- Jul 01, 2019
- PR Newswire
OKLAHOMA CITY, Aug. 5, 2019 /PRNewswire/ -- Continental Resources, Inc. (NYSE: CLR) (the Company) today announced second quarter 2019 operating and financial results.
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The Company reported net income of $236.6 million, or $0.63 per diluted share, for the quarter ended June 30, 2019. The Company's net income includes certain items typically excluded by the investment community in published estimates, the result of which is referred to as "adjusted net income." In second quarter 2019, these typically excluded items in aggregate represented $17.4 million, or $0.04 per diluted share, of Continental's reported net income. Adjusted net income for second quarter 2019 was $219.1 million, or $0.59 per diluted share (non-GAAP). Net cash provided by operating activities for second quarter 2019 was $783.4 million and EBITDAX was $858.0 million (non-GAAP).
Adjusted net income, adjusted net income per share, 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.
"Since announcing our total shareholder return strategy, $92 million in share repurchases have been executed by the Company. This reflects Continental's alignment with shareholders and commitment to delivering value and returns," said Harold Hamm, Chairman and Chief Executive Officer.
Production Update: 2Q19 Average Daily Oil Production up 23% over 2Q18
Second quarter 2019 oil production increased 23% over second quarter 2018, averaging 193,586 barrels of oil per day (Bopd). Second quarter 2019 total production increased 17% over second quarter 2018, averaging 331,414 Boe per day (Boepd). Second quarter 2019 natural gas production increased 9% over second quarter 2018, averaging 827.0 million cubic feet per day (MMcfpd). The following table provides the Company's average daily production by region for the periods presented.
2019 Production Guidance Increased; LOE and G&A Expense Guidance Decreased
The Company improved 2019 annual oil production guidance to 195,000 to 200,000 Bopd, versus previous guidance of 190,000 to 200,000 Bopd. The Company also increased natural gas production guidance to 820,000 to 840,000 MMcfpd, versus previous guidance of 790,000 to 810,000 Mcfpd. In addition, the Company is releasing 7 rigs in the South by year-end 2019 due to Springer & Woodford efficiency gains.
Total G&A expense, which is comprised of cash and non-cash G&A expense, has been lowered to $1.55 to $1.85 per Boe for 2019, a reduction from the previous guidance of $1.70 to $2.00. Of this total, cash G&A expense is expected to be $1.15 to $1.35 per Boe, a reduction from the previous guidance of $1.25 to $1.45. Non-cash compensation expense per Boe is expected to be $0.40 to $0.50, a reduction from the previous guidance of $0.45 to $0.55. The Company is also lowering its 2019 guidance for production expense per Boe to $3.50 to $4.00 per Boe for the year, a reduction from the previous guidance of $3.75 to $4.25.
The Company is guiding natural gas differentials wider based on lower NGL realizations and expects natural gas differentials to be in a range of ($0.50) to ($1.00) per Mcf in 2019, a change from the previous guidance of $0.00 to ($0.50). The Company is also guiding production tax to approximately 8.5% due to the higher level of production in North Dakota.
The Company's full 2019 revised guidance is stated at the conclusion of this press release.
$92 Million of Share Repurchases Executed through August 2, 2019
As previously announced, the Company's Board of Directors authorized an initial share-repurchase program of up to $1 billion. The share-repurchase program commenced in the second quarter 2019 and is expected to continue through 2020. Share repurchases will be made at times and levels deemed appropriate by Company management. The Company intends to purchase shares under the program opportunistically using available funds while maintaining sufficient liquidity to fund operating needs, capital program, and dividend payments. As of August 2, 2019, the Company has executed $92 million of share repurchases for 2.4 million shares.
As also previously announced as part of the Company's total shareholder return strategy, the Company's Board of Directors approved the initiation of a quarterly dividend of $0.05 per share on the Company's outstanding common stock, payable on November 21, 2019 to stockholders of record on November 7, 2019.
$85 Million Divestiture of Eastern STACK Water Handling Facility
As previously announced, the Company sold its eastern STACK water handling facilities in Blaine County, Oklahoma for $85 million to Lagoon Water Solutions. The Company owns and operates three additional water handling facilities in Oklahoma as well as ten additional systems in the Bakken.
Bakken: 149,078 Average Daily 2Q19 Oil Production; Up 22% over 2Q18
In second quarter 2019, average daily Bakken oil production increased 22% over second quarter 2018, averaging 149,078 Bopd. The Company's second quarter 2019 total Bakken production increased 23% over second quarter 2018, averaging 194,014 Boepd. The Company completed 35 gross (23 net) operated wells with first production during the quarter.
The Company is developing the Long Creek Bakken Unit, which covers 10-square miles and includes approximately 6,400 gross (5,600 net) contiguous acres. The Company anticipates up to 56 wells will be drilled in Long Creek, with 5 existing producers. The Company will operate these wells with an average working interest of approximately 87%. First production is expected in third quarter 2020, with oil production expected to peak in the second half of 2021 at up to 20,000 Bopd. Pipeline infrastructure is currently being constructed to handle all produced volumes.
"The Long Creek Bakken Unit is another high impact oil project for Continental, much like our Project SpringBoard in Oklahoma. Forming this large unit allows Continental to maximize the value of these assets by capitalizing on the efficiencies that come with row development," said Jack Stark, President.
South: 36,337 Average Daily 2Q19 Oil Production; Up 35% over 2Q18
In second quarter 2019, average daily South oil production increased 35% over second quarter 2018, averaging 36,337 Bopd. This increase was driven by the strategic shift to oil-weighted assets and commencing Project SpringBoard in 2018. The Company's second quarter 2019 total South production increased 10% over second quarter 2018, averaging 128,777 Boepd. In second quarter 2019, the Company completed 22 gross (16 net) operated wells with first production in the South.
The Company is on track to achieve its SpringBoard oil production growth target of 18,000 Bopd in third quarter 2019. The Company's SpringBoard oil production averaged approximately 19,000 Bopd in July 2019. The Company is targeting 22,000 Bopd from SpringBoard in fourth quarter 2019. The Company expects to bring approximately 30 additional SpringBoard wells on line in the second half of 2019.
"Continental is performing at a high level with significant net income driven by solid corporate returns and production. Additionally, we continue to realize strong free cash flow and have commenced our share-repurchase program, which we believe will further enhance shareholder value," said John Hart, Chief Financial Officer.
As of June 30, 2019, the Company's balance sheet included approximately $206.5 million in cash and cash equivalents, $5.77 billion in total debt and $5.56 billion in net debt (non-GAAP).
In second quarter 2019, the Company's average net sales prices excluding the effects of derivative positions were $54.66 per barrel of oil and $1.66 per Mcf of gas, or $36.03 per Boe. Production expense per Boe was $3.74 for second quarter 2019. Total G&A expenses per Boe were $1.57 for second quarter 2019.
The Company's second quarter 2019 crude oil differential was $5.11 per barrel below the NYMEX daily average for the period. The wellhead natural gas price for second quarter 2019 was $0.98 per Mcf below the average NYMEX Henry Hub benchmark price.
As of August 2, 2019, the Company has realized approximately $43 million of cash gains from its natural gas hedges. For the balance of 2019, natural gas is hedged 577,000 MMBtus per day at an average NYMEX Henry Hub price of $2.80. As of August 2, 2019, the Company's unrealized non-cash mark-to-market gain on its natural gas hedges totaled approximately $41 million.
Non-acquisition capital expenditures for second quarter 2019 totaled approximately $688.8 million, including $569.7 million in exploration and development drilling and completion, $22.6 million in leasehold, $43.8 million in minerals, of which 80% was recouped from Franco-Nevada, and $52.7 million in workovers, recompletions and other.
The following table provides the Company's production results, per-unit operating costs, results of operations and certain non-GAAP financial measures for the periods presented. Average net sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.
Average net sales prices (non-GAAP), excluding effect from derivatives: (1)
Production taxes (% of net crude oil and gas sales)
Total general and administrative expenses ($/Boe) (2)
Net income attributable to Continental Resources (in thousands)
Diluted net income per share attributable to Continental Resources
Adjusted diluted net income per share (non-GAAP) (1)
Net cash provided by operating activities (in thousands)
(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 $1.17, $1.41, $1.18, and $1.33 for 2Q 2019, 2Q 2018, YTD 2019, and YTD 2018, respectively. Non-cash equity compensation expense per Boe was $0.40, $0.41, $0.40, and $0.42 for 2Q 2019, 2Q 2018, YTD 2019, and YTD 2018, respectively.
The Company plans to host a conference call to discuss second quarter 2019 results on Tuesday, August 6, 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:
A replay of the call will be available for 14 days on the Company's website or by dialing:
The Company plans to publish a second quarter 2019 summary presentation to its website at www.CLR.com prior to the start of its conference call on August 6, 2019.
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; our ability to pay future dividends or complete share repurchases; 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, 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.
Unaudited Condensed Consolidated Statements of Income
Depreciation, depletion, amortization and accretion
Net income per share attributable to Continental Resources:
(1) Balance is net of accumulated depreciation, depletion and amortization of $11.78 billion and $10.81 billion as of June 30, 2019 and December 31, 2018, respectively.
Unaudited Condensed Consolidated Statements of Cash Flows
Adjustments to reconcile net income to net cash provided by operating activities:
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, and gains and losses on asset sales. 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.
Net income attributable to Continental Resources (GAAP)
Net income attributable to Continental Resources (GAAP)
(1) Computed by applying a combined federal and state statutory tax rate of 24.5% in effect for 2019 and 24.0% in effect for 2018 to the pre-tax amount of adjustments associated with our operations in the United States.
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 June 30, 2019, the Company's total debt was $5.77 billion and its net debt amounted to $5.56 billion, representing total debt of $5.77 billion less cash and cash equivalents of $206.5 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.
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.
Depreciation, depletion, amortization and accretion
The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented.
Revenues and transportation expenses associated with production from our operated properties are reported separately. 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. As a result, the separate presentation of revenues and transportation expenses from our operated properties differs from the net presentation 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 between operated and non-operated revenues, 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 periods presented.
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.
(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 $1.55 to $1.85 per Boe.