OKLAHOMA CITY, Oct. 29, 2018 /PRNewswire/ -- Continental
Resources, Inc. (NYSE: CLR) (the Company) today announced third
quarter operating and financial results. The Company reported net
income of $314.2 million, or
$0.84 per diluted share, for the
quarter ended September 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 third quarter
2018, these typically excluded items in aggregate represented
$22.8 million, or $0.06 per diluted share, of Continental's
reported net income. Adjusted net income for third quarter 2018 was
$337.0 million, or $0.90 per diluted share.
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Net cash provided by operating activities for third quarter 2018
was $860.7 million. EBITDAX for third
quarter 2018 was $1.0 billion.
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.
The Company's third quarter 2018 crude oil differential was
$3.72 per barrel below the NYMEX
daily average for the period, an improvement of $1.26 per barrel compared to third quarter 2017
due to strong Gulf Coast pricing, strong seasonal demand and lower
Cushing inventories. The realized
wellhead natural gas price for third quarter 2018 was a premium of
$0.22 per Mcf compared to the average
NYMEX Henry Hub benchmark price.
"With up to 70 of our forecasted 2018 Bakken wells and up to 18
SpringBoard wells scheduled to be completed by year end,
Continental anticipates a strong wave of oil-weighted production
growth as we approach year end," said Harold Hamm, Chairman and Chief Executive
Officer. "Thanks to the quality of our oil assets, the ingenuity of
our teams, and the positive tailwind provided by our unhedged oil
portfolio, Continental's strategic move to optimize
capital-efficient, oil-weighted growth is enhancing shareholder
value."
$215 Million in Proceeds
Received in October from Minerals Venture Closing
On October 23, 2018, the Company
closed its strategic minerals agreement with Franco-Nevada. The
Company received approximately $215
million in net proceeds at closing, which offset previously
incurred Capex for acquired minerals. Moving forward, the minerals
relationship will capitalize on the Company's land and exploration
expertise and will focus predominantly on acquiring minerals under
the Company's drill plan. To grow the minerals portfolio,
Franco-Nevada has committed up to $300
million over the next three years, while the Company has
committed up to $75 million (or 20%
of the total investment) over the next three years, subject to
achieving agreed upon development thresholds. With a carry
structure in place, the Company will earn 25-50% of total revenue
from the minerals venture, based on achieving certain predetermined
targets.
Production Update
Third quarter 2018 production totaled 27.3 million barrels of
oil equivalent (Boe), or 296,904 Boe per day, up 22% from third
quarter 2017. Total production for third quarter included 164,605
barrels of oil (Bo) per day, as well as 793.8 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.
|
|
3Q
|
|
2Q
|
|
3Q
|
|
YTD
|
|
YTD
|
Boe per
day
|
|
2018
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
North
Region:
|
|
|
|
|
|
|
|
|
|
|
North Dakota
Bakken
|
|
161,008
|
|
151,805
|
|
129,582
|
|
155,796
|
|
114,435
|
Montana
Bakken
|
|
6,635
|
|
6,314
|
|
7,269
|
|
6,600
|
|
7,569
|
Red River
Units
|
|
8,989
|
|
8,404
|
|
9,536
|
|
8,909
|
|
9,832
|
Other
|
|
26
|
|
258
|
|
449
|
|
232
|
|
422
|
South
Region:
|
|
|
|
|
|
|
|
|
|
|
SCOOP
|
|
63,270
|
|
64,786
|
|
57,283
|
|
63,360
|
|
60,171
|
STACK
|
|
56,129
|
|
51,722
|
|
35,619
|
|
53,733
|
|
32,280
|
Arkoma(1)
|
|
8
|
|
9
|
|
1,722
|
|
6
|
|
1,755
|
Other
|
|
839
|
|
761
|
|
1,328
|
|
856
|
|
1,228
|
Total
|
|
296,904
|
|
284,059
|
|
242,788
|
|
289,492
|
|
227,692
|
|
(1) Producing
properties comprising approximately 1,700 Boe per day of the
Company's Arkoma production were sold in September 2017.
|
Bakken: 167,643 Boepd Average Daily 3Q18 Production; up 23%
over 3Q17
The Company's Bakken production hit an all-time quarterly
record, averaging 167,643 Boe per day in third quarter 2018, up 23%
versus third quarter 2017. During the quarter, the Company
completed 42 gross (26 net) operated wells flowing at an average
initial 24-hour rate of 2,013 Boe per day. Two of the wells ranked
as top ten 30-day rate Bakken wells for the Company, including the
Wiley 8-25H (2,289 Boe per day) and Mountain Gap 3-10H (2,094 Boe
per day). All Company top ten 30-day rate Bakken wells have been
completed in the past twelve months.
The Company currently has 8 rigs drilling in the Bakken, up 2
rigs from last quarter to facilitate continued oil growth in 2019.
In fourth quarter 2018, production is expected to ramp
significantly with up to 70 wells forecasted to be completed by
year end 2018.
"The performance and returns from the Bakken have been
exceptional," said Jack Stark,
President. "Our entire 2017 Bakken program, which included 133
operated wells, paid out by the end of third quarter 2018. Now
that's capital efficiency."
STACK: 3 Meramec Units Flow at Combined Initial Rate of
74,260 Boepd (24-Hr. IP)
The Company's STACK production increased 58% to 56,129 Boe per
day in third quarter 2018, compared to third quarter 2017. During
the quarter, the Company completed 15 gross (7 net) operated wells
with first production. The Company currently has 5 operated
drilling rigs in STACK.
The Company recently completed three outstanding Meramec units
in the over-pressured oil and condensate windows of STACK. All
three units were developed with the equivalent of six, two-mile
wells. In the oil window, the Jalou unit flowed at a combined
initial 24-hour rate of 25,404 Boe per day, averaging 2,470 Bo
per day per well and 10,587 Mcf per day per well. At an average
24-hour rate of 4,234 Boe per day, the Jalou wells set an industry
record for fully developed units in the STACK over-pressured oil
window. Additionally in the oil window, the Homsey unit flowed at a
combined initial 24-hour rate of 21,127 Boe per day, averaging
2,071 Bo per day per well and 8,701 Mcf per day per well. In the
condensate window, the Simba unit flowed at a combined initial
24-hour rate of 27,729 Boe per day, averaging 621 Bo per day per
well and 24,001 Mcf per day per well.
"The outstanding results from these units confirm both our unit
development model and the exceptional quality of our Meramec
reservoirs, which are some of the thickest and most over-pressured
in STACK," said Tony Barrett, Vice
President, Exploration. "These results demonstrate the potential of
our operated STACK inventory with up to 65 units remaining to
develop in the oil and condensate windows."
The following table provides the average initial 24-hour rates
per well for recent STACK units:
Unit
|
2-Mi Equiv.
Wells
per Unit
|
Bopd per
Well
|
Mcfpd per
Well
|
Boepd per
Well
|
Jalou
|
6
|
2,470
|
10,587
|
4,234
|
Homsey
|
6
|
2,071
|
8,701
|
3,521
|
Simba
|
6
|
621
|
24,001
|
4,622
|
SCOOP: Project SpringBoard Proceeding on Schedule with 14
Rigs Drilling
The Company's SCOOP production averaged 63,270 Boe per day in
third quarter 2018, up 10% versus third quarter 2017. The Company's
SCOOP crude oil production in third quarter 2018 increased 33% over
third quarter 2017. The Company completed 9 gross (7 net) operated
wells with first production in third quarter 2018. The Company
currently has 16 operated drilling rigs in SCOOP, ramping up to 18
by year end.
Project SpringBoard is proceeding on schedule with 14 rigs
drilling, 8 of which are targeting the Springer reservoir and 6 of
which are targeting the Woodford
and Sycamore reservoirs. In the Springer, the Company has finished
drilling 17 of the 18 wells planned for row 1 and has begun
drilling row 2. Of the 17 Springer wells drilled, 9 are
flowing-back and 8 are in various stages of completions. In the
Woodford and Sycamore, the Company
has finished drilling 9 wells to date.
"Project SpringBoard is a massive oil project where we are
concurrently developing three reservoirs," said Gary Gould, Senior Vice President of Production
& Resource Development. "As expected, we are already realizing
operational efficiencies that will translate to significant
additional value for our shareholders."
Financial Update
"Continental's strong third quarter and early fourth quarter
results reflect our strategic decision to focus operations on
oil-weighted production growth," said John
Hart, Chief Financial Officer. "Continental is poised to
deliver a strong exit rate, increase our oil production growth and
continue to use significant free cash flow to further reduce debt
toward our long-term target of $5
billion or below."
As of September 30, 2018, the
Company's balance sheet included approximately $13 million in cash and cash equivalents and
$5.96 billion in total debt. On
September 30, 2018, net debt
(non-GAAP) was $5.94 billion. Net
debt is projected to be between $5.4
and $5.6 billion at year end 2018,
driven by strong cash flow. The Company's third quarter annualized
net-debt-to-EBITDAX ratio was 1.49x and has now reached levels seen
prior to the three-year commodity down cycle.
In third quarter 2018, the Company's average net sales price
excluding the effects of derivative positions was $65.78 per barrel of oil and $3.12 per Mcf of gas, or $44.85 per Boe. The Company remains unhedged on
oil. Production expense per Boe was $3.77 for third quarter 2018.
Non-acquisition capital expenditures for third quarter 2018
totaled approximately $790.8 million,
including $633.5 million in
exploration and development drilling, $105.5
million in leasehold, and $51.8
million in workovers, recompletions and other.
Non-acquisition capital expenditures for third quarter were
slightly higher than projected due to timing of completions that
will see first production in fourth quarter 2018 or in 2019.
The following table provides the Company's production results,
per-unit operating costs, results of operations and certain
non-GAAP financial measures for the periods presented. Average net
sales prices exclude any effect of derivative transactions.
Per-unit expenses have been calculated using sales volumes.
|
Three months ended
September 30,
|
|
Nine months ended
September 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Average daily
production:
|
|
|
|
|
|
|
|
Crude oil (Bbl per
day)
|
164,605
|
|
140,611
|
|
161,856
|
|
128,476
|
Natural gas (Mcf per
day)
|
793,793
|
|
613,060
|
|
765,821
|
|
595,294
|
Crude oil equivalents
(Boe per day)
|
296,904
|
|
242,788
|
|
289,492
|
|
227,692
|
Average net sales
prices (non-GAAP), excluding effect from derivatives:
(1)
|
|
|
|
|
|
|
|
Crude oil
($/Bbl)
|
$65.78
|
|
$43.27
|
|
$62.73
|
|
$43.26
|
Natural gas
($/Mcf)
|
$3.12
|
|
$2.74
|
|
$2.92
|
|
$2.78
|
Crude oil equivalents
($/Boe)
|
$44.85
|
|
$31.86
|
|
$42.80
|
|
$31.67
|
Production expenses
($/Boe)
|
$3.77
|
|
$3.82
|
|
$3.62
|
|
$3.86
|
Production taxes (%
of net crude oil and gas sales)
|
8.0%
|
|
7.3%
|
|
7.8%
|
|
6.8%
|
DD&A
($/Boe)
|
$17.15
|
|
$19.00
|
|
$17.35
|
|
$19.31
|
Total general and
administrative expenses ($/Boe) (2)
|
$1.61
|
|
$1.99
|
|
$1.70
|
|
$2.10
|
Net income (loss) (in
thousands)
|
$314,169
|
|
$10,621
|
|
$790,580
|
|
($52,467)
|
Diluted net income
(loss) per share
|
$0.84
|
|
$0.03
|
|
$2.11
|
|
($0.14)
|
Adjusted net income
(non-GAAP) (in thousands) (1)
|
$337,017
|
|
$32,162
|
|
$865,033
|
|
$37,142
|
Adjusted diluted net
income per share (non-GAAP) (1)
|
$0.90
|
|
$0.09
|
|
$2.31
|
|
$0.10
|
Net cash provided by
operating activities (in thousands)
|
$860,748
|
|
$431,409
|
|
$2,500,741
|
|
$1,347,981
|
EBITDAX (non-GAAP)
(in thousands) (1)
|
$999,882
|
|
$563,767
|
|
$2,772,733
|
|
$1,525,730
|
|
(1) Net sales prices,
adjusted net income, adjusted diluted net income 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 $1.18, $1.45,
$1.28, and $1.58 for 3Q 2018, 3Q 2017, YTD 2018 and YTD 2017,
respectively. Non-cash equity compensation expense per Boe was
$0.43, $0.54, $0.42, and $0.52 for 3Q 2018, 3Q 2017, YTD 2018 and
YTD 2017, respectively.
|
Third Quarter Earnings Conference Call
Continental plans to host a conference call to discuss third
quarter results on Tuesday, October 30,
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, Tuesday,
October 30, 2018
|
Dial in:
|
844-309-6572
|
Intl. dial
in:
|
484-747-6921
|
Pass code:
|
3745129
|
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:
|
3745129
|
Continental plans to publish a third quarter 2018 summary
presentation to its website at www.CLR.com prior to the start of
its earnings conference call on October
30, 2018.
Upcoming Conferences
Members of Continental's management team expect to participate
in the following investment conference:
November 14-15,
2018 Bank of America Global Energy
Conference – Miami, Florida
Presentation materials for the conference 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 such conference.
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
September 30,
|
|
Nine months ended
September 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Revenues:
|
In thousands,
except per share data
|
Crude oil and natural
gas sales
|
$
1,273,238
|
|
$ 704,818
|
|
$
3,524,618
|
|
$
1,965,216
|
Gain (loss) on
natural gas derivatives, net
|
(2,025)
|
|
8,602
|
|
(4,536)
|
|
83,482
|
Crude oil and natural
gas service operations
|
10,938
|
|
13,323
|
|
40,210
|
|
24,959
|
Total
revenues
|
1,282,151
|
|
726,743
|
|
3,560,292
|
|
2,073,657
|
|
|
|
|
|
|
|
|
Operating costs and
expenses:
|
|
|
|
|
|
|
|
Production
expenses
|
103,032
|
|
84,514
|
|
286,165
|
|
239,842
|
Production
taxes
|
98,572
|
|
51,264
|
|
262,747
|
|
134,462
|
Transportation
expenses
|
46,008
|
|
-
|
|
142,559
|
|
-
|
Exploration
expenses
|
2,324
|
|
1,389
|
|
4,347
|
|
9,591
|
Crude oil and natural
gas service operations
|
5,163
|
|
3,349
|
|
17,434
|
|
10,664
|
Depreciation,
depletion, amortization and accretion
|
469,333
|
|
420,243
|
|
1,370,912
|
|
1,198,169
|
Property
impairments
|
23,770
|
|
35,130
|
|
86,715
|
|
209,819
|
General and
administrative expenses
|
44,151
|
|
44,006
|
|
134,368
|
|
130,413
|
Net (gain) loss on
sale of assets and other
|
(1,510)
|
|
(4,905)
|
|
(8,261)
|
|
764
|
Total operating costs
and expenses
|
790,843
|
|
634,990
|
|
2,296,986
|
|
1,933,724
|
Income from
operations
|
491,308
|
|
91,753
|
|
1,263,306
|
|
139,933
|
Other income
(expense):
|
|
|
|
|
|
|
|
Interest
expense
|
(73,409)
|
|
(74,756)
|
|
(223,590)
|
|
(218,672)
|
Loss on
extinguishment of debt
|
(7,133)
|
|
-
|
|
(7,133)
|
|
-
|
Other
|
869
|
|
394
|
|
2,231
|
|
1,209
|
|
(79,673)
|
|
(74,362)
|
|
(228,492)
|
|
(217,463)
|
Income (loss) before
income taxes
|
411,635
|
|
17,391
|
|
1,034,814
|
|
(77,530)
|
(Provision) benefit
for income taxes
|
(97,466)
|
|
(6,770)
|
|
(244,234)
|
|
25,063
|
Net income
(loss)
|
$
314,169
|
|
$
10,621
|
|
$
790,580
|
|
$
(52,467)
|
Basic net income
(loss) per share
|
$
0.84
|
|
$
0.03
|
|
$
2.13
|
|
$
(0.14)
|
Diluted net income
(loss) per share
|
$
0.84
|
|
$
0.03
|
|
$
2.11
|
|
$
(0.14)
|
Continental
Resources, Inc. and Subsidiaries
|
Unaudited Condensed
Consolidated Balance Sheets
|
|
|
September 30,
2018
|
|
December 31,
2017
|
Assets
|
In
thousands
|
Cash and cash
equivalents
|
$
|
12,896
|
|
$
|
43,902
|
Other current
assets
|
|
1,356,241
|
|
|
1,207,823
|
Net property and
equipment (1)
|
|
13,644,538
|
|
|
12,933,789
|
Other noncurrent
assets
|
|
17,385
|
|
|
14,137
|
Total
assets
|
$
|
15,031,060
|
|
$
|
14,199,651
|
|
|
|
|
|
|
Liabilities and
shareholders' equity
|
|
|
|
|
|
Current
liabilities
|
$
|
1,490,449
|
|
$
|
1,330,242
|
Long-term debt, net
of current portion
|
|
5,955,326
|
|
|
6,351,405
|
Other noncurrent
liabilities
|
|
1,646,475
|
|
|
1,386,801
|
Total shareholders'
equity
|
|
5,938,810
|
|
|
5,131,203
|
Total liabilities and
shareholders' equity
|
$
|
15,031,060
|
|
$
|
14,199,651
|
|
(1) Balance is net of
accumulated depreciation, depletion and amortization of $10.33
billion and $9.08 billion as of September 30, 2018 and December 31,
2017, respectively.
|
Continental
Resources, Inc. and Subsidiaries
|
Unaudited Condensed
Consolidated Statements of Cash Flows
|
|
|
|
Three months ended
September 30,
|
|
Nine months ended
September 30,
|
In
thousands
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Net income
(loss)
|
|
$
|
314,169
|
|
$
|
10,621
|
|
$
|
790,580
|
|
$
|
(52,467)
|
Adjustments to
reconcile net income (loss) to net cash provided by operating
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash
expenses
|
|
|
619,284
|
|
|
480,718
|
|
|
1,764,566
|
|
|
1,358,639
|
Changes in assets and
liabilities
|
|
|
(72,705)
|
|
|
(59,930)
|
|
|
(54,405)
|
|
|
41,809
|
Net cash provided by
operating activities
|
|
|
860,748
|
|
|
431,409
|
|
|
2,500,741
|
|
|
1,347,981
|
Net cash used in
investing activities
|
|
|
(759,880)
|
|
|
(494,934)
|
|
|
(2,103,483)
|
|
|
(1,374,254)
|
Net cash (used in)
provided by financing activities
|
|
|
(217,976)
|
|
|
57,080
|
|
|
(428,253)
|
|
|
20,361
|
Effect of exchange
rate changes on cash
|
|
|
15
|
|
|
20
|
|
|
(11)
|
|
|
34
|
Net change in cash
and cash equivalents
|
|
|
(117,093)
|
|
|
(6,425)
|
|
|
(31,006)
|
|
|
(5,878)
|
Cash and cash
equivalents at beginning of period
|
|
|
129,989
|
|
|
17,190
|
|
|
43,902
|
|
|
16,643
|
Cash and cash
equivalents at end of period
|
|
$
|
12,896
|
|
$
|
10,765
|
|
$
|
12,896
|
|
$
|
10,765
|
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
September 30,
|
|
|
2018
|
|
2017
|
In thousands,
except per share data
|
|
$
|
|
Diluted
EPS
|
|
$
|
|
Diluted
EPS
|
Net income
(GAAP)
|
|
$314,169
|
|
$
0.84
|
|
$ 10,621
|
|
$
0.03
|
Adjustments:
|
|
|
|
|
|
|
|
|
Non-cash loss on
derivatives
|
|
548
|
|
|
|
2,939
|
|
|
Property
impairments
|
|
23,770
|
|
|
|
35,130
|
|
|
Gain on sale of
assets
|
|
(1,510)
|
|
|
|
(3,562)
|
|
|
Loss on
extinguishment of debt
|
|
7,133
|
|
|
|
-
|
|
|
Total tax effect of
adjustments (1)
|
|
(7,093)
|
|
|
|
(12,966)
|
|
|
Total adjustments,
net of tax
|
|
22,848
|
|
0.06
|
|
21,541
|
|
0.06
|
Adjusted net income
(non-GAAP)
|
|
$337,017
|
|
$
0.90
|
|
$ 32,162
|
|
$0.09
|
Weighted average
diluted shares outstanding
|
|
374,623
|
|
|
|
373,015
|
|
|
Adjusted diluted net
income per share (non-GAAP)
|
|
$
0.90
|
|
|
|
$0.09
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended
September 30,
|
|
|
2018
|
|
2017
|
In thousands,
except per share data
|
|
$
|
|
Diluted
EPS
|
|
$
|
|
Diluted
EPS
|
Net income (loss)
(GAAP)
|
|
$790,580
|
|
$
2.11
|
|
$(52,467)
|
|
$
(0.14)
|
Adjustments:
|
|
|
|
|
|
|
|
|
Non-cash (gain) loss
on derivatives
|
|
12,013
|
|
|
|
(65,481)
|
|
|
Property
impairments
|
|
86,715
|
|
|
|
209,819
|
|
|
Gain on sale of
assets
|
|
(8,261)
|
|
|
|
(703)
|
|
|
Loss on
extinguishment of debt
|
|
7,133
|
|
|
|
-
|
|
|
Total tax effect of
adjustments (1)
|
|
(23,147)
|
|
|
|
(54,026)
|
|
|
Total adjustments,
net of tax
|
|
74,453
|
|
0.20
|
|
89,609
|
|
0.24
|
Adjusted net income
(non-GAAP)
|
|
$865,033
|
|
$
2.31
|
|
$ 37,142
|
|
$
0.10
|
Weighted average
diluted shares outstanding
|
|
374,762
|
|
|
|
373,588
|
|
|
Adjusted diluted net
income per share (non-GAAP)
|
|
$
2.31
|
|
|
|
$
0.10
|
|
|
|
(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 September 30,
2018, the Company's net debt amounted to $5.94 billion, representing total debt of
$5.96 billion less cash and cash
equivalents of $13 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
to EBITDAX for the periods presented.
|
|
Three months ended
September 30,
|
|
Nine months ended
September 30,
|
In
thousands
|
|
|
2018
|
|
|
2017
|
|
|
2018
|
|
|
2017
|
Net income
(loss)
|
|
$
|
314,169
|
|
$
|
10,621
|
|
$
|
790,580
|
|
$
|
(52,467)
|
Interest
expense
|
|
|
73,409
|
|
|
74,756
|
|
|
223,590
|
|
|
218,672
|
Provision (benefit)
for income taxes
|
|
|
97,466
|
|
|
6,770
|
|
|
244,234
|
|
|
(25,063)
|
Depreciation,
depletion, amortization and accretion
|
|
|
469,333
|
|
|
420,243
|
|
|
1,370,912
|
|
|
1,198,169
|
Property
impairments
|
|
|
23,770
|
|
|
35,130
|
|
|
86,715
|
|
|
209,819
|
Exploration
expenses
|
|
|
2,324
|
|
|
1,389
|
|
|
4,347
|
|
|
9,591
|
Impact from
derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (gain) loss on
derivatives, net
|
|
|
2,025
|
|
|
(9,945)
|
|
|
4,536
|
|
|
(82,015)
|
Total cash (paid)
received on derivatives, net
|
|
|
(1,477)
|
|
|
12,884
|
|
|
7,477
|
|
|
16,534
|
Non-cash (gain) loss
on derivatives, net
|
|
|
548
|
|
|
2,939
|
|
|
12,013
|
|
|
(65,481)
|
Non-cash equity
compensation
|
|
|
11,730
|
|
|
11,919
|
|
|
33,209
|
|
|
32,490
|
Loss on
extinguishment of debt
|
|
|
7,133
|
|
|
-
|
|
|
7,133
|
|
|
-
|
EBITDAX
(non-GAAP)
|
|
$
|
999,882
|
|
$
|
563,767
|
|
$
|
2,772,733
|
|
$
|
1,525,730
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table provides a reconciliation of our net cash
provided by operating activities to EBITDAX for the periods
presented.
|
|
|
|
|
|
|
|
|
|
|
Three months ended
September 30,
|
|
Nine months ended
September 30,
|
In
thousands
|
|
|
2018
|
|
|
2017
|
|
|
2018
|
|
|
2017
|
Net cash provided by
operating activities
|
|
$
|
860,748
|
|
$
|
431,409
|
|
$
|
2,500,741
|
|
$
|
1,347,981
|
Current income tax
provision (benefit)
|
|
|
(7,778)
|
|
|
(1)
|
|
|
(7,778)
|
|
|
-
|
Interest
expense
|
|
|
73,409
|
|
|
74,756
|
|
|
223,590
|
|
|
218,672
|
Exploration expenses,
excluding dry hole costs
|
|
|
2,324
|
|
|
1,389
|
|
|
4,346
|
|
|
9,434
|
Gain on sale of
assets, net
|
|
|
1,510
|
|
|
3,562
|
|
|
8,261
|
|
|
703
|
Other, net
|
|
|
(3,036)
|
|
|
(7,278)
|
|
|
(10,832)
|
|
|
(9,251)
|
Changes in assets and
liabilities
|
|
|
72,705
|
|
|
59,930
|
|
|
54,405
|
|
|
(41,809)
|
EBITDAX
(non-GAAP)
|
|
$
|
999,882
|
|
$
|
563,767
|
|
$
|
2,772,733
|
|
$
|
1,525,730
|
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 nine months
ended September 30, 2018. Information
is also presented for the three and nine months ended September 30, 2017 for comparative purposes.
|
|
Three months ended
September 30, 2018
|
|
Three months ended
September 30, 2017
|
In
thousands
|
|
Crude oil
|
|
Natural
gas
|
|
Total
|
|
Crude oil
|
|
Natural
gas
|
|
Total
|
Crude oil and natural
gas sales (GAAP)
|
|
$1,038,558
|
|
$234,680
|
|
$1,273,238
|
|
$550,451
|
|
$154,367
|
|
$704,818
|
Less: Transportation
expenses
|
|
(39,336)
|
|
(6,672)
|
|
(46,008)
|
|
—
|
|
—
|
|
—
|
Net crude oil and
natural gas sales (non-GAAP for 2018)
|
|
$999,222
|
|
$228,008
|
|
$1,227,230
|
|
$550,451
|
|
$154,367
|
|
$704,818
|
Sales volumes
(MBbl/MMcf/MBoe)
|
|
15,190
|
|
73,029
|
|
27,361
|
|
12,722
|
|
56,401
|
|
22,123
|
Net sales price
(non-GAAP for 2018)
|
|
$65.78
|
|
$3.12
|
|
$44.85
|
|
$43.27
|
|
$2.74
|
|
$31.86
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended
September 30, 2018
|
|
Nine months ended
September 30, 2017
|
In
thousands
|
|
Crude oil
|
|
Natural
gas
|
|
Total
|
|
Crude oil
|
|
Natural
gas
|
|
Total
|
Crude oil and natural
gas sales (GAAP)
|
|
$2,891,722
|
|
$632,896
|
|
$3,524,618
|
|
$1,512,990
|
|
$452,226
|
|
$1,965,216
|
Less: Transportation
expenses
|
|
(119,939)
|
|
(22,620)
|
|
(142,559)
|
|
—
|
|
—
|
|
—
|
Net crude oil and
natural gas sales (non-GAAP for 2018)
|
|
$2,771,783
|
|
$610,276
|
|
$3,382,059
|
|
$1,512,990
|
|
$452,226
|
|
$1,965,216
|
Sales volumes
(MBbl/MMcf/MBoe)
|
|
44,183
|
|
209,069
|
|
79,028
|
|
34,975
|
|
162,515
|
|
62,061
|
Net sales price
(non-GAAP for 2018)
|
|
$62.73
|
|
$2.92
|
|
$42.80
|
|
$43.26
|
|
$2.78
|
|
$31.67
|
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 October 29,
2018
|
|
|
|
2018
|
|
|
Full-year average
production
|
290,000 to 300,000
Boe per day
|
Exit-rate average
production
|
315,000 to 325,000
Boe per day
|
Capital expenditures
budget (non-acquisition)
|
$2.7
billion
|
|
|
Operating
Expenses:
|
|
Production expense per
Boe
|
$3.50 to $3.75
(updated(1))
|
Production tax (% of net oil
& gas revenue)
|
7.6% to
8.0%
|
Cash G&A expense per
Boe(2)
|
$1.20 to
$1.65
|
Non-cash equity compensation
per Boe
|
$0.40 to
$0.50
|
DD&A per Boe
|
$17.00 to
$18.00
|
|
|
Average Price
Differentials:
|
|
NYMEX WTI crude oil (per
barrel of oil)
|
($3.50) to
($4.50)
|
Henry Hub natural gas (per
Mcf)
|
$0.00 to
+$0.50
|
|
|
(1) Updated from
a prior guidance range of $3.00 to $3.50.
|
(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 $1.60 to $2.15 per Boe.
|
View original
content:http://www.prnewswire.com/news-releases/continental-resources-reports-third-quarter-2018-results-300739738.html
SOURCE Continental Resources