OKLAHOMA CITY, May 2, 2018 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the Company) today announced first quarter operating and financial results. The Company reported net income of $233.9 million, or $0.63 per diluted share, for the quarter ended March 31, 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 first quarter 2018, these typically excluded items in aggregate represented $21.2 million, or $0.05 per diluted share, of Continental's reported net income. Adjusted net income for first quarter 2018 was $255.1 million, or $0.68 per diluted share.
Net cash provided by operating activities for first quarter 2018 was $886.2 million. EBITDAX for first quarter 2018 was $876.2 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 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.
During first quarter 2018, the Company generated $207 million in free cash flow, allowing the Company to pay down its existing revolver balance to zero and build its cash on hand. At quarter-end, Continental's total debt was $6.17 billion, nearing the Company's short-term goal of $6 billion, while also underscoring the strides made towards achieving the long-term target of $5 billion. The Company's first quarter annualized net-debt-to-EBITDAX ratio was 1.73x, which now approaches the historical levels seen prior to the three year commodity down cycle.
Based on realizations without the effect of derivatives, the Company's first quarter 2018 crude oil differential was $3.91 per barrel below the NYMEX daily average for the period, an improvement of $3.18 per barrel compared to first quarter 2017. The realized wellhead natural gas price for first quarter 2018 was in line with the average NYMEX Henry Hub benchmark price.
"Our first quarter results show our 2018 breakout year is off to a strong start," said Harold Hamm, Chairman and Chief Executive Officer. "We are breaking away from our peers and capitalizing on decades of exploration success and operational achievements. Coupled with oil-weighted production growth and industry-leading efficiencies, we remain focused on maximizing returns and generating free cash flow now approaching $1 billion in 2018, at current commodity prices."
First quarter 2018 production totaled 25.9 million barrels of oil equivalent (Boe), or 287,410 Boe per day, up 34% from first quarter 2017. Oil production grew 37% from first quarter 2017 to first quarter 2018. The Company expects second quarter 2018 production will be in a range of 285,000 to 290,000 Boe per day.
Total production for first quarter 2018 included 163,837 barrels of oil (Bo) per day (57% of production) and 741.4 million cubic feet (MMcf) of natural gas per day (43% of production). The Company expects to remain in the range of 57% - 60% oil as a percent of overall production in 2018, which is in line with prior guidance.
The following table provides the Company's average daily production by region for the periods presented.
Boe per day
North Dakota Bakken
Red River Units
(1) Producing properties comprising approximately 1,700 Boe per day of the Company's Arkoma production were sold in September 2017.
Bakken: Record Well Performance and Improved Differentials
The Company's Bakken production averaged 161,356 Boe per day in first quarter 2018, up 48% versus first quarter 2017. Approximately 80% of the production was oil. The Company completed 31 gross (21 net) operated Bakken wells during the first quarter with an average 24-Hour IP of 2,079 Boe per day.
Three of the Company's top five all-time 30-day rate wells in the Bakken were completed in the first quarter, averaging 2,305 Boe per day. The top eight 30-day rate Bakken wells in the Company's history have now been completed in the past two quarters. These record rates are a result of the Company's optimized completion designs.
To date, the Company has completed 164 optimized Bakken wells in Dunn, McKenzie, Mountrail and Williams counties. On average, these wells are performing in line with the Company's current 1.1 MMBoe type curve, which delivers a rate of return of 140%, based on a $65 WTI oil price.
Bakken crude oil differentials averaged $4.31 per barrel in first quarter 2018, a 47% improvement over the first quarter 2017 average of $8.10 per barrel. This sustainable, structural shift has been driven by increased pipeline takeaway capacity and the renegotiated transportation contract with Belle Fourche-Tallgrass. Approximately 30% of the Company's Bakken crude now flows on Belle Fourche-Tallgrass pipeline systems at a reduced rate of $3.75 per barrel, down 40% from the previous rate. The renegotiated contract was effective January 1, 2018 and runs through October 2024.
"We are clearly seeing a structural uplift in well performance across the Bakken field," said Jack Stark, President. "Combined with improved differentials and low production costs, our optimized completions are generating some of the best returns we have seen from our Bakken assets. With over 4,000 locations in inventory, the future value to be realized by Continental and its shareholders from our Bakken assets is tremendous."
Continental operates six drilling rigs in the Bakken and plans to maintain that level through year end. The Company also operates eight stimulation crews in the play and plans to average seven to eight crews through the end of the year.
The Company's SCOOP production averaged 62,012 Boe per day (26% oil) in first quarter 2018. The Company had 18 gross (14 net) operated wells completed in first quarter 2018. Continental currently has eight operated drilling rigs working in SCOOP with five targeting the Springer formation, one targeting the Woodford and two targeting the Sycamore.
SCOOP: Project "SpringBoard" Announced with Phase 1 Springer Row Development Underway
The Company has initiated a multi-zone, oil development project within SCOOP named Project SpringBoard. The project covers 70-square miles and includes approximately 45,000 gross (31,000 net) contiguous acres. The Company anticipates approximately 100 Springer wells and up to 250 Woodford and/or Sycamore wells will be drilled in the project with gross unrisked reserve potential of over 400 MMBoe. The Company will operate these wells with an average working interest of approximately 75%. The Company currently plans to develop Project SpringBoard in two phases, with "Phase 1" focused on the Springer reservoir and "Phase 2" focused on Woodford and Sycamore reservoirs. These reservoirs will be developed in rows up to nine miles wide to maximize the efficiencies and returns from the project.
"Project SpringBoard is a massive oil project controlled and operated by Continental," said Tony Barrett, Vice President, Exploration. "SpringBoard marks the beginning of full scale development of our SCOOP oil assets, following years of exploration, leasing and delineation drilling. With oil differentials below $2.00, these barrels represent some of the most profitable barrels within the Company."
Before beginning row development of the Springer, the Company recently completed the four-well Triple H Springer unit within Project SpringBoard. The four Springer producers flowed at a maximum combined 24-hour IP rate of 6,065 Boe per day, with 88% of the production being high quality, sweet 46 gravity crude. The Triple H wells were drilled to test the productivity of thinner areas of the reservoir, using extended laterals that were 10,200 feet long. These extended laterals were drilled in approximately the same number of days (35 days) and at drilling costs comparable to one-mile laterals drilled approximately one year earlier.
SCOOP Woodford Oil: Updated Design Lowers Drilling Costs $1 Million per Well
Updated well designs and improved drilling performance have reduced completed well costs in the Woodford oil window by approximately $1 million to $11.7 million per well. At these reduced costs, a Woodford oil well now delivers a 70% rate of return, assuming the Company's current 1.5 MMBoe type curve and $65 WTI.
In addition, the Company recently completed two optimized Woodford completions. This includes the Pyle 1-36-25XH well announced last quarter, which flowed at a 24-Hour IP rate of 1,812 Boe per day (81% oil) and the Lillian 1-23-14XH well announced this quarter, which flowed at a 24-Hour IP rate of 1,593 Boe per day (74% oil). Both are outperforming the Company's 1.5 MMBoe type curve.
STACK: Shifting Rigs to Accelerate Development of Oil and Liquids-Rich Assets
The Company's STACK production increased 83% to 53,361 Boe per day in first quarter 2018, compared to first quarter 2017. Continental had 12 gross (7 net) operated wells completed in first quarter 2018.
The Company is shifting three of five rigs drilling in the STACK gas window, as acreage in the STACK JDA is now essentially held by production. Two rigs will move to unit development in the STACK over-pressured oil window and one will move to the over-pressured condensate window in SCOOP. With this reallocation, approximately 90% of the Company's 16 rigs in Oklahoma will be focused on oil and liquids-rich assets.
Project Wildcat: 400 MMcfd of Firm Transportation from SCOOP and STACK
The Company recently announced a firm transportation agreement on Enable Midstream Partners' Project Wildcat, which will provide 400 MMcf per day of additional takeaway capacity from SCOOP and STACK. As the anchor shipper, the Company will also have direct access to premium markets, including the growing North Texas region, where supplies of natural gas from the Barnett Shale continue to decline. Project Wildcat is expected to be fully in service in July 2018.
"With the announcement of Project Wildcat, Continental is in an extremely advantageous position in Oklahoma," said Harold Hamm, Chairman and Chief Executive Officer. "Wildcat provides additional flow assurance for Continental's growing production from SCOOP and STACK into a new premium market."
"2018 is off to a great start with the generation of $207 million in free cash flow in the first quarter," said John Hart, Chief Financial Officer. "With continued excess cash generation, we expect to be below $6 billion of net debt in the second quarter 2018, targeting our long-term goal of $5 billion of net debt being achieved sometime in 2019. This is yet another example of how Continental continues to deliver on its goals. We couldn't be more proud of what our Company is able to accomplish quarter-after-quarter."
On April 30, 2018, Fitch assigned an investment grade rating to the Company, which follows the February 12, 2018 upgrade by S&P to investment grade and reflects positive free cash flow and an improving leverage profile.
In first quarter 2018, the Company's average net sales price excluding the effects of derivative positions was $58.98 per barrel of oil and $2.98 per Mcf of gas, or $41.26 per Boe.
Production expense per Boe was $3.60 for first quarter 2018. Other select operating costs and expenses for first quarter 2018 included production taxes of 7.6% of net crude oil and natural gas sales; DD&A of $17.61 per Boe; and total G&A of $1.67 per Boe.
Non-acquisition capital expenditures for first quarter 2018 totaled approximately $596.3 million, including $496.3 million in exploration and development drilling, $67.0 million in leasehold and seismic, and $33.0 million in workovers, recompletions and other.
As of March 31, 2018, the Company's balance sheet included approximately $98.1 million in cash and cash equivalents and $6.17 billion in total debt.
The following table provides the Company's production results, average net sales prices, per-unit operating costs, results of operations and certain non-GAAP financial measures for the periods presented. Average net sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.
Average daily production:
Crude oil (Bbl per day)
Natural gas (Mcf per day)
Crude oil equivalents (Boe per day)
Average net sales prices (non-GAAP), excluding effect from derivatives: (1)
Crude oil ($/Bbl)
Natural gas ($/Mcf)
Crude oil equivalents ($/Boe)
Production expenses ($/Boe)
Production taxes (% of net crude oil and gas sales)
Total general and administrative expenses ($/Boe) (2)
Net income (in thousands) (3)
Diluted net income per share (3)
Adjusted net income (non-GAAP) (in thousands) (1)
Adjusted diluted net income per share (non-GAAP) (1)
Net cash provided by operating activities (in thousands)
EBITDAX (non-GAAP) (in thousands) (1)
(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 $1.25, $1.80, and $1.86 for 1Q 2018, 4Q 2017, and 1Q 2017, respectively. Non-cash equity compensation expense per Boe was $0.42, $0.50, and $0.59 for 1Q 2018, 4Q 2017, and 1Q 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 months ended December 31, 2017.
First Quarter Earnings Conference Call
Continental plans to host a conference call to discuss first quarter results on Thursday, May 3, 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, Thursday, May 3, 2018
Intl. dial in:
A replay of the call will be available for 14 days on the Company's website or by dialing:
855-859-2056 or 404-537-3406
Continental plans to publish a first quarter 2018 summary presentation to its website at www.CLR.com prior to the start of its earnings conference call on May 3, 2018.
Members of Continental's management team plan to participate in the following investment conferences:
May 7-8, 2018
Morgan Stanley E&P and Oil Services Conference, Houston
June 5, 2018
Raymond James Best Ideas Conference, Boston
June 18-20, 2018
JP Morgan Annual Oil & Gas Conference, New York
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.
Vice President, Investor Relations
Senior Vice President, Public Relations
Continental Resources, Inc. and Subsidiaries
Unaudited Condensed Consolidated Statements of Income
Three months ended March 31,
In thousands, except per share data
Crude oil and natural gas sales
Gain on natural gas derivatives, net
Crude oil and natural gas service operations
Operating costs and expenses:
Crude oil and natural gas service operations
Depreciation, depletion, amortization and accretion
General and administrative expenses
Net (gain) loss on sale of assets and other
Total operating costs and expenses
Income from operations
Other income (expense):
Income before income taxes
Provision for income taxes
Basic net income per share
Diluted net income per share
Continental Resources, Inc. and Subsidiaries
Unaudited Condensed Consolidated Balance Sheets
March 31, 2018
December 31, 2017
Cash and cash equivalents
Other current assets
Net property and equipment (1)
Other noncurrent assets
Liabilities and shareholders' equity
Long-term debt, net of current portion
Other noncurrent liabilities
Total shareholders' equity
Total liabilities and shareholders' equity
(1) Balance is net of accumulated depreciation, depletion and amortization of $9.53 billion and $9.08 billion as of March 31, 2018 and December 31, 2017, respectively.
Continental Resources, Inc. and Subsidiaries
Unaudited Condensed Consolidated Statements of Cash Flows
Three months ended March 31,
Adjustments to reconcile net income to net cash provided by operating activities:
Changes in assets and liabilities
Net cash provided by operating activities
Net cash used in investing activities
Net cash used in financing activities
Effect of exchange rate changes on cash
Net change in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
Non-GAAP Financial Measures
Adjusted earnings (net income) and adjusted earnings (net income) per share
Our presentation of adjusted earnings and adjusted earnings per share that exclude the effect of certain items are non-GAAP financial measures. Adjusted earnings and adjusted earnings per share represent earnings and diluted earnings per share determined under U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments, gains and losses on asset sales, and losses on extinguishment of debt. Management believes these measures provide useful information to analysts and investors for analysis of our operating results. In addition, management believes these measures are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to an entity's specific derivative portfolio, impairment methodologies, and property dispositions. Adjusted earnings and adjusted earnings per share should not be considered in isolation or as 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.
In thousands, except per share data
Net income (GAAP)
Non-cash (gain) loss on derivatives
(Gain) loss on sale of assets
Loss on extinguishment of debt
Total tax effect of adjustments (1)
Tax benefit from US tax reform legislation
Total adjustments, net of tax
Adjusted net income (non-GAAP)
Weighted average diluted shares outstanding
Adjusted diluted net income per share (non-GAAP)
(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 other than the tax benefit adjustment related to US tax reform legislation.
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. At March 31, 2018, the Company's net debt amounted to $6.07 billion, representing total debt of $6.17 billion less cash and cash equivalents of $98 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.
We use a variety of financial and operational measures to assess our performance. Among these measures is EBITDAX. We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, non-cash equity compensation expense, and losses on extinguishment of debt. EBITDAX is not a measure of net income 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 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 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.
Provision (benefit) for income taxes
Depreciation, depletion, amortization and accretion
Impact from derivative instruments:
Total gain on derivatives, net
Total cash received (paid) on derivatives, net
Non-cash (gain) loss on derivatives, net
Non-cash equity compensation
Loss on extinguishment of debt
The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented.
Net cash provided by operating activities
Current income tax provision (benefit)
Exploration expenses, excluding dry hole costs
Gain (loss) on sale of assets, net
Changes in assets and liabilities
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 and divestitures. 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.
The following table reconciles historical net cash provided by operating activities as determined under U.S. GAAP to free cash flow for the first quarter of 2018.
Net cash provided by operating activities (GAAP)
Exclude: Changes in working capital items
Less: Capital expenditures (1)
Free cash flow (non-GAAP)
(1) Capital expenditures are calculated as follows:
Cash paid for capital expenditures
Less: Total acquisitions
Plus: Change in accrued capital expenditures
Plus: Exploratory seismic costs
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 the majority of 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 the majority of 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 months ended March 31, 2018. Information is also presented for the three months ended March 31, 2017 for comparative purposes.
Three months ended March 31, 2018
Three months ended March 31, 2017
Crude oil and natural gas sales (GAAP)
Less: Transportation expenses
Net crude oil and natural gas sales (non-GAAP for 2018)
Sales volumes (MBbl, MMcf, MBoe)
Net sales price (non-GAAP for 2018)
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.
As of May 2, 2018
Full-year average production
285,000 to 300,000 Boe per day
Exit-rate average production
305,000 to 315,000 Boe per day
Capital expenditures (non-acquisition)
Production expense per Boe
$3.00 to $3.50
Production tax (% of net oil & gas revenue)
7.6% to 8.0%
Cash G&A expense per Boe(1)
$1.25 to $1.75
Non-cash equity compensation per Boe
$0.45 to $0.55
DD&A per Boe
$17.00 to $19.00
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) 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 $2.30 per Boe.
SOURCE Continental Resources