved the Company's original 2013 production and capital expenditures
    targets;
  oRecord proved reserves of 1.08 billion barrels of oil equivalent ("Boe")
    as of December 31, 2013, a 38% increase over year-end 2012 and a
    compounded annual growth of 47% since year-end 2008; and
  oRecord fourth quarter 2013 production of 144,254 Boe per day, a 35%
    increase over the fourth quarter of 2012.

Production

Fourth quarter 2013 Company net production totaled 13.3 million Boe, or
144,254 Boe per day, a sequential increase of 2% from third quarter 2013 and
35% higher than fourth quarter 2012. Total net production included
approximately 100,400 barrels of oil per day (70% of production) and
approximately 263 million cubic feet of natural gas per day (30% of
production). In the fourth quarter 2013, the Company sold its operated
natural gas production prior to processing based upon pricing provisions in
its natural gas contracts. The Company estimates 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 for fourth quarter 2013.

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

                     4Q       3Q       4Q
Boe per day          2013     2013     2012
North Region:
North Dakota Bakken  80,374   81,545   59,019
Montana Bakken       12,961   12,957   8,503
Red River Units     14,398   14,703   14,716
Other                812      408      967
South Region:
SCOOP                23,754   20,070   7,123
NW Cana              6,696    6,985    9,716
Arkoma               2,769    3,004    3,225
Other               2,490    2,201    2,556
East Region          -        -        1,006
Total                144,254  141,873  106,831

Bakken Development

Continental's Bakken production totaled 93,335 Boe per day in the fourth
quarter of 2013, essentially flat compared to third quarter 2013 and an
increase of 38% compared to fourth quarter 2012. Base production and growth,
including operated and non-operated production, were adversely affected by
winter weather conditions in the quarter, especially during December 2013.
As a result, Continental currently has approximately 110 gross wells that have
been drilled but are awaiting completion or infrastructure in the Bakken.
This is approximately 35 gross wells above the Company's typical run rate
level of activity. The Company has added additional third-party completion
services in order to reduce the inventory and expedite initial production of
recent drilled wells.

The Company plans to complete approximately 287 net (870 gross) wells in the
Bakken in 2014, including both operated and non-operated wells, and is subject
to change. The Company operated 20 rigs in the play in fourth quarter 2013
and anticipates operating an average rig count of 22 throughout 2014.
Continental's average operated well costs in the Bakken continue to trend
lower. Fourth quarter 2013 operated Bakken well costs were approximately $8.0
million per well. The Company is targeting even lower well costs with a goal
of $7.5 million per operated Bakken well by year-end 2014 for its typical
completion design. As previously indicated, Continental plans to test several
different completion design techniques on approximately 20% of its Bakken
completions in 2014 to evaluate possible performance enhancements. Projected
capital expenditures for the Northern region, which includes the Bakken and
the Red River units, are approximately $2.9 billion for 2014.

Bakken Density and Productivity Update: The Hawkinson Unit

In North Dakota during October 2013, Continental successfully completed the
first pilot density project at the Hawkinson unit in Dunn County. The 14
individual wells within the unit tested at a combined rate of 14,850 Boe per
day, which included three existing producing wells. The project included four
Middle Bakken, three TF1 (Three Forks 1), four TF2 and three TF3 wells spaced
1,320 feet apart in the same zone and offset 660 feet in the adjacent zones.

Based on the first 120 days of production, 12 of the 14 wells on the Hawkinson
unit are performing very well and average production is trending 50% above the
Company's 603,000 Boe estimated ultimate recovery ("EUR") model for a typical
North Dakota Bakken well. The two exception wells are in the TF3 zone and
were recently put on pump. Theyare producing on trend just below the 603,000
Boe EUR model, but improving. Given the limited amount of production history,
these trends could change over time. Continental has an approximate 55%
working interest in the Hawkinson Unit. 

W. F. "Rick" Bott, Continental's President and Chief Operating Officer,
commented, "The Hawkinson project has been a huge success and the culmination
of efforts across the entire company – geology, micro-seismic, drilling,
completions,surface logistics and marketing, to name a few. This is a
landmark event for our Company and the industry – unique production from four
different producing intervals and spaced 1,320 feet apart. This first test
validates our vision for full-field development of the Bakken and the vast
resource potential across our acreage position."

In addition to the Hawkinson project, Continental has three other density
pilot tests in North Dakota which the Company began drilling in 2013,
including wells in the Middle Bakken, TF1, TF2 and TF3. The Tangsrud project
in Divide County is a 1,320 feet inter-well spacing test including 12 new
wells. Ten of the wells are currently beginning the initial flowback stage
and the two remaining wells should commence production by early March. The
Rollefstad project in eastern McKenzie County involves 11 new wells drilled
with 1,320 feet same zone inter-well spacing, similar to the Hawkinson and
Tangsrud. Completion activities are in progress at the Rollefstad unit,
including well clean out and tubing installation and full production is
expected in late March. The Wahpeton density pilot in western McKenzie County
involves 13 new wells configured in four zones at increased density spacing of
660 feet inter-well spacing. Full unit production startup is expected in
early May. The original completion schedule for the Tangsrud, Rollefstad and
Wahpeton units was delayed due to challenging weather conditions. During
2014, Continental has begun drilling three additional density pilots to test
660 feet inter-well spacing at the Lawrence, Mack and Hartman units, which
include 18 new wells and six existing producers.

Antelope "Ears Back" Program Update

Continental announced in November 2013 the Company would begin its first
full-field development in the Bakken, including the deeper Three Forks
benches, in McKenzie and Mountrail counties in the Antelope area and plans to
drill between 350 to 400 gross wells over the next five years. The area was
selected due to the Company's large operated footprint and historical results
that are among the Company's highest rates of return. Continental currently
has three rigs running in the Antelope area and has 18 wells in various stages
of drilling or completion.

Growth in SCOOP Continues 

Continental continues to deliver excellent, repeatable results from its
drilling activity in the South Central Oklahoma Oil Province ("SCOOP"). The
play, discovered by Continental and announced in October 2012, currently
extends approximately 120 miles across several counties in Oklahoma and
contains oil and condensate-rich fairways as delineated by approximately 450
gross industry wells. Continental currently operates or has a working
interest in approximately 155 wells across its approximately 400,000 net acres
of leasehold in the play.

In fourth quarter 2013, SCOOP net production averaged approximately 23,750 Boe
per day, an increase of 18% sequentially and 233% above fourth quarter 2012.
The recent growth was driven by the addition of 12 net (23 gross) operated and
non-operated wells in the play during the fourth quarter 2013. 

In SCOOP, Continental's primary focus continues to be exploration, appraisal
and drilling to hold acreage (HBP), with an increasing shift to 2-mile lateral
wells. The Company operated an average of 14 rigs during fourth quarter 2013
and plans to average 18 operated rigs in the play in 2014, with 40% of the
activity on 2-mile lateral wells. Well costs in the play are targeted by
year-end 2014 to be approximately $8.7 million for a standard 1-mile lateral
across the play within the exploration program and approximately $13.5 million
for a 2-mile lateral. Continental plans a number of spacing tests and one
density pilot in 2014. Continental projects capital expenditures of
approximately $1.1 billion in the Southern region in 2014, which includes
SCOOP and other areas. 

In fourth quarter 2013, average initial one-day test rates from operated and
non-operated wells within the oil and condensate fairways of SCOOP were
approximately 1,300 boe per day.

Financial Update and Guidance

Continental's average realized sales price excluding the effects of derivative
positions was $84.47 per barrel of oil and $5.49 per thousand cubic feet of
natural gas ("Mcf"), or $68.80 per Boe for fourth quarter 2013. Settlements
of matured commodity derivative positions generated a $1.05 loss per barrel of
oil resulting in a net loss on matured derivatives of $9.6 million, or $0.73
per Boe for the fourth quarter 2013. Based on realizations without the effect
of derivatives, the Company's fourth quarter 2013 oil differential was $13.05
per barrel below the NYMEX daily average for the period. The realized natural
gas price differential for fourth quarter 2013 was a positive $1.88 per Mcf.
Full-year 2013 realized differential without the effect of derivatives was a
negative $8.23 per barrel of oil and a positive $1.59 per Mcf as compared to
the NYMEX daily averages for the year. Full-year 2013 oil differential was
above the Company's guidance estimate due to fourth quarter price volatility,
while natural gas differential was better than guidance. 

Production expense per Boe was $6.03 for fourth quarter 2013, an increase from
third quarter 2013 due to increased costs and lower volumes due to weather
conditions. Other select operating costs and expenses for fourth quarter 2013
included production taxes of 8.1% of oil and natural gas sales; DD&A of $20.40
per Boe; and G&A (cash and non-cash, excluding relocation expenses) of $3.06
per Boe. On a full-year basis, these expense categories were within the
Company's full-year guidance.

As of December 31, 2013, Continental's balance sheet included approximately
$28 million in cash and cash equivalents and $275 million of borrowings
against the Company's $1.5 billion credit facility. During fourth quarter
2013, Moody's Investor Services upgraded the Company's senior unsecured rating
to investment grade status of Baa3, up from Ba2.

Non-acquisition capital expenditures for fourth quarter 2013 totaled
approximately $868 million, including $766 million in exploration and
development drilling, $62 million in leasehold and seismic and $40 million in
workovers, recompletions and other. Acquisition capital expenditures totaled
approximately $71 million for fourth quarter 2013. Full-year 2013
non-acquisition capital expenditures totaled approximately $3.574 billion,
just below guidance. Acquisition spending totaled approximately $268 million
for the year.

Continental's 2014 guidance remains unchanged as originally disclosed on
September 10, 2013, which includes organic production growth of 26% to 32%
with a capital budget of $4.05 billion. A table with the Company's full 2014
guidance, which includes differentials and select cost elements, can be found
at the conclusion of this release.

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.



                         Three months ended December  Year ended December 31,
                         31,
                         2013            2012         2013        2012
Average daily
production:
Crude oil (Bbl per day)  100,443         76,449       95,859      68,497
Natural gas (Mcf per     262,866         182,289      240,355     174,521
day)
Crude oil equivalents    144,254         106,831      135,919     97,583
(Boe per day)
Average sales prices, excluding
effect from derivatives:
Crude oil ($/Bbl)        $84.47          $84.99       $89.93      $84.59
Natural gas ($/Mcf)      $5.49           $4.82        $5.25       $4.20
Crude oil equivalents    $68.80          $68.89       $72.71      $66.83
($/Boe)
Production expenses      $6.03           $5.90        $5.69       $5.49
($/Boe)
Production taxes (% of   8.1%            8.3%         8.2%        8.2%
oil and gas revenues)
DD&A ($/Boe)             $20.40          $19.76       $19.47      $19.44
General and
administrative expenses  $2.27           $2.70        $2.07       $2.38
($/Boe) ^(1)
Non-cash equity          $0.79           $0.85        $0.80       $0.82
compensation ($/Boe)
Net income (in           $132,824        $220,511     $764,219    $739,385
thousands)
Diluted net income per   $0.72           $1.19        $4.13       $4.07
share
Adjusted net income (in  $228,132        $191,801     $986,125    $611,870
thousands) ^(2)
Adjusted diluted net     $1.23           $1.04        $5.33       $3.36
income per share ^(2)
EBITDAX (in thousands)   $712,300        $594,452     $2,839,510  $1,963,123
^(2)

    General and administrative expenses ($/Boe) exclude non-recurring
    corporate relocation expenses of $0.2 million ($0.01 per Boe) for the
    three months ended December 31, 2013 and $0.5 million ($0.05 per Boe) for
(1) the three months ended December 31, 2012. For the year ended December 31,
    2013, general and administrative expenses exclude non-recurring corporate
    relocation expenses of $1.6 million ($0.04 per Boe) and $7.8 million
    ($0.22 per Boe) for the same period in 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 fourth
quarter and full-year 2013 results on Thursday, February 27, 2014 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, February 27, 2014
Dial in:       800 708 4539
Intl. dial in: 847 619 6396
Pass code:     36590660

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:     36590660

Continental plans to publish a fourth quarter and full-year 2013 summary
presentation to its website at www.CLR.com prior to the start of its earnings
conference call on February 27, 2014.

Upcoming Conferences

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

March 3, 2014  Raymond James Institutional Investors Conference: Orlando
March 5, 2014  Barclays Investment Grade Energy & Pipeline Conference: New
               York
March 26, 2014 Howard Weil 42^nd Annual Energy Conference: New Orleans

The Company's presentation at the Raymond James conference will be available
via webcast and a replay 30 days thereafter. Instructions regarding how to
access the live and replay webcast for the Raymond James presentation and
presentation materials for all conferences mentioned above 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 2014, the company will celebrate 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 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, 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.

CONTACTS: Continental Resources,
Inc.
Investors:                                    Media:
John 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
Warren Henry
Vice President, Research and Policy
405-234-9127

Waren.Henry@CLR.com



Continental Resources, Inc. 
Consolidated Statements of Income 
                       (Unaudited)
                       Three months ended December  Year ended December 31,
                       31,
                       2013           2012          2013         2012
Revenues:              In thousands, except per share data
Crude oil and        $ 912,286        $  670,438    $ 3,606,774  $ 2,379,433
natural gas sales
Gain (loss) on
derivative             (102,202)         9,639        (191,751)    154,016
instruments, net
Crude oil and
natural gas service    10,250            8,895        40,127       39,071
operations
Total revenues         820,334           688,972      3,455,150    2,572,520
Operating costs and
expenses:
Production expenses    79,892            57,399       282,197      195,440
Production taxes and   84,183            65,558       332,130      228,438
other expenses
Exploration expenses   5,809             5,755        34,947       23,507
Crude oil and
natural gas service    7,097             7,525        29,665       32,248
operations
Depreciation,
depletion,             270,456           192,271      965,645      692,118
amortization and
accretion
Property impairments   58,548            29,121       220,508      122,274
General and
administrative         40,619            35,031       144,379      121,735
expenses
Gain (loss) on sale    24                (68,908)     (88)         (136,047)
of assets, net
Total operating        546,628           323,752      2,009,383    1,279,713
costs and expenses
Income from            273,706           365,220      1,445,767    1,292,807
operations
Other income
(expense):
Interest expense       (63,666)          (45,534)     (235,275)    (140,708)
Other                 792               817          2,557        3,097
                       (62,874)          (44,717)     (232,718)    (137,611)
Income before income   210,832           320,503      1,213,049    1,155,196
taxes
Provision for income   78,008            99,992       448,830      415,811
taxes
Net income           $ 132,824        $  220,511    $ 764,219    $ 739,385
Basic net income per $ 0.72           $  1.20       $ 4.15       $ 4.08
share
Diluted net income   $ 0.72           $  1.19       $ 4.13       $ 4.07
per share





Continental Resources, Inc. 
Consolidated Balance Sheets 
                                           December 31,  December 31,
                                           2013          2012
Assets                                     In thousands
Current assets                             $ 1,147,266   $  946,783
Net property and equipment ^(1)              10,721,272     8,105,269
Other noncurrent assets                      72,644         87,957
Total assets                               $ 11,941,182  $  9,140,009
Liabilities and shareholders' equity
Current liabilities                        $ 1,473,156   $  1,125,865
Long-term debt                               4,713,821      3,537,771
Other noncurrent liabilities                 1,801,087      1,312,674
Total shareholders' equity                   3,953,118      3,163,699
Total liabilities and shareholders' equity $ 11,941,182  $  9,140,009

    Balance is net of accumulated depreciation, depletion and amortization of
(1) $3.12 billion and $2.12 billion as of December 31, 2013 and 2012,
    respectively.

Continental Resources, Inc. 
Consolidated Statements of Cash Flows 
                     (Unaudited)
                     Three months ended December    Year ended December 31,
                     31,
In thousands         2013          2012           2013           2012
Net income          $  132,824    $ 220,511      $ 764,219      $ 739,385
Adjustments to
reconcile net
income to net cash
provided by
operating
activities:
Non-cash expenses       512,189      223,804        1,809,951      905,695
Changes in assets       (60,171)     39,853         (10,875)       (13,015)
and liabilities
Net cash provided
by operating            584,842      484,168        2,563,295      1,632,065
activities
Net cash used in
investing               (911,623)    (1,312,243)    (3,711,011)    (3,903,370)
activities
Net cash provided
by financing            263,756      604,359        1,140,469      2,253,490
activities
Net change in cash
and cash                (63,025)     (223,716)      (7,247)        (17,815)
equivalents
Cash and cash
equivalents at          91,507       259,445        35,729         53,544
beginning of period
Cash and cash
equivalents at end   $  28,482     $ 35,729       $ 28,482       $ 35,729
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.

                         Three months ended December  Year ended December 31,
                         31,
In thousands             2013            2012         2013         2012
Net income               $   132,824     $  220,511   $ 764,219    $ 739,385
Interest expense             63,666         45,534      235,275      140,708
Provision for income         78,008         99,992      448,830      415,811
taxes
Depreciation,
depletion, amortization      270,456        192,271     965,645      692,118
and accretion
Property impairments         58,548         29,121      220,508      122,274
Exploration expenses         5,809          5,755       34,947       23,507
Impact from derivative
instruments:
Total (gain) loss on         102,202        (9,639)     191,751      (154,016)
derivatives, net
Total cash (paid)
received on                  (9,644)        2,655       (61,555)     (45,721)
derivatives, net
Non-cash (gain) loss on      92,558         (6,984)     130,196      (199,737)
derivatives, net
Non-cash equity              10,431         8,252       39,890       29,057
compensation
EBITDAX                  $   712,300     $  594,452   $ 2,839,510  $ 1,963,123

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

                     Three months ended December 31,  Year ended December 31,
In thousands         2013             2012            2013         2012
Net cash provided
by operating         $   584,842      $   484,168     $ 2,563,295  $ 1,632,065
activities
Current income tax       (4,014)          18,241        6,209        10,517
provision (benefit)
Interest expense         63,666           45,534        235,275      140,708
Exploration
expenses, excluding      5,639            5,307         25,597       22,740
dry hole costs
Gain (loss) on sale      (24)             68,908        88           136,047
of assets, net
Excess tax benefit
from stock-based         -                15,618        -            15,618
compensation
Other, net               2,020            (3,471)       (1,829)      (7,587)
Changes in assets        60,171           (39,853)      10,875       13,015
and liabilities
EBITDAX              $   712,300      $   594,452     $ 2,839,510  $ 1,963,123

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.

                            Three Months Ended December 31,
                            2013                        2012
In thousands, except per    After-Tax $  Diluted EPS    After-Tax $  Diluted
share data                                                           EPS
Net income (GAAP)           $ 132,824    $          $ 220,511    $    
                                         0.72                        1.19
Adjustments, net of tax:
 Non-cash (gain) loss on    58,312       0.31           (4,331)      (0.02)
 derivatives, net
 Property impairments       36,885       0.20           18,054       0.10
 (Gain) loss on sale of     15           -              (42,723)     (0.23)
 assets, net
 Corporate relocation       96           -              290          -
 expenses
  Adjusted net income       $ 228,132    $          $ 191,801    $    
  (Non-GAAP)                             1.23                        1.04
  Weighted average diluted  185,007                     184,603
  shares outstanding
  Adjusted diluted net      $                        $   
  income per share          1.23                        1.04
  (Non-GAAP)
                            Year Ended December 31,
                            2013                        2012
In thousands, except per    After-Tax $  Diluted EPS    After-Tax $  Diluted
share data                                                           EPS
Net income (GAAP)           $ 764,219    $          $ 739,385    $    
                                         4.13                        4.07
Adjustments, net of tax:
 Non-cash (gain) loss on    82,023       0.44           (123,838)    (0.68)
 derivatives, net
 Property impairments       138,920      0.75           75,810       0.41
 (Gain) loss on sale of     (55)         -              (84,349)     (0.46)
 assets, net
 Corporate relocation       1,018        0.01           4,862        0.02
 expenses
  Adjusted net income       $ 986,125    $          $ 611,870    $    
  (Non-GAAP)                             5.33                        3.36
  Weighted average diluted  184,849                     181,846
  shares outstanding
  Adjusted diluted net      $                        $   
  income per share          5.33                        3.36
  (Non-GAAP)



Continental Resources, Inc.
2014 Guidance Outlook
As of February 26, 2014*
                                                        2014
Production growth (YOY)                                 26% to 32%
Capital expenditures (non-acquisition)                  $4.05B
Operating Expenses:
 Production expense per Boe                         $5.60 to $6.10
 Production tax (% of oil & gas revenue)            8% to 9%
 DD&A per Boe                                       $17.50 to $19.50
 G&A expense per Boe                                $2.00 to $2.50
 Non-cash equity compensation per Boe               $0.70 to $0.90
Average Price Differentials:
 NYMEX WTI crude oil (per barrel of oil)            ($8.00) to ($11.00)
 Henry Hub natural gas (per Mcf)                    +$1.00 to $1.50
Income tax rate                                         37%
Deferred taxes                                          90% to 95%
* No change from previously announced 2014 Guidance Outlook on September
10, 2013

SOURCE Continental Resources

Website: http://www.clr.com
 
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