Continental Resources Reports Second Quarter 2013 Results

          Continental Resources Reports Second Quarter 2013 Results

Record Production Totaling 135,700 Boe per Day for Second Quarter 2013, an
Increase of 12% Sequentially and 43% Compared to Second Quarter 2012

Adjusted Net Income for Second Quarter 2013 of $246 Million, or $1.33 per
Diluted Share; Record EBITDAX of $708 Million, an Increase of 14% Compared to
First Quarter 2013 and 68% Compared to Second Quarter 2012

Mid-Year 2013 Proved Reserves Total 922 Million Boe, an Increase of 17% from
Year-End 2012

Lower Three Forks Activity Delineates Productive Footprint of 3,800 Square
Miles in Bakken

2013 Production Growth Target Range Tightened Upward to 38% to 40%; Bakken
Operated Well Cost Target Lowered to $8.0 Million by Year-End 2013

PR Newswire

OKLAHOMA CITY, Aug. 7, 2013

OKLAHOMA CITY, Aug. 7, 2013 /PRNewswire/ -- Continental Resources, Inc. (NYSE:
CLR) ("Continental" or the "Company") announced second quarter 2013 operating
and financial results, reporting net income of $323 million, or $1.75 per
diluted share. Adjusted net income, which excludes items typically excluded
from published analyst estimates, totaled $246 million, or $1.33 per diluted
share. The Company achieved record EBITDAX of $708 million, an increase of
$87 million or 14% compared to first 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. 


Significant second quarter 2013 operational highlights include:

  oRecord net production of approximately 135,700 barrels of oil equivalent
    ("Boe") per day in second quarter 2013, of which 71% is crude oil;
  oNet Bakken production increased to approximately 88,000 Boe per day for
    second quarter 2013, representing 65% of total production;
  oRecent lower Three Forks completions further delineate the productive
    footprint across 3,800 square miles in the Bakken; and 
  oNet production from South Central Oklahoma Oil Province ("SCOOP") play
    increased to approximately 17,550 Boe per day, up 23% from first quarter

"Continental continues to deliver exceptional oil growth while maintaining
capital discipline," said Harold G. Hamm, Continental's Chairman and Chief
Executive Officer. "We are extremely pleased with our progress to date on
productivity and interference testing in the lower Three Forks benches across
a large area. Our industry-leading approach to scientifically understanding
the field will allow us to optimize the development of America's greatest oil
play – the Bakken. At the same time, our SCOOP play is having tremendous
success in growth and delineation."

Production, Realizations and Expenses

Second quarter 2013 net production totaled 12.3 million Boe, or approximately
135,700 Boe per day, a sequential increase of 12% from first quarter 2013.
Total net production included approximately 96,000 barrels of oil per day (71%
of production) and approximately 238 million cubic feet of natural gas per day
(29% of production). 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 combined natural gas liquids and oil would account for more
than 80% of total production. Current production is estimated at
approximately 140,000 Boe per day.

Continental's average realized sales price excluding the effects of derivative
positions was $87.22 per barrel of oil and $5.22 per thousand cubic feet
("Mcf") of natural gas, or $71.13 per Boe for second quarter 2013. Realized
settlements of commodity derivative positions generated a $0.26 gain per
barrel of oil and $0.33 loss per Mcf of natural gas resulting in a net
realized hedging loss of $4.8 million, or $0.38 per Boe for the second quarter
2013. Based on realizations without the effect of derivatives, the Company's
second quarter 2013 oil differential was $7.07 per barrel below the NYMEX WTI
daily average for the period. The realized natural gas price differential for
second quarter 2013 was a positive $1.13 to Henry Hub.

Production expense per Boe was $5.86 for second quarter 2013, above the
Company's expectations due to adverse weather conditions, which temporarily
impacted production costs in certain areas. Other select operating costs and
expenses for second quarter 2013 included production taxes of 8.3% of oil and
natural gas sales; DD&A of $18.88 per Boe and G&A (cash and non-cash,
excluding relocation expenses) of $2.81 per Boe, all within or better than the
range of the Company's annual guidance. The Company's 2013 guidance can be
found on the last page of this release.

W. F. "Rick" Bott, Continental's President and Chief Operating Officer, added,
"Given our solid execution and performance in the first half of the year, we
are tightening our annual production growth guidance range upward from 35% to
40%, to 38% to 40%, while maintaining our original $3.6 billion
non-acquisition capital expenditure budget. Our focus and capital discipline,
as well as continued strong commodity prices, have put us in a position for a
strong finish to 2013, which underscores our confidence in achieving our
5-year growth targets."

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

                      2Q       1Q       2Q
 Boe per day          2013     2013     2012
 North Region:
 North Dakota Bakken  76,909   67,575   47,166
 Montana Bakken       11,081   9,352    6,305
 Red River Units     14,886   15,055   15,482
 Other                2,141    1,267    1,445
 South Region:
 SCOOP                17,547   14,243   3,282
 NW Cana              7,763    8,323    13,390
 Arkoma               3,064    3,234    3,806
 Other               2,309    2,483    2,912
 East Region          -        -        1,064
 Total                135,700  121,532  94,852

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.

                                                  2Q        1Q        2Q
                                                  2013      2013      2012
 Average daily production:
 Crude oil (Bbl per day)                          96,029    86,071    65,274
 Natural gas (Mcf per day)                        238,028   212,766   177,471
 Crude oil equivalents (Boe per day)              135,700   121,532   94,852
 Average sales prices, excluding effect from
 Crude oil ($/Bbl)                                $87.22    $89.99    $80.56
 Natural gas ($/Mcf)                              $5.22     $4.99     $3.51
 Crude oil equivalents ($/Boe)                    $71.13    $72.31    $61.69
 Production expenses ($/Boe)                      $5.86     $5.70     $5.16
 Production taxes (% of oil and gas revenues)     8.3%      8.2%      8.1%
 DD&A ($/Boe)                                     $18.88    $19.72    $18.98
 General and administrative expenses ($/Boe) ^(1) $2.03     $2.20     $2.20
 Non-cash equity compensation ($/Boe)             $0.78     $0.85     $0.92
 Net income (in thousands)                       $323,270  $140,627  $405,684
 Diluted net income per share                     $1.75     $0.76     $2.25
 Adjusted net income (in thousands) ^(2)         $245,728  $215,386  $122,816
 Adjusted diluted net income per share ^(2)      $1.33     $1.17     $0.68
 EBITDAX (in thousands) ^(2)                     $708,107  $621,528  $421,860

    General and administrative expenses ($/Boe) exclude non-recurring
(1) corporate relocation expenses of $0.7 million ($0.05 per Boe) for second
    quarter 2013, $0.7 million ($0.06 per Boe) for first quarter 2013, and
    $3.3 million ($0.39 per Boe) for second 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.

Mid-Year 2013 Proved Reserves Update

Proved reserves increased to 922 million Boe as of June 30, 2013, based on
internal estimates, an increase of 17% from year-end 2012. The Company's
proved reserve PV10 value increased by approximately $3 billion to $16.2
billion. Continental operates 87% of its proved reserves, and 70% are crude

Strong Bakken Production Growth

Net production from the Company's industry-leading activity in the Bakken play
in North Dakota and Montana increased to approximately 88,000 Boe per day in
second quarter 2013, an increase of 14% sequentially and 65% above second
quarter 2012. The Company's gross operated Bakken production averaged 112,000
Boe per day in second quarter 2013. Continental operated 20 rigs across its
leasehold position of approximately 1.2 million net acres in the Bakken play.
The Company is able to operate fewer rigs while achieving the upper end of
its production guidance due to the realization of meaningful drilling
efficiency gains. 

The Company participated in completing 73 net (180 gross) wells in second
quarter 2013. The Company's Bakken backlog of gross operated wells drilled,
but not yet completed, is currently 75 wells.

Development drilling and completion activity for second quarter 2013 continued
to meet expectations. In North Dakota, Company-operated wells completed during
second quarter 2013 averaged an initial one-day test of 1,150 Boe per day,
which included 84% oil. Company-operated Montana wells completed during
second quarter 2013 averaged an initial one-day test of 455 Boe per day, which
included 94% 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.

The Company has experienced continual success driving operated drilling and
completion costs lower in the Bakken. These savings have a direct impact on
overall returns on development and exploratory efforts. For example,
comparing second quarter 2013 with second quarter 2012, Continental's drilling
cycle time of well spud to total depth has improved by approximately 20%, a
reduction of 4 days; time spent drilling the lateral section of the well has
improved by nearly 30%, a reduction of more than 2.5 days; and time and cost
of rig moves is down substantially as the Company's activity on multiple well
drilling pads has increased. Currently, 70% of the Company's drilling rig
activity in the Bakken is on multiple well pads. 

Richard E. Muncrief, Continental's Senior Vice President of Operations,
stated, "We are very proud of our industry-leading efficiency performance in
the Bakken. Our consistent goal is to be the premier operator in the play.
Our combination of focus, strong working relationships with service providers,
commitment to safety and continual process improvements have driven these
results. Our initial target was to lower our operated well cost by $1 million
per well by year-end 2013 to $8.2 million and now we think we can get to $8.0
million or lower per operated well."

Lower Three Forks Activity

Continental's 2013 Lower Three Forks (LTF) exploration program is on target to
complete 20 new wells by year-end to establish productive capacity in all LTF
intervals, identify unique reserves and de-risk a broad area where the company
has existing leasehold. To date, the Company has completed 14 LTF wells,
which include one Three Forks first bench (TF1) interference test well, six
Three Forks second bench (TF2) wells, five Three Forks third bench (TF3) wells
and two Three Forks fourth bench (TF4) wells. The TF2 and TF3 wells have
average 24-hour initial production rates of 1,200 Boe per day and 970 Boe per
day, respectively. The outline of these LTF producers defines a productive
area of approximately 3,800 square miles.

The following table summarizes the Company's LTF activity and indicates there
are eight more LTF wells planned by year-end 2013.

Lower Three Forks Exploration Well Status
Zone   Drilling Completing Producing To Be Drilled  Total
TF1             2          1         1              4
TF2    1        2          6         2              11
TF3                        5                        5
TF4                        2                        2
Total  1        4          14        3              22

Data in table includes two wells drilled in late 2011 and 2012 and 20 wells
drilled or planned in 2013

At this time, 85% of the LTF wells have less than 120 days of production, and
most have less than 90 days of production. The Company is monitoring early
production from the wellsclosely, and the data indicates the wells are
producing in line with typical TF1 producers in each area of the play.
Continental's longest producing LTF wells, the Charlotte 2-22H and 3-22H, have
produced a cumulative 123,000 Boe and 68,000 Boe, respectively, since initial
production began in late 2011 and late 2012. To date, Continental has not
seen evidence of production interference in its LTF exploration program,
except in the Colter spacing unit in Dunn County.

In the Colter unit, the Company observed direct evidence of production
interference between a Middle Bakken (MB) well, TF1 legacy well and two newly
completed LTF bench wells. The Company interprets natural vertical fracturing
has connected the MB and LTF reservoirs in this 1,280-acre spacing unit. This
area of the Nesson Anticline exhibits more pronounced faulting and natural
vertical fracturing associated with uplift. Continental observed some
pressure draw-down in its two new TF2 and TF4 completions, the Colter 3-14H-2
and 4-4H-4, and believes the reduced pressure relates to existing TF1 and MB
wells producing above them in the unit. These two legacy wells, located on the
east side of the Colter unit, commenced production in 2008 and 2011,
respectively, and have produced a cumulative 530,000 Boe. All four wells are
vertically aligned within a 660'-wide window. On the west side of the Colter
unit, Continental recently completed a fifth well, the Colter 5-14H-3. This
TF3 producer is flowing 1,750 Boe per day at 3,200 psi with no indication of
pressure draw-down.

Other LTF recent completions in second quarter 2013 include a TF2 producer,
the Charlotte 6-22H well, which had an initial test of 730 Boe per day; TF3
producers include the Barney 3-29H-3, which had an initial test of 1,190 Boe
per day, and the Rosenvold 3-30H-3, which had an initial test of520 Boe per
day. Continental completed the industry's first TF4 well in the Bakken, the
Farver 2-29H-4 well in Divide County, which was recently completed flowing 480
Boe per day. 

Bakken Downspacing Activity

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

Continental has drilled all of its planned 11 wells and completion activities
are under way on its first 320-acre pilot density project at the Hawkinson pad
in Dunn County. The Hawkinson project includes microseismic monitoring of
completions from multiple wellbores to help determine the most efficient
completion methods to maximize recoveries. This is likely to be the largest
microseismic program utilized to date worldwide. 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 project at the 11-well Rollefstad pad has spud its initial
well. In summary, of the 47-well pilot density program across four pads, 23
wells have been drilled and are waiting on completion. Once each pad has
reached initial production, the wells will be announced together as part of
the Company's quarterly results.

The Company plans to complete 245 net (790 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 the year,
which should deliver the planned production growth and stay within capital
expenditure guidance.

SCOOP Success Continues 

Continental continues to experience excellent repeatable results from its
drilling activity in the SCOOP. The play, discovered by Continental and
disclosed in October 2012, currently extends approximately 80 miles across
Grady, Stephens, McClain and Carter counties in Oklahoma and contains an oil
and condensate-rich window. To date, more than 90 gross wells in the area
have de-risked the productive footprint for more than 40 miles. Continental
is the largest producer, most active operator and largest leaseholder with
approximately 277,000 net acres in the play. In second quarter 2013, SCOOP
net production averaged approximately 17,550 Boe per day, an increase of 23%
sequentially and 435% above second quarter 2012. The recent growth was driven
by the addition of eight net (14 gross) operated and non-operated wells in the
play during the second quarter 2013.

In the condensate window, initial one-day tests averaged approximately 1,490
Boe per day, which included 29% oil for wells completed during second quarter
2013. Completed second quarter 2013 wells in the oil window averaged
approximately 1,460 Boe per day, which included 55% oil. Continental
completed its first cross-unit extended lateral at the Singer 1-18-7XH well in
Grady County to enhance productivity from one surface location. The well was
drilled to a total measured depth of 25,105 feet, with the lateral portion
9,377 feet. This extended lateral is an additional 4,877 feet longer than the
standard 4,500 feet of lateral with traditional 640-acre spacing. Initial
expectations for cross-unit wells could double production and proved reserves
with only an incremental increase of 55% to 60% in cost.

Select Continental-operated SCOOP wells completed in second quarter 2013

  oThe Vanarkel 1-15H well in Stephens County produced 2,045 Boe per day (44%
    oil) in its initial one-day test period;
  oThe Singer 1-18-7XH well in Grady County produced 1,915 Boe per day (37%
    oil) in its initial one-day test period; and
  oThe Dicksion 1-21H well in Grady County produced 1,590 Boe per day (45%
    oil) in its initial one-day test period.

The Company is currently operating 10 rigs in the play with plans to increase
to 12 by the end of third quarter 2013. The Company plans to complete a total
of 55 net (115 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.

Financial Update

As of June 30, 2013, Continental's balance sheet included approximately $220
million in cash and cash equivalents and an undrawn $1.5 billion revolving
credit facility. During second quarter 2013, the borrowing base was increased
to $4.25 billion, with commitments remaining unchanged at $1.5 billion.

Non-acquisition capital expenditures for second quarter 2013 totaled $897
million, including $793 million in exploration and development drilling, $78
million in leasehold and seismic and $26 million in workovers, recompletions
and other. Acquisition capital expenditures totaled approximately $101
million for second quarter 2013, and are excluded from the Company's capital
expenditure guidance for 2013 of $3.6 billion.

Conference Call Information and Summary Presentation

Continental Resources plans to host a conference call to discuss second
quarter 2013 results on Thursday, August 8, 2013 at 11 a.m. ET (10 a.m. CT)
and publish a second quarter 2013 summary presentation to its website prior to
the start of the conference call in order to be used as reference material.
Those wishing to listen to the conference call may do so via the Company's
website at or by phone:

Time and date:       11 a.m. ET, Thursday, August 8, 2013
Dial in:   888 713 4213
Intl. dial in:  617 213 4865
Pass code:       48272235

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:      80677475

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

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,, the day of the event.

August 13  EnerCom, Denver
August 27 Morgan Stanley Summer Energy Summit, Houston
September 12    Barclay's CEO Conference, New York City
September 24  Deutsche Bank Energy Conference, Boston

The Company's presentations at the conferences on August 13 and September 12
will be available via webcast. Instructions regarding how to access such
webcasts will be available on the Company's web site at 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 (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

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 
John J. Kilgallon
Director, Investor Relations

Continental Resources, Inc.
Unaudited Condensed Consolidated Statements of Income
                       Three months ended June 30,  Six months ended June 30,
                       2013            2012         2013          2012
Revenues:              In thousands, except per share data
Crude oil and natural  $    892,187    $ 523,393    $  1,675,704  $ 1,075,651
gas sales
Gain on derivative          199,056      471,728       114,225      302,671
instruments, net
Crude oil and natural       9,509        9,598         21,052       21,497
gas service operations
Total revenues              1,100,752    1,004,719     1,810,981    1,399,819
Operating costs and
Production expenses         73,452       43,756        135,255      83,831
Production taxes and        82,236       49,227        154,665      99,967
other expenses
Exploration expenses        11,151       8,702         20,965       12,853
Crude oil and natural       7,317        7,255         15,914       17,097
gas service operations
Depreciation, depletion,    236,790      161,018       450,468      310,473
amortization and accretion
Property impairments        79,712       35,871        119,793      65,778
General and
administrative              35,873       29,813        69,690       54,779
(Gain) loss on sale of      349          (17,397)      213          (67,024)
assets, net
Total operating costs       526,880      318,245       966,963      577,754
and expenses
Income from operations      573,872      686,474       844,018      822,065
Other income
Interest expense            (61,378)     (31,691)      (108,853)    (55,969)
Other                      634          789           1,180        1,570
                            (60,744)     (30,902)      (107,673)    (54,399)
Income before income        513,128      655,572       736,345      767,666
Provision for income        189,858      249,888       272,448      292,888
Net income             $    323,270    $ 405,684    $  463,897    $ 474,778
Basic net income per   $    1.76       $ 2.26       $  2.52       $ 2.64
Diluted net income per $    1.75       $ 2.25       $  2.51       $ 2.63

Continental Resources, Inc.
Unaudited Condensed Consolidated Balance Sheets
                                           June 30,      December 31,
                                           2013          2012
Assets                                     In thousands
Current assets                             $ 1,293,630   $  946,783
Net property and equipment                   9,440,216      8,105,269
Other noncurrent assets                      166,136        87,957
Total assets                               $ 10,899,982  $  9,140,009
Liabilities and shareholders' equity
Current liabilities                        $ 1,257,426   $  1,125,865
Long-term debt                               4,440,820      3,537,771
Other noncurrent liabilities                 1,558,396      1,312,674
Total shareholders' equity                   3,643,340      3,163,699
Total liabilities and shareholders' equity $ 10,899,982  $  9,140,009

Continental Resources, Inc.
Unaudited Condensed Consolidated Statements of Cash Flows
                                                  Six months ended June 30,
                                                  2013           2012
                                                  In thousands
Net income                                       $ 463,897      $ 474,778
Adjustments to reconcile net income to net cash
provided by operating activities:
Non-cash expenses                                   739,003        269,885
Changes in assets and liabilities                   (45,955)       26,167
Net cash provided by operating activities           1,156,945      770,830
Net cash used in investing activities               (1,850,177)    (1,773,492)
Net cash provided by financing activities           877,916        978,255
Net change in cash and cash equivalents             184,684        (24,407)
Cash and cash equivalents at beginning of period    35,729         53,544
Cash and cash equivalents at end of period        $ 220,413      $ 29,137

Non-GAAP Financial Measures


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

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.

                                             2Q 2013      1Q 2013    2Q 2012
                                           in thousands
 Net income                                $ 323,270    $ 140,627  $ 405,684
 Interest expense                            61,378       47,475     31,691
 Provision for income taxes                  189,858      82,590     249,888
 Depreciation, depletion, amortization and   236,790      213,678    161,018
 Property impairments                        79,712       40,081     35,871
 Exploration expenses                        11,151       9,814      8,702
 Impact from derivative instruments:
 Total (gain) loss on derivatives, net       (199,056)    84,831     (471,728)
 Total realized loss (cash flow) on          (4,752)      (6,810)    (7,056)
 derivatives, net
 Non-cash (gain) loss on derivatives, net    (203,808)    78,021     (478,784)
 Non-cash equity compensation                9,756        9,242      7,790
 EBITDAX                                   $ 708,107    $ 621,528  $ 421,860

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

                                                Six months ended June 30,
                                                   2013          2012
                                                in thousands
 Net cash provided by operating activities      $  1,156,945   $ 770,830
 Current income tax provision                      5,830         2,150
 Interest expense                                  108,853       55,969
 Exploration expenses, excluding dry hole costs    12,902        12,755
 Gain (loss) on sale of assets, net                (213)         67,024
 Other, net                                        (637)         (6,169)
 Changes in assets and liabilities                 45,955        (26,167)
 EBITDAX                                        $  1,329,635   $ 876,392

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.

                    2Q 2013             1Q 2013             2Q 2012
In thousands,       After-Tax  Diluted  After-Tax  Diluted  After-Tax  Diluted
except per share    $          EPS      $          EPS      $          EPS
Net income (GAAP)   $ 323,270  $     $ 140,627  $     $ 405,684  $   
                               1.75               0.76               2.25
Adjustments, net
of tax:
 Non-cash (gain)               $   
 loss on            (128,399)  (0.69)   49,153     0.27     (296,367)  (1.64)
 derivatives, net
 Property           50,219     $     25,251     0.14     22,204     0.12
 impairments                   0.27
 (Gain) loss on
 sale of assets,    220        -        (86)       -        (10,769)   (0.06)
 relocation         418        -        441        -        2,064      0.01
  Adjusted net                 $                $                $   
  income            $ 245,728  1.33    $ 215,386  1.17    $ 122,816  0.68
  Weighted average
  diluted shares    184,739             184,656             180,335
  Adjusted diluted  $                 $                 $  
  net income per    1.33               1.17               0.68
  share (Non-GAAP)

Continental Resources, Inc.
2013 Guidance Outlook
As of August 7, 2013(1)
Production growth                                38% to 40%
Capital expenditures ^(2)                        $3.6 billion
Price differentials:
 NYMEX 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) Changes to previous Outlook dated May 8, 2013 are presented in bold.
(2) Excludes acquisition capital expenditures.

SOURCE Continental Resources

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