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Continental Resources Reports Net Income Of $1.19 Per Diluted Share For Fourth Quarter 2012



Continental Resources Reports Net Income Of $1.19 Per Diluted Share For Fourth
                                 Quarter 2012

Record Fourth Quarter EBITDAX of $594.5 Million Is 44 Percent Higher Than
Final Quarter of 2011

Continental Guides to 2013 Oil Differential Cost of $5 to $7 per Barrel, a 37
Percent Improvement

New Well Results - Latest Bakken Three Forks Well in the Second Bench Flows
1,556 Barrels of Oil Equivalent per Day

- New SCOOP Well Flows 1,761 Barrels of Oil Equivalent per Day

PR Newswire

OKLAHOMA CITY, Feb. 27, 2013

OKLAHOMA CITY, Feb. 27, 2013 /PRNewswire/ -- Continental Resources, Inc.
(NYSE: CLR) ("Continental" or the "Company") reported strong growth in cash
flow and earnings per share for the fourth quarter of 2012, benefiting from
increased crude oil production and strong oil price realizations on sales to
premium markets.

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

"We completed 2012 with an excellent fourth quarter, and growth momentum
continues in 2013," said Harold Hamm, Chairman and Chief Executive Officer.
"Production has increased, and realized oil prices have been strong as we
market an increased share of our Bakken production to U.S. coastal markets.
We've seen a fundamental change in oil markets with the significant increase
in rail transportation capacity out of the Bakken. Improved differentials and
lower operated well costs as we continue to drill and complete projects more
efficiently point to continued strong cash flow in 2013."

Significant fourth quarter and full-year 2012 accomplishments included:

  o Net income of $1.19 per diluted share for the fourth quarter of 2012,
    compared with a net loss of $0.62 per diluted share for the fourth quarter
    of 2011;
  o Full-year 2012 net income of $739.4 million, or $4.07 per diluted share, a
    72 percent increase compared with net income of $429.1 million, or $2.41
    per diluted share, for 2011;
  o Record EBITDAX for the fourth quarter of 2012, which was 44 percent higher
    than the fourth quarter of 2011 and 21 percent higher than the third
    quarter of 2012;
  o Record production of 106,831 barrels of oil equivalent per day (Boepd) for
    the fourth quarter of 2012, a 42 percent increase from fourth quarter 2011
    production.

Total production in February 2013 is on track to exceed 120,000 Boepd.

As a result of the Company's improved differential to NYMEX, Continental has
reduced its 2013 oil differential guidance range to $5 to $7 per barrel,
compared with previous guidance of $8 to $11.

Continental reported net income of $220.5 million, or $1.19 per diluted share,
for the fourth quarter of 2012. Net income for the quarter included several
non-recurring items, including a $42.7 million after-tax gain on sale of
assets and a $4.3 million non-cash unrealized gain on derivatives. Partially
offsetting these items were two after-tax adjustments – a charge of $18.1
million for property impairments and a small charge related to the relocation
of the Company's headquarters to Oklahoma City. Without these items, adjusted
net income for fourth quarter 2012 was $191.8 million, or $1.04 per diluted
share, an increase of 18 percent compared with adjusted net income per share
of $0.88 per diluted share for the fourth quarter of 2011.

Continental reported full-year 2012 net income of $739.4 million, or $4.07 per
diluted share, an increase of 72 percent over net income of $429.1 million, or
$2.41 per diluted share, for 2011. Adjusted net income for 2012 was $3.36 per
diluted share, without the effects of gains on sales of assets, non-cash
unrealized gains on derivatives, property impairment charges and relocation
expenses. 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.

Continental reported fourth quarter 2012 EBITDAX of $594.5 million, an
increase of 44 percent compared with EBITDAX of $411.9 million for the fourth
quarter of 2011.

Full-year 2012 EBITDAX was $2.0 billion, a 51 percent increase from EBITDAX of
$1.3 billion for 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.

Crude oil accounted for 72 percent of the Company's fourth quarter 2012
production, compared with 70 percent of full-year 2012 production. The balance
of Continental's production is natural gas and natural gas liquids.

Continental reported oil and natural gas sales of $670.4 million for the
fourth quarter of 2012, compared with $508.3 million for the fourth quarter of
2011, representing a 32 percent increase.

Continental's blended sales price was $68.89 per barrel of oil equivalent
(Boe) in the fourth quarter of 2012, comprised of average prices of $84.99 per
barrel of crude oil and $4.82 per thousand cubic feet (Mcf) for natural gas.
The Company's fourth quarter 2012 average price for crude oil does not include
the effect of a $2.7 million pre-tax realized gain on derivatives, but does
include transportation, gathering and marketing expenses. In the fourth
quarter of 2011, the Company's blended sales price was $72.60 per Boe.

Production expense per Boe was $5.90 for the fourth quarter of 2012, compared
with $5.73 per Boe for the fourth quarter of 2011. As previously announced,
the Company delayed a number of fourth-quarter well completions to stay within
its 2012 capital expenditures budget. Deferred production contributed to
higher per-Boe expenses for the fourth quarter. At year-end 2012, Continental
had an inventory of 122 net wells drilling, completing or waiting on
completion, compared with 62 net wells at year-end 2011.

As previously announced, another key 2012 achievement was the Company's 54
percent increase in proved reserves to 785 million barrels of oil equivalent
at December 31, 2012.

At December 31, 2012, Continental's balance sheet included approximately $36
million in cash and cash equivalents and $3.5 billion in total debt, which
included $595 million borrowed under the Company's revolving credit facility.
Continental's revolving credit facility includes $1.5 billion in bank
commitments and a borrowing base of $3.25 billion.  Exploration and production
(E&P) capital expenditures for 2012 were $3.0 billion, of which 71 percent was
allocated to Bakken exploration and development. The Company also spent an
additional $1.3 billion acquiring producing and non-producing properties,
primarily in the Bakken and in SCOOP plays, representing considerable value in
terms of future drilling opportunities.

Based on current production guidance, approximately 77 percent of forecasted
2013 crude oil production and approximately 33 percent of forecasted 2013
natural gas production is hedged.  Further details on the Company's 2013, 2014
and 2015 derivative positions can be found in Continental's Form 10-K for the
year ended December 31, 2012.    

John D. Hart, Senior Vice President and Chief Financial Officer, added, "Our
EBITDAX and net earnings results were very strong for the fourth quarter 2012
and the full year.  Financially, we ended the year in a position of strength,
closed a bolt-on Bakken acquisition, had ample liquidity, and exited 2012 with
a debt-to-EBITDAX ratio of 1.8, in line with our target we discussed with
investors at our October 2012 Investors Day." 

Improved Oil Differential Impacts 2013 Guidance

Continental's oil differential was $3.21 per barrel for the fourth quarter
2012, a decrease of $6.24 from the third quarter of 2012. Continental's oil
differential reflects an all-in average of transportation costs from well-head
to end market and differential discounts for all of its operated and
non-operated production.  

The improvement since mid-2012 in differentials primarily reflects
Continental's ability to market and deliver oil to premium markets throughout
the United States, with an increased reliance on rail transportation versus
pipeline. In December 2012, 72 percent of the Company's operated Bakken
production was transported to market by rail, compared with only 41 percent in
January 2012.

"Lower differentials and more efficient access to premium markets are key
factors driving higher cash margins and profitability," said Rick Bott,
President and Chief Operating Officer. "We now expect average oil
differentials in 2013 will be $5 to $7 per barrel.

"2012 saw fundamental changes in U.S. oil markets, with Bakken crude shipped
directly to all major U.S. refining centers and making progress, we believe,
toward becoming a national benchmark crude," he said. "Refiners on the East,
Gulf and West coasts value the consistently high quality of sweet Bakken crude
and the fact that supply from the basin continues to grow.

"Consistent with our strategy to develop versatility in transportation modes
and markets, Continental was a first mover in establishing new markets on all
three U.S. coasts for Bakken crude. Because of our size, flexibility and
growth trajectory, we are one of only a few companies capable of providing a
reliable, growing supply of this consistently high-quality crude to major
refinery customers," Mr. Bott said. "End-users in turn continue to build pipe
and rail off-loading facilities at delivery points throughout the nation to
take advantage of the increased visibility of crude oil production growth from
the Bakken."

Well Costs Improvement

Continental also achieved progress in reducing average drilling and completion
costs per well in the fourth quarter of 2012.

This resulted from faster cycle times, lower stimulation costs per stage, and
increased pad drilling in the Bakken. The Company drilled 259 gross wells in
the Bakken with an average of 21 rigs during 2012, or 12 wells per rig for the
year. This compares with an average of seven wells per rig in 2011. A key
contributor to this improvement was Continental's 35 percent improvement in
single well spud-to-spud cycle times last year, compared with 2011.

As another example of reduced well costs, Continental recently completed its
six-well Florida-Alpha project for $46.8 million, or less than $8 million per
well. This compares with an average ECO-Pad^® well cost of $8.5 million per
well in 2012, as disclosed at Continental's Investors Day in October 2012.
Two-thirds of the Company's operated rigs in the Bakken are currently working
on multi-well pad projects.

"Along with our continued focus on operational excellence and safety,
Continental was the first to envision the utility of multi-well pad drilling
in the Bakken and the efficiencies it could generate," Mr. Bott said. "Pad
drilling is the future for full-field development, and, given our transition
to more pads, we are on track to meet our goal of reducing average operated
well costs in the Bakken to $8.2 million per well by year-end 2013, a
reduction of $1 million per well in early 2012."

Operating Highlights

Continental's operating and financial results for 2012 were in line with its
guidance for the year.

                         Three months ended December  Year ended December 31,
                         31,
                         2012            2011         2012         2011
Average daily
production:
Crude oil (Bbl per day)      76,449        53,905       68,497       45,121
Natural gas (Mcf per         182,289       127,883      174,521      100,469
day)
Crude oil equivalents        106,831       75,219       97,583       61,865
(Boe per day)
Average sales prices:
^(1)
Crude oil ($/Bbl)        $   84.99       $ 89.24      $ 84.59      $ 88.51
Natural gas ($/Mcf)          4.82          4.97         4.20         5.24
Crude oil equivalents        68.89         72.60        66.83        73.05
($/Boe)
Production expenses          5.90          5.73         5.49         6.13
($/Boe) ^(1)
General and administrative   3.60          3.02         3.42         3.23
expenses ($/Boe) ^(1)(2)
Net income (loss) (in        220,511       (112,064)    739,385      429,072
thousands) 
Diluted net income           1.19          (0.62)       4.07         2.41
(loss) per share
EBITDAX (in                  594,452       411,919      1,963,123    1,303,959
thousands)^(3)

(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) include non-cash equity
    compensation expense of $0.85 per Boe and relocation expense of $0.05 per
    Boe for the three months ended December 31, 2012 compared to non-cash
    equity compensation expense of $0.69 per Boe and relocation expense of
(2) $0.25 per Boe for the three months ended December 31, 2011.  For the year
    ended December 31, 2012, general and administrative expenses include
    non-cash equity compensation expense of $0.82 per Boe and relocation
    expense of $0.22 per Boe compared to non-cash equity compensation expense
    of $0.73 per Boe and relocation expense of $0.14 per Boe for the year
    ended December 31, 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
(3) 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
    operating cash flows to EBITDAX are provided subsequently under the header
    Non-GAAP Financial Measures.

     

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

                     4Q       3Q       4Q
Boe per day          2012     2012     2011
North Region:
North Dakota Bakken  59,019   55,918   35,565
Montana Bakken       8,503    6,535    5,678
Red River Units      14,716   14,916   15,246
Other                967      1,343    964
South Region:
NW Cana Woodford     9,716    11,395   7,949
SCOOP Woodford       7,123    5,108    1,871
Arkoma Woodford      3,225    4,061    3,688
Other                2,556    2,590    3,080
East Region          1,006    1,098    1,178
Total                106,831  102,964  75,219

In December 2012 Continental sold its producing crude oil and natural gas
properties in its East Region.

Bakken Production Continues to Grow

Continental, the leading liquids producer in the Rocky Mountain region,
reported Bakken production of 67,522 Boepd for the fourth quarter of 2012, a
64 percent increase compared with the fourth quarter of 2011.

Bakken production as a percent of total production continued to increase over
the past year, accounting for 63 percent of the Company's total production in
the fourth quarter of 2012, compared with 55 percent in the fourth quarter of
2011.

Continental almost doubled its proved reserves in the Bakken in 2012, ending
the year with 564 MMBoe in proved reserves at December 31, 2012.

The Company participated in 51 net (135 gross) operated and non-operated wells
in the Bakken during the fourth quarter of 2012.

In terms of operated wells, Continental completed 42 net (55 gross) wells in
the Bakken in the fourth quarter of 2012, with 30 net (42 gross) wells in
North Dakota and the remainder in Montana.

Initial well results continue to meet Continental's expectations. In North
Dakota, Company-operated wells completed during the fourth quarter averaged
1,187 Boepd, while Montana wells averaged 655 Boepd in their initial one-day
test-periods. These results are consistent with the Company's estimated
ultimate recovery (EUR) models of 603,000 Boe for North Dakota wells and
430,000 Boe for Montana wells.

Continental's Lower Three Forks exploratory program is underway with one well
drilling and seven wells completing. The 2013 program, recently expanded to 20
wells, is designed to establish the productive extent of the lower Three Forks
benches, building on the success of the Charlotte 2-22H and 3-22H wells, the
initial producing wells in the second and third benches in the field,
respectively.

Its most recent completion in this program was the Angus 2-9H-2 (85% WI),
which flowed 1,556 Boepd at 3,200 psi in its initial one-day test period. The
Angus 2-9H-2 is the Company's second well to be completed in the second bench
of the Three Forks formation. The well is a significant step-out, located 27
miles northeast of the Charlotte 2-22H.

The Charlotte 2-22H has produced 108 MBoe in approximately 14 months. The
Charlotte 3-22H (TF3) has produced 35 MBoe in its initial three months. The
wells are performing in line with typical Bakken/Three Forks first-bench
wells.

In the future, the Company expects to report quarterly on the exploratory
Lower Three Forks program.

Lower Three Forks Exploration Well Status
Zone  Drilling Completing Producing To Be Drilled Total
TF1            1                    3             4
TF2            3          2         6             11
TF3   1        2          1         1             5
TF4            1                    1             2
Total 1        7          3*        11            22

*Total producing wells include the Charlotte 2-22H and 3-22H, which were
completed prior to the 2013 Lower Three Forks Exploration program, and the
recently completed Angus 2-9H-2.

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

Continental has initiated its first 320-acre pilot density project, with three
wells currently being completed and two more being drilled. The 160-acre pilot
and the next 320-acre pilot are scheduled to spud by mid-2013, with the third
320-acre pilot planned to spud in the third quarter of 2013.

"These are aggressive pilot projects over a wide area in the field," Mr. Bott
said. "We plan to spend the next 18 months drilling and completing the 47
wells, with production coming on line starting in late 2013. All wells in the
program should be producing in the first quarter of 2014.These exploration and
appraisal programs should help determine the ultimate recovery of the field
and drive valuations higher by accelerated de-risking and down-spacing."

Continental increased its Bakken acreage position to approximately 1,140,000
net acres at year-end 2012, up 24 percent from year-end 2011, solidifying its
position as the largest leasehold owner in the play.

The Company plans to complete or participate in completing 226 net (558 gross)
wells in the Bakken in 2013, including both operated and non-operated wells.
The Company currently has 21 operated rigs in the play, with 16 drilling in
North Dakota and five in Montana.

SCOOP/Northwest Cana Woodford Results

Continental produced 7,123 Boepd in the South Central Oklahoma Oil Province
(SCOOP) in the fourth quarter of 2012, a 281 percent increase compared with
fourth quarter production last year and a 39 percent increase compared with
the third quarter 2012 production.

Fourth quarter production in the Northwest Cana (Blaine and Dewey counties)
declined from the third quarter of 2012 due to reduced drilling activity as
the Company refocused capital to the more oily SCOOP.

The Company participated in 10 net (17 gross) wells in SCOOP during the fourth
quarter of 2012. Twelve gross wells were drilled in the condensate fairway and
five in the oil fairway. The new wells' average initial production rates were
in line with or better than the average for earlier wells in the two fairways.

"Although SCOOP is in the early stages of development, we are very pleased
with the repeatability we are seeing within each of the fairways and with the
wells' strong rates of return, which are comparable to the Bakken," said Jack
Stark, Senior Vice President of Exploration. "We're continuing to extend the
limits of the play and to drill to hold our acreage."

Continental-operated wells completed in the condensate fairway since the
beginning of fourth quarter 2012 have included:

  o Cosby 1-13H (84% WI), which produced 1,761 Boepd (23% crude oil) in its
    initial one-day test period;
  o Lowrance 1-10H (73% WI), which produced 1,580 Boepd (38% crude oil) in its
    initial one-day test period;
  o Wooten 1-28H (64% WI), which produced 1,103 Boepd (25% crude oil) in its
    initial one-day test period.

Fourth quarter operated wells in the oil fairway included:

  o Elliott 1-35H (94% WI), which produced 633 Boepd (67% crude oil) in its
    initial one-day test period;
  o Nightengale 1-16H (71% WI), which produced 523 Boepd (78% crude oil) in
    its initial one-day test period.

The new SCOOP wells are producing substantial natural gas liquids. The
combined total of oil and natural gas liquids typically ranges from 45 percent
to 80 percent of production for these wells.

Continental had approximately 218,000 net acres leased in SCOOP as of December
31, 2012, but has since increased its position to approximately 245,000 net
acres. Continental believes its acreage is evenly split between the condensate
and oil fairways. The Company plans to complete or participate in completing
41 net (90 gross) wells in SCOOP in 2013, including both operated and
non-operated wells. The Company currently has 6 operated rigs in SCOOP and
plans to increase to 12 rigs over the course of this year.

Current 2013 Guidance                                         

Production growth range                   35% to 40%
Capital expenditures*                     $3.6 billion
Price differentials:
     WTI crude oil (per barrel of oil)**  $5.00 to $7.00
     Henry Hub natural gas (per Mcf)      +$1.00 to +$1.50
Operating expenses:
     Production expense per Boe           $5.20 to $5.60
     Production tax as a percent 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 compensation per Boe        $0.70 to $0.90
Income tax rate**                         37%
Deferred taxes                            90% to 95%

*Excludes acquisition capital expenditures
**Updated with this press release
***Does not include other expenses, such as natural gas transportation fees,
which could represent another 1%.
****Excludes non-cash equity compensation of $0.70 to $0.90 per Boe

Conference Call Information

Continental Resources plans to host a conference call to discuss fourth
quarter and full-year 2012 results on Thursday, February 28, 2013, at 10 a.m.
ET (9 a.m. CT). Those wishing to listen to the conference call may do so via
the Company's web site at www.CLR.com or by phone:

Time and date:          10 a.m. ET
                        Thursday, February 28, 2013
Dial in:                888 680 0878
Intl. dial in:          617 213 4855
Pass code:              14983127

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:     29374525

Callers who wish to pre-register for the call may go to:
https://www.theconferencingservice.com/prereg/key.process?key=PCPLHQ7VN

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 on the day of the presentation.

March 4  2013 Raymond James 34^th Annual Institutional Investors Conference,
         Orlando
March 18 2013 Howard Weil 41^st Annual Energy 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 $2.6 billion for 2012. Continental is headquartered in Oklahoma
City. 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, 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 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, 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, VP Investor Relations    Kristin Miskovsky, VP Public Relations
405-234-9127                           405-234-9480
Warren.Henry@CLR.com                   Kristin.Miskovsky@CLR.com

 

Consolidated Statements of Income
                         Three months ended December  Year ended December 31,
                         31,
                         2012            2011         2012         2011
Revenues:                In thousands, except per share data
Crude oil and natural    $   670,438     $ 508,309    $ 2,379,433  $ 1,647,419
gas sales
Gain (loss) on
derivative instruments,      9,639         (402,539)    154,016      (30,049)
net
Crude oil and natural        8,895         8,348        39,071       32,419
gas service operations
Total revenues               688,972       114,118      2,572,520    1,649,789
Operating costs and
expenses:
Production expenses          57,399        40,146       195,440      138,236
Production taxes and         65,558        44,495       228,438      144,810
other expenses
Exploration expenses         5,755         6,260        23,507       27,920
Crude oil and natural        7,525         7,022        32,248       26,735
gas service operations
Depreciation, depletion,     192,271       126,663      692,118      390,899
amortization and accretion
Property impairments         29,121        42,143       122,274      108,458
General and                  35,031        21,121       121,735      72,817
administrative expenses 
Gain on sale of assets,      (68,908)      (5,451)      (136,047)    (20,838)
net
Total operating costs        323,752       282,399      1,279,713    889,037
and expenses
Income (loss) from           365,220       (168,281)    1,292,807    760,752
operations
Other income (expense):
Interest expense             (45,534)      (19,985)     (140,708)    (76,722)
Other                        817           890          3,097        3,415
                             (44,717)      (19,095)     (137,611)    (73,307)
Income (loss) before         320,503       (187,376)    1,155,196    687,445
income taxes
Provision (benefit) for      99,992        (75,312)     415,811      258,373
income taxes
Net income (loss)        $   220,511     $ (112,064)  $ 739,385    $ 429,072
Basic net income (loss)  $   1.20        $ (0.62)     $ 4.08       $ 2.42
per share
Diluted net income       $   1.19        $ (0.62)     $ 4.07       $ 2.41
(loss) per share

 

 

Consolidated Balance Sheets
                                           December 31,  December 31,
                                           2012          2011
Assets                                     In thousands
Current assets                             $  946,783    $  936,373
Net property and equipment                    8,105,269     4,681,733
Other noncurrent assets                       87,957        27,980
Total assets                               $  9,140,009  $  5,646,086
Liabilities and shareholders' equity
Current liabilities                        $  1,125,865  $  1,111,801
Long-term debt                                3,537,771     1,254,301
Other noncurrent liabilities                  1,312,674     971,858
Total shareholders' equity                    3,163,699     2,308,126
Total liabilities and shareholders' equity $  9,140,009  $  5,646,086

 

 

Consolidated Statements of Cash Flows
                                                  Year ended December 31, 
                                                  2012           2011
                                                  In thousands
Net income                                        $ 739,385      $ 429,072
Adjustments to reconcile net income to net cash
provided by operating activities:
Non-cash expenses                                   905,695        748,792
Changes in assets and liabilities                   (13,015)       (109,949)
Net cash provided by operating activities           1,632,065      1,067,915
Net cash used in investing activities               (3,903,370)    (2,004,714)
Net cash provided by financing activities           2,253,490      982,427
Net change in cash and cash equivalents             (17,815)       45,628
Cash and cash equivalents at beginning of period    53,544         7,916
Cash and cash equivalents at end of period        $ 35,729       $ 53,544

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 provides a
reconciliation of our net income to EBITDAX for the periods presented.

                     Three months ended December 31,  Year ended December 31,
                     2012             2011            2012         2011
                     in thousands
Net income (loss)    $   220,511      $   (112,064)   $ 739,385    $ 429,072
Interest expense         45,534           19,985        140,708      76,722
Provision (benefit)      99,992           (75,312)      415,811      258,373
for income taxes
Depreciation,
depletion,               192,271          126,663       692,118      390,899
amortization and
accretion
Property impairments     29,121           42,143        122,274      108,458
Exploration expenses     5,755            6,260         23,507       27,920
Impact from
derivative
instruments:
Total (gain) loss on     (9,639)          402,539       (154,016)    30,049
derivatives, net
Total realized gain
(loss) (cash flow)       2,655            (3,125)       (45,721)     (34,106)
on derivatives, net
Non-cash (gain) loss     (6,984)          399,414       (199,737)    (4,057)
on derivatives, net
Non-cash equity          8,252            4,830         29,057       16,572
compensation
EBITDAX              $   594,452      $   411,919     $ 1,963,123  $ 1,303,959

 

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

                                                 Year ended December 31,
                                                 2012         2011
                                                 in thousands
Net cash provided by operating activities        $ 1,632,065  $ 1,067,915
Current income tax provision                       10,517       13,170
Interest expense                                   140,708      76,722
Exploration expenses, excluding dry hole costs     22,740       19,971
Gain on sale of assets, net                        136,047      20,838
Excess tax benefit from stock-based compensation   15,618       -
Other, net                                         (7,587)      (4,606)
Changes in assets and liabilities                  13,015       109,949
EBITDAX                                          $ 1,963,123  $ 1,303,959

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 December 31, 
                              2012                  2011
In thousands, except per      After-Tax $  Diluted  After-Tax $  Diluted EPS
share data                                 EPS
Net income (loss) (GAAP)      $ 220,511    $        $(112,064)   $      
                                            1.19                 (0.62)
Adjustments, net of tax:
 Non-cash (gain) loss on      (4,331)      (0.02)   247,237      1.37
 derivatives, net
 Property impairments         18,054       0.10     26,087       0.14
 Gain on sale of assets, net  (42,723)     (0.23)   (3,374)      (0.02)
 Corporate relocation         290          -        1,076        0.01
 expenses
   Adjusted net income        $ 191,801    $        $ 158,962    $        0.88
   (Non-GAAP)                               1.04
   Weighted average diluted   184,603               180,343
   shares outstanding
   Adjusted diluted net
   income per share           $      1.04           $      0.88
   (Non-GAAP)

                              Year ended December 31, 
                              2012                        2011
In thousands, except per      After-Tax $  Diluted EPS    After-Tax $  Diluted
share data                                                             EPS
Net income (GAAP)             $ 739,385    $        4.07  $ 429,072    $      
                                                                        2.41
Adjustments, net of tax:
 Non-cash gain on             (123,838)    (0.68)         (2,511)      (0.01)
 derivatives, net
 Property impairments         75,810       0.41           67,136       0.37
 Gain on sale of assets, net  (84,349)     (0.46)         (12,899)     (0.07)
 Corporate relocation         4,862        0.02           1,974        0.01
 expenses
   Adjusted net income        $ 611,870    $        3.36  $ 482,772    $      
   (Non-GAAP)                                                           2.71
   Weighted average diluted   181,846                     178,230
   shares outstanding
   Adjusted diluted net
   income per share           $      3.36                 $      2.71
   (Non-GAAP)

SOURCE Continental Resources

Website: http://www.clr.com
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