Continental Resources Reports 55 Percent Production Growth And 46
Percent EBITDAX Growth In Third Quarter Of 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)
- Record 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;
- $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;
- A $9.45 per barrel oil
differential for the third quarter of 2012, with September's
differential improving to $5.19 per
barrel;
- Capital 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
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Three
months ended September 30,
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Nine
months ended September 30,
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2012
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2011
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2012
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2011
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Average
daily production:
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Crude oil
(Bbl per day)
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72,235
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47,552
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65,826
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42,160
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Natural
gas (Mcf per day)
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184,377
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112,423
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171,912
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91,231
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Crude oil
equivalents (Boe per day)
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102,964
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66,289
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94,478
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57,365
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Average
sales prices: (1)
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Crude oil
($/Bbl)
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$
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82.87
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$
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84.02
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$
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84.44
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$
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88.19
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Natural
gas ($/Mcf)
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4.00
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5.50
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3.97
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5.37
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Crude oil
equivalents ($/Boe)
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65.62
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69.57
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66.06
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73.25
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Production
expenses ($/Boe) (1)
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5.62
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5.98
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5.34
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6.31
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General
and administrative expenses ($/Boe) (1)(2)
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3.31
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2.98
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3.35
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3.32
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Net income
(in thousands)
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44,096
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439,143
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518,874
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541,136
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Diluted
net income per share
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0.24
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2.44
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2.86
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3.05
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EBITDAX
(in thousands)(3)
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492,279
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337,754
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1,368,671
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892,040
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(1)
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Average
sales prices and per unit expenses have been calculated using sales
volumes and exclude any effect of derivative
transactions.
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(2)
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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 $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.
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(3)
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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 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.
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3Q
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2Q
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3Q
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Boe per
day
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2012
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2012
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2011
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North
Region:
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North
Dakota Bakken
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55,918
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47,166
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28,987
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Montana
Bakken
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6,535
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6,305
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5,518
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Red River
Units
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14,916
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15,482
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14,954
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Other
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1,343
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1,445
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1,052
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South
Region:
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NW Cana
Woodford
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11,320
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13,516
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5,949
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SCOOP
Woodford
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5,183
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3,156
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1,215
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Arkoma
Woodford
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4,061
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3,806
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4,099
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Other
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2,590
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2,912
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3,387
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East
Region
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1,098
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1,064
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1,128
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Total
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102,964
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94,852
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66,289
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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.
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Crude Oil Derivative
Positions
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Swaps
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Collars
Wtd. Avg. Price
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Period and
Type of Contract
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Bbls
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Wtd. Avg.
Price
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Floor
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Ceiling
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October
2012 - December 2012
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Swaps -
WTI
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1,840,000
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$88.69
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Swaps -
Brent
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1,058,000
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$111.17
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Collars -
WTI
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1,340,440
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$80.00
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$94.71
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January
2013 - December 2013
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Swaps -
WTI
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11,862,500
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$92.66
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Swaps -
Brent
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2,372,500
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$109.19
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Collars -
WTI
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8,760,000
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$86.92
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$99.46
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January
2014 - December 2014
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Swaps -
WTI
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10,311,250
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$96.20
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Swaps -
Brent
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4,745,000
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$100.43
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Collars -
Brent
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1,460,000
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$90.00
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$107.50
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January
2015 - December 2015
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Swaps -
Brent
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1,277,500
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$98.48
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Natural Gas Derivative
Positions
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Swaps
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Period and
Type of Contract
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MMBtus
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Wtd. Avg.
Price
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January
2013 - December 2013
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Swaps -
Henry Hub
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18,250,000
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$3.76
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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
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30% to 35%
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Capital
expenditures*
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$3.4B
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Price
differentials:
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WTI crude oil (per barrel of
oil)
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$8 to
$11
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Henry Hub natural gas (per
Mcf)
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+$1.00 to
$1.50
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Operating
expenses:
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Production expense per
Boe
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$5.50 to
$5.90
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Production tax as a percent
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of oil and gas
revenues**
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8% to
9%
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DD&A per Boe
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$19 to
$21
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G&A expense per
Boe***
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$2.40 to
$2.90
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Non-cash equity compensation per
Boe
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$0.70 to
$0.90
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Income tax
rate
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38%
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Deferred
taxes
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90% to
95%
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* 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:
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10 a.m.
ET
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Thursday,
November 8, 2012
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Dial
in:
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888 680
0878
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Intl. dial
in:
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617 213
4855
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Pass
code:
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32316165
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A replay
of the call will be available for 30 days on the Company's web site
or by dialing:
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Replay
number:
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888 286
8010
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Intl.
replay
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617 801
6888
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Pass
code:
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72440131
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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
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2012
Bank of America Merrill Lynch Global Energy Conference,
Miami
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Nov.
14
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IHS
Pacesetters Energy Conference 2012, Washington, D.C.
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Nov.
28-29
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Jefferies
Global Energy Conference, Houston
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Dec.
3-4
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Dahlman
Rose Ultimate Oil Services and E&P Conference, New
York
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Dec.
3-5
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Bank of
America Merrill Lynch Leveraged Finance Conference 2012, Boca
Raton, FL
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Dec.
5
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Capital
One SouthCoast Equity Conference, New Orleans
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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.
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Investors
|
Media
|
Warren
Henry, VP Investor Relations
|
Kristin
Miskovsky, VP Public Relations
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405-234-9127
|
405-234-9480
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Warren.Henry@CLR.com
|
Kristin.Miskovsky@CLR.com
|
Unaudited Condensed Consolidated Statements of
Income
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Three
months ended September 30,
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Nine
months ended September 30,
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2012
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2011
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2012
|
|
2011
|
Revenues:
|
In
thousands, except per share data
|
Crude oil
and natural gas sales
|
$
|
633,344
|
|
$
|
423,859
|
|
$
|
1,708,995
|
|
$
|
1,139,110
|
Gain
(loss) on derivative instruments, net
|
|
(158,294)
|
|
|
537,340
|
|
|
144,377
|
|
|
372,490
|
Crude oil
and natural gas service operations
|
|
8,679
|
|
|
7,790
|
|
|
30,176
|
|
|
24,071
|
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 other expenses
|
|
62,913
|
|
|
39,262
|
|
|
162,880
|
|
|
100,315
|
Exploration expenses
|
|
4,899
|
|
|
9,814
|
|
|
17,752
|
|
|
21,660
|
Crude oil
and natural gas service operations
|
|
7,626
|
|
|
6,198
|
|
|
24,723
|
|
|
19,713
|
Depreciation, depletion, amortization and
accretion
|
189,374
|
|
|
105,085
|
|
|
499,847
|
|
|
264,236
|
Property
impairments
|
|
27,375
|
|
|
26,225
|
|
|
93,153
|
|
|
66,315
|
General
and administrative expenses (1)
|
|
31,925
|
|
|
18,140
|
|
|
86,704
|
|
|
51,696
|
(Gain)
loss on sale of assets, net
|
|
(115)
|
|
|
188
|
|
|
(67,139)
|
|
|
(15,387)
|
Total
operating costs and expenses
|
|
378,207
|
|
|
241,371
|
|
|
955,961
|
|
|
606,638
|
Income
from operations
|
|
105,522
|
|
|
727,618
|
|
|
927,587
|
|
|
929,033
|
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 taxes
|
|
67,027
|
|
|
709,631
|
|
|
834,693
|
|
|
874,821
|
Provision
for income taxes
|
|
22,931
|
|
|
270,488
|
|
|
315,819
|
|
|
333,685
|
Net
income
|
$
|
44,096
|
|
$
|
439,143
|
|
$
|
518,874
|
|
$
|
541,136
|
Basic net
income per share
|
$
|
0.24
|
|
$
|
2.45
|
|
$
|
2.88
|
|
$
|
3.06
|
Diluted
net income per share
|
$
|
0.24
|
|
$
|
2.44
|
|
$
|
2.86
|
|
$
|
3.05
|
(1)
|
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 $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 period
|
|
53,544
|
|
|
7,916
|
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 30,
|
|
Nine
months ended September 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 taxes
|
|
22,931
|
|
|
270,488
|
|
|
315,819
|
|
|
333,685
|
Depreciation, depletion, amortization and
accretion
|
|
189,374
|
|
|
105,085
|
|
|
499,847
|
|
|
264,236
|
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 derivatives, net
|
|
158,294
|
|
|
(537,340)
|
|
|
(144,377)
|
|
|
(372,490)
|
Total
realized gain (loss) (cash flow) on derivatives, net
|
|
(1,394)
|
|
|
1,113
|
|
|
(48,375)
|
|
|
(30,981)
|
Non-cash
(gain) loss on derivatives, net
|
|
156,900
|
|
|
(536,227)
|
|
|
(192,752)
|
|
|
(403,471)
|
Non-cash
equity compensation
|
|
7,499
|
|
|
4,245
|
|
|
20,804
|
|
|
11,742
|
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 operating activities
|
$
|
1,147,897
|
|
$
|
669,814
|
|
|
|
|
|
|
Current
income tax provision (benefit)
|
|
(7,724)
|
|
|
9,331
|
|
|
|
|
|
|
Interest
expense
|
|
95,174
|
|
|
56,737
|
|
|
|
|
|
|
Exploration expenses, excluding dry hole
costs
|
|
17,433
|
|
|
17,902
|
|
|
|
|
|
|
Gain on
sale of assets, net
|
|
67,139
|
|
|
15,387
|
|
|
|
|
|
|
Other,
net
|
|
(4,116)
|
|
|
(4,845)
|
|
|
|
|
|
|
Changes in
assets and liabilities
|
|
52,868
|
|
|
127,714
|
|
|
|
|
|
|
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 share data
|
|
After-Tax
$
|
|
Diluted
EPS
|
|
After-Tax
$
|
|
Diluted
EPS
|
Net income
(GAAP)
|
|
$
44,096
|
|
$
0.24
|
|
$
439,143
|
|
$
2.44
|
Adjustments, net of tax:
|
|
|
|
|
|
|
|
|
|
Non-cash
(gain) loss on derivatives, net
|
|
97,121
|
|
0.53
|
|
(332,461)
|
|
(1.84)
|
|
Property
impairments
|
|
16,945
|
|
0.09
|
|
16,259
|
|
0.09
|
|
(Gain)
loss on sale of assets, net
|
|
(71)
|
|
-
|
|
117
|
|
-
|
|
Corporate
relocation expenses
|
|
1,420
|
|
0.01
|
|
649
|
|
-
|
|
|
Adjusted
net income (Non-GAAP)
|
|
$
159,511
|
|
$
0.87
|
|
$
123,707
|
|
$
0.69
|
|
|
Weighted
average diluted shares outstanding
|
|
182,537
|
|
|
|
180,245
|
|
|
|
|
Adjusted
diluted net income per share (Non-GAAP)
|
|
$
0.87
|
|
|
|
$
0.69
|
|
|
SOURCE Continental Resources, Inc.