Continental Resources Reports Full-Year 2018 And 4Q18 Results
OKLAHOMA CITY, Feb. 18, 2019 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the Company) today announced full-year 2018 and fourth quarter 2018 operating and financial results.
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The Company reported full-year 2018 net income of $988.3 million, or $2.64 per diluted share. 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." Typically excluded items in aggregate represented $77.9 million, or $0.20 per diluted share. Adjusted net income for full-year 2018 was $1.07 billion, or $2.84 per diluted share (non-GAAP). Net cash provided by operating activities for full-year 2018 was $3.46 billion and EBITDAX was $3.62 billion (non-GAAP).
The Company reported net income of $197.7 million, or $0.53 per diluted share, for the quarter ended December 31, 2018. In fourth quarter 2018, typically excluded items in aggregate represented $3.9 million, or $0.01 per diluted share, of Continental's reported net income. Adjusted net income for fourth quarter 2018 was $201.7 million, or $0.54 per diluted share (non-GAAP). Net cash provided by operating activities for fourth quarter 2018 was $955.3 million and EBITDAX was $850.6 million (non-GAAP).
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 are non-GAAP financial measures. Definitions and explanations for how these measures relate to the most directly comparable U.S. generally accepted accounting principles (GAAP) financial measures are provided at the conclusion of this press release. Also presented at the end of this press release is the Company's calculation of return on capital employed for 2018.
"2018 was a breakout year of performance for Continental with significant cash flow generation and debt reduction, as well as corporate returns that compare favorably against our peers and are competitive with other industries," said Harold Hamm, Chairman and Chief Executive Officer. "In 2019, we will continue to deliver strong corporate returns coupled with growth that can adjust to various market conditions."
Production Update: 4Q18 Oil Production up 14% over 3Q18
Full-year 2018 production increased 23% over full-year 2017, averaging 298,190 Boe per day. 2018 oil production increased 21% over 2017, averaging 168,177 barrels of oil (Bo) per day. 2018 natural gas production averaged 780.1 million cubic feet (MMcf) per day.
Fourth quarter 2018 production increased 9% over third quarter 2018 and 13% over fourth quarter 2017, averaging 324,001 Boe per day. Fourth quarter 2018 oil production increased 14% over third quarter 2018 and 11% over fourth quarter 2017, averaging 186,934 Bo per day. Fourth quarter 2018 natural gas production averaged 822.4 MMcf per day.
The following table provides the Company's average daily production by region for the periods presented.
4Q
3Q
4Q
FY
FY
Boe per
day 2018 2018 2017 2018 2017
---
North
Region:
North
Dakota
Bakken 177,358 161,008 158,640 161,231 125,577
Montana
Bakken 6,478 6,635 6,958 6,569 7,415
Other 9,077 9,015 9,965 9,125 10,182
South
Region:
SCOOP 67,244 63,270 62,242 64,339 60,693
STACK 62,947 56,129 47,914 56,055 36,220
Other(1) 897 847 1,266 871 2,550
Total 324,001 296,904 286,985 298,190 242,637
(1) Producing properties comprising
approximately 1,700 Boe per day of
the Company's Arkoma production
were sold in September 2017.
Bakken: 183,836 Boepd Average Daily 4Q18 Production; up 10% over 3Q18
The Company's full-year 2018 Bakken production increased 26% over 2017, averaging 167,800 Boe per day. The Company's fourth quarter 2018 Bakken production increased 10% over third quarter 2018 and 11% over fourth quarter 2017, averaging 183,836 Boe per day. During the quarter, the Company completed 52 gross (34 net) operated wells with first production flowing at an average initial 24-hour rate per well of 2,800 Boe per day.
"Continental has entered a new era of optimized full field development in the Bakken where technology and operational efficiencies have uplifted performance across the play," said Jack Stark, President. "As we look to 2019 and beyond, the Bakken will continue to underpin Continental's sustainable, value-driven and oil-weighted growth."
STACK: Another Over-Pressured Condensate Unit Outperforms Parent Type Curve
The Company's fourth quarter 2018 STACK production increased 12% over third quarter 2018 and 31% over fourth quarter 2017, averaging 62,947 Boe per day. During the quarter, the Company completed 19 gross (9 net) operated wells with first production flowing at an average initial 24-hour rate per well of 3,645 Boe per day.
The Company recently completed another outstanding Meramec unit in the over-pressured condensate window of STACK. The Boden unit flowed at an impressive combined initial 24-hour rate of 14,071 Boe per day, averaging 1,197 Bo per day per well and 20,961 Mcf per day per well.
"Recent results from the Boden unit further validate Continental's optimized density development and the high quality of the over-pressured Meramec that underlies our acreage position in STACK," said Gary Gould, Senior Vice President of Production & Resource Development.
SCOOP: SpringBoard on Pace to Add 10% to CLR Net Oil Production (3Q18-3Q19)
The Company's fourth quarter 2018 SCOOP production increased 6% over third quarter 2018 and 8% over fourth quarter 2017, averaging 67,244 Boe per day. The Company completed 17 gross (14 net) operated wells with first production in fourth quarter 2018. The Company's fourth quarter 2018 SCOOP oil production increased 47% over fourth quarter 2017, reflecting the decision made in early 2018 to shift to the Company's oil-weighted assets.
As previously announced in the Company's Project SpringBoard conference call, Project SpringBoard is expected to add 10%, or 16,500 barrels of oil per day, to the Company's total net oil production from third quarter 2018 to third quarter 2019. In fourth quarter 2018, Project SpringBoard production growth was on pace, producing an average 5,260 barrels of oil per day. The Company currently has 45 gross operated wells waiting on completion in Project SpringBoard with 18 gross operated wells in the Springer reservoir and 27 gross operated wells in the Woodford and Sycamore reservoirs. Approximately 12 rigs will be focused on Project SpringBoard in 2019, with approximately 7 rigs targeting the Springer and approximately 5 rigs targeting the Woodford and Sycamore.
Financial Update
"Continental's 2018 performance signals a structural transition to free cash flow generation through low cost operations and development," said John Hart, Chief Financial Officer. "Over the next five years, we are targeting free cash flow generation, continued debt reduction and an average 12.5% compound annual production growth rate to drive strong corporate returns and continued shareholder value."
As of December 31, 2018, the Company's balance sheet included approximately $282.7 million in cash and cash equivalents, $5.77 billion in total debt and $5.49 billion in net debt (non-GAAP). The Company anticipates further reducing net debt to $5 billion late in 2019.
For full-year 2018, the Company's average net sales prices excluding the effects of derivative positions were $59.19 per barrel of oil and $3.01 per Mcf of gas, or $41.25 per Boe. The Company remains unhedged on oil. Production expense per Boe was $3.59 for full-year 2018, a record annual low for the Company and well within annual guidance of $3.50 to $3.75.
Non-acquisition capital expenditures for full-year 2018 totaled approximately $2.8 billion, including $2.4 billion in exploration and development drilling and completion, $276.4 million in leasehold and minerals, and $198.8 million in workovers, recompletions and other.
In fourth quarter 2018, the Company's average net sales prices excluding the effects of derivative positions were $50.06 per barrel of oil and $3.26 per Mcf of gas, or $37.13 per Boe. Production expense per Boe was $3.50 for fourth quarter 2018.
Non-acquisition capital expenditures for fourth quarter 2018 totaled approximately $742.6 million, including $611.0 million in exploration and development drilling and completion, $59.0 million in leasehold and minerals, and $72.6 million in workovers, recompletions and other.
The Company's 2019 guidance remains as announced on February 13, 2019 and can be found at the conclusion of this press release.
CLR's Five Year Vision Targets
Over the next five years, the Company is targeting an average 12.5% compound annual production growth rate from existing inventory. The Company is also targeting an average annual free cash flow of $500 million per year at $60 per barrel WTI. Individual years may vary above or below these targets depending on the timing of future projects.
In addition to cash flow generation, the Company expects ROCE to remain strong over the next five years, competing against other energy companies as well as other industries. The Company is targeting average annual ROCE of approximately 14.5% per year over the five years at $60 per barrel WTI.
The Company expects capital allocation between its North and South assets to be reasonably consistent with the historical norm of approximately 50% to 60% in the North and approximately 40% to 50% in the South.
The Company's operating expenses on a per Boe basis are expected to remain relatively consistent or improve. Additionally, the Company expects oil and gas differentials to improve with continued infrastructure directed toward coastal markets, which will allow the Company to benefit from access to both premium domestic and global markets.
The Company's five year vision is underpinned by the depth and quality of current inventory. The Company estimates less than 30% of current inventory is to be developed under this five year vision. The five year inventory is projected to deliver a 60% blended average rate of return (ROR) at $60 per barrel WTI.
The following table provides the Company's production results, per-unit operating costs, results of operations and certain non-GAAP financial measures for the periods presented. Average net sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.
Three months ended December 31, Year ended December 31,
2018 2017 2018 2017
Average daily
production:
Crude oil (Bbl per
day) 186,934 168,066 168,177 138,455
Natural gas (Mcf per
day) 822,402 713,518 780,083 625,093
Crude oil
equivalents (Boe
per day) 324,001 286,985 298,190 242,637
Average net sales
prices (non-GAAP),
excluding effect
from derivatives:
(1)
Crude oil ($/Bbl) $50.06 $51.16 $59.19 $45.70
Natural gas ($/Mcf) $3.26 $3.30 $3.01 $2.93
Crude oil
equivalents ($/Boe) $37.13 $38.27 $41.25 $33.65
Production expenses
($/Boe) $3.50 $3.17 $3.59 $3.66
Production taxes (%
of net crude oil
and gas sales) 8.2% 7.3% 7.9% 7.0%
DD&A ($/Boe) $16.41 $17.93 $17.09 $18.89
Total general and
administrative
expenses ($/Boe)
(2) $1.65 $2.30 $1.69 $2.16
Net income
attributable to
Continental
Resources (in
thousands) (3) $197,738 $841,914 $988,317 $789,447
Diluted net income
per share
attributable to
Continental
Resources $0.53 $2.25 $2.64 $2.11
Adjusted net income
(non-GAAP) (in
thousands) (1) $201,686 $153,660 $1,066,237 $190,803
Adjusted diluted net
income per share
(non-GAAP) (1) $0.54 $0.41 $2.84 $0.51
Net cash provided by
operating
activities (in
thousands) $955,267 $731,125 $3,456,008 $2,079,106
EBITDAX (non-GAAP)
(in thousands) (1) $850,640 $837,887 $3,623,373 $2,363,617
(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 at
the end of this press release.
(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, $1.80,
$1.25, and $1.64 for 4Q 2018, 4Q
2017, FY 2018 and FY 2017,
respectively. Non-cash equity
compensation expense per Boe was
$0.47, $0.50, $0.44, and $0.52 for
4Q 2018, 4Q 2017, FY 2018 and FY
2017, respectively.
(3) In December 2017, the Tax Cuts
and Jobs Act was signed into law,
which among other things reduced
the U.S. federal corporate income
tax rate from 35% to 21% effective
January 1, 2018. In accordance
with U.S. GAAP, the Company
remeasured its deferred income tax
assets and liabilities as of
December 31, 2017 to reflect the
reduced tax rate, which resulted
in a one-time increase in net
income of approximately $713.7
million ($1.91 per diluted share)
for the three and twelve months
ended December 31, 2017.
Fourth Quarter Earnings Conference Call
Continental plans to host a conference call to discuss fourth quarter and full-year 2018 results on Tuesday, February 19, 2019 at 12:00 p.m. ET (11:00 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,
February 19, 2019
Dial-in:
844-309-6572
Intl. dial-in:
484-747-6921
Conference ID: 5856777
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
Conference ID: 5856777
Continental plans to publish a fourth quarter and full-year 2018 summary presentation to its website at www.CLR.com prior to the start of its conference call on February 19, 2019.
Upcoming Conferences
Members of Continental's management team expect to participate in the following investment conference:
March 25-26, 2019 Scotia Howard Weil 47th Annual Energy Conference - New Orleans, LA
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 2019, the Company will celebrate 52 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," "target," "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, and once filed, for the year ended December 31, 2018, 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
Consolidated Statements of Income
Three months ended December 31, Year ended December 31,
---
2018 2017 2018 2017
---
Revenues:
In thousands, except per share data
Crude oil and natural gas
sales $1,154,104 $1,017,750 $4,678,722 $2,982,966
Gain (loss) on natural gas
derivatives, net (19,394) 8,165 (23,930) 91,647
Crude oil and natural gas
service operations 14,584 21,257 54,794 46,215
---
Total revenues 1,149,294 1,047,172 4,709,586 3,120,828
Operating costs and expenses:
Production expenses 104,258 84,371 390,423 324,214
Production taxes 90,393 73,816 353,140 208,278
Transportation expenses 49,028 191,587 -
Exploration expenses 3,295 2,802 7,642 12,393
Crude oil and natural gas
service operations 4,205 6,216 21,639 16,880
Depreciation, depletion,
amortization and accretion 488,416 476,732 1,859,327 1,674,901
Property impairments 38,494 27,552 125,210 237,370
General and administrative
expenses 49,201 61,294 183,569 191,706
Litigation settlement 59,600 59,600
Net gain on sale of assets
and other (8,410) (54,679) (16,671) (53,915)
---
Total operating costs and
expenses 818,880 737,704 3,115,866 2,671,427
---
Income from operations 330,414 309,468 1,593,720 449,401
Other income (expense):
Interest expense (69,441) (75,823) (293,032) (294,495)
Loss on extinguishment of
debt (554) (7,133) (554)
Other 1,016 506 3,247 1,715
(68,425) (75,871) (296,918) (293,334)
---
Income before income taxes 261,989 233,597 1,296,802 156,067
(Provision) benefit for
income taxes (62,868) 608,317 (307,102) 633,380
---
Net income 199,121 841,914 989,700 789,447
Net income attributable to
noncontrolling interests 1,383 1,383 -
Net income attributable to
Continental Resources $197,738 $841,914 $988,317 $789,447
Net income per share attributable to Continental Resources:
Basic $0.53 $2.27 $2.66 $2.13
Diluted $0.53 $2.25 $2.64 $2.11
Continental Resources, Inc. and Subsidiaries
Consolidated Balance Sheets
December 31, 2018 December 31, 2017
---
Assets
In thousands
Cash and cash
equivalents $
282,749 $
43,902
Other current assets 1,129,612 1,207,823
Net property and equipment (1) 13,869,800 12,933,789
Other noncurrent assets 15,786 14,137
Total assets $
15,297,947 $
14,199,651
---
Liabilities and equity
Current liabilities $
1,387,509 $
1,330,242
Long-term debt, net of current
portion 5,765,989 6,351,405
Other noncurrent liabilities 1,722,588 1,386,801
Equity attributable to Continental
Resources 6,145,133 5,131,203
Equity attributable to
noncontrolling interests 276,728
Total liabilities
and equity $
15,297,947 $
14,199,651
---
(1) Balance is net of
accumulated depreciation,
depletion and amortization of
$10.81 billion and $9.08
billion as of December 31, 2018
and December 31, 2017,
respectively.
Continental Resources, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
Three months ended December 31,
Year ended December 31,
In thousands 2018 2017 2018 2017
---
Net income $
199,121 $
841,914 $
989,700 $
789,447
Adjustments to reconcile
net income to net cash
provided by operating
activities:
Non-cash expenses 576,033 (70,395) 2,340,600 1,288,244
Changes in assets and
liabilities 180,113 (40,394) 125,708 1,415
Net cash provided by
operating activities 955,267 731,125 3,456,008 2,079,106
Net cash used in investing
activities (756,689) (434,591) (2,860,172) (1,808,845)
Net cash provided by (used
in) financing activities 71,319 (263,395) (356,934) (243,034)
Effect of exchange rate
changes on cash (44) (2) (55) 32
Net change in cash and
cash equivalents 269,853 33,137 238,847 27,259
Cash and cash equivalents
at beginning of period 12,896 10,765 43,902 16,643
Cash and cash equivalents
at end of period $
282,749 $
43,902 $
282,749 $
43,902
Non-GAAP adjusted net income and adjusted net income per share attributable to Continental
Our presentation of adjusted net income and adjusted net income per share that exclude the effect of certain items are non-GAAP financial measures. Adjusted net income and adjusted net income per share represent net income and diluted net income per share determined under U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments, losses on certain litigation settlements, gains and losses on asset sales, losses on extinguishment of debt, and the impact of U.S. tax reform legislation 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 net income and adjusted net income per share should not be considered in isolation or as an alternative to, or more meaningful than, net income or diluted net income 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 net income and diluted net income per share as determined under U.S. GAAP to adjusted net income and adjusted diluted net income per share for the periods presented.
Three months ended December 31,
2018 2017
In thousands, except per share data
$
Diluted EPS
$
Diluted EPS
---
Net income attributable to Continental
Resources (GAAP) $197,738 $0.53 $841,914 $2.25
Adjustments:
Non-cash (gain) loss on derivatives (25,022) 7,450
Property impairments 38,494 27,552
Litigation settlement 59,600
Gain on sale of assets (8,410) (54,420)
Loss on extinguishment of debt 554
Total tax effect of adjustments (1) (1,114) (15,335)
Tax benefit from US tax reform
legislation (713,655)
Total adjustments, net of tax 3,948 0.01 (688,254) (1.84)
Adjusted net income (non-GAAP) $201,686 $0.54 $153,660 $0.41
Weighted average diluted shares
outstanding 374,525 373,764
Adjusted diluted net income per share
(non-GAAP) $0.54 $0.41
Year ended December 31,
2018 2017
In thousands, except per share data
$
Diluted EPS
$
Diluted EPS
---
Net income attributable to Continental
Resources (GAAP) $988,317 $2.64 $789,447 $2.11
Adjustments:
Non-cash gain on derivatives (13,009) (58,031)
Property impairments 125,210 237,370
Litigation settlement 59,600
Gain on sale of assets (16,671) (55,124)
Loss on extinguishment of debt 7,133 554
Total tax effect of adjustments (1) (24,743) (69,358)
Tax benefit from US tax reform
legislation (713,655)
Total adjustments, net of tax 77,920 0.20 (598,644) (1.60)
Adjusted net income (non-GAAP) $1,066,237 $2.84 $190,803 $0.51
Weighted average diluted shares
outstanding 374,838 373,768
Adjusted diluted net income per share
(non-GAAP) $2.84 $0.51
(1) Computed by applying a
combined federal and state
statutory tax rate of 24.5% 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 other
than the 2017 tax benefit
adjustment related to US tax
reform legislation.
Non-GAAP 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, total debt, the most directly 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 December 31, 2018, the Company's total debt was $5.77 billion and its net debt amounted to $5.49 billion, representing total debt of $5.77 billion less cash and cash equivalents of $282.7 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 the most directly comparable forward-looking GAAP measure of total debt 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.
Non-GAAP EBITDAX
We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX, a non-GAAP measure. 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 December 31,
Year ended December 31,
In thousands 2018 2017 2018 2017
---
Net income $
199,121 $
841,914 $
989,700 $
789,447
Interest expense 69,441 75,823 293,032 294,495
Provision (benefit)
for income taxes 62,868 (608,317) 307,102 (633,380)
Depreciation,
depletion,
amortization and
accretion 488,416 476,732 1,859,327 1,674,901
Property impairments 38,494 27,552 125,210 237,370
Exploration expenses 3,295 2,802 7,642 12,393
Impact from derivative
instruments:
Total (gain) loss on
derivatives, net 19,394 (8,417) 23,930 (90,432)
Total cash (paid)
received on
derivatives, net (44,416) 15,867 (36,939) 32,401
Non-cash (gain) loss
on derivatives, net (25,022) 7,450 (13,009) (58,031)
Non-cash equity
compensation 14,027 13,377 47,236 45,868
Loss on extinguishment
of debt 554 7,133 554
EBITDAX (non-GAAP) $
850,640 $
837,887 $
3,623,373 $
2,363,617
The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented.
Three months ended December 31,
Year ended December 31,
In thousands 2018 2017 2018 2017
---
Net cash
provided by
operating
activities $
955,267 $
731,125 $
3,456,008 $
2,079,106
Current income
tax provision
(benefit) 2 (7,781) (7,776) (7,781)
Interest
expense 69,441 75,823 293,032 294,495
Exploration
expenses,
excluding dry
hole costs 3,149 2,783 7,495 12,217
Litigation
settlement (59,600) (59,600)
Gain on sale
of assets,
net 8,410 54,420 16,671 55,124
Other, net (5,516) 723 (16,349) (8,529)
Changes in
assets and
liabilities (180,113) 40,394 (125,708) (1,415)
EBITDAX (non-
GAAP) $
850,640 $
837,887 $
3,623,373 $
2,363,617
Non-GAAP Free Cash Flow
Our presentation of projected free cash flow is a non-GAAP measure. We define projected free cash flow as cash flows from operations before changes in working capital items, less capital expenditures, plus noncontrolling interest capital contributions, less distributions to noncontrolling interests. Noncontrolling interest capital contributions and distributions primarily relate to our new relationship formed with Franco-Nevada in 2018 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 operating cash flows as determined by U.S. GAAP and should not be considered an alternative to, or more meaningful than, the comparable GAAP measure, and free cash flow does not represent residual cash flows available for discretionary expenditures. Management believes that this measure is 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. From time to time the Company provides forward-looking free cash flow estimates or targets; 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.
Non-GAAP 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 on January 1, 2018 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, to achieve comparability between operated and non-operated revenues, 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 twelve months ended December 31, 2018. Information is also presented for the three and twelve months ended December 31, 2017 for comparative purposes.
Three months ended December 31, 2018 Three months ended December 31, 2017
In thousands
Crude oil
Natural gas
Total
Crude oil
Natural gas
Total
---
Crude oil and natural gas
sales (GAAP) $900,872 $253,232 $1,154,104 $800,871 $216,879 $1,017,750
Less: Transportation expenses (42,373) (6,655) (49,028)
Net crude oil and natural gas
sales (non-GAAP for 2018) $858,499 $246,577 $1,105,076 $800,871 $216,879 $1,017,750
Sales volumes (MBbl/MMcf/
MBoe) 17,149 75,661 29,759 15,653 65,644 26,594
Net sales price (non-GAAP for
2018) $50.06 $3.26 $37.13 $51.16 $3.30 $38.27
Year ended December 31, 2018
Year ended December 31, 2017
In thousands
Crude oil
Natural gas
Total
Crude oil
Natural gas
Total
---
Crude oil and natural gas
sales (GAAP) $3,792,594 $886,128 $4,678,722 $2,313,862 $669,104 $2,982,966
Less: Transportation expenses (162,312) (29,275) (191,587)
Net crude oil and natural gas
sales (non-GAAP for 2018) $3,630,282 $856,853 $4,487,135 $2,313,862 $669,104 $2,982,966
Sales volumes (MBbl/MMcf/
MBoe) 61,332 284,730 108,787 50,628 228,159 88,655
Net sales price (non-GAAP for
2018) $59.19 $3.01 $41.25 $45.70 $2.93 $33.65
Non-GAAP 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.
The following table reconciles total G&A per Boe as determined under U.S. GAAP to cash G&A per Boe for the periods presented.
Three months ended December 31, Year ended December 31,
2018 2017 2018 2017
Total G&A per Boe
(GAAP) $1.65 $2.30 $1.69 $2.16
Less: Non-cash
equity compensation
per Boe (0.47) (0.50) (0.44) (0.52)
Cash G&A per Boe
(non-GAAP) $1.18 $1.80 $1.25 $1.64
Calculation of Return on Capital Employed (ROCE)
The following table shows the calculation of ROCE for 2018.
In thousands 2018
Net income attributable to
Continental Resources $988,317
Impact from derivative instruments:
Total (gain) loss on derivatives, net 23,930
Total cash received (paid), net (36,939)
Non-cash (gain) loss on derivatives,
net (13,009)
Provision for income taxes 307,102
Non-cash equity compensation 47,236
Interest expense 293,032
Loss on extinguishment of debt 7,133
Adjusted EBIT $1,629,811
Equity attributable to Continental
Resources -beginning of 2018 $5,131,203
Total debt -beginning of 2018 6,353,691
Capital employed -beginning of 2018 11,484,894
Equity attributable to Continental
Resources -end of 2018 6,145,133
Total debt - end of 2018 5,768,349
Capital employed -end of 2018 11,913,482
Average capital employed $11,699,188
ROCE 13.9%
Continental Resources, Inc.
2019 Guidance
As of February 18, 2019
2019
Full-year average oil 190,000 to 200,000 Bo
production per day
Full-year average natural 790,000 to 810,000 Mcf
gas production per day
Capital expenditures
budget
$2.6 billion
Operating Expenses:
---
Production expense per Boe
$3.75 to $4.25
Production tax (% of net
oil & gas revenue) 8.0% to 8.3%
Cash G&A expense per
Boe(1)
$1.25 to $1.45
Non-cash equity
compensation per Boe
$0.45 to $0.55
DD&A per Boe
$15.00 to $17.00
Average Price
Differentials:
---
NYMEX WTI crude oil (per
barrel of oil) ($4.50) to ($5.50)
Henry Hub natural gas (per
Mcf)
$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
$1.70 to $2.00 per Boe.
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SOURCE Continental Resources
