Continental Resources Reports First Quarter 2014 Results

           Continental Resources Reports First Quarter 2014 Results

First Quarter 2014 Adjusted Net Income Totals $272 Million, or $1.47 per
Diluted Share; First Quarter 2014 EBITDAX of $775 Million

14-Well Hawkinson Density Test Production Performance Remains Strong After 150
Days on Production

Strong Early Performance at Rollefstad Density Pilot, Eight New Wells Have
Combined Initial Production of 22,460 Boe per Day

PR Newswire

OKLAHOMA CITY, May 7, 2014

OKLAHOMA CITY, May 7, 2014 /PRNewswire/ -- Continental Resources, Inc. (NYSE:
CLR) ("Continental" or the "Company") today announced first quarter 2014
operating and financial results. Net income for the quarter ended March 31,
2014 was $226 million, or $1.22 per diluted share, compared with net income of
$133 million, or $0.72 per diluted share, for fourth quarter 2013. Excluding
items typically excluded from published analyst estimates, adjusted net income
for first quarter 2014 was $272 million, or $1.47 per diluted share, a 19%
increase over adjusted net income of $228 million, or $1.23 per diluted share,
for fourth quarter 2013.

Logo - http://photos.prnewswire.com/prnh/20120327/DA76602LOGO

EBITDAX for first quarter 2014 was $775 million, a 9% increase over EBITDAX of
$712 million for fourth quarter 2013 and 25% above EBITDAX for first quarter
2013. 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.

Harold G. Hamm, Chairman and Chief Executive Officer, commented, "2014 is off
to a solid start. We battled challenging weather in the quarter, and several
pad locations experienced delays getting connected. However, we are very proud
of the efforts of the team to stay focused on execution in order to achieve
our target of 26% to 32% organic production growth in 2014." 

Production and Sales Volumes

First quarter 2014 net production totaled 13.7 million barrels of oil
equivalent ("Boe"), or 152,500 Boe per day, a sequential increase of 6% from
fourth quarter 2013 and 25% higher than first quarter 2013. Total net
production included approximately 106,400 barrels of oil per day (70% of
production) and approximately 276 million cubic feet of natural gas ("MMcf")
per day (30% of production). In first quarter 2014, sales volumes totaled
approximately 13.4 million Boe, or 148,400 Boe per day, which was
approximately 363,000 barrels below the amount produced for the quarter. This
increased level of oil inventory is attributed to recent line fill
requirements, logistical management of volumes during winter and initial tank
fill at oil storage facilities. As part of the Company's 2013-2014 facilities
capital projects, the Company is in the process of adding incremental oil
storage facilities with a maximum working capacity of 240,000 barrels,
providing greater flexibility and improved balancing of crude oil sales
logistics. Continental anticipates additional significant line fill during the
summer months of 2014 as new pipelines are put into service.

Hamm added, "Within the next few quarters new pipelines will be commissioned
along with our new tank storage in the Bakken which will serve us well by
reducing transportation costs, improving differentials and adding significant
optionality to our portfolio marketing strategy. These new assets and our
proactive steps are the natural next phase in the evolution of our Company's
marketing and infrastructure in the Bakken as we move closer to full-field
development."

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



                     1Q       4Q       1Q
Boe per day          2014     2013     2013
North Region:
North Dakota Bakken  83,725   80,374   67,575
Montana Bakken       13,732   12,961   9,352
Red River Units     14,140   14,398   15,055
Other                824      812      1,267
South Region:
SCOOP                29,363   23,754   14,243
NW Cana              5,685    6,696    8,323
Arkoma               2,565    2,769    3,234
Other               2,437    2,490    2,483
Total                152,471  144,254  121,532



Bakken Development

Continental's Bakken production totaled 97,457 Boe per day in first quarter
2014, an increase of 4% compared to fourth quarter 2013 and an increase of 27%
compared to first quarter 2013. The Company completed 67 net (177 gross)
wells in the Bakken during first quarter 2014. North Dakota completions
included 50 net wells in Middle Bakken ("MB") and Three Forks One ("TF1") and
six net wells in each of the Three Forks Two ("TF2") and Three Forks Three
("TF3"). Montana completions for first quarter 2014 totaled 11 net wells, all
in the MB. 

The Company concluded first quarter 2014 with an inventory of approximately
100 gross Bakken wells drilled, but not yet completed. As surface conditions
have improved, the Company has been able to accelerate completions, with
approximately half of the completions in first quarter 2014 occurring in
March. The Company currently expects to complete approximately 287 net (870
gross) wells in the Bakken in full-year 2014, including both operated and
non-operated wells, which is subject to change. The Company operated 20 rigs
in the play in first quarter 2014 and anticipates operating an average rig
count of 21 throughout 2014.

Enhanced Bakken Completions

During fourth quarter 2013 and first quarter 2014, Continental operated and
completed approximately 40 gross wells using various completion methods,
including several different test elements such as fluid type, increased
proppant and shorter stage length, among other items. Early results from
several of the techniques are encouraging, which include two slickwater
completion tests indicating an approximate 30% increase in the initial 120
days of production above the Company's blended 603,000 Boe model estimated
ultimate recovery ("EUR") and approximately 50% above existing offset wells in
the area. Estimated incremental completed well costs for these enhanced
completions is an additional $1.5 - $2.0 million above the Company's standard
completed well cost of $7.8 - $8.0 million today and $7.5 million targeted by
year-end 2014. Continental plans to continue enhanced completions on
approximately 20% (60 gross wells) of its Bakken activity in 2014 to determine
the optimal completion design to maximize value. It is important to evaluate
more production history as well as build a statistical database of results
before firm conclusions can be drawn.

Bakken Density Pilot Project Update

In 2013, the Company embarked on a plan to test different areas across the
Bakken field to determine what well density and pattern best maximizes crude
oil recovery and returns. In all, the Company has initiated seven density
pilot projects, and all are designed to develop the MB, TF1, TF2 and TF3
across a broad section of Continental's 1.2 million net acres of leasehold.
Three of these projects are testing 1,320 foot inter-well spacing and four are
testing 660 foot inter-well spacing. The Hawkinson 1,320 foot inter-well
spacing pilot project was the first to be completed by the Company and was
announced as a fourth quarter 2013 completion. During first quarter 2014 the
Company completed two additional 1,320 foot inter-well spacing pilot projects,
the Rollefstad and Tangsrud units. The four remaining pilot projects are
testing 660 foot inter-well spacing and are in various stages of drilling or
completion. These include the Wahpeton, Mack, Lawrence and Hartman units.
The Wahpeton unit, located in McKenzie County, includes 13 wells and is
expected to be completed by mid summer. The Lawrence, Mack and Hartman units
include a combined 18 new wells and six existing producers, and are expected
to be completed in the second half of 2014.

The Hawkinson Unit

Continental successfully completed the first density pilot project in North
Dakota at the Hawkinson unit in Dunn County in October 2013. 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
MB, three TF1, four TF2 and three TF3 wells spaced 1,320 feet apart in the
same zone and offset 660 feet in the adjacent zones.

Performance of the wells during their initial 150 producing days continues to
be very strong with 13 of the 14 wells producing on average 50% above the
Company's 603,000 Boe EUR model. The remaining well is a TF3 producer that is
producing on trend 35% below the 603,000 Boe EUR model. Although it is still
early in the life of the wells in this unit, to date the original existing
three wells continue to produce on average at or better than prior to the
commencement of drilling and completing the additional 11 wells in the density
test. Continental has an approximate 55% working interest in the Hawkinson
unit. 

The Tangsrud Unit

The Tangsrud density pilot project located in Divide County, ND was designed
to both test and extend the productive footprint of the Lower Three Forks
formation to the north in the Bakken and test 1,320 foot inter-well spacing
across the MB, TF1, TF2 and TF3. The project includes two existing wells and
12 new wells spaced 1,320 feet apart. The 12 new wells were completed in
first quarter 2014 and had a combined maximum 24-hour initial rate of 5,340
Boe per day, or 445 Boe per day per well. The five newly completed wells in
the unit in the MB and TF1 had an average initial rate of 670 Boe per day and
the seven newly completed TF2 and TF3 initially produced at approximately 285
Boe per day. All the wells in the unit were completed using Continental's
standard completion method (30 stages, 100,000 lbs. of proppant per stage) and
have recently been put on pump, producing 87% oil. The wells are being
monitored closely to assess if economics using current completion designs will
justify including TF2 and TF3 in future development in this particular area.
Continental has an approximate 96% working interest in the Tangsrud unit.

The Rollefstad Unit

The Rollefstad density pilot project located in McKenzie County, ND was
completed in April 2014 and is located in the Antelope project area. This
pilot includes eight new wells (two in each of the MB, TF1, TF2 and TF3) and 3
legacy wells (two MB and one TF1) spaced 1,320 feet apart. The eight new wells
had a combined maximum 24-hour initial rate of 22,460 Boe per day or 2,810 Boe
per day per well. Seven new completions at the Rollefstad unit were conducted
using twice the proppant, 200,000 lbs. per stage, compared to the Company's
standard design and had an average initial rate of 2,675 Boe per well. One
well was completed at three times the proppant, 300,000 lbs. per stage,
compared to the Company's standard completion design and had an initial rate
of 3,720 Boe per day. Due to the larger enhanced completion techniques used
and the temporary limitation of the existing infrastructure at the unit, a
larger test vessel was used to help measure these significant initial rates.
Seven of the eight new wells continue to flow naturally, thus it is too early
in the life of the wells to estimate ultimate recovery. Continental has an
80% working interest in the unit.

W. F. "Rick" Bott, Continental's President and Chief Operating Officer,
commented, "The continued success of our Hawkinson downspacing pilot gives us
confidence we can take our full-field development plans across a large portion
of the play. The Rollefstad results are very exciting as the enhanced
completions have the opportunity to dramatically change the overall return
profile of the play. It is still very early in the process and different
areas and formations may respond differently.Our goal is to combine our
completion design tests with our downspacing pilot results to maximize
recoveries, accelerate production earlier in the life of the well and thus
drive higher realized returns and greater net present value."

Growth in SCOOP Continues 

Continental continues to deliver excellent 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 185 wells across
its approximately 425,000 net acres of leasehold in the play.

In first quarter 2014, SCOOP net production averaged 29,363 Boe per day, an
increase of 24% sequentially and 106% above first quarter 2013. The recent
growth was driven by the addition of 11 net (13 gross) operated and 2 net (15
gross) non-operated wells in the play during first quarter 2014.

In SCOOP, Continental's primary focus continues to be exploration and
appraisal as well as drilling to hold acreage by production ("HBP"), with an
increasing shift to 1.5 to 2-mile extended lateral wells for superior
returns. The Company operated an average of 19 rigs during first quarter 2014
and plans to average at least 18 operated rigs in the play in 2014, with
approximately 50% of the activity consisting of extended lateral wells.
Operated 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 and
approximately $13.5 million for a 2-mile lateral. Continental plans to
conduct spacing tests and at least one density pilot in SCOOP in 2014.

In first quarter 2014, average initial one-day test rates from operated wells
within the condensate and oil window of SCOOP included:

  oThe Claudine 1-29-32XH well in Stephens County tested at 18.1 million
    cubic feet of natural gas equivalent ("MMcfe") per day, which included 245
    barrels of oil. The gas stream is estimated at 1,230 British thermal
    units per standard cubic foot ("Btu/scf"). Continental has a 60% working
    interest in the well;
  oThe Chalfant 1-7H well in Stephens County tested at 16.2 MMcfe per day,
    which included 375 barrels of oil. The gas stream is estimated at 1,190
    Btu/scf. Continental has a 28% working interest in the well; and
  oThe Green Acres 1-36H well in Garvin County tested at 980 Boe per day,
    which included 78% oil. Continental has a 97% working interest in the
    well.

Financial Update and Guidance

Continental's average realized sales price excluding the effects of derivative
positions was $89.73 per barrel of oil and $7.06 per thousand cubic feet of
natural gas ("Mcf"), or $75.03 per Boe for first quarter 2014. Settlements of
matured commodity derivative positions generated a $2.51 loss per barrel of
oil and $0.41 loss per Mcf of natural gas, resulting in a net loss on matured
derivatives of $33.3 million, or $2.49 per Boe for the first quarter 2014.
Based on realizations without the effect of derivatives, the Company's first
quarter 2014 oil differential was $8.98 per barrel below the NYMEX daily
average for the period. The realized natural gas price differential for first
quarter 2014 was a positive $2.14 per Mcf.

Production expense per Boe was $5.76 for first quarter 2014. Other select
operating costs and expenses for first quarter 2014 included production taxes
of 7.7% of oil and natural gas sales; DD&A of $20.43 per Boe; and G&A (cash
and non-cash) of $3.26 per Boe.

As of March 31, 2014, Continental's balance sheet included approximately $52
million in cash and cash equivalents and $630 million of borrowings against
the Company's $1.5 billion credit facility.

Non-acquisition capital expenditures for first quarter 2014 totaled
approximately $1,037 million, including $902 million in exploration and
development drilling, $87 million in leasehold and seismic and $48 million in
facilities, workovers, recompletions and other. Acquisition capital
expenditures totaled approximately $66 million for first quarter 2014.

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.

                                                  1Q 2014   4Q 2013   1Q 2013
Average daily production:
Crude oil (Bbl per day)                           106,398   100,443   86,071
Natural gas (Mcf per day)                         276,439   262,866   212,766
Crude oil equivalents (Boe per day)               152,471   144,254   121,532
Average sales prices, excluding effect from
derivatives:
Crude oil ($/Bbl)                                 $89.73    $84.47    $89.99
Natural gas ($/Mcf)                               $7.06     $5.11     $4.59
Crude oil equivalents ($/Boe)                     $75.03    $68.12    $71.61
Production expenses ($/Boe)                      $5.76     $6.03     $5.70
Production taxes (% of oil and gas revenues)      7.7%      8.1%      8.3%
DD&A ($/Boe)                                      $20.43    $20.40    $19.72
General and administrative expenses ($/Boe)      $2.43     $2.28     $2.26
Non-cash equity compensation ($/Boe)              $0.83     $0.79     $0.85
Net income (in thousands)                        $226,234  $132,824  $140,627
Diluted net income per share                      $1.22     $0.72     $0.76
Adjusted net income (in thousands) ^(1)          $272,297  $228,132  $215,386
Adjusted diluted net income per share ^(1)       $1.47     $1.23     $1.17
EBITDAX (in thousands) ^(1)                       $775,407  $712,300  $621,528

    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
(1) 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 first quarter
results on Thursday, May 8, 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, May 8, 2014
Dial in:       800 708 4539
Intl. dial in: 847 619 6396
Pass code:     37065209

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:     37065209

Continental plans to publish a first quarter summary presentation to its
website at www.CLR.com prior to the start of its earnings conference call on
May 8, 2014.

Upcoming Conferences

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

May 20, 2014  UBS Global Oil & Gas Conference, Austin, TX
June 3, 2014 RBC Capital Markets' Global Energy and Power Conference, New
              York, NY

Presentation materials for all conferences mentioned above will be available
on the Company's website at www.CLR.comon 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, completion and production
equipment and services and transportation infrastructure, environmental risks,
drilling and other operating risks, lack of availability and security of
computer-based systems, 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.
Investor Contact:                         Media Contact:
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



Continental Resources, Inc.
Unaudited Condensed Consolidated Statements of Income
                                           Three months ended March 31,
                                           2014                 2013
Revenues:                                  In thousands, except per share data
Crude oil and natural gas sales            $    1,002,333       $   775,931
Loss on derivative instruments, net             (39,674)            (84,831)
Crude oil and natural gas service               9,836               11,543
operations
Total revenues                                  972,495             702,643
Operating costs and expenses:
Production expenses                             76,886              61,804
Production taxes and other expenses             78,302              64,842
Exploration expenses                            4,813               9,814
Crude oil and natural gas service               8,074               8,597
operations
Depreciation, depletion, amortization and       272,861             213,678
accretion
Property impairments                            58,208              40,081
General and administrative expenses            43,536              33,817
(Gain) loss on sale of assets, net              8,498               (136)
Total operating costs and expenses              551,178             432,497
Income from operations                          421,317             270,146
Other income (expense):
Interest expense                                (62,975)            (47,475)
Other                                          759                 546
                                                (62,216)            (46,929)
Income before income taxes                      359,101             223,217
Provision for income taxes                      132,867             82,590
Net income                                 $    226,234         $   140,627
Basic net income per share                 $    1.23            $   0.76
Diluted net income per share               $    1.22            $   0.76



Continental Resources, Inc.
Unaudited Condensed Consolidated Balance Sheets
                                           March 31,     December 31,
                                           2014          2013
Assets                                     In thousands
Current assets                             $ 1,241,575   $ 1,147,266
Net property and equipment ^(1)              11,443,951    10,721,272
Other noncurrent assets                      79,375        72,644
Total assets                               $ 12,764,901  $ 11,941,182
Liabilities and shareholders' equity
Current liabilities                        $ 1,567,714   $ 1,473,156
Long-term debt                               5,067,814     4,713,821
Other noncurrent liabilities                 1,941,612     1,801,087
Total shareholders' equity                   4,187,761     3,953,118
Total liabilities and shareholders' equity $ 12,764,901  $ 11,941,182

    Balance is net of accumulated depreciation, depletion and amortization of
(1) $3.33 billion and $3.12 billion as of March 31, 2014 and December 31,
    2013, respectively.



Continental Resources, Inc.
Unaudited Condensed Consolidated Statements of Cash Flows
                                                 Three months ended March 31,
In thousands                                     2014              2013
Net income                                      $  226,234        $ 140,627
Adjustments to reconcile net income to net cash
provided by operating activities:
Non-cash expenses                                   498,339          428,913
Changes in assets and liabilities                   (33,911)         (111,429)
Net cash provided by operating activities           690,662          458,111
Net cash used in investing activities               (1,019,480)      (873,153)
Net cash provided by financing activities           351,871          437,859
Net change in cash and cash equivalents             23,053           22,817
Cash and cash equivalents at beginning of           28,482           35,729
period
Cash and cash equivalents at end of period       $  51,535         $ 58,546



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.

In thousands                                  1Q 2014     4Q 2013    1Q 2013
Net income                                    $ 226,234   $ 132,824  $ 140,627
Interest expense                                62,975      63,666     47,475
Provision for income taxes                      132,867     78,008     82,590
Depreciation, depletion, amortization and       272,861     270,456    213,678
accretion
Property impairments                            58,208      58,548     40,081
Exploration expenses                            4,813       5,809      9,814
Impact from derivative instruments:
Total (gain) loss on derivatives, net           39,674      102,202    84,831
Total cash paid on derivatives, net             (33,264)    (9,644)    (6,810)
Non-cash loss on derivatives, net               6,410       92,558     78,021
Non-cash equity compensation                    11,039      10,431     9,242
EBITDAX                                       $ 775,407   $ 712,300  $ 621,528

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

In thousands                                  1Q 2014     4Q 2013    1Q 2013
Net cash provided by operating activities     $ 690,662   $ 584,842  $ 458,111
Current income tax provision (benefit)          1,552       (4,014)    -
Interest expense                                62,975      63,666     47,475
Exploration expenses, excluding dry hole        4,813       5,639      7,553
costs
Gain (loss) on sale of assets, net              (8,498)     (24)       136
Other, net                                      (10,008)    2,020      (3,176)
Changes in assets and liabilities               33,911      60,171     111,429
EBITDAX                                       $ 775,407   $ 712,300  $ 621,528

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 2014             4Q 2013             1Q 2013
In thousands,       After-Tax  Diluted  After-Tax  Diluted  After-Tax  Diluted
except per share    $          EPS      $          EPS      $          EPS
data
Net income (GAAP)   $ 226,234  $     $ 132,824  $     $ 140,627  $   
                               1.22               0.72               0.76
Adjustments, net
of tax:
 Non-cash loss on   4,038      0.02     58,312     0.31     49,153     0.27
 derivatives, net
 Property           36,671     0.20     36,885     0.20     25,251     0.14
 impairments
 (Gain) loss on
 sale of assets,    5,354      0.03     15         -        (86)       -
 net
 Corporate
 relocation         -          -        96         -        441        -
 expenses
  Adjusted net                 $                $                $   
  income            $ 272,297  1.47    $ 228,132  1.23    $ 215,386  1.17
  (Non-GAAP)
  Weighted average
  diluted shares    185,028             185,007             184,656
  outstanding
  Adjusted diluted  $                 $                 $  
  net income per    1.47               1.23               1.17
  share (Non-GAAP)



Continental Resources, Inc.
2014 Guidance Outlook
As of May 7, 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 and most recently reaffirmed on February 26, 2014.



SOURCE Continental Resources

Website: http://www.clr.com
 
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