Continental Resources Reports First Quarter 2013 Results

           Continental Resources Reports First Quarter 2013 Results

Record Production Totaling 121,500 Boe per Day for First Quarter 2013, an
Increase of 14% Sequentially and 42% Compared to First Quarter 2012

Company Reports Adjusted Net Income for First Quarter 2013 of $215 Million, or
$1.17 per Diluted Share; Record EBITDAX of $622 Million, an Increase of 5%
Compared to Fourth Quarter 2012 and 37% Compared to First Quarter 2012

Three Recent Successful Lower Three Forks Completions Announced; SCOOP
Production Doubles Quarter over Quarter on Strong Wells

PR Newswire

OKLAHOMA CITY, May 8, 2013

OKLAHOMA CITY, May 8, 2013 /PRNewswire/ -- Continental Resources, Inc. (NYSE:
CLR) ("Continental" or the "Company") announced first quarter 2013 operating
and financial results, reporting net income of $141 million, or $0.76 per
diluted share. Adjusted net income, which excludes items typically excluded
from published analyst estimates, totaled $215 million, or $1.17 per diluted
share. EBITDAX reached a record level of $622 million, an increase of $27
million or 5% compared to fourth quarter 2012. 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)

Significant first quarter 2013 operational highlights:

  oAchieved record net production of approximately 121,500 barrels oil
    equivalent ("Boe") per day in first quarter 2013, which includes 71% crude
    oil;
  oNet Bakken production increased to approximately 76,900 Boe per day for
    first quarter 2013, representing 63% of total production. Gross operated
    Bakken production surpassed a significant milestone, averaging more than
    100,000 Boe per day for first quarter 2013;
  oThree recent successful Lower Three Forks completions expand the potential
    aerial extent of productivity and are performing in-line with similar
    Middle Bakken and Upper Three Forks wells in the surrounding areas; 
  oAhead of plan to reduce operated Bakken averagewell costs to $8.2 million
    by year-end 2013, current operated well costs are approximately $8.3
    million; and
  oNet production from South Central Oklahoma Oil Province ("SCOOP") play
    increased to approximately 14,200 Boe per day, up 100% from fourth quarter
    2012 and up 462% from first quarter 2012.

"We are off to an excellent start in 2013 in executing our strategy of
profitably growing our world-class position in the Bakken, testing the lower
benches and downspacing capability, and also delineating our exciting new
play, SCOOP," said Harold G. Hamm, Continental's Chairman and Chief Executive
Officer. "Our focus on driving well costs lower has been successful due to
enhanced utilization of pad drilling, improved cycle times and supply chain
efforts. We intend to maintain our capital spending discipline this year, as
evident in our first quarter results."

Production, Realizations and Expenses

First quarter 2013 net production totaled 10.9 million Boe, or approximately
121,500 Boe per day, a sequential increase of 14% from fourth quarter 2012.
Total production included approximately 86,100 barrels of oil per day (71% of
production) and approximately 212.8 million cubic feet of natural gas per day
(29% of production). While the Company currently sells 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 Company's combined natural gas liquids and oil would account
for approximately 80% of total production.

Continental's average realized sales price excluding the effects of derivative
positions was $89.99 per barrel of oil and $4.99 per thousand cubic feet
("Mcf") of natural gas, or $72.31 per Boe. Realized settlements of
commodityderivative positions generated a $1.24 loss per barrel of oil and
$0.14 gain per Mcf of natural gas resulting in a net realized hedging loss of
$6.8 million, or $0.63 per Boe for the first quarter 2013.

Based on realizations without the effect of derivatives, the Company's first
quarter 2013 oil differential, as compared to the NYMEX daily average for the
period, was a negative $4.29 per barrel, favorable to annual guidance of
negative $5.00 to $7.00 per barrel. The natural gas differential for first
quarter 2013 was a positive $1.65 per Mcf of natural gas, favorable to annual
guidance range of positive $1.00 to $1.50 per Mcf.

Production expense per Boe was $5.70 for first quarter 2013, sequentially
below $5.90 per Boe from fourth quarter 2012, but above annual guidance range
of $5.20 to $5.60 per Boe, due to typical winter weather temporarily impacting
production costs in certain areas. The Company expects per unit production
expense to decrease throughout a majority of the remainder of the year. Other
select operating costs and expenses for first quarter 2013 were as follows:
production taxes 8.2% of oil and natural gas sales; DD&A $19.72 per Boe and
G&A (cash and non-cash, excluding relocation expenses) $3.05 per Boe, all
within the range of the Company's annual guidance. The Company's 2013
guidance can be found on the last page of this release and remains unchanged
from previous guidance provided on February 27, 2013. 

W. F. "Rick" Bott, Continental's President and Chief Operating Officer, added,
"Our production growth remained strong despite seasonal challenges in the
Bakken. Our realizations remain on track, driving an impressive 74% cash
margin, which benefited from 80% of our operated Bakken production being
transported by rail as we continue to access markets on all US coasts. We
continue to monitor oil differentials and transportation costs to ensure we
realize the most attractive pricing for our premium Bakken oil."

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

                     1Q       4Q       1Q
Boe per day          2013     2012     2012
North Region:
North Dakota Bakken  67,575   59,019   41,895
Montana Bakken       9,352    8,503    6,129
Red River Units      15,055   14,716   15,415
Other                1,267    967      1,445
South Region:
SCOOP                14,243   7,123    2,533
NW Cana              8,323    9,716    10,293
Arkoma               3,234    3,225    3,637
Other                2,483    2,556    2,988
East Region          -        1,006    1,191
Total                121,532  106,831  85,526

The following table provides 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 are calculated using sales
volumes.

                                                  1Q        4Q        1Q
                                                  2013      2012      2012
Average daily production:
Crude oil (Bbl per day)                           86,071    76,449    59,901
Natural gas (Mcf per day)                         212,766   182,289   153,751
Crude oil equivalents (Boe per day)               121,532   106,831   85,526
Average sales prices, excluding effect from
derivatives:
Crude oil ($/Bbl)                                 $89.99    $84.99    $90.58
Natural gas ($/Mcf)                               $4.99     $4.82     $4.48
Crude oil equivalents ($/Boe)                     $72.31    $68.89    $71.39
Production expenses ($/Boe)                       $5.70     $5.90     $5.18
Production taxes (% of oil and gas revenues)      8.2%      8.3%      8.1%
DD&A ($/Boe)                                      $19.72    $19.76    $19.32
General and administrative expenses ($/Boe) ^(1)  $2.20     $2.70     $2.29
Non-cash equity compensation ($/Boe)              $0.85     $0.85     $0.71
Net income (in thousands)                        $140,627  $220,511  $69,094
Diluted net income per share                      $0.76     $1.19     $0.38
Adjusted net income (in thousands) ^(2)          $215,386  $191,801  $137,900
Adjusted diluted net income per share ^(2)       $1.17     $1.04     $0.76
EBITDAX (in thousands) ^(2)                      $621,528  $594,452  $454,532

    General and administrative expenses exclude non-recurring corporate
(1) relocation expenses of $0.7 million ($0.06 per Boe) for first quarter
    2013, $0.5 million ($0.05 per Boe) for fourth quarter 2012 and $1.7
    million ($0.23 per Boe) for first quarter 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.

Financial Update 

At March 31, 2013, Continental's balance sheet included approximately $59
million in cash and cash equivalents and approximately $4.0 billion in total
debt, which included approximately $1.0 billion borrowed under the Company's
revolving credit facility. On April 5, 2013, Continental completed a $1.5
billion, 4½ % senior unsecured notes offering, which matures in 2023.
Proceeds from the offering were applied to fully repay borrowings under the
credit facility and for future development and exploratory drilling. 

Non-acquisition capital expenditures for first quarter 2013 totaled
approximately $899 million, including $792 million in exploration and
development drilling, $84 million in leasehold and seismic and $23 million in
workovers, recompletions and other. Acquisition capital expenditures totaled
approximately $22 million for first quarter 2013, and are excluded from the
Company's capital expenditure guidance for 2013 of $3.6 billion. 

John D. Hart, Continental's Chief Financial Officer, added, "Our recent notes
offering was highly successful, and our focus on cost reduction and efficiency
gains is on schedule to keep us in-line with our capital expenditure guidance.
Our significant production growth and consistent top-tier cash margins per
Boe allow us to self-fund a larger portion of our planned activity."

Strong Bakken Production Growth

Net production from the Company's activity in the Bakken play in North Dakota
and Montana increased to approximately 76,900 Boe per day in first quarter
2013, an increase of 14% sequentially and 60% above first quarter 2012. The
Company's gross operated average production in first quarter 2013in the
Bakken reached a milestone of more than 100,000 Boe per day. Continental
operated 22 rigs across its industry-leading leasehold position of
approximately 1.2 million net acres in the Bakken play. The Company
participated in completing 66 net (162 gross) wells in first quarter 2013,
which included 21 gross wells deferred from fourth quarter 2012. The
Company's Bakken backlog of gross wells drilled, but not yet completed, is
currently 80 gross wells, which is down from fourth quarter 2012, however is
expected to grow at various times of the year due to increased utilization of
pad drilling.

Development drilling and completion activity for first quarter 2013 continued
to meet expectations. In North Dakota, Company-operated wells completed during
first quarter 2013 averaged an initial one-day test of 1,125 Boe per day,
which included 84% oil. Company-operated Montana wells completed during first
quarter 2013 averaged an initial one-day test of 670 Boe per day, which
included 87% oil. These results are consistent with the Company's estimated
ultimate recovery ("EUR") models of 603,000 Boe for North Dakota wells and
430,000 Boe for Montana wells.

Continental continues to make progress on its 22-well Lower Three Forks
exploratory program, which is testing the productive extent of the lower
benches. Initial 24-hour flow rates from Lower Three Forks tests for first
quarter 2013 included the Barney 2-29H-2 well, which is a second-bench test
and had an initial flow rate of 1,075 Boe per day. The well is located 16
miles north of the Company's Charlotte pad. At the Company-operated Stedman
pad, located on the western flank of the play near the North Dakota and
Montana border and 35 miles northwest of the Charlotte pad, the Stedman
2-24H-2 well, a second-bench test flowed at an initial rate of 1,030 Boe per
day. Additionally, the Stedman 3-24H-3 well, a third-bench test had initial
one-day production of 465 Boe.

Inclusive of these wells, the Company currently has six producing wells in the
lower benches with average initial production rates of approximately 1,170 Boe
per day. On average, these six wells are performing in-line with typical
Middle Bakken and Three Forks first-bench wells in their respective areas.

The following table summarizes the Company's Lower Three Forks activity:

Lower Three Forks Exploration Well Status
Zone      Drilling     Completing     Producing     To Be Drilled     Total
TF1                    1                            3                 4
TF2       2            1              4             4                 11
TF3                    3              2                               5
TF4                    2                                              2
Total     2            7              6             7                 22
Data in table includes two wells drilled in 2012 and 20 wells drilled or
planned in 2013

Cumulative approximate production from the Company's initial lower bench tests
include 116,000 Boe from the Charlotte 2-22H well, a second-bench test of 18
months; 55,000 Boe from the Charlotte 3-22H well, a third-bench test of 5.5
months; and 53,000 Boe from the Angus 2-9H-2 well, a second-bench test of 2
months.

The Company's other Bakken exploration and appraisal initiative involves four
pilot density projects to test 320-acre and 160-acre spacing in the Middle
Bakken and first three benches of the Three Forks. The Company plans to
complete 47 gross wells in the pilot density program, to help determine the
optimum well spacing and pattern to maximize the ultimate recovery from the
multiple Bakken and Three Forks reservoirs.

Continental has drilled eight wells and is currently drilling the ninth on its
first 320-acre pilot density project at the Hawkinson pad in Dunn County.
Drilling is under way on the 13-well, 160-acre pilot on the Wahpeton pad in
McKenzie County and the 12-well, 320-acre pilot on the Tangsrud pad in Divide
County. One additional 320-acre pilot at the Rollefstad pad is scheduled to
spud in the second half of 2013. In summary, of the 47-well pilot density
program, 10 wells are currently in the drilling stage, 10 wells are waiting on
completion and 27 wells have yet to be drilled. Once each pad has reached
initial production, the wells will be announced together as part of the
quarterly results.

The Company plans to complete 245 net (790 gross) wells in the Bakken in 2013,
including both operated and non-operated wells. Due to efficiency gains, the
Company plans to reduce operated rig activity to an average of 20 rigs through
the balance of the year, whichshould deliver the planned production growth
and keep within capital expenditure guidance.

Mr. Bott added, "Quarter after quarter, our Bakken operations continue to
deliver impressive growth with highly attractive returns. On the exploration
front, we are very excited about the continual success of our Lower Three
Forks productivity tests. Our cost focus has put us ahead of target on
reducing average drilling and completion well costs in the Bakken. Based on
field estimates, we are down to approximately $8.3 million in April 2013." 

SCOOP Results

Continental has approximately 232,000 net acres of leasehold in the SCOOP
play, which stretches from Grady County to the southeast to Love County. In
first quarter 2013, SCOOP net production averaged approximately 14,200 Boe per
day, an increase of 100% sequentially and 462% above first quarter 2012. The
recent growth was driven by impressive initial production rates and increased
activity in the play, which included nine net (15 gross) additional operated
and non-operated wells in the play during the first quarter 2013. In the
condensate window, wells completed during first quarter 2013 averaged initial
one-day tests of 1,050 Boe per day, which included 24% oil. The company is
currently operating nine rigs in the play with plans to increase to 12.

Select Continental-operated wells completed in the condensate window in first
quarter 2013 include:

  oColbert 1-32H well produced 1,769 Boe per day (30% oil) in its initial
    one-day test period; and
  oKnox 1-1H well produced 1,151 Boe per day (26% oil) in its initial one-day
    test period.

The Company plans to complete 55 net (115 gross) wells in the SCOOP play in
2013, including both operated and non-operated wells.

Richard E. Muncrief, Continental's Senior Vice President of Operations,
stated, "We are extremely excited about the doubling of our SCOOP production
in one quarter. It is a huge credit to our teams, who have ramped up to nine
rigs in a short period of time. We remain focused on delivering production
targets, but also reducing cycle times and well costs, which is essential in
order to compete for capital with our highly profitable Bakken activity."


Conference Call Information

Continental Resources plans to host a conference call to discuss first quarter
2013 results on Thursday, May, 9, 2013 at 10 a.m. ET (9 a.m. CT). Those
wishing to listen to the conference call may do so via the Company's web site
at www.CLR.com or by phone:

Time and date: 10 a.m. ET, Thursday, May 9, 2013
Dial in:         888 680 0892
Intl. dial in:   617 213 4858
Pass code:       62640885

A replay of the call will be available for 30 days on the Company's web site
or by dialing:

Replay number:             888 286 8010
Intl. replay 617 801 6888
Pass code:        82241170

Callers who wish to pre-register for the call may go to:

https://www.theconferencingservice.com/prereg/key.process?key=PL6YUULQB

Upcoming Company Presentations

Continental management is currently scheduled to present at the following
investment conferences. Presentation materials will be available on the
Company's website, www.CLR.com,the day of the event.

May 13      FBR Energy & Industrials Conference, Boston;
May 14   Bank of America Merrill Lynch Global Energy and Power
                Leveraged Finance Conference, New York City;
May 16     Barrington Research Industrial & Business Services Conference,
                Chicago;
May 21   UBS Oil and Gas Conference, Austin;
June 11  Williams Financial Group First Annual Energy Conference,
                Dallas; and
June 25 Global Hunter Securities 100 Energy Conference, Chicago.

The Company's presentations at the conferences on May 21 and June 25 will be
available via webcast. Instructions regarding how to access such webcasts
will be available on the Company's web site at www.CLR.com on or prior to the
day of the presentations. Such webcasts will be available for 30 days on the
Company's web site.

About Continental Resources

Continental Resources, Inc. (NYSE: CLR), based in Oklahoma City, is focused on
the exploration and production of onshore oil-prone plays and is a Top 10
independent oil producer in the United States. The Company has a long and
successful history of developing its industry-leading leasehold and production
in the nation's premier oil play, the Bakken of North Dakota and Montana, as
well as significant positions in Oklahoma in its recently discovered SCOOP
play and the Northwest Cana play. In 2013, the Company will celebrate 46
years of operation. Further information can be found at 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 March 31,
                                           2013                  2012
Revenues:                                  In thousands, except per share data
Crude oil and natural gas sales            $      783,517        $  552,258
Loss on derivative instruments, net               (84,831)          (169,057)
Crude oil and natural gas service                 11,543            11,899
operations
Total revenues                                    710,229           395,100
Operating costs and expenses:
Production expenses                               61,803            40,075
Production taxes and other expenses               72,429            50,740
Exploration expenses                              9,814             4,151
Crude oil and natural gas service                 8,597             9,842
operations
Depreciation, depletion, amortization and         213,678           149,455
accretion
Property impairments                              40,081            29,907
General and administrative expenses              33,817            24,966
Gain on sale of assets, net                       (136)             (49,627)
Total operating costs and expenses                440,083           259,509
Income from operations                            270,146           135,591
Other income (expense):
Interest expense                                  (47,475)          (24,278)
Other                                            546               781
                                                  (46,929)          (23,497)
Income before income taxes                        223,217           112,094
Provision for income taxes                        82,590            43,000
Net income                                 $      140,627        $  69,094
Basic net income per share                 $      0.76           $  0.38
Diluted net income per share               $      0.76           $  0.38

Continental Resources, Inc.
Unaudited Condensed Consolidated Balance Sheets
                                           March 31,    December 31,
                                           2013         2012
Assets                                     In thousands
Current assets                             $ 1,080,592  $  946,783
Net property and equipment                   8,764,624     8,105,269
Other noncurrent assets                      86,960        87,957
Total assets                               $ 9,932,176  $  9,140,009
Liabilities and shareholders' equity
Current liabilities                        $ 1,217,058  $  1,125,865
Long-term debt                               3,976,801     3,537,771
Other noncurrent liabilities                 1,426,237     1,312,674
Total shareholders' equity                   3,312,080     3,163,699
Total liabilities and shareholders' equity $ 9,932,176  $  9,140,009



Continental Resources, Inc.
Unaudited Condensed Consolidated Statements of Cash Flows
                                                 Three months ended March 31,
                                                 2013            2012
                                                 In thousands
Net income                                      $  140,627      $  69,094
Adjustments to reconcile net income to net cash
provided by operating activities:
Non-cash expenses                                   428,913         306,966
Changes in assets and liabilities                   (111,429)       (11,116)
Net cash provided by operating activities           458,111         364,944
Net cash used in investing activities               (873,153)       (995,115)
Net cash provided by financing activities           437,859         619,310
Net change in cash and cash equivalents             22,817          (10,861)
Cash and cash equivalents at beginning of period    35,729          53,544
Cash and cash equivalents at end of period       $  58,546       $  42,683

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.

                                                1Q 2013    4Q 2012    1Q 2012
                                              in thousands
 Net income                                   $ 140,627  $ 220,511  $ 69,094
 Interest expense                               47,475     45,534     24,278
 Provision for income taxes                     82,590     99,992     43,000
 Depreciation, depletion, amortization and      213,678    192,271    149,455
 accretion
 Property impairments                           40,081     29,121     29,907
 Exploration expenses                           9,814      5,755      4,151
 Impact from derivative instruments:
 Total (gain) loss on derivatives, net          84,831     (9,639)    169,057
 Total realized gain (loss) (cash flow) on      (6,810)    2,655      (39,925)
 derivatives, net
 Non-cash (gain) loss on derivatives, net       78,021     (6,984)    129,132
 Non-cash equity compensation                   9,242      8,252      5,515
 EBITDAX                                      $ 621,528  $ 594,452  $ 454,532



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

                                                  1Q 2013    1Q 2012
                                                in thousands
 Net cash provided by operating activities      $ 458,111  $ 364,944
 Current income tax provision                     -          2,150
 Interest expense                                 47,475     24,278
 Exploration expenses, excluding dry hole costs   7,553      4,063
 Gain on sale of assets, net                      136        49,627
 Other, net                                       (3,176)    (1,646)
 Changes in assets and liabilities                111,429    11,116
 EBITDAX                                        $ 621,528  $ 454,532



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.

                    1Q 2013             4Q 2012             1Q 2012
In thousands,       After-Tax  Diluted  After-Tax  Diluted  After-Tax  Diluted
except per share    $          EPS      $          EPS      $          EPS
data
Net income (GAAP)   $ 140,627  $     $ 220,511  $     $ 69,094  $   
                               0.76               1.19               0.38
Adjustments, net
of tax:
 Non-cash (gain)
 loss on            49,153     0.27     (4,331)    (0.02)   79,933     0.44
 derivatives, net
 Property           25,251     0.14     18,054     0.10     18,512     0.10
 impairments
 Gain on sale of    (86)       -        (42,723)   (0.23)   (30,719)   (0.17)
 assets, net
 Corporate
 relocation         441        -        290        -        1,080      0.01
 expenses
  Adjusted net                 $                $                $   
  income            $ 215,386  1.17    $ 191,801  1.04    $ 137,900  0.76
  (Non-GAAP)
  Weighted average
  diluted shares    184,656             184,603             180,283
  outstanding
  Adjusted diluted  $                 $                 $  
  net income per    1.17               1.04               0.76
  share (Non-GAAP)

Continental Resources, Inc.
2013 Guidance Outlook
As of May 8, 2013
Production growth                                35% to 40%
Capital expenditures ^(1)                        $3.6 billion
Price differentials:
 WTI crude oil (per barrel of oil)           ($5.00) to ($7.00)
 Henry Hub natural gas (per Mcf)             +$1.00 to +$1.50
Operating expenses:
 Production expense per Boe                  $5.20 to $5.60
 Production tax (% of oil and gas revenues)  8% to 9%
 DD&A per Boe                                $19.00 to $21.00
 G&A expense per Boe                         $2.20 to $2.70
 Non-cash equity compensation per Boe        $0.70 to $0.90
Income tax rate                                  37%
Deferred taxes                                   90% to 95%

(1) Excludes acquisition capital expenditures.

SOURCE Continental Resources

Website: http://www.CLR.com
 
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