Continental Resources Reports 55 Percent Production Growth And 46 Percent EBITDAX Growth In Third Quarter Of 2012

  Continental Resources Reports 55 Percent Production Growth And 46 Percent
                   EBITDAX Growth In Third Quarter Of 2012

PR Newswire

OKLAHOMA CITY, Nov. 7, 2012

OKLAHOMA CITY, Nov. 7, 2012 /PRNewswire/ -- Continental Resources, Inc. (NYSE:
CLR) announced strong year-over-year growth in production and EBITDAX for the
third quarter ended September 30, 2012. Among the Company's significant third
quarter accomplishments were:

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

  oRecord production of 102,964 barrels of oil equivalent per day (Boepd), 55
    percent above third quarter 2011 production and nine percent above second
    quarter 2012 production. September 2012 production was 105,874 Boepd;
  o$492.3 million of EBITDAX, 46 percent higher than the third quarter of
    2011 and 17 percent above EBITDAX for the second quarter of 2012;
  oA $9.45 per barrel oil differential for the third quarter of 2012, with
    September's differential improving to $5.19 per barrel;
  oCapital expenditures, excluding acquisitions, of $727 million in the third
    quarter of 2012, bringing total non-acquisition capital expenditures for
    the first nine months of 2012 to $2.3 billion.

Third quarter production and EBITDAX growth was driven by continued production
increases in the Bakken play and the South Central Oklahoma Oil Province
(SCOOP), the oil- and condensate-rich resource play unveiled at Continental's
2012 Investors Day on October 9, 2012. Bakken production increased 81 percent
compared with the third quarter of 2011, while SCOOP production was 327
percent higher than the third quarter last year.

Seventy percent of the Company's third quarter 2012 production was oil, with
the balance being natural gas and natural gas liquids.

"We expect to achieve 2012 production growth guidance of 57 percent to 59
percent," said Harold Hamm, Chairman and Chief Executive Officer. "Other
positive trends we expect to continue are reduced drilling and completion
cycle times and low production costs.

"2013 is shaping up as another year of production growth with efficiency
gains," Mr. Hamm said. "We expect 30-to-35 percent production growth next
year, the first year in our new five-year plan aimed at tripling production
and proved reserves."

Financial Results

Continental reported net income of $44.1 million, or $0.24 per diluted share,
for the third quarter of 2012. Adjusted earnings were $0.87 per diluted share
for the quarter, excluding the combined effects of an unrealized loss on
derivatives, property impairment charges and relocation expenses.

After-tax adjustments that reduced net income included a net non-cash
unrealized loss on derivatives of $97.1 million, property impairment charges
of $16.9 million, and $1.4 million in costs related to the Company's
headquarters relocation to Oklahoma City.

For the third quarter of 2011, the Company reported net income of $439.1
million, or $2.44 per diluted share. Last year's third quarter net income, on
an after-tax basis, was increased by a $332.5 million net non-cash unrealized
gain on mark-to-market derivative instruments and reduced by a net charge of
$16.3 million for property impairments. Adjusted earnings for the third
quarter of 2011 were $0.69 per diluted share, excluding the unrealized gain on
derivatives and the property impairments.

Consequently, third quarter 2012 adjusted net income of $0.87 per share was 26
percent above adjusted net income for the third quarter of 2011 and a similar
increase over adjusted net income for the second quarter of 2012.

For the reconciliation to U.S. GAAP earnings per share, see "Non-GAAP
Financial Measures – Adjusted earnings per share" at the end of this press
release.

Oil and natural gas sales were $633.3 million for the third quarter of 2012,
compared with $423.9 million for the third quarter of 2011, representing a 49
percent increase.

Third quarter 2012 EBITDAX was $492.3 million, a 46 percent increase compared
with the third quarter of 2011. For the Company's definition and
reconciliation of EBITDAX to net income and operating cash flows, see
"Non-GAAP Financial Measures – EBITDAX" at the end of this press release.

Continental reduced production expense per barrel of oil equivalent (Boe) by
six percent to $5.62 for the third quarter of 2012, compared with $5.98 per
Boe for the third quarter of 2011. For the first nine months of 2012,
production expense per Boe declined 15 percent to $5.34 per Boe.

General and administrative expense (G&A) was $3.31 per Boe for the third
quarter of 2012, compared with G&A of $2.98 per Boe for the third quarter of
2011. G&A expense for the third quarter of 2012 included non-cash equity
compensation of $0.78 per Boe and relocation expenses of $0.24 per Boe. For
the same quarter last year, G&A included $0.70 per Boe for non-cash equity
compensation and $0.17 per Boe for relocation expenses.

Marketing and Commodity Prices

Continental reported a blended sales price of $65.62 per Boe in the third
quarter of 2012, comprised of average prices of $82.87 per barrel of crude oil
and $4.00 per Mcf for natural gas. The Company's third quarter 2012 average
price for crude oil does not include the effect of a $1.4 million pre-tax
realized loss on derivatives for the quarter. In the third quarter of 2011, it
reported a blended price of $69.57 per Boe.

The Company's third quarter 2012 oil differential declined to $9.45 per
barrel, a $3.18 per barrel sequential drop from the previous quarter. In the
third quarter of 2011, Continental's oil differential was $5.62. The average
natural gas differential to Henry Hub for the third quarter of 2012 was a
premium of $1.19 per Mcf, reflecting the high liquids content of its natural
gas production. This compared with a premium of $1.30 per Mcf for the third
quarter of 2011.

"We've recently seen a significant improvement in Bakken oil price
differentials, reflecting higher volumes being shipped by rail to the coasts
and the anticipation of increased pipeline capacity," said Rick Bott,
President and Chief Operating Officer. "In mid-October, Continental was
railing 21,000 barrels per day of operated production to the West Coast, a
similar volume by rail to the Gulf coast, and 8,000 barrels per day to the
East Coast. In November, we plan to ship 65 percent of our Bakken operated oil
production by rail.

"We now have excess transportation capacity in both pipe and rail, and, with
additional infrastructure projects in the planning and construction stages,
capacity should remain ahead of Bakken production growth," Mr. Bott said. "Our
primary focus today is identifying the highest-value opportunities to market
our oil to the refinery end-customer."

Operating Highlights

                            Three months ended     Nine months ended September
                            September 30,          30,
                            2012        2011       2012            2011
Average daily production:
Crude oil (Bbl per day)        72,235     47,552      65,826          42,160
Natural gas (Mcf per day)      184,377    112,423     171,912         91,231
Crude oil equivalents (Boe     102,964    66,289      94,478          57,365
per day)
Average sales prices: ^(1)
Crude oil ($/Bbl)           $  82.87    $ 84.02    $  84.44        $  88.19
Natural gas ($/Mcf)            4.00       5.50        3.97            5.37
Crude oil equivalents          65.62      69.57       66.06           73.25
($/Boe)
Production expenses ($/Boe)    5.62       5.98        5.34            6.31
^(1)
General and administrative     3.31       2.98        3.35            3.32
expenses ($/Boe) ^(1)(2)
Net income (in thousands)     44,096     439,143     518,874         541,136
Diluted net income per         0.24       2.44        2.86            3.05
share
EBITDAX (in thousands)^(3)     492,279    337,754     1,368,671       892,040



(1) Average sales prices and per unit expenses have been calculated using
    sales volumes and exclude any effect of derivative transactions.
    General and administrative expenses ($/Boe) includes non-cash equity
    compensation expense of $0.78 per Boe and relocation expense of $0.24 per
    Boe for the three months ended September 30, 2012 compared to non-cash
    equity compensation expense of $0.70 per Boe and relocation expense of
(2) $0.17 per Boe for the three months ended September 30, 2011. For the nine
    months ended September 30, 2012, general and administrative expenses
    includes non-cash equity compensation expense of $0.80 per Boe and
    relocation expense of $0.29 per Boe compared to non-cash equity
    compensation expense of $0.76 per Boe and relocation expense of $0.09 per
    Boe for the nine months ended September 30, 2011.
    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. Reconciliations of net income and
(3) operating cash flows to EBITDAX are provided subsequently under the header
    Non-GAAP Financial Measures – EBITDAX.

    

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



                     3Q       2Q      3Q
Boe per day          2012     2012    2011
North Region:
North Dakota Bakken  55,918   47,166  28,987
Montana Bakken       6,535    6,305   5,518
Red River Units     14,916   15,482  14,954
Other                1,343    1,445   1,052
South Region:
NW Cana Woodford     11,320   13,516  5,949
SCOOP Woodford       5,183    3,156   1,215
Arkoma Woodford     4,061    3,806   4,099
Other               2,590    2,912   3,387
East Region          1,098    1,064   1,128
Total                102,964  94,852  66,289



North Dakota and Montana Bakken Production Continues to Grow

Continental's Bakken production was 62,453 Boepd for the third quarter of
2012, an 81 percent increase over the third quarter of 2011 and 17 percent
higher than the second quarter of 2012.

The Company participated in 137 gross (46 net) wells in the Bakken during the
third quarter of 2012.

In terms of operated wells, Continental completed 46 gross (34 net) wells in
the Bakken in the third quarter of 2012, with 41 gross (29 net) wells in North
Dakota and 5 gross (5 net) wells in Montana.

Company-operated wells completed during the third quarter averaged 1,076 Boepd
for North Dakota Bakken wells and 886 Boepd for Montana wells in their initial
one-day test-periods. Twenty-two of Continental's 41 gross operated wells in
North Dakota had initial production test rates of more than 1,000 Boepd, while
two of its five operated Montana wells surpassed that level in the third
quarter of 2012. Bakken well performance continues to meet the Company's
expectations.

A notable project completed during the third quarter of 2012 was the
Antelope-Bohmbach ECO-Pad® in McKenzie County, consisting of the Antelope
3-23H and 4-23H and the Bohmbach 3-35H and 4-35H wells. The four wells tested
at an aggregate initial rate of 6,240 Boepd in total, for an average of 1,560
Boepd per well, with average flowing tubing pressure of 3,800 psi. Continental
has an 85 percent working interest in the wells.

Continental is the leading leaseholder in the Bakken, with 984,040 net acres
at September 30, 2012. The Company currently has 19 operated drilling rigs in
the Bakken, including 15 operated rigs in North Dakota and four in Montana.

SCOOP/Northwest Cana Woodford Results (Oklahoma)

Continental's SCOOP production was 5,183 Boepd in the third quarter of 2012, a
327 percent increase over third quarter production last year and 64 percent
above second quarter 2012 production. Third quarter 2012 production volumes
were temporarily impacted in SCOOP as infrastructure was added to handle
increasing volumes. This oil- and condensate-rich play primarily involves
197,340 net acres leased as of September 30, 2012 in Grady, McClain, Garvin,
Stephens, Murray, Carter and Love counties.

In the Northwest Cana, which is comprised primarily of acreage in Blaine and
Dewey counties, third quarter 2012 production was 11,320 Boepd, a 90 percent
increase over production for the same period last year. Production declined
from the second quarter of 2012 due to reduced drilling activity and
third-party infrastructure downtime.

Continental differentiates the SCOOP area from other Oklahoma Woodford plays
(NW Cana and Arkoma) because of its significant oil volumes and associated
economics.

The Company participated in 12 gross (5 net) wells in SCOOP and Northwest Cana
during the quarter. In terms of Continental-operated wells, it completed five
gross (four net) SCOOP wells in the third quarter of 2012. The five operated
wells tested at an average rate of 754 Boepd in one-day test periods, with oil
production averaging 28 percent.

Continental is currently operating six drilling rigs in SCOOP and none in
Northwest Cana.

Financial Position and Derivatives

At September 30, 2012, the Company's balance sheet included $259.4 million in
cash and cash equivalents and $2.9 billion in total long-term debt, which
included no borrowings under Continental's revolving credit facility.
Continental's revolving credit facility includes $1.5 billion in bank
commitments and a borrowing base of $2.75 billion.

On August 16, 2012, the Company completed the placement of $1.2 billion of new
5% senior unsecured notes due 2022 at 102.375% of par, yielding 4.624%.
Continental used part of the net proceeds to pay down outstanding amounts on
borrowings under its revolving credit facility.

Aside from $2.3 billion of non-acquisition capital expenditures in the first
nine months of 2012, Continental reported an additional $594 million in
capital expenditures acquiring producing and non-producing properties.

"Our debt-to-EBITDAX metrics remain strong, and we have ample liquidity to
fund our robust production growth," said John Hart, Senior Vice President and
Chief Financial Officer.

Continental has systematically established derivative positions to stabilize
cash flow as it continues to grow production. Derivative positions as of
October 26, 2012 are listed in the following table.

Crude Oil Derivative                   Swaps           Collars Wtd. Avg. Price
Positions
Period and Type of         Bbls      Wtd. Avg.       Floor         Ceiling
Contract                               Price
October 2012 - December
2012
       Swaps - WTI         1,840,000   $88.69
       Swaps - Brent      1,058,000   $111.17
       Collars - WTI       1,340,440                   $80.00        $94.71
January 2013 - December
2013
       Swaps - WTI         11,862,500  $92.66
       Swaps - Brent      2,372,500   $109.19
       Collars - WTI       8,760,000                   $86.92        $99.46
January 2014 - December
2014
       Swaps - WTI         10,311,250  $96.20
       Swaps - Brent      4,745,000   $100.43
       Collars - Brent     1,460,000                   $90.00        $107.50
January 2015 - December
2015
       Swaps - Brent       1,277,500   $98.48
Natural Gas Derivative                 Swaps
Positions
Period and Type of         MMBtus    Wtd. Avg.
Contract                               Price
January 2013 - December
2013
       Swaps - Henry Hub   18,250,000  $3.76

For additional information on crude oil and natural gas derivative positions,
please see the Company's most recent SEC filings.

2013 Guidance

Continental announced the following operating and financial guidance for 2013:

2013 Production growth range             30% to 35% 
Capital expenditures*                    $3.4B
Price differentials:
 WTI crude oil (per barrel of oil)     $8 to $11
 Henry Hub natural gas (per Mcf)       +$1.00 to $1.50 
Operating expenses:
 Production expense per Boe            $5.50 to $5.90
 Production tax as a percent
 of oil and gas revenues**           8% to 9%
 DD&A per Boe                          $19 to $21
 G&A expense per Boe***                $2.40 to $2.90
 Non-cash equity compensation per Boe  $0.70 to $0.90
Income tax rate                          38%
Deferred taxes                           90% to 95%

* Excludes acquisition capital expenditures

**Does not include other expenses, such as natural gas transportation fees,
which could represent another 1%.

***Excludes non-cash equity compensation

Conference Call Information

Continental Resources plans to host its third quarter 2012 earnings conference
call on Thursday, November 8, 2012, 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, November 8, 2012
Dial in:                        888 680 0878
Intl. dial in:                  617 213 4855
Pass code:                      32316165
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:                      72440131



Conference Presentations

Continental management is currently scheduled to present at the following
research conferences. Presentation materials will be available on the
Company's web site.

Nov. 13    2012 Bank of America Merrill Lynch Global Energy Conference,
            Miami
Nov. 14    IHS Pacesetters Energy Conference 2012, Washington, D.C.
Nov. 28-29 Jefferies Global Energy Conference, Houston
Dec. 3-4   Dahlman Rose Ultimate Oil Services and E&P Conference, New York
Dec. 3-5   Bank of America Merrill Lynch Leveraged Finance Conference 2012,
            Boca Raton, FL
Dec. 5     Capital One SouthCoast Equity Conference, New Orleans



About Continental Resources

Continental Resources is a Top 10 petroleum liquids producer in the United
States. In October 2012, the Company announced a new five-year plan to triple
production and proved reserves by year-end 2017. The Company's growth plan is
based on developing its industry-leading leasehold in the nation's premier oil
play, the Bakken of North Dakota and Montana, as well as its position in the
SCOOP and Northwest Cana plays of Oklahoma. The company reported total
revenues of $1.6 billion for 2011. Visit www.clr.com for more information.

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 that 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, 2011, 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 that 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, 2011, 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, VP Investor Relations  Kristin Miskovsky, VP Public Relations
405-234-9127                         405-234-9480
Warren.Henry@CLR.com                 Kristin.Miskovsky@CLR.com





Unaudited Condensed Consolidated Statements of Income
                     Three months ended September  Nine months ended September
                     30,                           30,
                     2012            2011          2012            2011
Revenues:            In thousands, except per share data
Crude oil and        $  633,344      $  423,859    $  1,708,995    $ 1,139,110
natural gas sales
Gain (loss) on
derivative              (158,294)       537,340       144,377        372,490
instruments, net
Crude oil and
natural gas service     8,679           7,790         30,176         24,071
operations
Total revenues          483,729         968,989       1,883,548      1,535,671
Operating costs and
expenses:
Production expenses     54,210          36,459        138,041        98,090
Production taxes and    62,913          39,262        162,880        100,315
other expenses
Exploration expenses    4,899           9,814         17,752         21,660
Crude oil and
natural gas service     7,626           6,198         24,723         19,713
operations
Depreciation,
depletion, amortization 189,374         105,085       499,847        264,236
and accretion
Property impairments    27,375          26,225        93,153         66,315
General and
administrative          31,925          18,140        86,704         51,696
expenses ^(1)
(Gain) loss on sale     (115)           188           (67,139)       (15,387)
of assets, net
Total operating         378,207         241,371       955,961        606,638
costs and expenses
Income from             105,522         727,618       927,587        929,033
operations
Other income
(expense):
Interest expense        (39,205)        (18,981)      (95,174)       (56,737)
Other                  710             994           2,280          2,525
                        (38,495)        (17,987)      (92,894)       (54,212)
Income before income    67,027          709,631       834,693        874,821
taxes
Provision for income    22,931          270,488       315,819        333,685
taxes
Net income          $  44,096       $  439,143    $  518,874      $ 541,136
Basic net income per $  0.24         $  2.45       $  2.88         $ 3.06
share
Diluted net income   $  0.24         $  2.44       $  2.86         $ 3.05
per share

      General and administrative expenses ($/Boe) includes non-cash equity
      compensation expense of $0.78 per Boe and relocation expense of $0.24
      per Boe for the three months ended September 30, 2012 compared to
      non-cash equity compensation expense of $0.70 per Boe and relocation
  (1) expense of $0.17 per Boe for the three months ended September 30, 2011.
      For the nine months ended September 30, 2012, general and administrative
      expenses includes non-cash equity compensation expense of $0.80 per Boe
      and relocation expense of $0.29 per Boe compared to non-cash equity
      compensation expense of $0.76 per Boe and relocation expense of $0.09
      per Boe for the nine months ended September 30, 2011.



Unaudited Condensed Consolidated Balance Sheets
                                           September 30,  December 31,
                                           2012           2011
Assets                                     In thousands
Current assets                             $  1,194,282   $  936,373
Net property and equipment                    6,922,283      4,681,733
Other noncurrent assets                       109,785        27,980
Total assets                               $  8,226,350   $  5,646,086
Liabilities and shareholders' equity
Current liabilities                        $  1,097,484   $  1,111,801
Long-term debt                                2,943,741      1,254,301
Other noncurrent liabilities                  1,259,754      971,858
Total shareholders' equity                    2,925,371      2,308,126
Total liabilities and shareholders' equity $  8,226,350   $  5,646,086



Unaudited Condensed Consolidated Statements of Cash Flows
                                              Nine months ended September 30,
                                              2012              2011
                                              In thousands
Net income                                   $  518,874        $  541,136
Adjustments to reconcile net income to net
cash provided by operating activities:
Non-cash expenses                                681,891           256,392
Changes in assets and liabilities                (52,868)          (127,714)
Net cash provided by operating activities        1,147,897         669,814
Net cash used in investing activities            (2,591,127)       (1,263,139)
Net cash provided by financing activities        1,649,131         627,684
Net change in cash and cash equivalents          205,901           34,359
Cash and cash equivalents at beginning of        53,544            7,916
period
Cash and cash equivalents at end of period    $  259,445        $  42,275

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 consistently with the definition
of EBITDAX utilized and presented by us. The following table is a
reconciliation of our net income to EBITDAX for the periods presented.

                     Three months ended September  Nine months ended September
                     30,                           30,
                     2012            2011          2012            2011
                     in thousands
Net income           $  44,096       $  439,143    $  518,874      $ 541,136
Interest expense        39,205          18,981        95,174         56,737
Provision for income    22,931          270,488       315,819        333,685
taxes
Depreciation,
depletion,              189,374         105,085       499,847        264,236
amortization and
accretion
Property impairments    27,375          26,225        93,153         66,315
Exploration expenses    4,899           9,814         17,752         21,660
Impact from
derivative
instruments:
Total (gain) loss on    158,294         (537,340)     (144,377)      (372,490)
derivatives, net
Total realized gain
(loss) (cash flow)      (1,394)         1,113         (48,375)       (30,981)
on derivatives, net
Non-cash (gain) loss    156,900         (536,227)     (192,752)      (403,471)
on derivatives, net
Non-cash equity         7,499           4,245         20,804         11,742
compensation
EBITDAX              $  492,279      $  337,754    $  1,368,671    $ 892,040
The following table provides a reconciliation of our net cash provided by
operating activities to EBITDAX for the periods presented.
                     Nine months ended September
                     30,
                     2012            2011
                     in thousands
Net cash provided by $  1,147,897    $  669,814
operating activities
Current income tax      (7,724)         9,331
provision (benefit)
Interest expense        95,174          56,737
Exploration
expenses, excluding     17,433          17,902
dry hole costs
Gain on sale of         67,139          15,387
assets, net
Other, net              (4,116)         (4,845)
Changes in assets       52,868          127,714
and liabilities
EBITDAX              $  1,368,671    $  892,040

Adjusted earnings per share

Our presentation of adjusted earnings per share that excludes the effect of
certain items is a non-GAAP financial measure.Adjusted earnings per share
represents 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 this measure provides 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 this
measure is 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 per share
should not be considered in isolation or as a substitute for 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.

                            Three months ended September 30,
                            2012                      2011
In thousands, except per    After-Tax $   Diluted     After-Tax $   Diluted
share data                                EPS                       EPS
Net income (GAAP)           $   44,096  $       $  439,143   $    
                                          0.24                      2.44
Adjustments, net of tax:
 Non-cash (gain) loss on    97,121        0.53        (332,461)     (1.84)
 derivatives, net
 Property impairments       16,945        0.09        16,259        0.09
 (Gain) loss on sale of     (71)          -           117           -
 assets, net
 Corporate relocation       1,420         0.01        649           -
 expenses
  Adjusted net income       $  159,511   $       $  123,707   $    
  (Non-GAAP)                              0.87                      0.69
  Weighted average diluted  182,537                   180,245
  shares outstanding
  Adjusted diluted net      $                     $    
  income per share          0.87                      0.69
  (Non-GAAP)

SOURCE Continental Resources, Inc.

Website: http://www.clr.com
 
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