OKLAHOMA CITY, Aug. 7, 2018 /PRNewswire/ --/PRNewswire/
-- Continental Resources, Inc. (NYSE: CLR) (the Company) today
announced second quarter operating and financial results. The
Company reported net income of $242.5
million, or $0.65 per diluted
share, for the quarter ended June 30,
2018. The Company's net income includes certain items
typically excluded by the investment community in published
estimates, the result of which is referred to as "adjusted net
income." In second quarter 2018, these typically excluded items in
aggregate represented $30.4 million,
or $0.08 per diluted share, of
Continental's reported net income. Adjusted net income for second
quarter 2018 was $272.9 million, or
$0.73 per diluted share.
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Net cash provided by operating activities for second quarter
2018 was $753.8 million. EBITDAX for
second quarter 2018 was $896.7
million. Definitions and reconciliations of adjusted net
income, adjusted net income per share, free cash flow, EBITDAX, net
debt, net sales prices and cash general and administrative
(G&A) expenses per barrel of oil equivalent (Boe) presented
herein to the most directly comparable U.S. generally accepted
accounting principles (GAAP) financial measures are provided in the
supporting tables at the conclusion of this press release.
As of June 30, 2018, the Company's
balance sheet included approximately $130.0
million in cash and cash equivalents and $6.17 billion in total debt. During June, the
Company achieved its short-term goal to drop below $6 billion in net debt. On June 30, 2018, net debt was slightly higher at
$6.04 billion due to working capital
changes and incremental acquired minerals. On July 12, 2018, the Company announced a partial
call of its 5% Senior Notes Due 2022. This represents 20%
($400 million) of the $2 billion in aggregate principal amount of these
notes currently outstanding. The Company continues to pursue its
$5 billion long-term net debt goal.
The Company's second quarter annualized net-debt-to-EBITDAX ratio
was 1.68x and continues to approach the historically low levels
seen prior to the three-year commodity down cycle.
The Company's second quarter 2018 crude oil differential was
$4.55 per barrel below the NYMEX
daily average for the period, an improvement of $1.76 per barrel compared to second quarter 2017.
The realized wellhead natural gas price for second quarter 2018 was
$0.15 per Mcf below the average NYMEX
Henry Hub benchmark price. The Company expects to realize improved
crude oil differentials in third quarter 2018 based on widening
Brent/WTI spread and lower Cushing
inventories.
Updated 2018 Guidance
The Company is increasing its 2018 annual production guidance to
290,000 to 300,000 Boe per day and is increasing its projected exit
rate by 10,000 Boe per day to 315,000 to 325,000 Boe per day. This
increase is driven primarily by Bakken outperformance, realized
operational efficiencies and the reallocation of rigs to
higher, non-carried working interest wells in SCOOP and STACK.
The Company also updated its 2018 Capex guidance from
$2.3 billion to $2.7 billion. Approximately $275 million of this increase is associated with
an investment in minerals within our existing leasehold, which is
expected to be partially funded by mineral divestiture proceeds of
approximately $220 million in fourth
quarter 2018. New capital of $125
million and reallocated capital of $75 million will be used for additional drilling
and completions (D&C) activity, including the addition of three
rigs by year end, focused on high rate of return, oil-weighted
assets. One-third of the D&C Capex increase is associated with
higher value, 60-stage Bakken completions and two-thirds is
associated with activity in Oklahoma.
Included within the updated 2018 Capex guidance is approximately
$600 million for wells that will not
have first production until 2019, providing a catalyst for
continued oil-weighted production growth. The Company expects to
exit 2018 with a wells in progress (WIP) inventory in the Bakken of
approximately 130 gross operated wells, including approximately 50
already stimulated, with first production expected in 2019. In
Oklahoma, the Company expects to
exit 2018 with a WIP inventory of approximately 55 gross operated
wells, including approximately 5 already stimulated, with first
production expected in 2019. These wells will further prompt
oil-focused growth in 2019.
"Continental is in an advantaged position in the current market,
with high rate of return oil plays benefitting from existing
infrastructure," said Harold Hamm,
Chairman and Chief Executive Officer. "As we look into the second
half of 2018 and beyond, Continental and its shareholders have an
exciting opportunity to accelerate capital-efficient, oil-focused
production growth while remaining disciplined in achieving our
targets for free cash flow and debt reduction."
In the Bakken, the Company is projected to average 5 completion
crews and 6 rigs in the second half of the year, ramping up to 7
rigs by year end. The Company expects to complete approximately 125
additional Bakken wells with first production by year end, with
more than half of these in fourth quarter 2018. In Oklahoma, the Company is projected to average
4 completion crews and 18 rigs in the second half of the year,
ramping up to 19 rigs at year end. Over 95% of our drilling
activity in 2018 will be focused on oil and liquids-rich
prospects.
The Company also improved guidance for select 2018 operating
expenses. Total G&A expense, which is comprised of cash and
non-cash G&A expense, is expected to be $1.60 to $2.15 per
Boe in 2018. Of this total, cash G&A expense is expected to be
$1.20 to $1.65 per Boe, a reduction from the previous
$1.25 to $1.75 per Boe. Non-cash equity compensation is
expected to be $0.40 to $0.50 per Boe, a reduction from the previous
$0.45 to $0.55 per Boe. Continental also reduced 2018
guidance for DD&A to $17.00 to
$18.00 per Boe for the year, down
from the previous range of $17.00 to
$19.00 due to strong well
productivity and capital efficiency.
2018 Updated
Guidance Metrics
|
Previous
Guidance
|
Updated
Guidance
|
Annual
production (Boe per day)
|
285,000 to
300,000
|
290,000 to
300,000
|
Exit rate production
(Boe per day)
|
305,000 to
315,000
|
315,000 to
325,000
|
Capex
(non-acquisition)
|
$2.3
billion
|
$2.7
billion
|
Cash G&A expense
per Boe
|
$1.25 to
$1.75
|
$1.20 to
$1.65
|
Non-cash equity
compensation per Boe
|
$0.45 to
$0.55
|
$0.40 to
$0.50
|
DD&A per
Boe
|
$17.00 to
$19.00
|
$17.00 to
$18.00
|
The Company's full 2018 guidance is stated in a table at the
conclusion of this release.
$220 Million Minerals
Divestiture & Strategic Mineral Relationship Formed
The Company announced yesterday the formation of a strategic
minerals relationship with Franco-Nevada. The Company expects to
receive approximately $220 million in
net proceeds at closing in fourth quarter 2018. In addition, the
parties have also committed, subject to satisfaction of agreed upon
development thresholds, to spend up to a combined $125 million per year over the next three years
to acquire additional minerals through the newly-formed subsidiary.
With a carry component on capital acquisition costs, the Company is
to fund 20% of future mineral acquisitions. The Company will be
entitled to between 25% and 50% of total revenues generated by the
minerals subsidiary based upon performance relative to certain
predetermined targets. This new relationship is expected to enhance
the value of minerals by targeting areas of the Company's future
development in Oklahoma.
Production Update
Second quarter 2018 production totaled 25.8 million barrels of
oil equivalent (Boe), or 284,059 Boe per day, up 26% from second
quarter 2017. Total production for second quarter included 157,116
barrels of oil (Bo) per day and 761.7 million cubic feet (MMcf) of
natural gas per day. The following table provides the Company's
average daily production by region for the periods presented.
|
|
2Q
|
|
1Q
|
|
2Q
|
|
YTD
|
|
YTD
|
Boe per
day
|
|
2018
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
North
Region:
|
|
|
|
|
|
|
|
|
|
|
North Dakota
Bakken
|
|
151,805
|
|
154,503
|
|
112,397
|
|
153,147
|
|
106,736
|
Montana
Bakken
|
|
6,314
|
|
6,853
|
|
7,464
|
|
6,582
|
|
7,720
|
Red River
Units
|
|
8,404
|
|
9,338
|
|
9,878
|
|
8,868
|
|
9,983
|
Other
|
|
258
|
|
418
|
|
483
|
|
337
|
|
409
|
South
Region:
|
|
|
|
|
|
|
|
|
|
|
SCOOP
|
|
64,786
|
|
62,012
|
|
61,107
|
|
63,406
|
|
61,640
|
STACK
|
|
51,722
|
|
53,361
|
|
31,934
|
|
52,515
|
|
30,582
|
Arkoma(1)
|
|
9
|
|
2
|
|
1,788
|
|
6
|
|
1,771
|
Other
|
|
761
|
|
923
|
|
1,162
|
|
864
|
|
1,177
|
Total
|
|
284,059
|
|
287,410
|
|
226,213
|
|
285,725
|
|
220,018
|
|
(1) Producing
properties comprising approximately 1,700 Boe per day of the
Company's Arkoma production were sold in September 2017.
|
Bakken: Record Results and Type Curve Uplifted to 1.2 MMBoe
per Well
The Company uplifted its type curve EUR for the Bakken 9% to
1,200 MBoe per well in the second quarter. This increase reflects
the Company's move from 40-stage to 60-stage completions, based on
improved performance observed from 70 wells completed with the
Company's 60-stage optimized completion techniques. A 60-stage
completion increases the cost of a typical Bakken well by
approximately $0.5 million for a
total completed well cost of $8.4
million. At this cost, the 1,200 MBoe type curve delivers a
175% rate of return (ROR) at $70 WTI
and approximately $0.4 million of
incremental cash flow per well in the first year, as compared to
the Company's previous 1,100 MBoe type curve.
"Our Bakken team continues to unlock value for our shareholders
through innovative thinking and advanced technologies," said
Gary Gould, Senior Vice President of
Production & Resource Development. "Over the past year, our
team increased our Bakken type curve twice, cumulatively raising
the EUR 22%, doubling the rate of return, and adding $3.5 million of incremental first-year cash flow
per well for an additional cost of only $1.4
million per well. This step change in performance is
uplifting Bakken economics throughout the field. With 4,000 wells
of operated inventory still ahead of us, the Bakken will be a
growth vehicle for Continental for many years to come."
The Company's Bakken production averaged 158,119 Boe per day in
second quarter 2018, up 32% versus second quarter 2017. During the
quarter, the Company completed 35 gross (19 net) operated wells
flowing at an average initial 24-hour rate of 2,282 Boe per day.
Four of the wells ranked as top ten 30-day rate Bakken wells for
the Company, including the first 30-day Bakken well to average over
3,000 Boe per day (Mountain Gap 7-10H in Dunn County, 3,104 Boe per
day).
SCOOP: Project SpringBoard Phase I and Phase II
Underway
The Company's SCOOP production averaged 64,786 Boe per day in
second quarter 2018, up 6% versus second quarter 2017. The Company
completed 16 gross (13 net) operated wells with first production in
second quarter 2018.
The Company previously announced Project SpringBoard, which is a
massive, multi-year, stacked pay, oil development project that
covers approximately 70-square miles and includes 45,000 gross
(31,000 net) contiguous acres. SpringBoard holds up to 400 MMBoe of
gross unrisked resource potential, with wells expecting to average
70%-85% oil across both phases. The Company estimates up to 100
Springer and 250 Woodford and Sycamore potential locations and will
operate SpringBoard with an average working interest of
approximately 75%. In addition, SpringBoard is expected to benefit
from the Company's row development operational efficiencies and
production will benefit from access to premium markets through
existing pipeline infrastructure.
Drilling is underway in both Phase I and Phase II of Project
SpringBoard, with 7 rigs targeting the Springer reservoir (Phase I)
and 4 rigs, ramping up to 6 rigs by year end, targeting the
Woodford and Sycamore reservoirs
(Phase II). The Company expects first production from the Springer
wells in Project SpringBoard to begin late third quarter 2018, with
up to 18 Springer wells producing by year end 2018. First
production from the Woodford and
Sycamore wells is expected to begin in first quarter 2019.
"Project SpringBoard is an outstanding, high impact oil project
for Continental and its shareholders," said Jack Stark, President. "This project alone has
the potential to increase Continental's oil production by as much
as 10% over the next 12 months."
STACK: Oil Window Drilling Accelerated with Strong Well
Results
The Company's STACK production increased 62% to 51,722 Boe per
day in second quarter 2018, compared to second quarter 2017.
Continental completed 26 gross (13 net) operated wells with first
production in second quarter 2018. The top Company-operated STACK
oil wells in second quarter include the Swaim 3-14H: 3,476 Boepd
(2,596 Bopd), Madeline 2-4-9XH: 3,540 Boepd (2,548 Bopd), Lugene
1-33H: 3,600 Boepd (2,004 Bopd), Nelda 1-3-10XH: 4,032 Boepd (1,886
Bopd) and Brown Family 1-13-24XH: 3,065 Boepd (1,443 Bopd).
Financial Update
"Continental's positive revisions to production guidance reflect
the oil-focused opportunity we see in accelerating our activity in
a capital-efficient manner. The momentum built from these decisions
will directly correlate to revenue generation and oil-weighted
growth as we enter the back half of 2018 and 2019," said
John Hart, Chief Financial Officer.
"Continental will conduct the capital spend from both our D&C
activity and our new minerals opportunity in a manner supportive of
cash flow enhancement and debt reduction."
In second quarter 2018, the Company's average net sales price
excluding the effects of derivative positions was $63.35 per barrel of oil and $2.65 per Mcf of gas, or $42.16 per Boe.
Production expense per Boe was $3.49 for second quarter 2018, which represented
an $0.11 quarter over quarter
improvement versus first quarter 2018 and a $0.50 year over year improvement versus second
quarter 2017. Other select operating costs and expenses for second
quarter 2018 included production taxes of 7.7% of net crude oil and
natural gas sales; DD&A of $17.29
per Boe; and total G&A of $1.82
per Boe.
Non-acquisition capital expenditures for second quarter 2018
totaled approximately $714.2 million,
including $627.9 million in
exploration and development drilling, $44.9
million in leasehold, and $41.4
million in workovers, recompletions and other.
The following table provides the Company's production results,
per-unit operating costs, results of operations and certain
non-GAAP financial measures for the periods presented. Average net
sales prices exclude any effect of derivative transactions.
Per-unit expenses have been calculated using sales volumes.
|
Three months ended
June 30,
|
|
Six months ended June
30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Average daily
production:
|
|
|
|
|
|
|
|
Crude oil (Bbl per
day)
|
157,116
|
|
125,381
|
|
160,458
|
|
122,308
|
Natural gas (Mcf per
day)
|
761,653
|
|
604,991
|
|
751,603
|
|
586,263
|
Crude oil equivalents
(Boe per day)
|
284,059
|
|
226,213
|
|
285,725
|
|
220,018
|
Average net sales
prices (non-GAAP), excluding effect from derivatives:
(1)
|
|
|
|
|
|
|
|
Crude oil
($/Bbl)
|
$63.35
|
|
$41.91
|
|
$61.14
|
|
$43.26
|
Natural gas
($/Mcf)
|
$2.65
|
|
$2.63
|
|
$2.81
|
|
$2.81
|
Crude oil equivalents
($/Boe)
|
$42.16
|
|
$30.31
|
|
$41.71
|
|
$31.56
|
Production expenses
($/Boe)
|
$3.49
|
|
$3.99
|
|
$3.54
|
|
$3.89
|
Production taxes (%
of net crude oil and gas sales)
|
7.7%
|
|
6.7%
|
|
7.6%
|
|
6.6%
|
DD&A
($/Boe)
|
$17.29
|
|
$19.14
|
|
$17.45
|
|
$19.48
|
Total general and
administrative expenses ($/Boe) (2)
|
$1.82
|
|
$1.89
|
|
$1.75
|
|
$2.16
|
Net income (loss) (in
thousands)
|
$242,464
|
|
($63,557)
|
|
$476,410
|
|
($63,088)
|
Diluted net income
(loss) per share
|
$0.65
|
|
($0.17)
|
|
$1.27
|
|
($0.17)
|
Adjusted net income
(loss) (non-GAAP) (in thousands) (1)
|
$272,877
|
|
($1,801)
|
|
$528,016
|
|
$4,979
|
Adjusted diluted net
income (loss) per share (non-GAAP) (1)
|
$0.73
|
|
$0.00
|
|
$1.41
|
|
$0.01
|
Net cash provided by
operating activities (in thousands)
|
753,802
|
|
$446,371
|
|
1,639,993
|
|
$916,572
|
EBITDAX (non-GAAP)
(in thousands) (1)
|
896,654
|
|
$479,490
|
|
1,772,850
|
|
$961,963
|
|
(1) Net sales prices,
adjusted net income (loss), adjusted diluted net income (loss) per
share, and EBITDAX represent non-GAAP financial measures. Further
information about these non-GAAP financial measures as well as
reconciliations to the most directly comparable U.S. GAAP financial
measures are provided subsequently under the header Non-GAAP
Financial Measures.
|
|
(2) 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 $1.41, $1.45,
$1.33, and $1.65 for 2Q 2018, 2Q 2017, YTD 2018 and YTD 2017,
respectively. Non-cash equity compensation expense per Boe was
$0.41, $0.44, $0.42, and $0.51 for 2Q 2018, 2Q 2017, YTD 2018 and
YTD 2017, respectively.
|
Second Quarter Earnings Conference Call
Continental plans to host a conference call to discuss second
quarter results on Wednesday, August 8,
2018, 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 8, 2018
|
Dial in:
|
844-309-6572
|
Intl. dial
in:
|
484-747-6921
|
Pass code:
|
4798234
|
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:
|
4798234
|
Continental plans to publish a second quarter 2018 summary
presentation to its website at www.CLR.com prior to the start of
its earnings conference call on August
8, 2018.
Upcoming Conferences
Members of Continental's management team plan to participate in
the following investment conferences:
August 15-16, 2018 Heikkinen Energy
Conference
September 4-6, 2018 Barclays Global
CEO-Energy Power Conference
Presentation materials for all conferences mentioned above will
be available on the Company's web site at www.CLR.com prior to the
start of the Company's presentation at the applicable conference.
For each presentation, the Company will utilize its web site to
post updated materials or indicate which previously posted
presentation materials will be used for the conference in
question.
About Continental Resources
Continental Resources (NYSE: CLR) is a top 10 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 the largest
producer in the nation's premier oil field, the Bakken play of
North Dakota and Montana. The Company also has significant
positions in Oklahoma, including
its SCOOP Woodford and SCOOP Springer 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 2018, the Company will celebrate 51 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 ended December 31, 2017, 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:
|
Rory
Sabino
|
Kristin
Thomas
|
Vice President,
Investor Relations
|
Senior Vice
President, Public Relations
|
405-234-9620
|
405-234-9480
|
Rory.Sabino@CLR.com
|
Kristin.Thomas@CLR.com
|
|
|
Lucy
Guttenberger
|
|
Senior Investor
Relations Associate
|
|
405-774-5878
|
|
Lucy.Guttenberger@CLR.com
|
|
Continental
Resources, Inc. and Subsidiaries
Unaudited Condensed
Consolidated Statements of Income (Loss)
|
|
|
Three months ended
June 30,
|
|
Six months ended June
30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Revenues:
|
In thousands,
except per share data
|
Crude oil and natural
gas sales
|
$
1,137,528
|
|
$
626,548
|
|
$
2,251,380
|
|
$
1,260,398
|
Gain (loss) on
natural gas derivatives, net
|
(12,685)
|
|
28,022
|
|
(2,511)
|
|
74,880
|
Crude oil and natural
gas service operations
|
12,270
|
|
6,916
|
|
29,272
|
|
11,636
|
Total
revenues
|
1,137,113
|
|
661,486
|
|
2,278,141
|
|
1,346,914
|
|
|
|
|
|
|
|
|
Operating costs and
expenses:
|
|
|
|
|
|
|
|
Production
expenses
|
90,171
|
|
82,474
|
|
183,133
|
|
155,328
|
Production
taxes
|
83,595
|
|
41,965
|
|
164,175
|
|
83,198
|
Transportation
expenses
|
47,254
|
|
-
|
|
96,551
|
|
-
|
Exploration
expenses
|
303
|
|
3,204
|
|
2,023
|
|
8,202
|
Crude oil and natural
gas service operations
|
7,688
|
|
4,478
|
|
12,271
|
|
7,315
|
Depreciation,
depletion, amortization and accretion
|
447,200
|
|
395,770
|
|
901,578
|
|
777,926
|
Property
impairments
|
29,162
|
|
123,316
|
|
62,946
|
|
174,689
|
General and
administrative expenses
|
47,174
|
|
39,186
|
|
90,217
|
|
86,407
|
Net (gain) loss on
sale of assets and other
|
(6,710)
|
|
134
|
|
(6,751)
|
|
5,669
|
Total operating costs
and expenses
|
745,837
|
|
690,527
|
|
1,506,143
|
|
1,298,734
|
Income (loss) from
operations
|
391,276
|
|
(29,041)
|
|
771,998
|
|
48,180
|
Other income
(expense):
|
|
|
|
|
|
|
|
Interest
expense
|
(74,288)
|
|
(72,744)
|
|
(150,182)
|
|
(143,916)
|
Other
|
708
|
|
373
|
|
1,362
|
|
815
|
|
(73,580)
|
|
(72,371)
|
|
(148,820)
|
|
(143,101)
|
Income (loss) before
income taxes
|
317,696
|
|
(101,412)
|
|
623,178
|
|
(94,921)
|
(Provision) benefit
for income taxes
|
(75,232)
|
|
37,855
|
|
(146,768)
|
|
31,833
|
Net income
(loss)
|
$
242,464
|
|
$
(63,557)
|
|
$
476,410
|
|
$
(63,088)
|
Basic net income
(loss) per share
|
$
0.65
|
|
$
(0.17)
|
|
$
1.28
|
|
$
(0.17)
|
Diluted net income
(loss) per share
|
$
0.65
|
|
$
(0.17)
|
|
$
1.27
|
|
$
(0.17)
|
Continental
Resources, Inc. and Subsidiaries
Unaudited Condensed
Consolidated Balance Sheets
|
|
|
June 30,
2018
|
|
December 31,
2017
|
Assets
|
In
thousands
|
Cash and cash
equivalents
|
$
|
129,989
|
|
$
|
43,902
|
Other current
assets
|
|
1,311,300
|
|
|
1,207,823
|
Net property and
equipment (1)
|
|
13,339,571
|
|
|
12,933,789
|
Other noncurrent
assets
|
|
17,620
|
|
|
14,137
|
Total
assets
|
$
|
14,798,480
|
|
$
|
14,199,651
|
|
|
|
|
|
|
Liabilities and
shareholders' equity
|
|
|
|
|
|
Current
liabilities
|
$
|
1,484,439
|
|
$
|
1,330,242
|
Long-term debt, net
of current portion
|
|
6,164,221
|
|
|
6,351,405
|
Other noncurrent
liabilities
|
|
1,536,332
|
|
|
1,386,801
|
Total shareholders'
equity
|
|
5,613,488
|
|
|
5,131,203
|
Total liabilities and
shareholders' equity
|
$
|
14,798,480
|
|
$
|
14,199,651
|
|
(1) Balance is net of
accumulated depreciation, depletion and amortization of $9.88
billion and $9.08 billion as of June 30, 2018 and December 31,
2017, 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
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Net income
(loss)
|
|
$
|
242,464
|
|
$
|
(63,557)
|
|
$
|
476,410
|
|
$
|
(63,088)
|
Adjustments to
reconcile net income (loss) to net cash provided by operating
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash
expenses
|
|
|
576,109
|
|
|
465,966
|
|
|
1,145,283
|
|
|
877,921
|
Changes in assets and
liabilities
|
|
|
(64,771)
|
|
|
43,962
|
|
|
18,300
|
|
|
101,739
|
Net cash provided by
operating activities
|
|
|
753,802
|
|
|
446,371
|
|
|
1,639,993
|
|
|
916,572
|
Net cash used in
investing activities
|
|
|
(715,392)
|
|
|
(490,049)
|
|
|
(1,343,603)
|
|
|
(879,320)
|
Net cash (used in)
provided by financing activities
|
|
|
(6,553)
|
|
|
43,666
|
|
|
(210,277)
|
|
|
(36,719)
|
Effect of exchange
rate changes on cash
|
|
|
(13)
|
|
|
14
|
|
|
(26)
|
|
|
14
|
Net change in cash
and cash equivalents
|
|
|
31,844
|
|
|
2
|
|
|
86,087
|
|
|
547
|
Cash and cash
equivalents at beginning of period
|
|
|
98,145
|
|
|
17,188
|
|
|
43,902
|
|
|
16,643
|
Cash and cash
equivalents at end of period
|
|
$
|
129,989
|
|
$
|
17,190
|
|
$
|
129,989
|
|
$
|
17,190
|
Non-GAAP Financial Measures
Adjusted earnings (net income/loss) and adjusted earnings
(net income/loss) 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 as applicable. 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 an alternative to, or more meaningful than, 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,
|
|
|
2018
|
|
2017
|
In thousands,
except per share data
|
|
$
|
|
Diluted
EPS
|
|
$
|
|
Diluted
EPS
|
Net income (loss)
(GAAP)
|
|
$
242,464
|
|
$
0.65
|
|
$
(63,557)
|
|
$
(0.17)
|
Adjustments:
|
|
|
|
|
|
|
|
|
Non-cash (gain) loss
on derivatives
|
|
17,443
|
|
|
|
(23,265)
|
|
|
Property
impairments
|
|
29,162
|
|
|
|
123,316
|
|
|
Gain on sale of
assets
|
|
(6,711)
|
|
|
|
(780)
|
|
|
Total tax effect of
adjustments (1)
|
|
(9,481)
|
|
|
|
(37,515)
|
|
|
Total adjustments,
net of tax
|
|
30,413
|
|
0.08
|
|
61,756
|
|
0.17
|
Adjusted net income
(loss) (non-GAAP)
|
|
$
272,877
|
|
$
0.73
|
|
$
(1,801)
|
|
$0.00
|
Weighted average
diluted shares outstanding
|
|
374,505
|
|
|
|
371,111
|
|
|
Adjusted diluted net
income (loss) per share (non-GAAP)
|
|
$
0.73
|
|
|
|
$0.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June
30,
|
|
|
2018
|
|
2017
|
In thousands,
except per share data
|
|
$
|
|
Diluted
EPS
|
|
$
|
|
Diluted
EPS
|
Net income (loss)
(GAAP)
|
|
$
476,410
|
|
$
1.27
|
|
$
(63,088)
|
|
$
(0.17)
|
Adjustments:
|
|
|
|
|
|
|
|
|
Non-cash (gain) loss
on derivatives
|
|
11,465
|
|
|
|
(68,420)
|
|
|
Property
impairments
|
|
62,946
|
|
|
|
174,689
|
|
|
(Gain) loss on sale
of assets
|
|
(6,751)
|
|
|
|
2,859
|
|
|
Total tax effect of
adjustments (1)
|
|
(16,054)
|
|
|
|
(41,061)
|
|
|
Total adjustments,
net of tax
|
|
51,606
|
|
0.14
|
|
68,067
|
|
0.18
|
Adjusted net income
(non-GAAP)
|
|
$
528,016
|
|
$
1.41
|
|
$
4,979
|
|
$
0.01
|
Weighted average
diluted shares outstanding
|
|
374,583
|
|
|
|
373,518
|
|
|
Adjusted diluted net
income per share (non-GAAP)
|
|
$
1.41
|
|
|
|
$
0.01
|
|
|
|
(1) Computed by
applying a combined federal and state statutory tax rate of 24% in
effect for 2018 and 38% in effect for 2017 to the pre-tax amount of
adjustments associated with our operations in the United
States.
|
Net debt
Net debt is a non-GAAP measure. We define net debt as total debt
less cash and cash equivalents as determined under U.S. GAAP. Net
debt should not be considered an alternative to, or more meaningful
than, the comparable GAAP measure. Management uses net debt to
determine the Company's outstanding debt obligations that would not
be readily satisfied by its cash and cash equivalents on hand. We
believe this metric is useful to analysts and investors
in determining the Company's leverage position since the Company
has the ability to, and may decide to, use a portion of its cash
and cash equivalents to reduce debt. This metric is sometimes
presented as a ratio with EBITDAX in order to provide investors
with another means of evaluating the Company's ability to service
its existing debt obligations as well as any future increase in the
amount of such obligations. At June 30,
2018, the Company's net debt amounted to $6.04 billion, representing total debt of
$6.17 billion less cash and cash
equivalents of $130.0 million. From
time to time the Company provides forward-looking net debt
forecasts; however, the Company is unable to provide a quantitative
reconciliation of the forward-looking non-GAAP measure to its most
directly comparable forward-looking GAAP measure because management
cannot reliably quantify certain of the necessary components of
such forward-looking GAAP measure. The reconciling items in future
periods could be significant.
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 as applicable. EBITDAX is not a
measure of net income 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
income/loss to EBITDAX for the periods presented.
|
|
Three months ended
June 30,
|
|
Six months ended June
30,
|
In
thousands
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Net income
(loss)
|
|
$
|
242,464
|
|
$
|
(63,557)
|
|
$
|
476,410
|
|
$
|
(63,088)
|
Interest
expense
|
|
|
74,288
|
|
|
72,744
|
|
|
150,182
|
|
|
143,916
|
Provision (benefit)
for income taxes
|
|
|
75,232
|
|
|
(37,855)
|
|
|
146,768
|
|
|
(31,833)
|
Depreciation,
depletion, amortization and accretion
|
|
|
447,200
|
|
|
395,770
|
|
|
901,578
|
|
|
777,926
|
Property
impairments
|
|
|
29,162
|
|
|
123,316
|
|
|
62,946
|
|
|
174,689
|
Exploration
expenses
|
|
|
303
|
|
|
3,204
|
|
|
2,023
|
|
|
8,202
|
Impact from
derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (gain) loss on
derivatives, net
|
|
|
12,685
|
|
|
(27,109)
|
|
|
2,511
|
|
|
(72,070)
|
Total cash received
on derivatives, net
|
|
|
4,758
|
|
|
3,844
|
|
|
8,954
|
|
|
3,650
|
Non-cash (gain) loss
on derivatives, net
|
|
|
17,443
|
|
|
(23,265)
|
|
|
11,465
|
|
|
(68,420)
|
Non-cash equity
compensation
|
|
|
10,562
|
|
|
9,133
|
|
|
21,478
|
|
|
20,571
|
EBITDAX
(non-GAAP)
|
|
$
|
896,654
|
|
$
|
479,490
|
|
$
|
1,772,850
|
|
$
|
961,963
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Net cash provided by
operating activities
|
|
$
|
753,802
|
|
$
|
446,371
|
|
$
|
1,639,993
|
|
$
|
916,572
|
Current income tax
provision
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
1
|
Interest
expense
|
|
|
74,288
|
|
|
72,744
|
|
|
150,182
|
|
|
143,916
|
Exploration expenses,
excluding dry hole costs
|
|
|
303
|
|
|
3,204
|
|
|
2,022
|
|
|
8,045
|
Gain (loss) on sale
of assets, net
|
|
|
6,711
|
|
|
780
|
|
|
6,751
|
|
|
(2,859)
|
Other, net
|
|
|
(3,221)
|
|
|
353
|
|
|
(7,798)
|
|
|
(1,973)
|
Changes in assets and
liabilities
|
|
|
64,771
|
|
|
(43,962)
|
|
|
(18,300)
|
|
|
(101,739)
|
EBITDAX
(non-GAAP)
|
|
$
|
896,654
|
|
$
|
479,490
|
|
$
|
1,772,850
|
|
$
|
961,963
|
Free cash flow
Our presentation of free cash flow is a non-GAAP measure. We
define free cash flow as cash flows from operations before changes
in working capital items less capital expenditures, excluding
acquisitions, plus non-controlling interest capital contributions,
less distributions to non-controlling interests. The inclusion of
non-controlling interest capital contributions and distributions,
expected to begin in the fourth quarter of 2018, is related to our
newly formed relationship with Franco-Nevada to fund a portion of
certain mineral acquisitions which are included in our capital
expenditures and operating results. Free cash flow is not a measure
of net income or cash flows as determined by U.S. GAAP and should
not be considered an alternative to, or more meaningful than, the
comparable GAAP measure. Management believes that these measures
are useful to management and investors as a measure of a company's
ability to internally fund its capital expenditures and to service
or incur additional debt. These measures eliminate the impact of
certain items that management does not consider to be indicative of
the Company's performance from period to period. From time to time
the Company provides forward-looking free cash flow estimates;
however, the Company is unable to provide a quantitative
reconciliation of the forward-looking non-GAAP measure to its most
directly comparable forward-looking GAAP measure because management
cannot reliably quantify certain of the necessary components of
such forward-looking GAAP measure. The reconciling items in future
periods could be significant.
Net sales prices
On January 1, 2018, we adopted
Accounting Standards Update 2016-08, Revenue from Contracts with
Customers (Topic 606): Principal versus Agent Considerations
(Reporting Revenue Gross versus Net), which impacted the
presentation of our crude oil and natural gas revenues. We adopted
the new rules using a modified retrospective transition approach
whereby changes have been applied only to the most current period
presented and prior period results have not been adjusted to
conform to current presentation.
Under the new rules, revenues and transportation expenses
associated with production from our operated properties are now
reported on a gross basis compared to net presentation in the prior
year. For non-operated properties, we receive a net payment from
the operator for our share of sales proceeds which is net of costs
incurred by the operator, if any. Such non-operated revenues are
recognized at the net amount of proceeds received, consistent with
our historical practice. As a result, beginning January 1, 2018 the gross presentation of
revenues from our operated properties differs from the net
presentation of revenues from non-operated properties. This impacts
the comparability of certain operating metrics, such as per-unit
sales prices, when such metrics are prepared in accordance with
U.S. GAAP using gross presentation for some revenues and net
presentation for others.
In order to provide metrics prepared in a manner consistent with
how management assesses the Company's operating results, and to
achieve comparability with prior period metrics for analysis
purposes, we may present crude oil and natural gas sales net of
transportation expenses, which we refer to as "net crude oil and
natural gas sales," a non-GAAP measure. Average sales prices
calculated using net crude oil and natural gas sales are referred
to as "net sales prices," a non-GAAP measure, and are calculated by
taking revenues less transportation expenses divided by sales
volumes, whether for crude oil or natural gas, as applicable.
Management believes presenting our revenues and sales prices net of
transportation expenses is useful because it normalizes the
presentation differences between operated and non-operated revenues
and allows for a useful comparison of net realized prices to NYMEX
benchmark prices on a Company-wide basis.
The following table presents a reconciliation of crude oil and
natural gas sales (GAAP) to net crude oil and natural gas sales and
related net sales prices (non-GAAP) for the three and six months
ended June 30, 2018. Information is
also presented for the three and six months ended June 30, 2017 for comparative purposes.
|
|
Three months ended
June 30, 2018
|
|
Three months ended
June 30, 2017
|
In
thousands
|
|
Crude oil
|
|
Natural
gas
|
|
Total
|
|
Crude oil
|
|
Natural
gas
|
|
Total
|
Crude oil and natural
gas sales (GAAP)
|
|
$946,884
|
|
$190,644
|
|
$1,137,528
|
|
$481,898
|
|
$144,650
|
|
$626,548
|
Less: Transportation
expenses
|
|
(40,217)
|
|
(7,037)
|
|
(47,254)
|
|
—
|
|
—
|
|
—
|
Net crude oil and
natural gas sales (non-GAAP for 2018)
|
|
$906,667
|
|
$183,607
|
|
$1,090,274
|
|
$481,898
|
|
$144,650
|
|
$626,548
|
Sales volumes
(MBbl/MMcf/MBoe)
|
|
14,311
|
|
69,310
|
|
25,863
|
|
11,499
|
|
55,054
|
|
20,674
|
Net sales price
(non-GAAP for 2018)
|
|
$63.35
|
|
$2.65
|
|
$42.16
|
|
$41.91
|
|
$2.63
|
|
$30.31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June
30, 2018
|
|
Six months ended June
30, 2017
|
In
thousands
|
|
Crude oil
|
|
Natural
gas
|
|
Total
|
|
Crude oil
|
|
Natural
gas
|
|
Total
|
Crude oil and natural
gas sales (GAAP)
|
|
$1,853,165
|
|
$398,215
|
|
$2,251,380
|
|
$962,539
|
|
$297,859
|
|
$1,260,398
|
Less: Transportation
expenses
|
|
(80,603)
|
|
(15,948)
|
|
(96,551)
|
|
—
|
|
—
|
|
—
|
Net crude oil and
natural gas sales (non-GAAP for 2018)
|
|
$1,772,562
|
|
$382,267
|
|
$2,154,829
|
|
$962,539
|
|
$297,859
|
|
$1,260,398
|
Sales volumes
(MBbl/MMcf/MBoe)
|
|
28,993
|
|
136,040
|
|
51,667
|
|
22,253
|
|
106,114
|
|
39,938
|
Net sales price
(non-GAAP for 2018)
|
|
$61.14
|
|
$2.81
|
|
$41.71
|
|
$43.26
|
|
$2.81
|
|
$31.56
|
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.
|
2018
Guidance
|
As of August 7,
2018
|
|
|
|
|
|
Previous
2018
|
|
Updated
2018
|
|
|
|
|
Full-year average
production
|
285,000 to 300,000
Boe per day
|
|
290,000 to 300,000
Boe per day
|
Exit-rate average
production
|
305,000 to 315,000
Boe per day
|
|
315,000 to 325,000
Boe per day
|
Capital expenditures
(non-acquisition)
|
$2.3
billion
|
|
$2.7
billion
|
|
|
|
|
Operating
Expenses:
|
|
|
|
Production expense per
Boe
|
$3.00 to
$3.50
|
|
$3.00 to
$3.50
|
Production tax (% of net oil
& gas revenue)
|
7.6% to
8.0%
|
|
7.6% to
8.0%
|
Cash G&A expense per
Boe(1)
|
$1.25 to
$1.75
|
|
$1.20 to
$1.65
|
Non-cash equity compensation
per Boe
|
$0.45 to
$0.55
|
|
$0.40 to
$0.50
|
DD&A per Boe
|
$17.00
to $19.00
|
|
$17.00
to $18.00
|
|
|
|
|
Average Price
Differentials:
|
|
|
|
NYMEX WTI crude oil (per
barrel of oil)
|
($3.50) to
($4.50)
|
|
($3.50) to
($4.50)
|
Henry Hub natural gas (per
Mcf)
|
$0.00 to
+$0.50
|
|
$0.00 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 $1.60 to $2.15 per Boe.
|
View original
content:http://www.prnewswire.com/news-releases/continental-resources-reports-second-quarter-2018-results-and-updates-full-year-guidance-300693521.html
SOURCE Continental Resources