OKLAHOMA CITY, Aug. 8, 2017 /PRNewswire/ -- Continental
Resources, Inc. (NYSE: CLR) (the Company) today announced second
quarter operating and financial results. Continental reported a net
loss of $63.6 million, or
$0.17 per diluted share, for the
quarter ended June 30, 2017.
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The Company's net loss includes certain items typically excluded
by the investment community in published estimates, the result of
which is referred to as "adjusted net loss." In second quarter
2017, these typically excluded items in aggregate represented
$61.8 million, or $0.17 per diluted share, of Continental's
reported net loss. Adjusted net loss for the second quarter was
$1.8 million, or $0.00 per diluted share.
Net cash provided by operating activities for second quarter
2017 was $446.4 million. EBITDAX for
second quarter 2017 was $479.5
million. Definitions and reconciliations of adjusted net
income and net loss, adjusted net income and net loss per share,
EBITDAX and cash G&A expense to the most directly comparable
U.S. generally accepted accounting principles (GAAP) financial
measures are provided in the supporting tables and 2017 guidance
summary at the conclusion of this press release.
"Continental remained disciplined and strategic with its capital
spending during the quarter," said Harold
Hamm, Chairman and Chief Executive Officer. "The results
have been exceptional, raising our production guidance for 2017 and
lowering our guidance for operating costs. We now expect to exit
2017 with production up 24% to 31% over the fourth quarter of 2016,
with a lower range of capital expenditures for the year targeting
cash neutrality between $45 and $51
WTI."
Mr. Hamm noted the Company recently surpassed a significant
production milestone, with individual days of output of 250,000 Boe
per day. "We're bringing on a lot of pad projects. Looking ahead,
given the anticipated timing of additional pad projects in the
Bakken and STACK, we expect third quarter 2017 production will
average 240,000 to 250,000 Boe per day, with 58% of production
being crude oil," he said.
"The continuous improvements we are achieving position
Continental for even better results in 2018."
Improved 2017 Guidance Reflects Superior Assets, Efficiency
Gains and Disciplined Capital Program
The Company now expects annual production will be in a higher
range of 230,000 to 240,000 Boe per day, compared to its previous
guidance of 220,000 to 230,000 Boe per day. Continental expects to
exit the year with production between 260,000 and 275,000 Boe per
day, compared to the previous exit-rate guidance of 250,000 to
260,000 Boe per day. Continental is also adjusting its capital
expenditures for 2017 to a range between $1.75 billion and $1.95 billion. This level of
capital expenditure is expected to maintain cash neutrality at WTI
prices between $45 and $51 per barrel
for the year. Adjustments to capital expenditures will be
accomplished primarily by reducing completion crews and rigs. The
rig count for the second half of the year is projected to average
18, with 14 in Oklahoma and four
in Bakken. The Company has reduced its Bakken completion crew count
to four and has six crews in Oklahoma. As a result, the Company expects to
exit 2017 with a drilled but uncompleted (DUC) inventory in the
Bakken of approximately 160 gross operated wells, including
approximately 35 already stimulated with first production expected
in 2018, providing a strong catalyst for further oil focused
production growth in 2018.
Continental reduced 2017 guidance for production expense per
Boe, which is now expected to be in a range of $3.50 to $3.90 per Boe for the year, down from
$3.50 to $4.00 per Boe.
The Company also reduced its G&A guidance for 2017,
following lower G&A expense per Boe in the second quarter.
Total G&A expense, which is comprised of cash and non-cash
G&A expense, is expected to be $1.85 to
$2.35 per Boe for 2017. Of this total, cash G&A expense
is expected to be $1.35 to $1.75 per
Boe for 2017, a reduction from the previous $1.50 to $2.00 per Boe. Non-cash equity
compensation is expected to be $0.50 to
$0.60 per Boe, a reduction from the previous $0.60 to $0.70 per Boe.
Continental also reduced 2017 guidance for DD&A to
$18.00 to $20.00 per Boe for the
year, down approximately 7% from the previous range.
Finally, the Company improved its outlook for oil price
differentials, reflecting the impact of additional pipeline
capacity in the Bakken and continued infrastructure improvements in
Oklahoma. Average crude oil price
differential for 2017 companywide is expected to be in a range of
$5.50 to $6.50 per barrel of oil
(Bo), $1.00 below the previous
guidance of $6.50 to $7.50. The
Company expects further improvements to its crude oil price
differential in 2018. The Company also adjusted its outlook for
natural gas price differentials, reflecting continued natural gas
liquids price weakness. The differential is now expected to be a
negative $0.10 to a negative
$0.50 per Mcf.
2017 Updated
Guidance Metrics
|
Previous 2017
Guidance
|
Updated 2017
Guidance
|
Annual
production (Boe per day)
|
220,000 to
230,000
|
230,000 to
240,000
|
Exit rate production
(Boe per day)
|
250,000 to
260,000
|
260,000 to
275,000
|
Capital expenditures
(non-acquisition)
|
$1.95
billion
|
$1.75 to $1.95
billion
|
Production expense
per Boe
|
$3.50 to
$4.00
|
$3.50 to
$3.90
|
Cash G&A expense
per Boe(1)
|
$1.50 to
$2.00
|
$1.35 to
$1.75
|
Non-cash equity
compensation per Boe
|
$0.60 to
$0.70
|
$0.50 to
$0.60
|
DD&A per
Boe
|
$19.00 to
$22.00
|
$18.00 to
$20.00
|
Average price
differential for NYMEX WTI crude oil (per Bo)
|
($6.50) to
($7.50)
|
($5.50) to
($6.50)
|
Average price
differential for Henry Hub natural gas (per Mcf)
|
$0.10 to
($0.40)
|
($0.10) to
($0.50)
|
1.
|
Cash G&A is a
non-GAAP measure and excludes the range of values shown for
non-cash equity compensation per Boe in the item appearing
immediately below. Guidance for total G&A (cash and non-cash)
is an expected range of $1.85 to $2.35 per Boe.
|
The Company's full 2017 guidance is stated in a table at the
conclusion of this release.
"The superior quality of our assets and operations continues to
translate to the bottom line," said Jack
Stark, President. "As our historical performance and
updated guidance show, Continental is one of the lowest cost
operators in the industry, delivering some of the best margins and
recycle ratios among our peers."
Production
Second quarter 2017 net production totaled 20.6 million Boe, or
226,213 Boe per day, up 12,458 Boe per day from first quarter 2017,
or approximately 6%.
Total net production for second quarter 2017 included 125,381 Bo
per day (55% of production) and 605 million cubic feet (MMcf) of
natural gas per day (45% of production).
The following table provides the Company's average daily
production by region for the periods presented.
|
|
2Q
|
|
1Q
|
|
2Q
|
|
YTD
|
|
YTD
|
Boe per
day
|
|
2017
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
North
Region:
|
|
|
|
|
|
|
|
|
|
|
North Dakota
Bakken
|
|
112,397
|
|
101,012
|
|
114,554
|
|
106,736
|
|
121,861
|
Montana
Bakken
|
|
7,464
|
|
7,980
|
|
10,474
|
|
7,720
|
|
10,454
|
Red River
Units
|
|
9,878
|
|
10,089
|
|
11,075
|
|
9,983
|
|
11,188
|
Other
|
|
483
|
|
333
|
|
695
|
|
409
|
|
672
|
South
Region:
|
|
|
|
|
|
|
|
|
|
|
SCOOP
|
|
61,107
|
|
62,178
|
|
64,669
|
|
61,640
|
|
64,642
|
STACK
|
|
31,934
|
|
29,216
|
|
14,610
|
|
30,582
|
|
12,868
|
Arkoma
|
|
1,788
|
|
1,754
|
|
1,862
|
|
1,771
|
|
1,950
|
Other
|
|
1,162
|
|
1,193
|
|
1,384
|
|
1,177
|
|
1,428
|
Total
|
|
226,213
|
|
213,755
|
|
219,323
|
|
220,018
|
|
225,063
|
Bakken: Type Curve ROR Doubled to 82%
Continental's Bakken net production averaged 119,861 Boe per day
in second quarter 2017. The Company had 100 gross (38 net) operated
and non-operated Bakken wells completed during second quarter 2017.
At June 30, 2017, the Company had 205
gross operated DUCs.
In the second quarter, the Company had 19 gross operated wells
with first production with an average 24-hour initial production
(IP) rate of 1,606 Boe per day (82% oil). Five of the second
quarter wells rank in the Company's top 10 all-time producing
Bakken wells, based on 30 days of production. Also during the
quarter, Continental expanded the success of its optimized
completions 40 miles south of existing activity in northeast
McKenzie County to central Dunn County.
Based on the success of its optimized completions, the Company
announced a 12% increase in its type curve EUR to 1,100 MBoe per
well with a 24-hour IP of approximately 1,500 Boe. At an estimated
completed well cost of $7.5 million
for a 2-mile lateral well, a 1,100 MBoe EUR Bakken well will yield
an 82% ROR at $50 per barrel WTI and
$3.25 per Mcf of gas. This is more
than double the ROR compared to the previous 980 MBoe Bakken type
curve. Cumulative production at 180 days is approximately 64,000
Boe higher compared to the 980 MBoe type curve, generating over
$2 million more revenue in the first
six months. The new 1,100 MBoe type curve has a quicker estimated
payout period of 1.25 years, compared to 2.5 years for wells with
the previous type curve.
"In 2017 our Bakken team has doubled our rate of return and
reduced the payout period by 50%, based on our new type curve,"
said Gary Gould, Senior Vice
President of Production and Resource Development. "This is a
step-change improvement in Bakken economics."
STACK: The Company Announces Record Well and Initial Type
Curve with 80% ROR for Condensate Window
Continental's STACK net production averaged 31,934 Boe per day
in second quarter 2017. The Company had 36 gross (12 net) operated
and non-operated STACK wells completed during second quarter 2017.
By the end of August, the Company will have nine operated rigs in
the play, with seven rigs targeting the Meramec formation and two
targeting the Woodford
formation.
The Company reported six operated standalone wells in the STACK
Meramec over-pressured oil and condensate windows. Initial 24-hour
production test rates for these six wells averaged 1,915 Boe per
day (45% oil) from an average 6,860-foot lateral.
In early August the Company completed a record well in STACK.
The Tres C FIU 1-35-2XH flowed an impressive 1,021 Bo and 29.6 MMcf
of gas (5,953 Boe) in its initial 24-hour test, with flowing casing
pressure of 6,500 pounds per square inch from a 9,748-foot lateral.
Adding an additional 1,978 barrels of anticipated natural gas
liquids post-processing, Continental estimates the initial 24-hour
IP rate for the Tres C would be a record 7,442 Boe (40% liquids) on
a three-stream basis.
The Company also announced a type curve EUR of 2,400 MBoe (14%
oil) for wells in the STACK over-pressured condensate window. At a
targeted completed well cost of $10
million, a 9,800-foot lateral condensate well would generate
an 80% ROR at $50 per barrel WTI and
$3.25 per Mcf of natural gas.
The Company recently began flowing back the third of seven
Meramec density tests it has in process to establish proper well
spacing for future development of the Meramec reservoirs. The
Blurton unit was an 8-well density test, with three new wells in
the upper Meramec and four new wells and the existing parent well
in the lower Meramec. Average lateral length was approximately
10,000 feet per well. The unit is still in the early stages of
flowing back and has not reached peak production rates. To date the
combined 24-hour initial rate recorded from the eight wells is
10,514 Boe per day, with 78% of production being oil. Including
estimated post-processing natural gas liquids, the combined 24-hour
IP rate would have been approximately 11,883 Boe per day. The
Company continues to monitor the flowback of these wells and will
incorporate the results from the Blurton with those of other
density tests to guide future development in STACK.
SCOOP: Springer Shines
In second quarter 2017, SCOOP net production averaged 61,107 Boe
per day (27% oil). Continental had 8 gross (2 net) operated and
non-operated wells completed during second quarter 2017.
Continental currently has five operated drilling rigs working in
SCOOP, targeting the Springer,
Sycamore and Woodford
formations.
During the quarter, Continental announced one SCOOP Springer
well, the Robinson 2-15-10XHS. The initial 24-hour production test
rate was 1,636 Boe per day (82% oil) from a 7,700-foot lateral. The
Robinson outperformed the Company's historical 940 MBoe Springer
type curve by 89% in the first 60 days on production.
Last quarter, the Company announced the completion of the Cash
1-26H, an optimized Springer
producing well. At 90 days the Cash outperformed the Company's 940
MBoe type curve by 82%. At a cost of $7.6
million and an estimated EUR of 1,160 MBoe, the Cash well
has an estimated rate of return of over 100% and pays out in 12
months, assuming $50 per barrel WTI
and $3.25 per Mcf of gas. Longer
laterals, combined with shorter drill times and optimized
completions, are improving Springer well economics.
A notable second quarter well in the SCOOP Woodford oil window
was the Romanoff 1-25-24-13XH in eastern Grady County, which had a 24-hour IP rate of
1,188 Bo and 2.3 MMcf (1,563 Boe) from a 14,900-foot lateral. This
was the Company's first 3-mile lateral well in SCOOP. At 30 days,
the well was outperforming offset wells by over 25%, when
normalized to a 7,500-foot lateral, and had an average 30-day
production rate of 1,424 Boe per day (75% oil).
Two other recent completions in the SCOOP Woodford condensate
window were the Renea 1-23-14XH and Cottonwood East 1-25-24XH
wells. The Renea's 24-hour IP was 2,322 Boe per day (18% oil) from
a 10,160-foot lateral. The Cottonwood East's 24-hour IP was 1,918
(34% oil) from a 7,800-foot lateral. The Renea and Cottonwood
outperformed legacy offset wells by 80% to 90% during their first
30 days. They are located in an area of Stephens County where the Company has not been
active for the past two years.
Company Agrees to Sell Non-Strategic Leasehold and Property
for $147.5 Million
Continental announced today it has signed two definitive
purchase and sale agreements with undisclosed buyers to sell 6,590
net acres of non-core leasehold in the oil window of STACK in
northern Blaine County, Oklahoma
for $72.5 million, and 26,000 net
acres of leasehold in the Arkoma
Basin located in Atoka,
Coal, Hughes and Pittsburg counties, Oklahoma for
$68.0 million. The leaseholds are
non-strategic and include minimal proved reserves. The agreements
provide for customary closing conditions and adjustments. The
Company is also selling oil-loading facilities in Oklahoma for $7.0
million. The Company intends to use the proceeds from the
sales to reduce outstanding debt and noted that it has other
opportunities for non-core asset sales.
Financial Update
"Continental's results through the first half of the year
reflect strong outperformance and continued operating cost and
capital expenditure discipline," said John
Hart, Chief Financial Officer. "We are raising our
production estimates while lowering guidance for operating costs.
The updated guidance metrics are expected to be achieved while
targeting cash neutrality between $45 and
$51 WTI with capital expenditures ranging from $1.75 billion to $1.95 billion.
"Oil production was 55% of total production for second quarter,
slightly lower than consensus primarily due to working interest
adjustments. For third quarter we are projecting production to be
58% oil as additional Bakken and Springer wells are completed."
In second quarter 2017, Continental's average realized sales
price excluding the effects of derivative positions was
$41.91 per barrel of oil and
$2.63 per Mcf of gas, or $30.31 per Boe. Based on realizations without the
effect of derivatives, the Company's second quarter 2017 oil
differential was $6.31 per barrel
below the NYMEX daily average for the period, $0.78 better than the first quarter differential.
The realized wellhead natural gas price for the quarter was on
average $0.56 per Mcf below the
average NYMEX Henry Hub benchmark price.
Production expense per Boe was $3.99 for second quarter 2017. Other select
operating costs and expenses for second quarter 2017 included
production taxes of 6.7% of oil and natural gas sales, DD&A of
$19.14 per Boe, and total G&A of
$1.89 per Boe.
Non-acquisition capital expenditures for second quarter 2017
totaled approximately $551.9 million.
Non-acquisition capital expenditures for the quarter included
$471.0 million in exploration and
development drilling, $51.6 million
in leasehold and seismic, and $29.3
million in workovers, recompletions and other.
As of June 30, 2017, Continental's
balance sheet included approximately $17.2
million in cash and cash equivalents and $6.56 billion in long-term debt, essentially
in-line with first quarter 2017.
The following table provides the Company's production results,
average sales prices, per-unit operating costs, results of
operations and certain non-GAAP financial measures for the periods
presented. Average sales prices exclude any effect of derivative
transactions. Per-unit expenses have been calculated using sales
volumes.
|
Three months ended
June 30,
|
|
Six months ended June
30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Average daily
production:
|
|
|
|
|
|
|
|
Crude oil (Bbl per
day)
|
125,381
|
|
133,044
|
|
122,308
|
|
139,756
|
Natural gas (Mcf per
day)
|
604,991
|
|
517,677
|
|
586,263
|
|
511,837
|
Crude oil equivalents
(Boe per day)
|
226,213
|
|
219,323
|
|
220,018
|
|
225,063
|
Average sales prices,
excluding effect from derivatives:
|
|
|
|
|
|
|
|
Crude oil
($/Bbl)
|
$41.91
|
|
$38.38
|
|
$43.26
|
|
$31.76
|
Natural gas
($/Mcf)
|
$2.63
|
|
$1.31
|
|
$2.81
|
|
$1.33
|
Crude oil equivalents
($/Boe)
|
$30.31
|
|
$26.36
|
|
$31.56
|
|
$22.73
|
Production expenses
($/Boe)
|
$3.99
|
|
$3.72
|
|
$3.89
|
|
$3.74
|
Production taxes (%
of oil and gas revenues)
|
6.7%
|
|
7.4%
|
|
6.6%
|
|
7.5%
|
DD&A
($/Boe)
|
$19.14
|
|
$22.15
|
|
$19.48
|
|
$22.16
|
Total general and
administrative expenses ($/Boe) (1)
|
$1.89
|
|
$1.82
|
|
$2.16
|
|
$1.68
|
Net loss (in
thousands)
|
($63,557)
|
|
($119,402)
|
|
($63,088)
|
|
($317,727)
|
Diluted net loss per
share
|
($0.17)
|
|
($0.32)
|
|
($0.17)
|
|
($0.86)
|
Adjusted net income
(loss) (non-GAAP) (in thousands) (2)
|
($1,801)
|
|
($65,910)
|
|
$4,979
|
|
($216,378)
|
Adjusted diluted net
income (loss) per share (non-GAAP) (2)
|
$0.00
|
|
($0.18)
|
|
$0.01
|
|
($0.58)
|
Net cash provided by
operating activities
|
$446,371
|
|
$218,819
|
|
$916,572
|
|
$497,721
|
EBITDAX (non-GAAP)
(in thousands) (2)
|
$479,490
|
|
$528,109
|
|
$961,963
|
|
$842,718
|
|
|
|
|
|
|
|
|
(1) Total general and
administrative expense is comprised of cash general and
administrative expense and non-cash equity compensation expense.
Cash general and administrative expense per Boe was $1.45, $1.22,
$1.65, and $1.16 for 2Q 2017, 2Q 2016, YTD 2017 and YTD 2016,
respectively. Non-cash equity compensation expense per Boe was
$0.44, $0.60, $0.51, and $0.52 for 2Q 2017, 2Q 2016, YTD 2017 and
YTD 2016, respectively.
|
|
(2) Adjusted net
income (loss), adjusted diluted net income (loss) per share, and
EBITDAX represent non-GAAP financial measures. These measures
should not be considered as an alternative to, or more meaningful
than, net income (loss), diluted net income (loss) per share, or
net cash provided by operating activities as determined in
accordance with U.S. GAAP. Further information about these non-GAAP
financial measures as well as reconciliations of adjusted net
income (loss), adjusted diluted net income (loss) per share, and
EBITDAX to the most directly comparable U.S. GAAP financial
measures are provided subsequently under the header Non-GAAP
Financial Measures.
|
Second Quarter Earnings Conference Call
Continental plans to host a conference call to discuss second
quarter results on Wednesday, August 9,
2017, at 12 p.m. ET
(11 a.m. CT). Those wishing to listen
to the conference call may do so via the Company's website at
www.CLR.com or by phone:
Time and
date:
|
12 p.m. ET,
Wednesday, August 9, 2017
|
Dial in:
|
844-309-6572
|
Intl. dial
in:
|
484-747-6921
|
Pass code:
|
30586076
|
A replay of the call will be available for 14 days on the
Company's website or by dialing:
Replay
number:
|
855-859-2056 or
404-537-3406
|
Intl.
replay:
|
800-585-8367
|
Pass code:
|
30586076
|
Continental plans to publish a second quarter 2017 summary
presentation to its website at www.CLR.com prior to the start of
its earnings conference call on August
9, 2017.
Upcoming Conferences
Members of Continental's management team plan to participate in
the following investment conferences:
August 23,
2017
|
Heikkinen Energy
Conference, Houston
|
September 5-6,
2017
|
Barclays CEO
Energy-Power Conference, New York
|
September 27-28,
2017
|
Deutsche Bank Annual
Energy 1x1 Conference, Boston
|
About Continental Resources
Continental Resources (NYSE: CLR) is a top 15 independent oil
producer in the U.S. Lower 48 and a leader in America's energy
renaissance. Based in Oklahoma
City, Continental is the largest leaseholder and one of the
largest producers in the nation's premier oil field, the Bakken
play of North Dakota and
Montana. The Company also has
significant positions in Oklahoma,
including its SCOOP Woodford, SCOOP Springer and SCOOP Sycamore
discoveries and the STACK plays. With a focus on the exploration
and production of oil, Continental has unlocked the technology and
resources vital to American energy independence and our nation's
leadership in the new world oil market. In 2017, the Company will
celebrate 50 years of operations. For more information, please
visit www.CLR.com.
Cautionary Statement for the Purpose of the "Safe Harbor"
Provisions of the Private Securities Litigation Reform Act of
1995
This press release includes "forward-looking statements" within
the meaning of Section 27A of the Securities Act of 1933 and
Section 21E of the Securities Exchange Act of 1934. All statements
included in this press release other than statements of historical
fact, including, but not limited to, forecasts or expectations
regarding the Company's business and statements or information
concerning the Company's future operations, performance, financial
condition, production and reserves, schedules, plans, timing of
development, rates of return, budgets, costs, business strategy,
objectives, and cash flows 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 these assumptions and
expectations are reasonable, they are inherently subject to
numerous business, economic, competitive, regulatory and other
risks and uncertainties, most of which are difficult to predict and
many of which are beyond the Company's control. No assurance can be
given that such expectations will be correct or achieved or that
the assumptions are accurate. The risks and uncertainties include,
but are not limited to, commodity price volatility; the geographic
concentration of our operations; financial market and economic
volatility; the inability to access needed capital; the risks and
potential liabilities inherent in crude oil and natural gas
drilling and production and the availability of insurance to cover
any losses resulting therefrom; difficulties in estimating proved
reserves and other reserves-based measures; declines in the values
of our crude oil and natural gas properties resulting in impairment
charges; our ability to replace proved reserves and sustain
production; the availability or cost of equipment and oilfield
services; leasehold terms expiring on undeveloped acreage before
production can be established; our ability to project future
production, achieve targeted results in drilling and well
operations and predict the amount and timing of development
expenditures; the availability and cost of transportation,
processing and refining facilities; legislative and regulatory
changes adversely affecting our industry and our business,
including initiatives related to hydraulic fracturing; increased
market and industry competition, including from alternative fuels
and other energy sources; and the other risks described under Part
I, Item 1A. Risk Factors and elsewhere in the Company's Annual
Report on Form 10-K for the year December
31, 2016, 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 on
which such statement is made. 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.
Except as otherwise required by applicable law, the Company
undertakes no obligation to publicly correct or update any
forward-looking statement whether as a result of new information,
future events or circumstances after the date of this report, or
otherwise.
Readers are cautioned that initial production rates are subject
to decline over time and should not be regarded as reflective of
sustained production levels. In particular, production from
horizontal drilling in shale oil and natural gas resource plays and
tight natural gas plays that are stimulated with extensive pressure
fracturing are typically characterized by significant early
declines in production rates.
We use the term "EUR" or "estimated ultimate recovery" to
describe potentially recoverable oil and natural gas hydrocarbon
quantities. We include these estimates to demonstrate what we
believe to be the potential for future drilling and production on
our properties. These estimates are by their nature much more
speculative than estimates of proved reserves and require
substantial capital spending to implement recovery. Actual
locations drilled and quantities that may be ultimately recovered
from our properties will differ substantially. EUR data included
herein remain subject to change as more well data is analyzed.
Investor
Contact:
|
Media
Contact:
|
J. Warren
Henry
|
Kristin
Thomas
|
Vice President,
Investor Relations & Research
|
Senior Vice
President, Public Relations
|
405-234-9127
|
405-234-9480
|
Warren.Henry@CLR.com
|
Kristin.Thomas@CLR.com
|
|
|
Alyson L.
Gilbert
|
|
Manager, Investor
Relations
|
|
405-774-5814
|
|
Alyson.Gilbert@CLR.com
|
|
Continental
Resources, Inc. and Subsidiaries
|
Unaudited Condensed
Consolidated Statements of Loss
|
|
|
Three months ended
June 30,
|
|
Six months ended June
30,
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Revenues:
|
In thousands,
except per share data
|
Crude oil and natural
gas sales
|
$ 626,548
|
|
$
525,711
|
|
$
1,260,398
|
|
$
929,302
|
Gain (loss) on crude
oil and natural gas derivatives, net
|
28,022
|
|
(82,257)
|
|
74,880
|
|
(40,145)
|
Crude oil and natural
gas service operations
|
6,916
|
|
7,757
|
|
11,636
|
|
15,227
|
Total
revenues
|
661,486
|
|
451,211
|
|
1,346,914
|
|
904,384
|
|
|
|
|
|
|
|
|
Operating costs and
expenses:
|
|
|
|
|
|
|
|
Production
expenses
|
82,474
|
|
74,083
|
|
155,328
|
|
152,724
|
Production
taxes
|
41,965
|
|
39,141
|
|
83,198
|
|
69,634
|
Exploration
expenses
|
3,204
|
|
1,674
|
|
8,202
|
|
4,739
|
Crude oil and natural
gas service operations
|
4,478
|
|
3,576
|
|
7,315
|
|
6,618
|
Depreciation,
depletion, amortization and accretion
|
395,770
|
|
441,761
|
|
777,926
|
|
905,752
|
Property
impairments
|
123,316
|
|
66,112
|
|
174,689
|
|
145,039
|
General and
administrative expenses
|
39,186
|
|
36,246
|
|
86,407
|
|
68,654
|
Net (gain) loss on
sale of assets and other
|
134
|
|
(100,835)
|
|
5,669
|
|
(99,127)
|
Total operating costs
and expenses
|
690,527
|
|
561,758
|
|
1,298,734
|
|
1,254,033
|
Income (loss) from
operations
|
(29,041)
|
|
(110,547)
|
|
48,180
|
|
(349,649)
|
Other income
(expense):
|
|
|
|
|
|
|
|
Interest
expense
|
(72,744)
|
|
(81,922)
|
|
(143,916)
|
|
(162,875)
|
Other
|
373
|
|
435
|
|
815
|
|
819
|
|
(72,371)
|
|
(81,487)
|
|
(143,101)
|
|
(162,056)
|
Loss before income
taxes
|
(101,412)
|
|
(192,034)
|
|
(94,921)
|
|
(511,705)
|
Benefit for income
taxes
|
37,855
|
|
72,632
|
|
31,833
|
|
193,978
|
Net loss
|
$ (63,557)
|
|
$
(119,402)
|
|
$
(63,088)
|
|
$
(317,727)
|
Basic net loss per
share
|
$
(0.17)
|
|
$
(0.32)
|
|
$
(0.17)
|
|
$
(0.86)
|
Diluted net loss per
share
|
$
(0.17)
|
|
$
(0.32)
|
|
$
(0.17)
|
|
$
(0.86)
|
Continental
Resources, Inc. and Subsidiaries
|
Unaudited Condensed
Consolidated Balance Sheets
|
|
|
June 30,
2017
|
|
December 31,
2016
|
Assets
|
In
thousands
|
Current
assets
|
$
|
934,042
|
|
$
|
913,233
|
Net property and
equipment (1)
|
|
12,921,875
|
|
|
12,881,227
|
Other noncurrent
assets
|
|
15,340
|
|
|
17,316
|
Total
assets
|
$
|
13,871,257
|
|
$
|
13,811,776
|
|
|
|
|
|
|
Liabilities and
shareholders' equity
|
|
|
|
|
|
Current
liabilities
|
$
|
1,094,978
|
|
$
|
932,393
|
Long-term debt, net
of current portion
|
|
6,553,740
|
|
|
6,577,697
|
Other noncurrent
liabilities
|
|
1,968,204
|
|
|
1,999,690
|
Total shareholders'
equity
|
|
4,254,335
|
|
|
4,301,996
|
Total liabilities and
shareholders' equity
|
$
|
13,871,257
|
|
$
|
13,811,776
|
|
|
|
|
|
|
(1) Balance is net of
accumulated depreciation, depletion and amortization of $8.49
billion and $7.65 billion as of June 30, 2017 and December 31,
2016, respectively.
|
Continental
Resources, Inc. and Subsidiaries
|
Unaudited Condensed
Consolidated Statements of Cash Flows
|
|
|
|
Three months ended
June 30,
|
|
Six months ended June
30,
|
In
thousands
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Net loss
|
|
$
|
(63,557)
|
|
$
|
(119,402)
|
|
$
|
(63,088)
|
|
$
|
(317,727)
|
Adjustments to
reconcile net loss to net cash provided by operating
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash
expenses
|
|
|
465,966
|
|
|
470,257
|
|
|
877,921
|
|
|
903,030
|
Changes in assets and
liabilities
|
|
|
43,962
|
|
|
(132,036)
|
|
|
101,739
|
|
|
(87,582)
|
Net cash provided by
operating activities
|
|
|
446,371
|
|
|
218,819
|
|
|
916,572
|
|
|
497,721
|
Net cash used in
investing activities
|
|
|
(490,049)
|
|
|
(158,983)
|
|
|
(879,320)
|
|
|
(517,794)
|
Net cash (used in)
provided by financing activities
|
|
|
43,666
|
|
|
(56,181)
|
|
|
(36,719)
|
|
|
25,161
|
Effect of exchange
rate changes on cash
|
|
|
14
|
|
|
(22)
|
|
|
14
|
|
|
9
|
Net change in cash
and cash equivalents
|
|
|
2
|
|
|
3,633
|
|
|
547
|
|
|
5,097
|
Cash and cash
equivalents at beginning of period
|
|
|
17,188
|
|
|
12,927
|
|
|
16,643
|
|
|
11,463
|
Cash and cash
equivalents at end of period
|
|
$
|
17,190
|
|
$
|
16,560
|
|
$
|
17,190
|
|
$
|
16,560
|
Non-GAAP Financial Measures
EBITDAX
We use a variety of financial and operational measures to assess
our performance. Among these measures is EBITDAX. We define EBITDAX
as 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, non-cash equity
compensation expense, and losses on extinguishment of debt. EBITDAX
is not a measure of net income (loss) or net cash provided by
operating activities 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. Further, 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. We exclude the items listed
above from net income (loss) and net cash provided by operating
activities 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 (loss) or net cash provided by
operating activities 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.
The following table provides a reconciliation of our net loss to
EBITDAX for the periods presented.
|
|
Three months ended
June 30,
|
|
Six months ended June
30,
|
In
thousands
|
|
|
2017
|
|
|
2016
|
|
|
2017
|
|
|
2016
|
Net loss
|
|
$
|
(63,557)
|
|
$
|
(119,402)
|
|
$
|
(63,088)
|
|
$
|
(317,727)
|
Interest
expense
|
|
|
72,744
|
|
|
81,922
|
|
|
143,916
|
|
|
162,875
|
Benefit for income
taxes
|
|
|
(37,855)
|
|
|
(72,632)
|
|
|
(31,833)
|
|
|
(193,978)
|
Depreciation,
depletion, amortization and accretion
|
|
|
395,770
|
|
|
441,761
|
|
|
777,926
|
|
|
905,752
|
Property
impairments
|
|
|
123,316
|
|
|
66,112
|
|
|
174,689
|
|
|
145,039
|
Exploration
expenses
|
|
|
3,204
|
|
|
1,674
|
|
|
8,202
|
|
|
4,739
|
Impact from
derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (gain) loss on
derivatives, net
|
|
|
(27,109)
|
|
|
78,057
|
|
|
(72,070)
|
|
|
37,005
|
Total cash received
on derivatives, net
|
|
|
3,844
|
|
|
38,778
|
|
|
3,650
|
|
|
77,967
|
Non-cash (gain) loss
on derivatives, net
|
|
|
(23,265)
|
|
|
116,835
|
|
|
(68,420)
|
|
|
114,972
|
Non-cash equity
compensation
|
|
|
9,133
|
|
|
11,839
|
|
|
20,571
|
|
|
21,046
|
EBITDAX
(non-GAAP)
|
|
$
|
479,490
|
|
$
|
528,109
|
|
$
|
961,963
|
|
$
|
842,718
|
The following table provides a reconciliation of our net cash
provided by operating activities to EBITDAX for the periods
presented.
|
|
Three months ended
June 30,
|
|
Six months ended June
30,
|
In
thousands
|
|
|
2017
|
|
|
2016
|
|
|
2017
|
|
|
2016
|
Net cash provided by
operating activities
|
|
$
|
446,371
|
|
$
|
218,819
|
|
$
|
916,572
|
|
$
|
497,721
|
Current income tax
provision
|
|
|
-
|
|
|
6
|
|
|
1
|
|
|
12
|
Interest
expense
|
|
|
72,744
|
|
|
81,922
|
|
|
143,916
|
|
|
162,875
|
Exploration expenses,
excluding dry hole costs
|
|
|
3,204
|
|
|
1,468
|
|
|
8,045
|
|
|
4,533
|
Gain (loss) on sale
of assets, net
|
|
|
780
|
|
|
96,907
|
|
|
(2,859)
|
|
|
97,016
|
Other, net
|
|
|
353
|
|
|
(3,049)
|
|
|
(1,973)
|
|
|
(7,021)
|
Changes in assets and
liabilities
|
|
|
(43,962)
|
|
|
132,036
|
|
|
(101,739)
|
|
|
87,582
|
EBITDAX
(non-GAAP)
|
|
$
|
479,490
|
|
$
|
528,109
|
|
$
|
961,963
|
|
$
|
842,718
|
Adjusted earnings and adjusted earnings per
share
Our presentation of adjusted earnings and adjusted earnings per
share that exclude the effect of certain items are non-GAAP
financial measures. Adjusted earnings and adjusted earnings
per share represent earnings and diluted earnings per share
determined under U.S. GAAP without regard to non-cash gains and
losses on derivative instruments, property impairments, gains and
losses on asset sales, and losses on extinguishment of debt.
Management believes these measures provide useful information to
analysts and investors for analysis of our operating
results. In addition, management believes these measures are
used by analysts and others in valuation, comparison and investment
recommendations of companies in the oil and gas industry to allow
for analysis without regard to an entity's specific derivative
portfolio, impairment methodologies, and property dispositions.
Adjusted earnings and adjusted earnings per share should not be
considered in isolation or as a substitute for earnings or diluted
earnings per share as determined in accordance with U.S. GAAP and
may not be comparable to other similarly titled measures of other
companies. The following table reconciles earnings and diluted
earnings per share as determined under U.S. GAAP to adjusted
earnings and adjusted diluted earnings per share for the periods
presented.
|
|
|
|
|
|
Three months ended
June 30,
|
|
|
|
|
|
|
2017
|
|
2016
|
In thousands,
except per share data
|
|
$
|
|
Diluted
EPS
|
|
$
|
|
Diluted
EPS
|
Net loss
(GAAP)
|
|
$
(63,557)
|
|
$
(0.17)
|
|
$(119,402)
|
|
$
(0.32)
|
Adjustments:
|
|
|
|
|
|
|
|
|
Non-cash (gain) loss
on derivatives
|
|
(23,265)
|
|
|
|
116,835
|
|
|
Property
impairments
|
|
123,316
|
|
|
|
66,112
|
|
|
Gain on sale of
assets
|
|
(780)
|
|
|
|
(96,907)
|
|
|
Total tax effect of
adjustments
|
|
(37,515)
|
|
|
|
(32,548)
|
|
|
Total adjustments,
net of tax
|
|
61,756
|
|
0.17
|
|
53,492
|
|
0.14
|
Adjusted net loss
(non-GAAP)
|
|
$
(1,801)
|
|
$0.00
|
|
$
(65,910)
|
|
$
(0.18)
|
Weighted average
diluted shares outstanding
|
|
371,111
|
|
|
|
370,435
|
|
|
Adjusted diluted net
loss per share (non-GAAP)
|
|
$0.00
|
|
|
|
$
(0.18)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June
30,
|
|
|
|
|
|
|
2017
|
|
2016
|
In thousands,
except per share data
|
|
$
|
|
Diluted
EPS
|
|
$
|
|
Diluted
EPS
|
Net loss
(GAAP)(1)
|
|
$
(63,088)
|
|
$
(0.17)
|
|
$(317,727)
|
|
$
(0.86)
|
Adjustments:
|
|
|
|
|
|
|
|
|
Non-cash (gain) loss
on derivatives
|
|
(68,420)
|
|
|
|
114,972
|
|
|
Property
impairments
|
|
174,689
|
|
|
|
145,039
|
|
|
(Gain) loss on sale
of assets
|
|
2,859
|
|
|
|
(97,016)
|
|
|
Total tax effect of
adjustments
|
|
(41,061)
|
|
|
|
(61,646)
|
|
|
Total adjustments,
net of tax
|
|
68,067
|
|
0.18
|
|
101,349
|
|
0.28
|
Adjusted net income
(loss) (non-GAAP)
|
|
$
4,979
|
|
$
0.01
|
|
$(216,378)
|
|
$
(0.58)
|
Weighted average
diluted shares outstanding
|
|
373,518
|
|
|
|
370,248
|
|
|
Adjusted diluted net
income (loss) per share (non-GAAP)
|
|
$
0.01
|
|
|
|
$
(0.58)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) In 1Q 2017 we
adopted ASU 2016-09, Compensation-Stock Compensation (Topic
718): Improvements to Employee Share-Based Payment Accounting,
which requires, among other things, that companies recognize excess
tax benefits and deficiencies from stock-based compensation as
income tax benefit or expense in the income statement rather than
through additional paid-in capital. This change resulted in a $3.8
million ($0.01 per diluted share) increase in net loss for YTD 2017
with no comparable impact in the prior period.
|
Cash general and administrative expenses per Boe
Our presentation of cash general and administrative ("G&A")
expenses per Boe is a non-GAAP measure. We define cash G&A per
Boe as total G&A determined in accordance with U.S. GAAP less
non-cash equity compensation expenses, expressed on a per-Boe
basis. We report and provide guidance on cash G&A per Boe
because we believe this measure is commonly used by management,
analysts and investors as an indicator of cost management and
operating efficiency on a comparable basis from period to period.
In addition, management believes cash G&A per Boe is used by
analysts and others in valuation, comparison and investment
recommendations of companies in the oil and gas industry to allow
for analysis of G&A spend without regard to stock-based
compensation programs which can vary substantially from company to
company. Cash G&A per Boe should not be considered as an
alternative to, or more meaningful than, total G&A per Boe as
determined in accordance with U.S. GAAP and may not be comparable
to other similarly titled measures of other
companies.
Continental
Resources, Inc.
|
2017
Guidance(1)
|
As of August 8,
2017
|
|
|
|
|
|
2017
|
|
|
|
Full year average
production
|
|
230,000 to 240,000
Boe per day
|
Exit rate average
production
|
|
260,000 to 275,000
Boe per day
|
Capital
expenditures (non-acquisition)
|
|
$1.75 to $1.95
billion
|
|
|
|
Operating
Expenses:
|
|
|
Production expense per
Boe
|
|
$3.50 to
$3.90
|
Production tax (% of oil
& gas revenue)
|
|
6.75% to
7.25%
|
Cash G&A expense per
Boe(2)
|
|
$1.35 to
$1.75
|
Non-cash equity
compensation per Boe
|
|
$0.50 to
$0.60
|
DD&A per
Boe
|
|
$18.00 to $20.00
|
|
|
|
Average Price
Differentials:
|
|
|
NYMEX WTI crude oil (per
barrel of oil)
|
|
($5.50) to
($6.50)
|
Henry Hub natural gas
(per Mcf)
|
|
($0.10) to
($0.50)
|
|
|
|
Income tax
rate
|
|
38%
|
Deferred
taxes
|
|
90% to 95%
|
|
|
|
(1)
|
Changed items are
shown in bold
|
|
|
(2)
|
Cash G&A is a
non-GAAP measure and excludes the range of values shown for
non-cash equity compensation per Boe
in the item appearing immediately below. Guidance for total G&A
(cash and non-cash) is an expected range of $1.85 to $2.35 per
Boe.
|
View original
content:http://www.prnewswire.com/news-releases/continental-resources-reports-second-quarter-2017-results-and-updates-full-year-guidance-300501522.html
SOURCE Continental Resources