UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
þ Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended September 30, 2018
OR
o Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from _______ to ________
Commission file number: 001-12935
DENBURY RESOURCES INC.
(Exact name of registrant as specified in its charter)
Delaware | 20-0467835 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
5320 Legacy Drive, Plano, TX | 75024 | |
(Address of principal executive offices) | (Zip Code) | |
Registrant’s telephone number, including area code: | (972) 673-2000 | |
Not applicable
(Former name, former address and former fiscal year, if changed since last report)
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ | Accelerated filer o | Non-accelerated filer o | Smaller reporting company o | Emerging growth company o |
(Do not check if a smaller reporting company) | ||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
Class | Outstanding as of October 31, 2018 | |
Common Stock, $.001 par value | 460,546,469 | |
Denbury Resources Inc.
Table of Contents
Page | ||||
Unaudited Condensed Consolidated Balance Sheets as of September 30, 2018 and December 31, 2017 | ||||
Unaudited Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2018 and 2017 | ||||
Unaudited Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2018 and 2017 | ||||
Unaudited Condensed Consolidated Statement of Changes in Stockholders’ Equity for the Nine Months Ended September 30, 2018 | ||||
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Denbury Resources Inc.
Unaudited Condensed Consolidated Balance Sheets
(In thousands, except par value and share data)
September 30, | December 31, | |||||||
2018 | 2017 | |||||||
Assets | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 66,711 | $ | 58 | ||||
Accrued production receivable | 163,475 | 146,334 | ||||||
Trade and other receivables, net | 43,495 | 45,193 | ||||||
Other current assets | 14,504 | 10,670 | ||||||
Total current assets | 288,185 | 202,255 | ||||||
Property and equipment | ||||||||
Oil and natural gas properties (using full cost accounting) | ||||||||
Proved properties | 10,977,038 | 10,775,792 | ||||||
Unevaluated properties | 976,378 | 951,397 | ||||||
CO2 properties | 1,194,133 | 1,191,058 | ||||||
Pipelines and plants | 2,299,699 | 2,286,047 | ||||||
Other property and equipment | 286,443 | 339,218 | ||||||
Less accumulated depletion, depreciation, amortization and impairment | (11,477,873 | ) | (11,376,646 | ) | ||||
Net property and equipment | 4,255,818 | 4,166,866 | ||||||
Other assets | 100,014 | 102,178 | ||||||
Total assets | $ | 4,644,017 | $ | 4,471,299 | ||||
Liabilities and Stockholders’ Equity | ||||||||
Current liabilities | ||||||||
Accounts payable and accrued liabilities | $ | 201,373 | $ | 177,220 | ||||
Oil and gas production payable | 72,824 | 76,588 | ||||||
Derivative liabilities | 125,354 | 99,061 | ||||||
Current maturities of long-term debt (including future interest payable of $102,181 and $75,347, respectively – see Note 4) | 126,884 | 105,188 | ||||||
Total current liabilities | 526,435 | 458,057 | ||||||
Long-term liabilities | ||||||||
Long-term debt, net of current portion (including future interest payable of $190,410 and $241,472, respectively – see Note 4) | 2,693,424 | 2,979,086 | ||||||
Asset retirement obligations | 174,761 | 165,756 | ||||||
Derivative liabilities | 13,570 | — | ||||||
Deferred tax liabilities, net | 249,264 | 198,099 | ||||||
Other liabilities | 23,379 | 22,136 | ||||||
Total long-term liabilities | 3,154,398 | 3,365,077 | ||||||
Commitments and contingencies (Note 7) | ||||||||
Stockholders’ equity | ||||||||
Preferred stock, $.001 par value, 25,000,000 shares authorized, none issued and outstanding | — | — | ||||||
Common stock, $.001 par value, 600,000,000 shares authorized; 462,462,855 and 402,549,346 shares issued, respectively | 462 | 403 | ||||||
Paid-in capital in excess of par | 2,680,899 | 2,507,828 | ||||||
Accumulated deficit | (1,707,591 | ) | (1,855,810 | ) | ||||
Treasury stock, at cost, 1,893,882 and 457,041 shares, respectively | (10,586 | ) | (4,256 | ) | ||||
Total stockholders’ equity | 963,184 | 648,165 | ||||||
Total liabilities and stockholders’ equity | $ | 4,644,017 | $ | 4,471,299 | ||||
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
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Denbury Resources Inc.
Unaudited Condensed Consolidated Statements of Operations
(In thousands, except per share data)
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2018 | 2017 | 2018 | 2017 | |||||||||||||
Revenues and other income | ||||||||||||||||
Oil, natural gas, and related product sales | $ | 379,628 | $ | 259,030 | $ | 1,095,214 | $ | 776,088 | ||||||||
CO2 sales and transportation fees | 8,149 | 6,590 | 22,416 | 18,533 | ||||||||||||
Other income | 7,196 | 939 | 17,640 | 8,576 | ||||||||||||
Total revenues and other income | 394,973 | 266,559 | 1,135,270 | 803,197 | ||||||||||||
Expenses | ||||||||||||||||
Lease operating expenses | 122,527 | 117,768 | 361,267 | 342,926 | ||||||||||||
Marketing and plant operating expenses | 12,427 | 11,816 | 36,400 | 39,758 | ||||||||||||
CO2 discovery and operating expenses | 708 | 1,346 | 1,670 | 2,452 | ||||||||||||
Taxes other than income | 27,344 | 20,233 | 81,897 | 62,848 | ||||||||||||
General and administrative expenses | 21,579 | 27,273 | 61,223 | 81,303 | ||||||||||||
Interest, net of amounts capitalized of $9,514, $9,416, $26,817 and $22,217, respectively | 18,527 | 24,546 | 51,974 | 75,785 | ||||||||||||
Depletion, depreciation, and amortization | 51,316 | 52,101 | 156,711 | 154,448 | ||||||||||||
Commodity derivatives expense (income) | 44,577 | 25,263 | 189,601 | (9,712 | ) | |||||||||||
Other expenses | 1,933 | — | 7,241 | — | ||||||||||||
Total expenses | 300,938 | 280,346 | 947,984 | 749,808 | ||||||||||||
Income (loss) before income taxes | 94,035 | (13,787 | ) | 187,286 | 53,389 | |||||||||||
Income tax provision (benefit) | 15,616 | (14,229 | ) | 39,067 | 17,018 | |||||||||||
Net income | $ | 78,419 | $ | 442 | $ | 148,219 | $ | 36,371 | ||||||||
Net income per common share | ||||||||||||||||
Basic | $ | 0.17 | $ | 0.00 | $ | 0.35 | $ | 0.09 | ||||||||
Diluted | $ | 0.17 | $ | 0.00 | $ | 0.33 | $ | 0.09 | ||||||||
Weighted average common shares outstanding | ||||||||||||||||
Basic | 451,256 | 392,013 | 426,036 | 390,448 | ||||||||||||
Diluted | 458,450 | 393,023 | 455,934 | 392,625 | ||||||||||||
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
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Denbury Resources Inc.
Unaudited Condensed Consolidated Statements of Cash Flows
(In thousands)
Nine Months Ended September 30, | ||||||||
2018 | 2017 | |||||||
Cash flows from operating activities | ||||||||
Net income | $ | 148,219 | $ | 36,371 | ||||
Adjustments to reconcile net income to cash flows from operating activities | ||||||||
Depletion, depreciation, and amortization | 156,711 | 154,448 | ||||||
Deferred income taxes | 42,741 | 35,846 | ||||||
Stock-based compensation | 8,711 | 12,215 | ||||||
Commodity derivatives expense (income) | 189,601 | (9,712 | ) | |||||
Payment on settlements of commodity derivatives | (149,738 | ) | (38,618 | ) | ||||
Debt issuance costs | 4,980 | 4,801 | ||||||
Other, net | (7,066 | ) | (112 | ) | ||||
Changes in assets and liabilities, net of effects from acquisitions | ||||||||
Accrued production receivable | (17,140 | ) | 3,590 | |||||
Trade and other receivables | 139 | (13,604 | ) | |||||
Other current and long-term assets | (4,467 | ) | (4,734 | ) | ||||
Accounts payable and accrued liabilities | 27,435 | (22,736 | ) | |||||
Oil and natural gas production payable | (3,764 | ) | (10,848 | ) | ||||
Other liabilities | (2,832 | ) | (4,048 | ) | ||||
Net cash provided by operating activities | 393,530 | 142,859 | ||||||
Cash flows from investing activities | ||||||||
Oil and natural gas capital expenditures | (210,504 | ) | (197,982 | ) | ||||
Acquisitions of oil and natural gas properties | (151 | ) | (91,124 | ) | ||||
Pipelines and plants capital expenditures | (19,134 | ) | (1,479 | ) | ||||
Net proceeds from sales of oil and natural gas properties and equipment | 7,308 | 1,412 | ||||||
Other | 5,749 | (4,638 | ) | |||||
Net cash used in investing activities | (216,732 | ) | (293,811 | ) | ||||
Cash flows from financing activities | ||||||||
Bank repayments | (1,943,653 | ) | (1,188,000 | ) | ||||
Bank borrowings | 1,468,653 | 1,382,000 | ||||||
Interest payments treated as a reduction of debt | (37,233 | ) | (25,139 | ) | ||||
Proceeds from issuance of senior secured notes | 450,000 | — | ||||||
Cost of debt financing | (15,933 | ) | (341 | ) | ||||
Pipeline financing and capital lease debt repayments | (18,353 | ) | (20,523 | ) | ||||
Other | (13,288 | ) | 1,603 | |||||
Net cash provided by (used in) financing activities | (109,807 | ) | 149,600 | |||||
Net increase (decrease) in cash, cash equivalents, and restricted cash | 66,991 | (1,352 | ) | |||||
Cash, cash equivalents, and restricted cash at beginning of period | 15,992 | 17,050 | ||||||
Cash, cash equivalents, and restricted cash at end of period | $ | 82,983 | $ | 15,698 | ||||
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
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Denbury Resources Inc.
Unaudited Condensed Consolidated Statement of Changes in Stockholders' Equity
(Dollar amounts in thousands)
Common Stock ($.001 Par Value) | Paid-In Capital in Excess of Par | Retained Earnings (Accumulated Deficit) | Treasury Stock (at cost) | ||||||||||||||||||||||
Shares | Amount | Shares | Amount | Total Equity | |||||||||||||||||||||
Balance – December 31, 2017 | 402,549,346 | $ | 403 | $ | 2,507,828 | $ | (1,855,810 | ) | 457,041 | $ | (4,256 | ) | $ | 648,165 | |||||||||||
Issued or purchased pursuant to stock compensation plans | 4,663,554 | 4 | (4 | ) | — | — | — | — | |||||||||||||||||
Issued pursuant to notes conversion | 55,249,955 | 55 | 161,949 | — | — | — | 162,004 | ||||||||||||||||||
Stock-based compensation | — | — | 11,126 | — | — | — | 11,126 | ||||||||||||||||||
Tax withholding – stock compensation | — | — | — | — | 1,436,841 | (6,330 | ) | (6,330 | ) | ||||||||||||||||
Net income | — | — | — | 148,219 | — | — | 148,219 | ||||||||||||||||||
Balance – September 30, 2018 | 462,462,855 | $ | 462 | $ | 2,680,899 | $ | (1,707,591 | ) | 1,893,882 | $ | (10,586 | ) | $ | 963,184 | |||||||||||
See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.
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Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
Note 1. Basis of Presentation
Organization and Nature of Operations
Denbury Resources Inc., a Delaware corporation, is an independent oil and natural gas company with operations focused in two key operating areas: the Gulf Coast and Rocky Mountain regions. Our goal is to increase the value of our properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to CO2 enhanced oil recovery operations.
Interim Financial Statements
The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2017 (the “Form 10-K”). Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company” or “Denbury,” refer to Denbury Resources Inc. and its subsidiaries.
Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end, and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year. In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of September 30, 2018, our consolidated results of operations for the three and nine months ended September 30, 2018 and 2017, our consolidated cash flows for the nine months ended September 30, 2018 and 2017, and our consolidated statement of changes in stockholders’ equity for the nine months ended September 30, 2018.
Reclassifications
Certain prior period amounts have been reclassified to conform to the current year presentation. Such reclassifications had no impact on our reported net income, current assets, total assets, current liabilities, total liabilities or stockholders’ equity.
Cash, Cash Equivalents, and Restricted Cash
The following table provides a reconciliation of cash, cash equivalents, and restricted cash as reported within the Unaudited Condensed Consolidated Balance Sheets to “Cash, cash equivalents, and restricted cash at end of period” as reported within the Unaudited Condensed Consolidated Statements of Cash Flows:
In thousands | September 30, 2018 | December 31, 2017 | ||||||
Cash and cash equivalents | $ | 66,711 | $ | 58 | ||||
Restricted cash included in Other assets | 16,272 | 15,934 | ||||||
Total cash, cash equivalents, and restricted cash shown in the Unaudited Condensed Consolidated Statements of Cash Flows | $ | 82,983 | $ | 15,992 | ||||
Amounts included in restricted cash included in “Other assets” in the accompanying Unaudited Condensed Consolidated Balance Sheets represent escrow accounts that are legally restricted for certain of our asset retirement obligations.
Net Income per Common Share
Basic net income per common share is computed by dividing the net income attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net income per common share is calculated in the same manner, but includes the impact of potentially dilutive securities. Potentially dilutive securities consist of nonvested restricted stock, nonvested performance-based equity awards, and shares into which our previously-outstanding convertible senior notes were convertible.
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Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
The following table sets forth the reconciliations of net income and weighted average shares used for purposes of calculating the basic and diluted net income per common share for the periods indicated:
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
In thousands | 2018 | 2017 | 2018 | 2017 | ||||||||||||
Numerator | ||||||||||||||||
Net income – basic | $ | 78,419 | $ | 442 | $ | 148,219 | $ | 36,371 | ||||||||
Effect of potentially dilutive securities | ||||||||||||||||
Interest on convertible senior notes | — | — | 538 | — | ||||||||||||
Net income – diluted | $ | 78,419 | $ | 442 | $ | 148,757 | $ | 36,371 | ||||||||
Denominator | ||||||||||||||||
Weighted average common shares outstanding – basic | 451,256 | 392,013 | 426,036 | 390,448 | ||||||||||||
Effect of potentially dilutive securities | ||||||||||||||||
Restricted stock and performance-based equity awards | 7,194 | 1,010 | 6,983 | 2,177 | ||||||||||||
Convertible senior notes | — | — | 22,915 | — | ||||||||||||
Weighted average common shares outstanding – diluted | 458,450 | 393,023 | 455,934 | 392,625 | ||||||||||||
Basic weighted average common shares exclude shares of nonvested restricted stock. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net income per common share (although time-vesting restricted stock is issued and outstanding upon grant). For purposes of calculating diluted weighted average common shares during the three and nine months ended September 30, 2018 and 2017, the nonvested restricted stock and performance-based equity awards are included in the computation using the treasury stock method, with the deemed proceeds equal to the average unrecognized compensation during the period, and for the shares underlying the previously-outstanding convertible senior notes as if the convertible senior notes were converted at the beginning of the 2018 period. In April and May 2018, all outstanding convertible senior notes converted into shares of Denbury common stock, resulting in the issuance of 55.2 million shares of our common stock upon conversion. These shares have been included in basic weighted average common shares outstanding beginning on the date of conversion. See Note 4, Long-Term Debt, for further discussion.
The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income per share, as their effect would have been antidilutive:
Three Months Ended | Nine Months Ended | |||||||||||
September 30, | September 30, | |||||||||||
In thousands | 2018 | 2017 | 2018 | 2017 | ||||||||
Stock appreciation rights | 2,689 | 4,551 | 2,824 | 4,793 | ||||||||
Restricted stock and performance-based equity awards | — | 9,891 | 203 | 6,259 | ||||||||
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Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
Recent Accounting Pronouncements
Recently Adopted
Cash Flows. In November 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-18, Statement of Cash Flows (“ASU 2016-18”). ASU 2016-18 addresses the diversity that exists in the classification and presentation of changes in restricted cash on the statement of cash flows, and requires that a statement of cash flows explain the change in total cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, entities will no longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents in the statement of cash flows. Effective January 1, 2018, we adopted ASU 2016-18, which has been applied retrospectively for all comparative periods presented. Accordingly, restricted cash associated with our escrow accounts of $15.9 million and $15.4 million for the nine-month periods ended September 30, 2018 and 2017, respectively, have been included in “Cash, cash equivalents, and restricted cash at beginning of period” on our Unaudited Condensed Consolidated Statements of Cash Flows and $15.6 million included in “Cash, cash equivalents, and restricted cash at end of period” for the nine-month period ended September 30, 2017. The adoption of ASU 2016-18 did not have an impact on our consolidated balance sheets or results of operations.
Our quarterly reports on Form 10-Q for the periods ended March 31, 2018 and June 30, 2018, filed with the SEC on May 10, 2018 and August 9, 2018, respectively, incorrectly included in the beginning-of-period and end-of-period balances of “Cash, cash equivalents, and restricted cash” in our Statements of Cash Flows, certain U.S. Treasury Notes held in escrow accounts legally restricted for use in certain of our asset retirement obligations. Under Financial Accounting Standards Board Codification (“FASC”) 230-10-20, these notes do not meet the definition of restricted cash and restricted cash equivalents due to their maturity date exceeding 90 days. Previously disclosed balances of these U.S. Treasury Notes of $24.6 million, $25.2 million and $25.4 million as of January 1, 2018 (the date of adoption), March 31, 2018 and June 30, 2018, respectively, should have been excluded from “Cash, cash equivalents, and restricted cash” on the Consolidated Statements of Cash Flows. Accordingly, “Cash, cash equivalents, and restricted cash” as of January 1, 2018 (the date of adoption), March 31, 2018 and June 30, 2018, originally reported as $40.6 million, $40.9 million and $41.6 million, respectively, should have been reported as $16.0 million, $15.7 million and $16.2 million, respectively. In addition, changes in the U.S. Treasury Notes of $0.6 million and $0.8 million during the three months ended March 31, 2018 and six months ended June 30, 2018, respectively, should have been included in net cash used in investing activities. Accordingly, net cash used in investing activities for the three months ended March 31, 2018, originally reported as $50.8 million, should have been $51.4 million, and net cash used in investing activities for the six months ended June 30, 2018, originally reported as $134.1 million, should have been $134.9 million. Management has evaluated the quantitative and qualitative impact of the error to previously issued unaudited consolidated statements of cash flows and concluded that the previously issued consolidated financial statements were not materially misstated. However, management has elected to revise the unaudited consolidated statements of cash flows for each of the three months ended March 31, 2018 and six months ended June 30, 2018 in its future filings. These revisions had no impact on the Company’s financial condition or results of operations for the periods presented.
Revenue Recognition. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 amends the guidance for revenue recognition to replace numerous, industry-specific requirements. The core principle of the ASU is that an entity should recognize revenue for the transfer of goods or services equal to the amount that it expects to be entitled to receive for those goods or services. The ASU implements a five-step process for customer contract revenue recognition that focuses on transfer of control, as opposed to transfer of risk and rewards. The amendment also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenues and cash flows arising from contracts with customers. In March, April and May 2016, the FASB issued four additional ASUs which primarily clarified the implementation guidance on principal versus agent considerations, performance obligations and licensing, collectibility, presentation of sales taxes and other similar taxes collected from customers, and non-cash consideration. Effective January 1, 2018, we adopted ASU 2014-09 using the modified retrospective method. The adoption of ASU 2014-09 did not have an impact on our consolidated financial statements, but required enhanced footnote disclosures. See Note 2, Revenue Recognition, for additional information.
Not Yet Adopted
Fair Value Measurement. In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820) – Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurements (“ASU 2018-13”). ASU 2018-13 adds, modifies, or removes certain disclosure requirements for recurring and nonrecurring fair value measurements based on the FASB’s consideration of costs and benefits. The amendments in this ASU are effective for fiscal years beginning after December 15, 2019,
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Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
and interim periods within those fiscal years, and early adoption is permitted. Entities must adopt the amendments on changes in unrealized gains and losses, the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements, and the narrative description of measurement uncertainty prospectively, and all other amendments should be applied retrospectively to all periods presented. The adoption of ASU 2018-13 is currently not expected to have a material effect on our consolidated financial statements, but may require enhanced footnote disclosures.
Leases. In February 2016, the FASB issued ASU 2016-02, Leases (“ASU 2016-02”). ASU 2016-02 amends the guidance for lease accounting to require lease assets and liabilities to be recognized on the balance sheet, along with additional disclosures regarding key leasing arrangements. The ASU does not apply to mineral leases or leases that convey the right to explore for or use the land on which oil, natural gas, and similar natural resources are contained. The amendments in this ASU are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, and early adoption is permitted. Entities must adopt the standard using a modified retrospective transition and apply the guidance to the earliest comparative period presented, with certain practical expedients that entities may elect to apply. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842) – Land Easement Practical Expedient for Transition to Topic 842, which provides an optional practical expedient to existing or expired land easements that were not previously accounted for as leases under Topic 840, which permits a company to evaluate only new or modified land easements under the new guidance. We intend to elect the practical expedients provided in the new ASUs that allow historical lease classification of existing leases, allow entities to recognize leases with terms of one year or less in their statement of operations, and carry forward our accounting treatment for existing land easement agreements. We are currently evaluating our lease agreements and implementing a software system to summarize the key contract terms and financial information associated with each lease agreement, in order to assess the impact the adoption of ASU 2016-02 and ASU 2018-01 will have on our consolidated financial statements.
Note 2. Revenue Recognition
We record revenue in accordance with FASC Topic 606, Revenue from Contracts with Customers, which we adopted on January 1, 2018, and applied to all existing contracts using the modified retrospective method. The core principle of FASC Topic 606 is that an entity should recognize revenue for the transfer of goods or services equal to the amount of consideration that it expects to be entitled to receive for those goods or services. This principle is achieved through applying a five-step process for customer contract revenue recognition:
•Identify the contract or contracts with a customer – We derive the majority of our revenues from oil and natural gas sales contracts and CO2 sales and transportation contracts. The contracts specify each party’s rights regarding the goods or services to be transferred and contain commercial substance as they impact our financial statements. A high percentage of our receivables balance is current, and we have not historically entered into contracts with counterparties that pose a credit risk without requiring adequate economic protection to ensure collection.
•Identify the performance obligations in the contract – Each of our revenue contracts specify a volume per day, or production from a lease designated in the contract (a distinct good), to be delivered at the delivery point over the term of the contract (the identified performance obligation). The customer takes delivery and physical possession of the product at the delivery point, which generally is also the point at which title transfers and the customer obtains the risks and rewards of ownership (the identified performance obligation is satisfied).
•Determine the transaction price – Typically, our oil and natural gas contracts define the price as a formula price based on the average market price, as specified on set dates each month, for the specific commodity during the month of delivery. Certain of our CO2 contracts define the price as a fixed contractual price adjusted to an inflation index to reflect market pricing. Given the industry practice to invoice customers the month following the month of delivery and our high probability of collection of payment, no significant financing component is included in our contracts.
•Allocate the transaction price to the performance obligations in the contract – The majority of our revenue contracts are short-term, with terms of one year or less, to which we have applied the practical expedient permitted under the standard eliminating the requirement to disclose the transaction price allocated to remaining performance obligations. In limited instances, we have revenue contracts with terms greater than one year; however, the future delivery volumes are wholly unsatisfied as they represent separate performance obligations with variable consideration. We utilized the practical expedient which eliminates the requirement to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely
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Denbury Resources Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
to wholly unsatisfied performance obligations. As there is only one performance obligation associated with our contracts, no allocation of the transaction price is necessary.
•Recognize revenue when, or as, we satisfy a performance obligation – Once we have delivered the volume of commodity to the delivery point and the customer takes delivery and possession, we are entitled to payment and we invoice the customer for such delivered production. Payment under most oil and CO2 contracts is made within a month following product delivery and for natural gas and NGL contracts is generally made within two months following delivery. Timing of revenue recognition may differ from the timing of invoicing to customers; however, as the right to consideration after delivery is unconditional based on only the passage of time before payment of the consideration is due, upon delivery we record a receivable in “Accrued production receivable” in our Unaudited Condensed Consolidated Balance Sheets, which was $163.5 million and $146.3 million as of September 30, 2018 and December 31, 2017, respectively.
Disaggregation of Revenue
The following table summarizes our revenues by product type for the three and nine months ended September 30, 2018 and 2017:
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
In thousands | 2018 | 2017 | 2018 | 2017 | ||||||||||||
Oil sales | $ | 377,329 | $ | 256,621 | $ | 1,088,021 | $ | 768,912 | ||||||||
Natural gas sales | 2,299 | 2,409 | 7,193 | 7,176 | ||||||||||||
CO2 sales and transportation fees | 8,149 | 6,590 | 22,416 | 18,533 | ||||||||||||
Total revenues | $ | 387,777 | $ | 265,620 | $ | 1,117,630 | $ | 794,621 | ||||||||
Note 3. Assets Held for Sale
We are marketing for sale certain non-productive surface acreage in the Houston area. As of September 30, 2018, the carrying value of the land held for sale was $33.0 million, which is included in “Other property and equipment” on our Unaudited Condensed Consolidated Balance Sheets.
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Note 4. Long-Term Debt
The table below reflects long-term debt and capital lease obligations outstanding as of the dates indicated:
September 30, | December 31, | |||||||
In thousands | 2018 | 2017 | ||||||
Senior Secured Bank Credit Agreement | $ | — | $ | 475,000 | ||||
9% Senior Secured Second Lien Notes due 2021 | 614,919 | 614,919 | ||||||
9¼% Senior Secured Second Lien Notes due 2022 | 455,668 | 381,568 | ||||||
7½% Senior Secured Second Lien Notes due 2024 | 450,000 | — | ||||||
3½% Convertible Senior Notes due 2024 | — | 84,650 | ||||||
6⅜% Senior Subordinated Notes due 2021 | 203,545 | 215,144 | ||||||
5½% Senior Subordinated Notes due 2022 | 314,662 | 408,882 | ||||||
4⅝% Senior Subordinated Notes due 2023 | 307,978 | 376,501 | ||||||
Pipeline financings | 183,428 | 192,429 | ||||||
Capital lease obligations | 11,290 | 26,298 | ||||||
Total debt principal balance | 2,541,490 | 2,775,391 | ||||||
Future interest payable(1) | 292,590 | 316,818 | ||||||
Debt issuance costs | (13,772 | ) | (7,935 | ) | ||||
Total debt, net of debt issuance costs | 2,820,308 | 3,084,274 | ||||||
Less: current maturities of long-term debt(1) | (126,884 | ) | (105,188 | ) | ||||
Long-term debt and capital lease obligations | $ | 2,693,424 | $ | 2,979,086 | ||||
(1) | Future interest payable represents most of the interest due over the terms of our 9% Senior Secured Second Lien Notes due 2021 (the “2021 Senior Secured Notes”), 9¼% Senior Secured Second Lien Notes due 2022 (the “2022 Senior Secured Notes”), and to a small extent our previously outstanding 3½% Convertible Senior Notes due 2024 (the “2024 Convertible Senior Notes”) and has been accounted for as debt in accordance with FASC 470-60, Troubled Debt Restructuring by Debtors. Our current maturities of long-term debt as of September 30, 2018 include $102.2 million of future interest payable related to the 2021 Senior Secured Notes and 2022 Senior Secured Notes that is due within the next twelve months. See January 2018 Note Exchanges below for further discussion. |
The ultimate parent company in our corporate structure, Denbury Resources Inc. (“DRI”), is the sole issuer of all of our outstanding senior secured and senior subordinated notes. DRI has no independent assets or operations. Each of the subsidiary guarantors of such notes is 100% owned, directly or indirectly, by DRI, and the guarantees of the notes are full and unconditional and joint and several; any subsidiaries of DRI that are not subsidiary guarantors of such notes are minor subsidiaries.
Senior Secured Bank Credit Facility
In December 2014, we entered into an Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (as amended, the “Bank Credit Agreement”). The Bank Credit Agreement is a senior secured revolving credit facility with semiannual borrowing base redeterminations in May and November of each year, with the next such redetermination being scheduled for May 2019. If our outstanding debt under the Bank Credit Agreement were to ever exceed the borrowing base, we would be required to repay the excess amount over a period not to exceed six months. We incur a commitment fee of 0.50% on the undrawn portion of the aggregate lender commitments under the Bank Credit Agreement.
In August 2018, we entered into the Sixth Amendment to the Bank Credit Agreement (the “Sixth Amendment”), pursuant to which the following changes were made to the Bank Credit Agreement:
• | The maturity date was extended from December 9, 2019 to December 9, 2021, provided that the maturity date may occur earlier (between February 2021 and August 2021) if the 2021 Senior Secured Notes due in May 2021 or 6⅜% Senior Subordinated Notes due in August 2021 (the “2021 Subordinated Notes”) are not repaid or refinanced by their respective maturity dates; |
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Notes to Unaudited Condensed Consolidated Financial Statements
• | The borrowing base and total commitments were reduced from $1.05 billion to $615 million in connection with a reduction in the number of lenders party to the Bank Credit Agreement; |
• | The amount of junior lien debt we can incur was increased from $1.2 billion to $1.65 billion outstanding in the aggregate at any one time; and |
• | A Consolidated Total Debt to Consolidated EBITDAX financial maintenance covenant was added with a ratio not to exceed 5.25 to 1.0 through December 31, 2020, and 4.50 to 1.0 thereafter through the maturity date. |
At September 30, 2018, in addition to the Consolidated Total Debt to Consolidated EBITDAX covenant added by the Sixth Amendment, the Bank Credit Agreement contains certain financial performance covenants through the maturity of the facility, including the following:
• | A consolidated senior secured debt to consolidated EBITDAX covenant, with such ratio not to exceed 2.5 to 1.0. Currently, only debt under our Bank Credit Agreement is considered consolidated senior secured debt for purposes of this ratio; |
• | A minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 1.25 to 1.0; and |
• | A requirement to maintain a current ratio of 1.0 to 1.0. |
As of September 30, 2018, we had no outstanding borrowings and were in compliance with all debt covenants under the Bank Credit Agreement. The above description of our Bank Credit Agreement is qualified by the express language and defined terms contained in the Bank Credit Agreement and the amendments thereto, each of which are filed as exhibits to our periodic reports filed with the SEC.
January 2018 Note Exchanges
During January 2018, we closed transactions to exchange a total of $174.3 million aggregate principal amount of our then existing senior subordinated notes for $74.1 million aggregate principal amount of new 2022 Senior Secured Notes and $59.4 million aggregate principal amount of new 5% Convertible Senior Notes due 2023 (the “2023 Convertible Senior Notes”), resulting in a net reduction in our debt principal from these exchanges of $40.8 million. The exchanged notes consisted of $11.6 million aggregate principal amount of our 2021 Subordinated Notes, $94.2 million aggregate principal amount of our 5½% Senior Subordinated Notes due 2022 and $68.5 million aggregate principal amount of our 4⅝% Senior Subordinated Notes due 2023.
In accordance with FASC 470-60, the exchange was accounted for as a troubled debt restructuring due to the level of concession provided by our senior subordinated note holders. Under this guidance, future interest applicable to the new 2022 Senior Secured Notes and 2023 Convertible Senior Notes was recorded as debt up to the point that the principal and future interest of the new notes was equal to the principal amount of the extinguished notes, rather than recognizing a gain on extinguishment for this amount. In May 2018, the debt principal balance and future interest applicable to the 2023 Convertible Senior Notes were reclassified to “Paid-in capital in excess of par” and “Common stock” in our Unaudited Condensed Consolidated Balance Sheets following the conversion of the notes into shares of Denbury common stock (see Conversions of 2023 and 2024 Convertible Senior Notes into Common Stock in May and June 2018 below for further discussion). As of September 30, 2018, $20.6 million of future interest on the new 2022 Senior Secured Notes was recorded as debt, which will be reduced as semiannual interest payments are made, with the remaining $3.3 million of future interest to be recognized as interest expense over the term of the notes. Therefore, future interest expense reflected in our Unaudited Condensed Consolidated Statements of Operations on the new 2022 Senior Secured Notes will be significantly lower than the actual cash interest payments.
August 2018 Issuance of 7½% Senior Secured Second Lien Notes due 2024
In August 2018, we issued $450.0 million of 7½% Senior Secured Second Lien Notes due 2024 (the “2024 Senior Secured Notes”). The 2024 Senior Secured Notes, which bear interest at a rate of 7.50% per annum, were issued at par to repay outstanding borrowings on our Bank Credit Agreement, with additional proceeds used for general corporate purposes. The 2024 Senior Secured Notes mature on February 15, 2024, and interest is payable semiannually in arrears on February 15 and August 15 of each year, beginning in February 2019. We may redeem the 2024 Senior Secured Notes in whole or in part at our option beginning August 15, 2020, at a redemption price of 103.75% of the principal amount, and at declining redemption prices thereafter, as specified in the indenture governing the 2024 Senior Secured Notes. Prior to August 15, 2020, we may at our option redeem up to an aggregate of 35% of the principal amount of the 2024 Senior Secured Notes at a price of 107.50% of par with the proceeds of certain equity offerings. In addition, at any time prior to August 15, 2020, we may redeem the 2024 Senior Secured Notes in whole or in part at
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a price equal to 100% of the principal amount plus a “make-whole” premium and accrued and unpaid interest. The 2024 Senior Secured Notes are not subject to any sinking fund requirements.
The 2024 Senior Secured Notes are guaranteed jointly and severally by our subsidiaries representing substantially all of our assets, operations and income and are secured by second-priority liens on substantially all of the assets that secure the Bank Credit Agreement, which second-priority liens are contractually subordinated to liens that secure our Bank Credit Agreement and any future additional priority lien debt.
9¼% Senior Secured Second Lien Notes due 2022 issued in January 2018
In January 2018, we issued $74.1 million of 2022 Senior Secured Notes, which principal amount is in addition to the $381.6 million of 2022 Senior Secured Notes issued during December 2017. All $455.7 million of the 2022 Senior Secured Notes were issued in connection with exchanges with a limited number of holders of the Company’s existing senior subordinated notes in December 2017 and January 2018 (see January 2018 Note Exchanges above). The 2022 Senior Secured Notes bear interest at 9.25% per annum, with interest payable semiannually in arrears on March 31 and September 30 of each year, and mature on March 31, 2022. We may redeem the 2022 Senior Secured Notes in whole or in part at our option beginning March 31, 2019, at a redemption price of 109.25% of the principal amount, and at declining redemption prices thereafter, as specified in the indenture governing the 2022 Senior Secured Notes. Prior to March 31, 2019, we may at our option redeem up to an aggregate of 35% of the principal amount of the 2022 Senior Secured Notes at a price of 109.25% of par with the proceeds of certain equity offerings. In addition, at any time prior to March 31, 2019, we may redeem the 2022 Senior Secured Notes in whole or in part at a price equal to 100% of the principal amount plus a “make-whole” premium and accrued and unpaid interest. The 2022 Senior Secured Notes are not subject to any sinking fund requirements.
The 2022 Senior Secured Notes are guaranteed jointly and severally by our subsidiaries representing substantially all of our assets, operations and income and are secured by second-priority liens on substantially all of the assets that secure the Bank Credit Agreement, which second-priority liens are contractually subordinated to liens that secure our Bank Credit Agreement and any future additional priority lien debt.
Conversions of 2023 and 2024 Convertible Senior Notes into Common Stock in May and June 2018
During the second quarter of 2018, holders of all $59.4 million aggregate principal amount outstanding of our 2023 Convertible Senior Notes and $84.7 million aggregate outstanding principal amount of our 2024 Convertible Senior Notes converted their notes into shares of Denbury common stock, at the rates specified in the indentures for these notes, resulting in the issuance of 55.2 million shares of our common stock upon conversion. The debt principal balances and future interest treated as debt applicable to the 2023 Convertible Senior Notes and 2024 Convertible Senior Notes, totaling $162.0 million, were reclassified to “Paid-in capital in excess of par” and “Common stock” in our Unaudited Condensed Consolidated Balance Sheets upon the conversion of the notes into shares of Denbury common stock. As of April 18, 2018 and May 30, 2018, there were no remaining 2024 Convertible Senior Notes and 2023 Convertible Senior Notes outstanding, respectively.
Note 5. Commodity Derivative Contracts
We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; therefore, the changes in the fair values of these instruments are recognized in income in the period of change. These fair value changes, along with the settlements of expired contracts, are shown under “Commodity derivatives expense (income)” in our Unaudited Condensed Consolidated Statements of Operations.
Historically, we have entered into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production and to provide more certainty to our future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps. The production that we hedge has varied from year to year depending on our levels of debt, financial strength and expectation of future commodity prices.
We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring
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procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement (or affiliates of such lenders). As of September 30, 2018, all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.
The following table summarizes our commodity derivative contracts as of September 30, 2018, none of which are classified as hedging instruments in accordance with the FASC Derivatives and Hedging topic:
Months | Index Price | Volume (Barrels per day) | Contract Prices ($/Bbl) | ||||||||||||||||||||||||
Range(1) | Weighted Average Price | ||||||||||||||||||||||||||
Swap | Sold Put | Floor | Ceiling | ||||||||||||||||||||||||
Oil Contracts: | |||||||||||||||||||||||||||
2018 Fixed-Price Swaps | |||||||||||||||||||||||||||
Oct – Dec | NYMEX | 20,500 | $ | 50.00 | – | 56.65 | $ | 51.69 | $ | — | $ | — | $ | — | |||||||||||||
Oct – Dec | Argus LLS | 5,000 | 60.10 | – | 60.25 | 60.18 | — | — | — | ||||||||||||||||||
2018 Three-Way Collars(2) | |||||||||||||||||||||||||||
Oct – Dec | NYMEX | 15,000 | $ | 45.00 | – | 56.60 | $ | — | $ | 36.50 | $ | 46.50 | $ | 53.88 | |||||||||||||
2019 Fixed-Price Swaps | |||||||||||||||||||||||||||
Jan – June | NYMEX | 3,500 | $ | 59.00 | – | 59.10 | $ | 59.05 | $ | — | $ | — | $ | — | |||||||||||||
Jan - Dec | Argus LLS | 4,000 | 69.10 | – | 74.90 | 71.40 | — | — | — | ||||||||||||||||||
2019 Three-Way Collars(2) | |||||||||||||||||||||||||||
Jan – June | NYMEX | 18,500 | $ | 55.00 | – | 75.45 | $ | — | $ | 48.84 | $ | 56.84 | $ | 69.94 | |||||||||||||
July – Dec | NYMEX | 22,000 | 55.00 | – | 75.45 | — | 48.55 | 56.55 | 69.17 | ||||||||||||||||||
Jan – Dec | Argus LLS | 5,500 | 62.00 | – | 86.00 | — | 54.73 | 63.09 | 79.93 | ||||||||||||||||||
(1) | Ranges presented for fixed-price swaps represent the lowest and highest fixed prices of all open contracts for the period presented. For three-way collars, ranges represent the lowest floor price and highest ceiling price for all open contracts for the period presented. |
(2) | A three-way collar is a costless collar contract combined with a sold put feature (at a lower price) with the same counterparty. The value received for the sold put is used to enhance the contracted floor and ceiling price of the related collar. At the contract settlement date, (1) if the index price is higher than the ceiling price, we pay the counterparty the difference between the index price and ceiling price for the contracted volumes, (2) if the index price is between the floor and ceiling price, no settlements occur, (3) if the index price is lower than the floor price but at or above the sold put price, the counterparty pays us the difference between the index price and the floor price for the contracted volumes and (4) if the index price is lower than the sold put price, the counterparty pays us the difference between the floor price and the sold put price for the contracted volumes. |
Note 6. Fair Value Measurements
The FASC Fair Value Measurement topic defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (often referred to as the “exit price”). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the income approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:
• | Level 1 – Quoted prices in active markets for identical assets or liabilities as of the reporting date. |
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Notes to Unaudited Condensed Consolidated Financial Statements
• | Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded oil derivatives that are based on NYMEX pricing and fixed-price swaps that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). Our costless collars and the sold put features of our three-way collars are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contractual prices for the underlying instruments, maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. |
• | Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. As of September 30, 2018, instruments in this category include non-exchange-traded three-way collars that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). The valuation models utilized for costless collars and three-way collars are consistent with the methodologies described above; however, the implied volatilities utilized in the valuation of Level 3 instruments are developed using a benchmark, which is considered a significant unobservable input. An increase or decrease of 100 basis points in the implied volatility inputs utilized in our fair value measurement would result in a change of approximately $400 thousand in the fair value of these instruments as of September 30, 2018. |
We adjust the valuations from the valuation model for nonperformance risk, using our estimate of the counterparty’s credit quality for asset positions and our credit quality for liability positions. We use multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps.
The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of the periods indicated:
Fair Value Measurements Using: | ||||||||||||||||
In thousands | Quoted Prices in Active Markets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Total | ||||||||||||
September 30, 2018 | ||||||||||||||||
Liabilities | ||||||||||||||||
Oil derivative contracts – current | $ | — | $ | (120,298 | ) | $ | (5,056 | ) | $ | (125,354 | ) | |||||
Oil derivative contracts – long-term | — | (12,214 | ) | (1,356 | ) | (13,570 | ) | |||||||||
Total Liabilities | $ | — | $ | (132,512 | ) | $ | (6,412 | ) | $ | (138,924 | ) | |||||
December 31, 2017 | ||||||||||||||||
Liabilities | ||||||||||||||||
Oil derivative contracts – current | $ | — | $ | (99,061 | ) | $ | — | $ | (99,061 | ) | ||||||
Total Liabilities | $ | — | $ | (99,061 | ) | $ | — | $ | (99,061 | ) | ||||||
Since we do not apply hedge accounting for our commodity derivative contracts, any gains and losses on our assets and liabilities are included in “Commodity derivatives expense (income)” in the accompanying Unaudited Condensed Consolidated Statements of Operations.
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Notes to Unaudited Condensed Consolidated Financial Statements
Level 3 Fair Value Measurements
The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the three and nine months ended September 30, 2018 and 2017:
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
In thousands | 2018 | 2017 | 2018 | 2017 | ||||||||||||
Fair value of Level 3 instruments, beginning of period | $ | (1,168 | ) | $ | 99 | $ | — | $ | (526 | ) | ||||||
Fair value gains (losses) on commodity derivatives | (5,244 | ) | (97 | ) | (6,412 | ) | 528 | |||||||||
Fair value of Level 3 instruments, end of period | $ | (6,412 | ) | $ | 2 | $ | (6,412 | ) | $ | 2 | ||||||
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets or liabilities still held at the reporting date | $ | (5,244 | ) | $ | (71 | ) | $ | (6,412 | ) | $ | 54 | |||||
We utilize an income approach to value our Level 3 costless collars and three-way collars. We obtain and ensure the appropriateness of the significant inputs to the calculation, including contractual prices for the underlying instruments, maturity, forward prices for commodities, interest rates, volatility factors and credit worthiness, and the fair value estimate is prepared and reviewed on a quarterly basis. The following table details fair value inputs related to implied volatilities utilized in the valuation of our Level 3 oil derivative contracts:
Fair Value at 9/30/2018 (in thousands) | Valuation Technique | Unobservable Input | Volatility Range | |||||||
Oil derivative contracts | $ | (6,412 | ) | Discounted cash flow / Black-Scholes | Volatility of Light Louisiana Sweet for settlement periods beginning after September 30, 2018 | 20.7% – 29.9% | ||||
Other Fair Value Measurements
The carrying value of our loans under our Bank Credit Agreement approximate fair value, as they are subject to short-term floating interest rates that approximate the rates available to us for those periods. We use a market approach to determine the fair value of our fixed-rate long-term debt using observable market data. The fair values of our senior secured second lien notes, convertible senior notes, and senior subordinated notes are based on quoted market prices, which are considered Level 1 measurements under the fair value hierarchy. The estimated fair value of the principal amount of our debt as of September 30, 2018 and December 31, 2017, excluding pipeline financing and capital lease obligations, was $2,377.0 million and $2,260.6 million, respectively. We have other financial instruments consisting primarily of cash, cash equivalents, short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.
Note 7. Commitments and Contingencies
Litigation
We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses. We are also subject to audits for various taxes (income, sales and use, and severance) in the various states in which we operate, and from time to time receive assessments for potential taxes that we may owe. While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our financial position, results of operations or cash flows, litigation is subject to inherent uncertainties. Although a single or multiple adverse rulings or settlements could possibly have a material adverse effect on our finances, we only accrue for losses from litigation and claims if we determine that a loss is probable and the amount can be reasonably estimated.
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Notes to Unaudited Condensed Consolidated Financial Statements
Riley Ridge Helium Supply Contract Claim
As part of our 2010 and 2011 acquisitions of the Riley Ridge Unit and associated gas processing facility that was under construction, the Company assumed a 20-year helium supply contract under which we agreed to supply the helium separated from the full well stream by operation of the gas processing facility to a third-party purchaser, APMTG Helium, LLC. The helium supply contract provides for the delivery of a minimum contracted quantity of helium, subject to adjustment after startup of the Riley Ridge gas processing facility, with liquidated damages payable if specified quantities of helium are not supplied in accordance with the terms of the contract. The liquidated damages are specified in the contract at up to $8.0 million per contract year and are capped at an aggregate of $46.0 million over the term of the contract. As the gas processing facility has been shut-in since mid-2014, we have not been able to supply helium under the helium supply contract. APMTG Helium, LLC filed a case in November 2014 in the Ninth Judicial District Court of Sublette County, Wyoming, claiming multiple years of liquidated damages for non-delivery of volumes of helium specified under the helium supply contract. The Company’s position is that our contractual obligations are excused by virtue of events that fall within the force majeure provisions in the helium supply contract. The evidentiary phase of the trial concluded on November 29, 2017. The parties submitted written closing briefs and rebuttal briefs to the District Court during February and April of 2018. We are currently awaiting a ruling from the District Court, and we are unable to predict at this time the outcome of this dispute.
Note 8. Subsequent Event
On October 28, 2018, the Company entered into a definitive merger agreement pursuant to which the Company will acquire Penn Virginia Corporation (NASDAQ: PVAC) (“Penn Virginia”). On the terms and subject to the conditions set forth in the merger agreement, each share of Penn Virginia common stock (“Penn Virginia Common Stock”), issued and outstanding immediately prior to the effective time of the merger (other than as described in the merger agreement) will be converted into the right to receive, at the election of the holder of such share of Penn Virginia Common Stock, either, (i) $25.86 in cash without interest and 12.4 shares of the Company’s common stock (“Denbury Common Stock”), (ii) $79.80 in cash without interest (the “Cash Election”), or (iii) 18.3454 shares of Denbury Common Stock (the “Stock Election”). The Cash and Stock Elections will be subject to proration to ensure that the total amount of cash paid to holders of Penn Virginia Common Stock is equal to $400 million. In the aggregate, $400 million in cash and approximately 191.8 million shares of Denbury Common Stock are expected to be paid as merger consideration. Consummation of the merger is subject to satisfaction of customary conditions.
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Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and Notes thereto included herein and our Consolidated Financial Statements and Notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2017 (the “Form 10-K”), along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Form 10-K. Any terms used but not defined herein have the same meaning given to them in the Form 10-K. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with Risk Factors under Item 1A of the Form 10-K, along with Forward-Looking Information at the end of this section for information on the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.
OVERVIEW
Denbury is an independent oil and natural gas company with operations focused in two key operating areas: the Gulf Coast and Rocky Mountain regions. Our goal is to increase the value of our properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to CO2 enhanced oil recovery operations.
Recent Agreement to Acquire Penn Virginia Corporation. On October 28, 2018, Denbury and Penn Virginia Corporation (NASDAQ: PVAC) (“Penn Virginia”) entered into a definitive Agreement and Plan of Merger (the “Merger Agreement”) pursuant to which we will acquire Penn Virginia in a stock and cash transaction (the “Acquisition”) valued (based upon Denbury’s per share closing price on the NYSE on October 26, 2018) at approximately $1.7 billion, including the assumption of Penn Virginia debt. The following description constitutes only a summary of certain aspects of the Merger Agreement and the transactions contemplated thereby, and is not intended to be complete. For further information see our Form 8-K and exhibits thereto filed with the Commission on October 29, 2018.
The Acquisition is subject to approval by the shareholders of Penn Virginia and to approval by Denbury’s stockholders of the issuance of Denbury common stock in the Acquisition and an amendment to Denbury’s charter to increase its authorized shares. Consummation of the Acquisition is also subject to other customary mutual closing conditions, which are described in the above referenced Form 8-K. In connection with execution of the Merger Agreement, we signed voting agreements with Penn Virginia shareholders holding approximately 15% of its outstanding common shares, and under which they agreed to vote “for” the Acquisition.
On the terms and subject to the conditions set forth in the Merger Agreement, each share of Penn Virginia common stock (“Penn Virginia Common Stock”), issued and outstanding immediately prior to the merger effective time (other than as described in the Merger Agreement) shall be converted into the right to receive, at the election of the holder of such share of Penn Virginia Common Stock, either, (i) $25.86 in cash without interest and 12.4 shares of the Company’s common stock (“Denbury Common Stock”), (ii) $79.80 in cash without interest (the “Cash Election”), or (iii) 18.3454 shares of Denbury Common Stock (the “Stock Election”). The Cash Election and the Stock Election will be subject to proration to ensure that the total amount of cash paid to holders of Penn Virginia Common Stock is equal to $400 million. The overall mix of consideration to be received by Penn Virginia shareholders is expected to be approximately 68% Denbury Common Stock (approximately 191.8 million shares of Denbury Common Stock) and approximately 32% cash ($400 million cash) in the aggregate. Upon closing of the Acquisition, Denbury stockholders are expected to own approximately 71% of the outstanding equity of the combined company, and Penn Virginia shareholders are expected to own approximately 29%.
In connection with the Merger Agreement, Denbury received a commitment letter from JPMorgan Chase Bank, N.A., subject to certain funding conditions, for a proposed new $1.2 billion senior secured revolving credit facility with a maturity date of December 9, 2021 and a $400 million senior secured second lien bridge facility that will be available to the extent Denbury does not secure alternate financing prior to the end of the bridge takedown period. The two new debt financings will be used to fully or partially fund the $400 million cash portion of the consideration in the Acquisition, potentially retire and replace Penn Virginia’s $200 million second lien term loan, replace Penn Virginia’s existing bank credit facility, which had $283 million drawn and outstanding as of September 30, 2018, and pay fees and expenses.
The Merger Agreement contains certain termination rights for both Denbury and Penn Virginia, including, among others, if the Acquisition is not completed by April 30, 2019. On a termination of the Merger Agreement under certain circumstances, Penn
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Virginia may be required to pay Denbury a termination fee of $45 million, or Denbury may be required to pay Penn Virginia a termination fee of $45 million.
Prior to the merger effective time, we are required to take all necessary corporate action so that upon and after such effective time, (i) the size of the Denbury Board of Directors is increased by two members and (ii) two members of the Penn Virginia Board of Directors (that are (A) mutually agreed upon between Penn Virginia and Denbury and (B) determined to be independent under the standards of the NYSE) are appointed to the Denbury Board of Directors to fill the vacancies created by such increase. Denbury also is required to recommend that such directors be elected to the Denbury Board of Directors in the proxy statement relating to Denbury’s next annual meeting of stockholders following the consummation of the Acquisition.
Consummation of the Acquisition and the related financing, which cannot be assured and requires satisfaction of a variety of conditions, would have a significant impact on all aspects of our results of operations and financial condition. We anticipate providing further information on the proposed transaction to our stockholders and Penn Virginia’s shareholders in a registration statement on Form S-4 to be filed with the SEC that will include a joint proxy statement of the Company and Penn Virginia and a prospectus of the Company, and which will be submitted to the Company’s stockholders and Penn Virginia’s shareholders for their consideration, which is currently anticipated to occur in January 2019.
Oil Price Impact on Our Business. Our financial results are significantly impacted by changes in oil prices, as 97% of our production is oil. Over the last year, NYMEX oil prices have gradually improved from around $50 per Bbl in August 2017, to around $70 per Bbl at the end of September 2018, which are considerably higher than those experienced in 2015 and 2016, when oil prices generally ranged between $40-$50 per Bbl. NYMEX oil prices averaged approximately $70 per Bbl in the third quarter of 2018, compared to approximately $48 per Bbl in the third quarter of 2017 and $68 per Bbl in the second quarter of 2018. Increases in oil prices impact all aspects of our business; most notably our cash flow from operations, revenues, and capital allocation and budgeting decisions. Our 2018 capital spending has been budgeted at $300 million to $325 million, excluding capitalized interest and acquisitions, and we currently expect our capital spending to be in the upper half of that range. Based on the Company’s cash flow generated through the first three quarters of the year and projected cash flows for the fourth quarter of 2018 utilizing current futures prices, we currently project a level of cash flow that would more than fully fund our development capital spending plans.
Operating Highlights. We recognized net income of $78.4 million, or $0.17 per diluted common share, during the third quarter of 2018, compared to net income of $0.4 million, or $0.00 per diluted common share, during the third quarter of 2017. The primary drivers of our change in operating results between the comparative third quarters of 2018 and 2017 were the following:
• | Oil and natural gas revenues in the third quarter of 2018 improved by $120.6 million, or 47%, principally driven by a 50% improvement in realized oil prices. Our net realized oil price relative to NYMEX prices improved by $2.18 per Bbl from the prior-year period to $1.84 per Bbl above NYMEX. |
• | Commodity derivatives expense increased by $19.3 million ($44.6 million of expense in the current-year period compared to $25.3 million in the prior-year period). This increase in expense was the result of a $61.7 million increase in payments on derivative settlements, partially offset by a $42.4 million gain on noncash fair value adjustments between the periods. |
We generated $147.9 million of cash flow from operating activities in the third quarter of 2018, an increase of $82.3 million from third quarter of 2017 levels. The increase in cash flow from operations was due primarily to higher oil and natural gas revenues of $120.6 million and favorable working capital changes of $16.0 million ($13.4 million of cash inflows during the third quarter of 2018 compared to $2.6 million of cash outflows during the third quarter of 2017), partially offset by an increase in derivative settlement payments of $61.7 million.
Extension of Senior Secured Bank Credit Facility. In August 2018, we entered into the Sixth Amendment to the Bank Credit Agreement (the “Sixth Amendment”) which primarily extended the maturity date from December 9, 2019 to December 9, 2021 and reduced the borrowing base and total commitments from $1.05 billion to $615 million. See Capital Resources and Liquidity – Senior Secured Bank Credit Facility for further discussion.
Issuance of 7½% Senior Secured Second Lien Notes due 2024. In August 2018, we issued $450.0 million of 7½% Senior Secured Second Lien Notes due 2024 (the “2024 Senior Secured Notes”). The 2024 Senior Secured Notes, which bear interest at a rate of 7.50% per annum, were issued at par to repay outstanding borrowings on our Bank Credit Agreement, with additional
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Management’s Discussion and Analysis of Financial Condition and Results of Operations
proceeds used for general corporate purposes (See Note 4, Long-Term Debt, to the Consolidated Financial Statements for additional details).
Debt Reduction Transactions. We reduced our debt principal by $328.5 million between December 2017 and May 2018 through a series of exchange transactions and related debt conversions as follows:
• | During December 2017, we reduced debt principal by $143.6 million through privately negotiated transactions, in which institutional holders exchanged $609.8 million aggregate principal amount of our subordinated debt for: |
– | $381.6 million aggregate principal amount of 9¼% Senior Secured Second Lien Notes due 2022 (the “2022 Senior Secured Notes”) and |
– | $84.7 million aggregate principal amount of 3½% Convertible Senior Notes due 2024 (the “2024 Convertible Senior Notes”) |
• | During January 2018, we reduced debt principal by $40.8 million through additional exchange transactions, in which institutional holders exchanged $174.3 million aggregate principal amount of our subordinated debt for: |
– | $74.1 million aggregate principal amount of 2022 Senior Secured Notes and |
– | $59.4 million aggregate principal amount of 5% Convertible Senior Notes due 2023 (the “2023 Convertible Senior Notes”) |
• | In April and May 2018, we reduced debt principal by $144.1 million when holders of all outstanding 2024 Convertible Senior Notes and 2023 Convertible Senior Notes, issued in the exchanges above, converted their notes into shares of Denbury common stock, at rates specified in the indentures for the notes, which resulted in the issuance of 55.2 million shares of our common stock upon conversion. As of April 18, 2018 and May 30, 2018, there were no remaining 2024 Convertible Senior Notes or 2023 Convertible Senior Notes outstanding, with the conversion of these notes saving the Company annual cash interest payments of $5.9 million. |
Sanctioning of Enhanced Oil Recovery Development at Cedar Creek Anticline. In June 2018, we announced the sanctioning of the CO2 enhanced oil recovery development project at Cedar Creek Anticline. The capital outlay required to bring the initial phase of the project to first tertiary production is currently estimated at $250 million over the next four years, which includes $150 million for a 110-mile extension of the Greencore CO2 pipeline from Bell Creek Field, most of which will be incurred in 2019, and $100 million for development in the Red River formation at East Lookout Butte and Cedar Hills South fields. First tertiary production is currently expected in late 2021 or early 2022.
Exploitation Drilling Update. Following the success of our first exploitation horizontal well in the Mission Canyon interval at Cedar Creek Anticline at the end of 2017, we successfully completed two additional Mission Canyon wells in the first half of 2018, one near the end of the first quarter and another early in the second quarter of 2018. These first three wells had a combined 30-day initial production rate of over 3,000 gross barrels of oil per day. Drilling in the Mission Canyon interval paused throughout the second quarter to comply with Bureau of Land Management and state wildlife stipulations. We recently completed an additional three Mission Canyon wells in October 2018, including an initial test well in Cabin Creek, which had initial production rates exceeding 1,000 gross barrels of oil per day, and two southern delineation wells in Coral Creek. Within the Coral Creek wells, we encountered anomalously high water production that we believe is caused by reservoir fractures, and are currently diagnosing the issue and developing a plan to reduce water influx. We currently have an additional four Mission Canyon wells planned during the fourth quarter of 2018. During the second quarter of 2018, we successfully completed our first well in the Perry Sand interval at Tinsley Field in Mississippi, with better than expected deliverability and an initial 30-day gross production rate (constrained by artificial lift equipment) of approximately 150 barrels of oil per day, and we plan to test the Cotton Valley interval at Tinsley Field during the fourth quarter of 2018. For 2018, we have allocated $50 to $60 million of our 2018 capital budget to exploitation drilling across our company-wide portfolio of assets.
CAPITAL RESOURCES AND LIQUIDITY
Overview. Our primary sources of capital and liquidity are our cash flow from operations and availability of borrowing under our senior secured bank credit facility. For the nine months ended September 30, 2018, we generated cash flow from operations of $393.5 million, an increase of $250.7 million from the first nine months of 2017, primarily due to increasing revenues during 2018 due to rising oil prices.
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In August 2018, we issued $450.0 million of 2024 Senior Secured Notes, with a portion of the proceeds utilized to fully pay down outstanding borrowings on our senior secured bank credit facility. As of September 30, 2018, we had no outstanding borrowings on our senior secured bank credit facility and $66.7 million of cash and cash equivalents, compared to $475.0 million of borrowings outstanding as of December 31, 2017 and $415.0 million as of June 30, 2018 with nominal cash at those dates. In connection with entry into the Sixth Amendment to the senior secured bank credit facility in August 2018, our borrowing base and total commitments were reduced from $1.05 billion to $615 million; therefore, as of September 30, 2018, we had $552.8 million of borrowing base availability, after consideration of $62.2 million of outstanding letters of credit.
We have historically tried to limit our development capital spending to be roughly the same as, or less than, our cash flow from operations, and our 2018 cash flow from operations are expected to well exceed our planned $300 million to $325 million of development capital expenditures for the year.
The Company has been engaged in two asset sale processes. We are marketing for sale certain non-producing surface acreage in the Houston area. The acreage contains numerous parcels, and we currently anticipate that these sales principally will occur in 2019. Further, in February 2018, we initiated a sale process for our mature EOR properties located in Mississippi and Louisiana and Citronelle Field located in Alabama. In aggregate, these fields accounted for 12% of our third quarter 2018 production and approximately 7% of our 2017 year-end proved reserves. Through September 30, 2018, we have completed sales of a minor portion of the non-producing surface acreage in the Houston area, and also completed the sale of our Lockhart Crossing Field, with combined net proceeds of $8.6 million. The pace and outcome of any sales of the remaining assets cannot be predicted at this time, but their successful completion could provide additional liquidity for financial or operational uses.
We have reduced our outstanding debt principal, net of cash by nearly $1.1 billion between December 31, 2014 and September 30, 2018, primarily through debt exchanges, opportunistic open market debt repurchases, and the conversion in the second quarter of 2018 of all of our outstanding convertible senior notes into common stock. The improvement in oil prices and our business, and the market price of our debt securities, has reduced our opportunity for additional exchange transactions, but we remain opportunistic for occasions that may arise from time to time to improve the Company’s balance sheet, both in terms of overall debt reduction and extension of debt maturities. We also remain keenly focused on continuing to improve our overall leverage metrics. Our leverage metrics have improved considerably over the past year, due primarily to our cost reduction efforts, continued improvement in oil prices and our overall reduction in debt. In conjunction with our efforts to improve the Company’s balance sheet, we may have discussions with bondholders from time to time regarding potential debt reduction or maturity extension transactions of various types.
Senior Secured Bank Credit Facility. In December 2014, we entered into an Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (as amended, the “Bank Credit Agreement”). In August 2018, we entered into the Sixth Amendment to the Bank Credit Agreement (the “Sixth Amendment”), pursuant to which the following changes were made to the Bank Credit Agreement:
• | The maturity date was extended from December 9, 2019 to December 9, 2021, provided that the maturity date may occur earlier (between February 2021 and August 2021) if the 9% Senior Secured Second Lien Notes due in May 2021 (“2021 Senior Secured Notes”) or 6⅜% Senior Subordinated Notes due in August 2021 are not repaid or refinanced by their respective maturity dates; |
• | The borrowing base and total commitments were reduced from $1.05 billion to $615 million in connection with a reduction in the number of lenders party to the Bank Credit Facility; |
• | The amount of junior lien debt we can incur was increased from $1.2 billion to $1.65 billion outstanding in the aggregate at any one time; and |
• | A Consolidated Total Debt to Consolidated EBITDAX financial maintenance covenant was added with a ratio not to exceed 5.25 to 1.0 through December 31, 2020, and 4.50 to 1.0 thereafter through the maturity date. |
At September 30, 2018, in addition to the Consolidated Total Debt to Consolidated EBITDAX covenant added with the Sixth Amendment, the Bank Credit Agreement contained certain financial performance covenants through the maturity of the facility, including the following:
• | A consolidated senior secured debt to consolidated EBITDAX covenant, with such ratio not to exceed 2.5 to 1.0. Currently, only debt under our Bank Credit Agreement is considered consolidated senior secured debt for purposes of this ratio; |
• | A minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 1.25 to 1.0; and |
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Management’s Discussion and Analysis of Financial Condition and Results of Operations
• | A requirement to maintain a current ratio of 1.0 to 1.0. |
Under these financial performance covenant calculations, as of September 30, 2018, our ratio of consolidated total debt to consolidated EBITDAX was 4.10 to 1.0 (with a maximum permitted ratio of 5.25 to 1.0), our consolidated senior secured debt to consolidated EBITDAX was 0.00 to 1.0 (with a maximum permitted ratio of 2.5 to 1.0), our ratio of consolidated EBITDAX to consolidated interest charges was 3.27 to 1.0 (with a required ratio of not less than 1.25 to 1.0), and our current ratio was 3.07 to 1.0 (with a required ratio of not less than 1.0 to 1.0). Based upon our currently forecasted levels of production and costs, hedges in place as of November 7, 2018, and current oil commodity futures prices, we currently anticipate continuing to be in compliance with our financial performance covenants during the foreseeable future.
The above description of our Bank Credit Agreement is qualified by the express language and defined terms contained in the Bank Credit Agreement and the amendments thereto, each of which are filed as exhibits to our periodic reports filed with the SEC.
Debt Reduction Transactions. Through a series of debt exchange transactions completed in December 2017 and January 2018 and related conversions of all of our convertible senior notes into equity in April and May 2018, we have reduced the outstanding debt principal of our notes by $328.5 million between December 2017 and May 2018. See Overview – Debt Reduction Transactions for further discussion.
Capital Spending. We anticipate that our full-year 2018 capital spending, excluding capitalized interest and acquisitions, will be in the upper half of our $300 million to $325 million capital budget range. Capitalized interest is currently estimated at approximately $30 million for 2018. The 2018 capital budget, excluding capitalized interest and acquisitions, provides for approximate spending as follows:
• | $155 million allocated for tertiary oil field expenditures; |
• | $95 million allocated for other areas, primarily non-tertiary oil field expenditures including exploitation; |
• | $20 million to be spent on CO2 sources and pipelines; and |
• | $45 million for other capital items such as capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs. |
Capital Expenditure Summary. The following table reflects incurred capital expenditures (including accrued capital) for the nine months ended September 30, 2018 and 2017:
Nine Months Ended | ||||||||
September 30, | ||||||||
In thousands | 2018 | 2017 | ||||||
Capital expenditures by project | ||||||||
Tertiary oil fields | $ | 107,133 | $ | 98,797 | ||||
Non-tertiary fields | 51,714 | 41,023 | ||||||
Capitalized internal costs(1) | 34,027 | 37,732 | ||||||
Oil and natural gas capital expenditures | 192,874 | 177,552 | ||||||
CO2 pipelines, sources and other | 22,345 | 3,246 | ||||||
Capital expenditures, before acquisitions and capitalized interest | 215,219 | 180,798 | ||||||
Acquisitions of oil and natural gas properties | 150 | 91,015 | ||||||
Capital expenditures, before capitalized interest | 215,369 | 271,813 | ||||||
Capitalized interest | 26,817 | 22,217 | ||||||
Capital expenditures, total | $ | 242,186 | $ | 294,030 | ||||
(1) | Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs. |
For the nine months ended September 30, 2018, our operating cash flow of $393.5 million exceeded our development capital expenditures and interest payments not reflected as interest for financial reporting payments by $113.5 million.
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Management’s Discussion and Analysis of Financial Condition and Results of Operations
Off-Balance Sheet Arrangements. Our off-balance sheet arrangements include operating leases for office space and various obligations for development and exploratory expenditures that arise from our normal capital expenditure program or from other transactions common to our industry, none of which are recorded on our balance sheet. In addition, in order to recover our undeveloped proved reserves, we must also fund the associated future development costs estimated in our proved reserve reports.
Our commitments and obligations consist of those detailed as of December 31, 2017, in our Form 10-K under Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – Commitments and Obligations.
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Management’s Discussion and Analysis of Financial Condition and Results of Operations
RESULTS OF OPERATIONS
Our tertiary operations represent a significant portion of our overall operations and are our primary long-term strategic focus. The economics of a tertiary field and the related impact on our financial statements differ from a conventional oil and gas play, and we have outlined certain of these differences in our Form 10-K and other public disclosures. Our focus on these types of operations impacts certain trends in both current and long-term operating results. Please refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations – Financial Overview of Tertiary Operations in our Form 10-K for further information regarding these matters.
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Management’s Discussion and Analysis of Financial Condition and Results of Operations
Operating Results Table
Certain of our operating results and statistics for the comparative three and nine months ended September 30, 2018 and 2017 are included in the following table:
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
In thousands, except per-share and unit data | 2018 | 2017 | 2018 | 2017 | ||||||||||||
Operating results | ||||||||||||||||
Net income | $ | 78,419 | $ | 442 | $ | 148,219 | $ | 36,371 | ||||||||
Net income per common share – basic | 0.17 | 0.00 | 0.35 | 0.09 | ||||||||||||
Net income per common share – diluted | 0.17 | 0.00 | 0.33 | 0.09 | ||||||||||||
Net cash provided by operating activities | 147,904 | 65,651 | 393,530 | 142,859 | ||||||||||||
Average daily production volumes | ||||||||||||||||
Bbls/d | 57,410 | 58,376 | 58,621 | 58,182 | ||||||||||||
Mcf/d | 10,623 | 11,710 | 11,275 | 10,985 | ||||||||||||
BOE/d(1) | 59,181 | 60,328 | 60,500 | 60,013 | ||||||||||||
Operating revenues | ||||||||||||||||
Oil sales | $ | 377,329 | $ | 256,621 | $ | 1,088,021 | $ | 768,912 | ||||||||
Natural gas sales | 2,299 | 2,409 | 7,193 | 7,176 | ||||||||||||
Total oil and natural gas sales | $ | 379,628 | $ | 259,030 | $ | 1,095,214 | $ | 776,088 | ||||||||
Commodity derivative contracts(2) | ||||||||||||||||
Receipt (payment) on settlements of commodity derivatives | $ | (61,611 | ) | $ | 89 | $ | (149,738 | ) | $ | (38,618 | ) | |||||
Noncash fair value gains (losses) on commodity derivatives(3) | 17,034 | (25,352 | ) | (39,863 | ) | 48,330 | ||||||||||
Commodity derivatives income (expense) | $ | (44,577 | ) | $ | (25,263 | ) | $ | (189,601 | ) | $ | 9,712 | |||||
Unit prices – excluding impact of derivative settlements | ||||||||||||||||
Oil price per Bbl | $ | 71.44 | $ | 47.78 | $ | 67.99 | $ | 48.41 | ||||||||
Natural gas price per Mcf | 2.35 | 2.24 | 2.34 | 2.39 | ||||||||||||
Unit prices – including impact of derivative settlements(2) | ||||||||||||||||
Oil price per Bbl | $ | 59.78 | $ | 47.80 | $ | 58.63 | $ | 45.98 | ||||||||
Natural gas price per Mcf | 2.35 | 2.24 | 2.34 | 2.39 | ||||||||||||
Oil and natural gas operating expenses | ||||||||||||||||
Lease operating expenses | $ | 122,527 | $ | 117,768 | $ | 361,267 | $ | 342,926 | ||||||||
Marketing expenses, net of third-party purchases, and plant operating expenses(4) | 9,872 | 9,706 | 28,902 | 29,758 | ||||||||||||
Production and ad valorem taxes | 25,387 | 18,418 | 75,782 | 57,548 | ||||||||||||
Oil and natural gas operating revenues and expenses per BOE | ||||||||||||||||
Oil and natural gas revenues | $ | 69.73 | $ | 46.67 | $ | 66.31 | $ | 47.37 | ||||||||
Lease operating expenses | 22.50 | 21.22 | 21.87 | 20.93 | ||||||||||||
Marketing expenses, net of third-party purchases, and plant operating expenses(4) | 1.81 | 1.75 | 1.75 | 1.82 | ||||||||||||
Production and ad valorem taxes | 4.66 | 3.32 | 4.59 | 3.51 | ||||||||||||
CO2 sources – revenues and expenses | ||||||||||||||||
CO2 sales and transportation fees | $ | 8,149 | $ | 6,590 | $ | 22,416 | $ | 18,533 | ||||||||
CO2 discovery and operating expenses | (708 | ) | (1,346 | ) | (1,670 | ) | (2,452 | ) | ||||||||
CO2 revenue and expenses, net | $ | 7,441 | $ | 5,244 | $ | 20,746 | $ | 16,081 | ||||||||
(1) | Barrel of oil equivalent using the ratio of one barrel of oil to six Mcf of natural gas (“BOE”). |
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(2) | See also Commodity Derivative Contracts below and Item 3. Quantitative and Qualitative Disclosures about Market Risk for information concerning our derivative transactions. |
(3) | Noncash fair value gains (losses) on commodity derivatives is a non-GAAP measure and is different from “Commodity derivatives expense (income)” in the Unaudited Condensed Consolidated Statements of Operations in that the noncash fair value gains (losses) on commodity derivatives represent only the net changes between periods of the fair market values of commodity derivative positions, and exclude the impact of settlements on commodity derivatives during the period, which were payments on settlements of $61.6 million and $149.7 million for the three and nine months ended September 30, 2018, respectively, compared to receipts on settlements of $0.1 million for the three months ended September 30, 2017 and payments on settlements of $38.6 million for the nine months ended September 30, 2017, respectively. We believe that noncash fair value gains (losses) on commodity derivatives is a useful supplemental disclosure to “Commodity derivatives expense (income)” in order to differentiate noncash fair market value adjustments from receipts or payments upon settlements on commodity derivatives during the period. This supplemental disclosure is widely used within the industry and by securities analysts, banks and credit rating agencies in calculating EBITDA and in adjusting net income (loss) to present those measures on a comparative basis across companies, as well as to assess compliance with certain debt covenants. Noncash fair value gains (losses) on commodity derivatives is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for “Commodity derivatives expense (income)” in the Unaudited Condensed Consolidated Statements of Operations. |
(4) | Represents “Marketing and plant operating expenses” as presented in the Unaudited Condensed Consolidated Statements of Operations excluding expenses for purchases of oil from third-parties. |
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Management’s Discussion and Analysis of Financial Condition and Results of Operations
Production
Average daily production by area for each of the four quarters of 2017 and for the first, second, and third quarters of 2018 is shown below:
Average Daily Production (BOE/d) | ||||||||||||||||||||||
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | First Quarter | Second Quarter | Third Quarter | ||||||||||||||||
Operating Area | 2017 | 2017 | 2017 | 2017 | 2018 | 2018 | 2018 | |||||||||||||||
Tertiary oil production | ||||||||||||||||||||||
Gulf Coast region | ||||||||||||||||||||||
Delhi | 4,991 | 4,965 | 4,619 | 4,906 | 4,169 | 4,391 | 4,383 | |||||||||||||||
Hastings | 4,288 | 4,400 | 4,867 | 5,747 | 5,704 | 5,716 | 5,486 | |||||||||||||||
Heidelberg | 4,730 | 4,996 | 4,927 | 4,751 | 4,445 | 4,330 | 4,376 | |||||||||||||||
Oyster Bayou | 5,075 | 5,217 | 4,870 | 4,868 | 5,056 | 4,961 | 4,578 | |||||||||||||||
Tinsley | 6,666 | 6,311 | 6,506 | 6,241 | 6,053 | 5,755 | 5,294 | |||||||||||||||
Other | 14 | 10 | 19 | 7 | 57 | 142 | 240 | |||||||||||||||
Mature properties(1) | 7,502 | 7,171 | 6,893 | 6,763 | 6,726 | 6,725 | 6,612 | |||||||||||||||
Total Gulf Coast region | 33,266 | 33,070 | 32,701 | 33,283 | 32,210 | 32,020 | 30,969 | |||||||||||||||
Rocky Mountain region | ||||||||||||||||||||||
Bell Creek | 3,209 | 3,060 | 3,406 | 3,571 | 4,050 | 4,010 | 3,970 | |||||||||||||||
Salt Creek(2) | — | 23 | 2,228 | 2,172 | 2,002 | 2,049 | 2,274 | |||||||||||||||
Other | — | — | — | — | — | — | 6 | |||||||||||||||
Total Rocky Mountain region | 3,209 | 3,083 | 5,634 | 5,743 | 6,052 | 6,059 | 6,250 | |||||||||||||||
Total tertiary oil production | 36,475 | 36,153 | 38,335 | 39,026 | 38,262 | 38,079 | 37,219 | |||||||||||||||
Non-tertiary oil and gas production | ||||||||||||||||||||||
Gulf Coast region | ||||||||||||||||||||||
Mississippi | 1,342 | 1,004 | 867 | 721 | 875 | 901 | 1,038 | |||||||||||||||
Texas | 4,333 | 5,002 | 4,024 | 4,617 | 4,386 | 4,947 | 4,533 | |||||||||||||||
Other | 483 | 448 | 503 | 472 | 431 | 388 | 421 | |||||||||||||||
Total Gulf Coast region | 6,158 | 6,454 | 5,394 | 5,810 | 5,692 | 6,236 | 5,992 | |||||||||||||||
Rocky Mountain region | ||||||||||||||||||||||
Cedar Creek Anticline | 15,067 | 15,124 | 14,535 | 14,302 | 14,437 | 15,742 | 14,208 | |||||||||||||||
Other | 1,626 | 1,475 | 1,514 | 1,533 | 1,485 | 1,490 | 1,409 | |||||||||||||||
Total Rocky Mountain region | 16,693 | 16,599 | 16,049 | 15,835 | 15,922 | 17,232 | 15,617 | |||||||||||||||
Total non-tertiary production | 22,851 | 23,053 | 21,443 | 21,645 | 21,614 | 23,468 | 21,609 | |||||||||||||||
Total continuing production | 59,326 | 59,206 | 59,778 | 60,671 | 59,876 | 61,547 | 58,828 | |||||||||||||||
Property sales | ||||||||||||||||||||||
Lockhart Crossing(3) | 607 | 568 | 550 | 473 | 462 | 447 | 353 | |||||||||||||||
Total production | 59,933 | 59,774 | 60,328 | 61,144 | 60,338 | 61,994 | 59,181 | |||||||||||||||
(1) | Mature properties include Brookhaven, Cranfield, Eucutta, Little Creek, Mallalieu, Martinville, McComb and Soso fields. |
(2) | Represents production related to the acquisition of a 23% non-operated working interest in Salt Creek Field in Wyoming, which closed on June 30, 2017. |
(3) | Includes production from Lockhart Crossing Field sold in the third quarter of 2018. |
Total continuing production during the third quarter of 2018 averaged 58,828 BOE/d, including 37,219 Bbls/d, or 63%, from tertiary properties and 21,609 BOE/d from non-tertiary properties. Total continuing production excludes production from Lockhart Crossing Field sold in the third quarter of 2018. This total continuing production level represents a decrease of 2,719 BOE/d (4%) compared to second quarter of 2018 production levels, and a decrease of 950 BOE/d (2%) compared to third quarter of 2017
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Management’s Discussion and Analysis of Financial Condition and Results of Operations
production levels. Our production during the three and nine months ended September 30, 2018 was 97% oil, consistent with oil production during the prior-year periods. The sequential quarter decrease was primarily due to a scheduled pause in our Mission Canyon drilling program, production downtime at Cedar Creek Anticline and Oyster Bayou fields, and the seasonal impacts of summer temperatures at certain Gulf Coast fields.
Continuing oil production from our tertiary operations during the third quarter of 2018 decreased 860 Bbls/d (2%) when comparing the second and third quarters of 2018 and decreased 1,116 Bbls/d (3%) compared to the third quarter of 2017. The sequential decrease was primarily due to unplanned downtime at Oyster Bayou and the seasonal impacts of summer temperatures and workovers at Tinsley, Oyster Bayou, and Hastings fields in the Gulf Coast region, slightly offset by increased production at Salt Creek Field in the Rocky Mountain region. The year-over-year decrease in production was due principally to expected natural production declines at Tinsley, Heidelberg, and our mature fields, partially offset by higher production from the redevelopment project in mid-2017 at Hastings Field and production response from continued expansion at Bell Creek Field.
Continuing production from our non-tertiary operations averaged 21,609 BOE/d during the third quarter of 2018, a decrease of 1,859 BOE/d (8%) compared to the second quarter of 2018 principally due to the pause at Mission Canyon and production downtime at Cedar Creek Anticline mentioned above. Compared to the third quarter of 2017, continuing production from our non-tertiary operations increased slightly by 166 BOE/d (1%), primarily due to the new Mission Canyon wells drilled in early 2018, offset in part by production downtime at Cedar Creek Anticline.
Oil and Natural Gas Revenues
Our oil and natural gas revenues during the three and nine months ended September 30, 2018 increased 47% and 41%, respectively, compared to these revenues for the same periods in 2017. The changes in our oil and natural gas revenues are due to changes in production quantities and commodity prices (excluding any impact of our commodity derivative contracts), as reflected in the following table:
Three Months Ended | Nine Months Ended | |||||||||||||
September 30, | September 30, | |||||||||||||
2018 vs. 2017 | 2018 vs. 2017 | |||||||||||||
In thousands | Increase (Decrease) in Revenues | Percentage Increase (Decrease) in Revenues | Increase in Revenues | Percentage Increase in Revenues | ||||||||||
Change in oil and natural gas revenues due to: | ||||||||||||||
Increase (decrease) in production | $ | (4,924 | ) | (2 | )% | $ | 6,299 | 1 | % | |||||
Increase in commodity prices | 125,522 | 49 | % | 312,827 | 40 | % | ||||||||
Total increase in oil and natural gas revenues | $ | 120,598 | 47 | % | $ | 319,126 | 41 | % | ||||||
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Management’s Discussion and Analysis of Financial Condition and Results of Operations
Excluding any impact of our commodity derivative contracts, our net realized commodity prices and NYMEX differentials were as follows during the first quarters, second quarters, third quarters and nine months ended September 30, 2018 and 2017:
Three Months Ended | Nine Months Ended | |||||||||||||||||||||||||||||||
March 31, | June 30, | September 30, | September 30, | |||||||||||||||||||||||||||||
2018 | 2017 | 2018 | 2017 | 2018 | 2017 | 2018 | 2017 | |||||||||||||||||||||||||
Average net realized prices | ||||||||||||||||||||||||||||||||
Oil price per Bbl | $ | 64.25 | $ | 50.31 | $ | 68.24 | $ | 47.16 | $ | 71.44 | $ | 47.78 | $ | 67.99 | $ | 48.41 | ||||||||||||||||
Natural gas price per Mcf | 2.44 | 2.50 | 2.21 | 2.46 | 2.35 | 2.24 | 2.34 | 2.39 | ||||||||||||||||||||||||
Price per BOE | 62.61 | 49.35 | 66.57 | 46.12 | 69.73 | 46.67 | 66.31 | 47.37 | ||||||||||||||||||||||||
Average NYMEX differentials | ||||||||||||||||||||||||||||||||
Gulf Coast region | ||||||||||||||||||||||||||||||||
Oil per Bbl | $ | 2.05 | $ | (1.42 | ) | $ | 1.12 | $ | (0.78 | ) | $ | 3.21 | $ | 0.01 | $ | 2.10 | $ | (0.71 | ) | |||||||||||||
Natural gas per Mcf | 0.10 | 0.09 | 0.04 | (0.03 | ) | 0.06 | (0.11 | ) | 0.07 | (0.03 | ) | |||||||||||||||||||||
Rocky Mountain region | ||||||||||||||||||||||||||||||||
Oil per Bbl | $ | (0.06 | ) | $ | (2.09 | ) | $ | (0.84 | ) | $ | (1.96 | ) | $ | (0.54 | ) | $ | (0.98 | ) | $ | (0.47 | ) | $ | (1.69 | ) | ||||||||
Natural gas per Mcf | (0.92 | ) | (0.97 | ) | (1.25 | ) | (1.42 | ) | (1.05 | ) | (1.38 | ) | (1.07 | ) | (1.25 | ) | ||||||||||||||||
Total Company | ||||||||||||||||||||||||||||||||
Oil per Bbl | $ | 1.29 | $ | (1.64 | ) | $ | 0.39 | $ | (1.16 | ) | $ | 1.84 | $ | (0.34 | ) | $ | 1.16 | $ | (1.04 | ) | ||||||||||||
Natural gas per Mcf | (0.40 | ) | (0.57 | ) | (0.62 | ) | (0.69 | ) | (0.51 | ) | (0.72 | ) | (0.51 | ) | (0.67 | ) | ||||||||||||||||
Prices received in a regional market fluctuate frequently and can differ from NYMEX pricing due to a variety of reasons, including supply and/or demand factors, crude oil quality, and location differentials.
• | Gulf Coast Region. Our average NYMEX oil differential in the Gulf Coast region was a positive $3.21 per Bbl and a positive $0.01 per Bbl during the third quarters of 2018 and 2017, respectively, and a positive $1.12 per Bbl during the second quarter of 2018. These differentials are impacted significantly by the changes in prices received for our crude oil sold under LLS index prices relative to the changes in NYMEX prices, as well as various other price adjustments such as those noted above. The average LLS-to-NYMEX differential (on a trade-month basis) averaged a positive $4.48 per Bbl in the third quarter of 2018, an increase from the positive $2.37 per Bbl in the third quarter of 2017 and a positive $3.32 per Bbl in the second quarter of 2018. During the third quarter of 2018, we sold approximately 60% of our crude oil at prices based on, or partially tied to, the LLS index price, and the balance at prices based on various other indexes tied to NYMEX prices, primarily in the Rocky Mountain region. |
• | Rocky Mountain Region. NYMEX oil differentials in the Rocky Mountain region averaged $0.54 per Bbl and $0.98 per Bbl below NYMEX during the third quarters of 2018 and 2017, respectively, and $0.84 per Bbl below NYMEX during the second quarter of 2018. Differentials in the Rocky Mountain region can fluctuate significantly on a month-to-month basis due to weather, refinery or transportation issues, and Canadian and U.S. crude oil price index volatility. |
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Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Commodity Derivative Contracts
The following table summarizes the impact our crude oil derivative contracts had on our operating results for the three and nine months ended September 30, 2018 and 2017:
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
In thousands | 2018 | 2017 | 2018 | 2017 | ||||||||||||
Receipt (payment) on settlements of commodity derivatives | $ | (61,611 | ) | $ | 89 | $ | (149,738 | ) | $ | (38,618 | ) | |||||
Noncash fair value gains (losses) on commodity derivatives(1) | 17,034 | (25,352 | ) | (39,863 | ) | 48,330 | ||||||||||
Total income (expense) | $ | (44,577 | ) | $ | (25,263 | ) | $ | (189,601 | ) | $ | 9,712 | |||||
(1) | Noncash fair value gains (losses) on commodity derivatives is a non-GAAP measure. See Operating Results Table above for a discussion of the reconciliation between noncash fair value gains (losses) on commodity derivatives to “Commodity derivatives expense (income)” in the Unaudited Condensed Consolidated Statements of Operations. |
In order to provide a level of price protection to a portion of our oil production, we have hedged a portion of our estimated oil production through 2020 using both NYMEX and LLS fixed-price swaps and three-way collars. See Note 5, Commodity Derivative Contracts, to the Consolidated Financial Statements for additional details of our outstanding commodity derivative contracts as of September 30, 2018, and Item 3, Quantitative and Qualitative Disclosures about Market Risk below for additional discussion. In addition, the following table summarizes our commodity derivative contracts as of November 7, 2018:
4Q 2018 | 1H 2019 | 2H 2019 | 2020 | ||
WTI NYMEX | Volumes Hedged (Bbls/d) | 15,500 | — | — | — |
Fixed-Price Swaps | Swap Price(1) | $50.13 | — | — | — |
WTI NYMEX | Volumes Hedged (Bbls/d) | 5,000 | 3,500 | — | — |
Fixed-Price Swaps | Swap Price(1) | $56.54 | $59.05 | — | — |
Argus LLS | Volumes Hedged (Bbls/d) | 5,000 | 4,000 | 4,000 | — |
Fixed-Price Swaps | Swap Price(1) | $60.18 | $71.40 | $71.40 | — |
WTI NYMEX | Volumes Hedged (Bbls/d) | 15,000 | 8,500 | 12,000 | — |
3-Way Collars | Sold Put Price / Floor / Ceiling Price(1)(2) | $36.50 / $46.50 / $53.88 | $47.00 / $55.00 / $66.71 | $47.00 / $55.00 / $66.23 | — |
WTI NYMEX | Volumes Hedged (Bbls/d) | — | 10,000 | 10,000 | 1,000 |
3-Way Collars | Sold Put Price / Floor / Ceiling Price(1)(2) | — | $50.40 / $58.40 / $72.69 | $50.40 / $58.40 / $72.69 | $50.00 / $60.00 / $82.50 |
Argus LLS | Volumes Hedged (Bbls/d) | — | 3,000 | 3,000 | — |
3-Way Collars | Sold Put Price / Floor / Ceiling Price(1)(2) | — | $54.00 / $62.00 / $78.50 | $54.00 / $62.00 / $78.50 | — |
Argus LLS | Volumes Hedged (Bbls/d) | — | 2,500 | 2,500 | 1,000 |
3-Way Collars | Sold Put Price / Floor / Ceiling Price(1)(2) | — | $55.60 / $64.40 / $81.65 | $55.60 / $64.40 / $81.65 | $55.00 / $65.00 / $86.80 |
Total Volumes Hedged (Bbls/d) | 40,500 | 31,500 | 31,500 | 2,000 | |
(1) | Averages are volume weighted. |
(2) | If oil prices were to average less than the sold put price, receipts on settlement would be limited to the difference between the floor price and the sold put price. |
Based on current contracts in place and NYMEX oil futures prices as of November 7, 2018, which averaged approximately $62 per Bbl, we currently expect that we would make cash payments of approximately $45 million during the remainder of 2018
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upon settlement of the 2018 contracts, the amount of which is dependent upon fluctuations in future NYMEX oil prices in relation to the prices of our 2018 fixed-price swaps which have weighted average prices of $51.69 per Bbl and $60.18 per Bbl for NYMEX and LLS hedges, respectively, and weighted average ceiling prices of our 2018 three-way collars of $53.88 per Bbl. Changes in commodity prices, expiration of contracts, and new commodity contracts entered into cause fluctuations in the estimated fair value of our oil derivative contracts. Because we do not utilize hedge accounting for our commodity derivative contracts, the period-to-period changes in the fair value of these contracts, as outlined above, are recognized in our statements of operations.
Production Expenses
Lease Operating Expenses
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
In thousands, except per-BOE data | 2018 | 2017 | 2018 | 2017 | ||||||||||||
Total lease operating expenses | $ | 122,527 | $ | 117,768 | $ | 361,267 | $ | 342,926 | ||||||||
Total lease operating expenses per BOE | $ | 22.50 | $ | 21.22 | $ | 21.87 | $ | 20.93 | ||||||||
Total lease operating expenses increased $4.8 million (4%) and $18.3 million (5%) on an absolute-dollar basis, or $1.28 (6%) and $0.94 (4%) on a per-BOE basis, during the three and nine months ended September 30, 2018, respectively, compared to levels in the same periods in 2017. Our lease operating expenses during the current-year periods were primarily impacted by an increase in workover expense and contract labor. Lease operating expenses for the nine months ended September 30, 2018 were further impacted by operating expenses related to our non-operated working interest in Salt Creek Field, which was acquired in June 2017 and has higher per-BOE operating cost than our corporate average, and higher CO2 expense due to increases in oil prices. Sequentially, lease operating expenses increased $2.1 million (2%) on an absolute-dollar basis primarily due to higher workover expense and $1.16 (5%) on a per-BOE basis between the second quarter of 2018 and the third quarter of 2018, with the per-BOE change further impacted by lower production volumes.
Currently, our CO2 expense comprises approximately 20% of our typical tertiary lease operating expenses, and for the CO2 reserves we already own, consists of CO2 production expenses, and for the CO2 reserves we do not own, consists of our purchase of CO2 from royalty and working interest owners and industrial sources. During the third quarters of 2018 and 2017, approximately 52% and 55%, respectively, of the CO2 utilized in our CO2 floods consisted of CO2 owned and produced by us (our net revenue interest). The price we pay others for CO2 varies by source and is generally indexed to oil prices. When combining the production cost of the CO2 we own with what we pay third parties for CO2, our average cost of CO2 was approximately $0.41 per Mcf during the third quarter of 2018, including taxes paid on CO2 production but excluding depletion, depreciation and amortization of capital expended at our CO2 source fields and industrial sources. This per-Mcf CO2 cost during the third quarter of 2018 was lower than the $0.46 per Mcf comparable measure during the third quarter of 2017 and $0.44 per Mcf comparable measure during the second quarter of 2018 due to higher injection volumes and a lower utilization in our Gulf Coast region of industrial-sourced CO2, which has a higher average cost than our naturally-occurring CO2 sources.
Marketing and Plant Operating Expenses
Marketing and plant operating expenses primarily consist of amounts incurred relating to the marketing, processing, and transportation of oil and natural gas production. Marketing and plant operating expenses were $12.4 million and $11.8 million for the three months ended September 30, 2018 and 2017, respectively, and $36.4 million and $39.8 million for the nine months ended September 30, 2018 and 2017, respectively.
Taxes Other Than Income
Taxes other than income includes production, ad valorem and franchise taxes. Taxes other than income increased $7.1 million (35%) during the three months ended September 30, 2018 compared to the same prior-year period and increased $19.0 million (30%) during the nine months ended September 30, 2018 compared to the same period in 2017 due primarily to an increase in production taxes resulting from higher oil and natural gas revenues.
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Management’s Discussion and Analysis of Financial Condition and Results of Operations
General and Administrative Expenses (“G&A”)
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
In thousands, except per-BOE data and employees | 2018 | 2017 | 2018 | 2017 | ||||||||||||
Gross cash compensation and administrative costs | $ | 57,765 | $ | 64,104 | $ | 172,287 | $ | 193,853 | ||||||||
Gross stock-based compensation | 4,597 | 4,252 | 11,126 | 15,684 | ||||||||||||
Operator labor and overhead recovery charges | (31,586 | ) | (32,211 | ) | (94,910 | ) | (96,319 | ) | ||||||||
Capitalized exploration and development costs | (9,197 | ) | (8,872 | ) | (27,280 | ) | (31,915 | ) | ||||||||
Net G&A expense | $ | 21,579 | $ | 27,273 | $ | 61,223 | $ | 81,303 | ||||||||
G&A per BOE | ||||||||||||||||
Net administrative costs | $ | 3.31 | $ | 4.32 | $ | 3.18 | $ | 4.22 | ||||||||
Net stock-based compensation | 0.65 | 0.59 | 0.53 | 0.74 | ||||||||||||
Net G&A expenses | $ | 3.96 | $ | 4.91 | $ | 3.71 | $ | 4.96 | ||||||||
Employees as of September 30 | 847 | 897 | ||||||||||||||
Our gross G&A expenses on an absolute-dollar basis decreased $6.0 million (9%) and $26.1 million (12%) during the three and nine months ended September 30, 2018, respectively, compared to the same periods in 2017, primarily due to 2017 severance-related payments associated with the workforce reduction recognized in the third quarter of 2017 and lower employee-related costs such as salaries and long-term incentives during the nine months ended September 30, 2018 following the August 2017 involuntary workforce reduction.
Net G&A expense on a per-BOE basis decreased 19% and 25% during the three and nine months ended September 30, 2018, respectively, compared to levels in the same periods in 2017 due to the items previously mentioned impacting gross G&A during the 2018 periods, with the nine-month period ended September 30, 2018 partially offset by lower capitalized exploration and development costs.
Our well operating agreements allow us, when we are the operator, to charge a well with a specified overhead rate during the drilling phase and also to charge a monthly fixed overhead rate for each producing well. In addition, salaries associated with field personnel are initially recorded as gross cash compensation and administrative costs and subsequently reclassified to lease operating expenses or capitalized to field development costs to the extent those individuals are dedicated to oil and gas production, exploration, and development activities.
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Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Interest and Financing Expenses
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
In thousands, except per-BOE data and interest rates | 2018 | 2017 | 2018 | 2017 | ||||||||||||
Cash interest(1) | $ | 46,515 | $ | 45,110 | $ | 138,660 | $ | 130,962 | ||||||||
Less: interest on Senior Secured Notes and Convertible Senior Notes not reflected as interest for financial reporting purposes(1) | (21,186 | ) | (12,604 | ) | (64,849 | ) | (37,761 | ) | ||||||||
Noncash interest expense | 2,712 | 1,456 | 4,980 | 4,801 | ||||||||||||
Less: capitalized interest | (9,514 | ) | (9,416 | ) | (26,817 | ) | (22,217 | ) | ||||||||
Interest expense, net | $ | 18,527 | $ | 24,546 | $ | 51,974 | $ | 75,785 | ||||||||
Interest expense, net per BOE | $ | 3.40 | $ | 4.42 | $ | 3.15 | $ | 4.63 | ||||||||
Average debt principal outstanding | $ | 2,542,712 | $ | 2,971,205 | $ | 2,611,225 | $ | 2,887,010 | ||||||||
Average interest rate(2) | 7.3 | % | 6.1 | % | 7.1 | % | 6.0 | % | ||||||||
(1) | Cash interest is presented on an accrual basis and includes the portion of interest on our 2021 Senior Secured Notes, 2022 Senior Secured Notes, 2023 Convertible Senior Notes and 2024 Convertible Senior Notes versus the GAAP financial statement presentation in which interest on these notes is accounted for as debt and not reflected as interest for financial reporting purposes in accordance with Financial Accounting Standards Board Codification 470-60, Troubled Debt Restructuring by Debtors. See below for further discussion. |
(2) | Includes commitment fees but excludes debt issue costs. |
As reflected in the table above, cash interest expense during the three and nine months ended September 30, 2018 increased $1.4 million (3%) and $7.7 million (6%), respectively, when compared to the prior-year periods due primarily to the series of exchange transactions completed during 2017 and 2018 (see Overview – Debt Reduction Transactions) and issuance of 2024 Senior Secured Notes during the third quarter of 2018. Despite an overall reduction in the debt principal balance as a result of the exchange transactions, our average interest rate increased between the third quarter of 2017 and 2018 as the combined interest payments on the senior secured and convertible senior notes was higher than the previously issued senior subordinated notes and interest rate on our senior secured bank credit facility. As more fully described in Note 4, Long-Term Debt, to the Unaudited Condensed Consolidated Financial Statements, the exchange transactions were accounted for in accordance with Financial Accounting Standards Board Codification 470-60, Troubled Debt Restructuring by Debtors, whereby most of the future interest associated with the 2021 Senior Secured Notes, 2022 Senior Secured Notes, 2023 Convertible Senior Notes and 2024 Convertible Senior Notes was recorded as debt as of the transaction date, which will be reduced as semiannual interest payments are made. During the second quarter of 2018, the debt principal balance and future interest applicable to the 2024 Convertible Senior Notes and 2023 Convertible Senior Notes, respectively, were reclassified to “Paid-in capital in excess of par” and “Common stock” in our Unaudited Condensed Consolidated Balance Sheets upon the conversion of those notes into shares of Denbury common stock (see Overview – Debt Reduction Transactions). The conversion of these notes saves the Company annual cash interest payments of $5.9 million. Future interest payable related to our senior secured second lien notes recorded as debt totaled $292.6 million as of September 30, 2018. Therefore, interest expense reflected in our Unaudited Condensed Consolidated Financial Statements will be significantly lower than the actual cash interest payment. Capitalized interest during the nine months ended September 30, 2018 increased $4.6 million (21%) compared to the same period in 2017, primarily due to an increase in the number of projects that qualify for interest capitalization.
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Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Depletion, Depreciation, and Amortization (“DD&A”)
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
In thousands, except per-BOE data | 2018 | 2017 | 2018 | 2017 | ||||||||||||
Oil and natural gas properties | $ | 32,559 | $ | 29,990 | $ | 97,788 | $ | 86,973 | ||||||||
CO2 properties, pipelines, plants and other property and equipment | 18,757 | 22,111 | 58,923 | 67,475 | ||||||||||||
Total DD&A | $ | 51,316 | $ | 52,101 | $ | 156,711 | $ | 154,448 | ||||||||
DD&A per BOE | ||||||||||||||||
Oil and natural gas properties | $ | 5.98 | $ | 5.40 | $ | 5.92 | $ | 5.31 | ||||||||
CO2 properties, pipelines, plants and other property and equipment | 3.45 | 3.99 | 3.57 | 4.12 | ||||||||||||
Total DD&A cost per BOE | $ | 9.43 | $ | 9.39 | $ | 9.49 | $ | 9.43 | ||||||||
The increase in our oil and natural gas properties depletion during the three and nine months ended September 30, 2018 when compared to the same periods in 2017 was primarily due to an increase in depletable costs associated with our reserves base, partially offset by an increase in proved oil and natural gas reserve quantities. Total DD&A per BOE during the three months ended September 30, 2018 was also impacted by a decrease in production volumes during 2018 when compared to production in the 2017 period.
Income Taxes
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
In thousands, except per-BOE amounts and tax rates | 2018 | 2017 | 2018 | 2017 | ||||||||||||
Current income tax expense (benefit) | $ | (1,888 | ) | $ | 1,072 | $ | (3,674 | ) | $ | (18,828 | ) | |||||
Deferred income tax expense (benefit) | 17,504 | (15,301 | ) | 42,741 | 35,846 | |||||||||||
Total income tax expense (benefit) | $ | 15,616 | $ | (14,229 | ) | $ | 39,067 | $ | 17,018 | |||||||
Average income tax expense (benefit) per BOE | $ | 2.87 | $ | (2.57 | ) | $ | 2.37 | $ | 1.04 | |||||||
Effective tax rate | 16.6 | % | 103.2 | % | 20.9 | % | 31.9 | % | ||||||||
Total net deferred tax liability | $ | 249,264 | $ | 329,724 | ||||||||||||
We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. Our income taxes are based on an estimated statutory rate of approximately 25% and 38% in 2018 and 2017, respectively, due to a reduction of the federal income tax rate from 35% to 21% as enacted by the Tax Cut and Jobs Act in December 2017. Our effective tax rates for the three and nine months ended September 30, 2018 were lower than our estimated statutory rate, primarily due to tax benefits resulting from enhanced oil recovery income tax credits and stock-based compensation (tax deduction greater than book expense recognized). Our effective tax rate for the three months ended September 30, 2017, differed from our estimated statutory rate, primarily due to the impact of recognizing a tax benefit of $8.6 million for enhanced oil recovery income tax credits, which was offset in part by a stock-based compensation deduction shortfall of $2.1 million. With last year’s pre-tax income for the three months ended September 30, 2017 being close to break-even, the net tax benefit from these items had a significant impact on the effective tax rate during that period.
The current income tax benefits for the nine months ended September 30, 2018 and 2017, represent the estimated receivable resulting from alternative minimum tax credits.
As of September 30, 2018, we had estimated amounts available for carry forward of $58.3 million of enhanced oil recovery credits related to our tertiary operations, $21.6 million of research and development credits, and $10.3 million of alternative
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Management’s Discussion and Analysis of Financial Condition and Results of Operations
minimum tax credits (net of $10.3 million related to the estimated credits to be applied to our 2018 tax return), which under the Tax Cut and Jobs Act, will be fully refundable by 2021. The enhanced oil recovery credits and research and development credits do not begin to expire until 2024 and 2031, respectively.
Per-BOE Data
The following table summarizes our cash flow and results of operations on a per-BOE basis for the comparative periods. Each of the significant individual components is discussed above.
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
Per-BOE data | 2018 | 2017 | 2018 | 2017 | ||||||||||||
Oil and natural gas revenues | $ | 69.73 | $ | 46.67 | $ | 66.31 | $ | 47.37 | ||||||||
Receipt (payment) on settlements of commodity derivatives | (11.32 | ) | 0.02 | (9.07 | ) | (2.36 | ) | |||||||||
Lease operating expenses | (22.50 | ) | (21.22 | ) | (21.87 | ) | (20.93 | ) | ||||||||
Production and ad valorem taxes | (4.66 | ) | (3.32 | ) | (4.59 | ) | (3.51 | ) | ||||||||
Marketing expenses, net of third-party purchases, and plant operating expenses | (1.81 | ) | (1.75 | ) | (1.75 | ) | (1.82 | ) | ||||||||
Production netback | 29.44 | 20.40 | 29.03 | 18.75 | ||||||||||||
CO2 sales, net of operating and exploration expenses | 1.37 | 0.95 | 1.26 | 0.98 | ||||||||||||
General and administrative expenses | (3.96 | ) | (4.91 | ) | (3.71 | ) | (4.96 | ) | ||||||||
Interest expense, net | (3.40 | ) | (4.42 | ) | (3.15 | ) | (4.63 | ) | ||||||||
Other | 1.26 | 0.27 | 0.44 | 1.78 | ||||||||||||
Changes in assets and liabilities relating to operations | 2.46 | (0.46 | ) | (0.04 | ) | (3.20 | ) | |||||||||
Cash flows from operations | 27.17 | 11.83 | 23.83 | 8.72 | ||||||||||||
DD&A | (9.43 | ) | (9.39 | ) | (9.49 | ) | (9.43 | ) | ||||||||
Deferred income taxes | (3.21 | ) | 2.76 | (2.59 | ) | (2.19 | ) | |||||||||
Noncash fair value gains (losses) on commodity derivatives(1) | 3.13 | (4.57 | ) | (2.41 | ) | 2.95 | ||||||||||
Other noncash items | (3.26 | ) | (0.55 | ) | (0.37 | ) | 2.17 | |||||||||
Net income | $ | 14.40 | $ | 0.08 | $ | 8.97 | $ | 2.22 | ||||||||
(1) | Noncash fair value gains (losses) on commodity derivatives is a non-GAAP measure. See Operating Results Table above for a discussion of the reconciliation between noncash fair value gains (losses) on commodity derivatives to “Commodity derivatives expense (income)” in the Unaudited Condensed Consolidated Statements of Operations. |
CRITICAL ACCOUNTING POLICIES
For additional discussion of our critical accounting policies, see Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Form 10-K. Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements have been included in the notes to the Company’s Unaudited Condensed Consolidated Financial Statements contained in this Quarterly Report on Form 10-Q.
FORWARD-LOOKING INFORMATION
The data and/or statements contained in this Quarterly Report on Form 10-Q that are not historical facts, including, but not limited to, statements found in the section Management’s Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements, as that term is defined in Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), that involve a number of risks and uncertainties. Such forward-looking statements may be or may concern, among other things, financial forecasts, future hydrocarbon prices and their volatility, the sustainability of current oil prices, current
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Denbury Resources Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
or future liquidity sources or their adequacy to support our anticipated future activities, our ability to further reduce our debt levels, together with assumptions based on current and projected production levels, oil and gas prices and oilfield costs, current or future expectations or estimations of our cash flows or the impact of changes in commodity prices on cash flows, availability of capital, borrowing capacity, price and availability of advantageous commodity derivative contracts or the predicted cash flow benefits therefrom, forecasted capital expenditures, drilling activity or methods, including the timing and location thereof, the nature of any future asset purchase or sales or the timing or proceeds thereof, estimated timing of commencement of CO2 flooding of particular fields or areas, including CCA, or the availability of capital for CCA pipeline construction, or its ultimate cost or date of completion, timing of CO2 injections and initial production responses in tertiary flooding projects, development activities, finding costs, anticipated future cost savings, capital budgets, interpretation or prediction of formation details, hydrocarbon reserve quantities and values, CO2 reserves and supply and their availability, potential reserves, barrels or percentages of recoverable original oil in place, levels of U.S. and worldwide tariffs or other trade restrictions, the likelihood, timing and impact of increased interest rates, the impact of regulatory rulings or changes, anticipated outcomes of pending litigation, prospective legislation affecting the oil and gas industry, environmental regulations, mark-to-market values, competition, rates of return, estimated costs, changes in costs, future capital expenditures and overall economics, worldwide economic conditions and other variables surrounding operations and future plans. Such forward-looking statements generally are accompanied by words such as “plan,” “estimate,” “expect,” “predict,” “forecast,” “to our knowledge,” “anticipate,” “projected,” “preliminary,” “should,” “assume,” “believe,” “may” or other words that convey, or are intended to convey, the uncertainty of future events or outcomes. Such forward-looking information is based upon management’s current plans, expectations, estimates, and assumptions and is subject to a number of risks and uncertainties that could significantly and adversely affect current, anticipated actions, the timing of such actions and our financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by us or on our behalf. Among the factors that could cause actual results to differ materially are fluctuations in worldwide oil prices or in U.S. oil prices and consequently in the prices received or demand for our oil and natural gas; decisions as to production levels and/or pricing by OPEC or production levels by U.S. shale producers in future periods; levels of future capital expenditures; effects of our indebtedness; success of our risk management techniques; accuracy of our cost estimates; availability or terms of credit in the commercial banking or other debt markets; fluctuations in the prices of goods and services; the uncertainty of drilling results and reserve estimates; operating hazards and remediation costs; disruption of operations and damages from well incidents, hurricanes, tropical storms, forest fires, or other natural occurrences; acquisition risks; requirements for capital or its availability; conditions in the worldwide financial, trade and credit markets; general economic conditions; competition; government regulations, including changes in tax or environmental laws or regulations; and unexpected delays, as well as the risks and uncertainties inherent in oil and gas drilling and production activities or that are otherwise discussed in this quarterly report, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in our other public reports, filings and public statements including, without limitation, the Company’s most recent Form 10-K.
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Item 3. Quantitative and Qualitative Disclosures about Market Risk
Debt and Interest Rate Sensitivity
We finance some of our acquisitions and other expenditures with fixed and variable rate debt. These debt agreements expose us to market risk related to changes in interest rates. As of September 30, 2018, we did not have any outstanding borrowings on our senior secured bank credit facility. None of our existing debt has any triggers or covenants regarding our debt ratings with rating agencies, although under the NEJD financing lease, in light of credit downgrades in February 2016, we were required to provide a $41.3 million letter of credit to the lessor, which we provided on March 4, 2016. The letter of credit may be drawn upon in the event we fail to make a payment due under the pipeline financing lease agreement or upon other specified defaults set out in the pipeline financing lease agreement (filed as Exhibit 99.1 to the Form 8-K filed with the SEC on June 5, 2008). The fair values of our senior secured second lien notes and senior subordinated notes are based on quoted market prices. The following table presents the principal and fair values of our outstanding debt as of September 30, 2018.
In thousands | 2021 | 2022 | 2023 | 2024 | Total | Fair Value | ||||||||||||||||||
Fixed rate debt: | ||||||||||||||||||||||||
9% Senior Secured Second Lien Notes due 2021 | $ | 614,919 | $ | — | $ | — | $ | — | $ | 614,919 | $ | 664,113 | ||||||||||||
9¼% Senior Secured Second Lien Notes due 2022 | — | 455,668 | — | — | 455,668 | 490,982 | ||||||||||||||||||
7½% Senior Secured Second Lien Notes due 2024 | — | — | — | 450,000 | 450,000 | 462,375 | ||||||||||||||||||
6⅜% Senior Subordinated Notes due 2021 | 203,545 | — | — | — | 203,545 | 198,456 | ||||||||||||||||||
5½% Senior Subordinated Notes due 2022 | — | 314,662 | — | — | 314,662 | 290,276 | ||||||||||||||||||
4⅝% Senior Subordinated Notes due 2023 | — | — | 307,978 | — | 307,978 | 270,836 | ||||||||||||||||||
See Note 4, Long-Term Debt, to the Unaudited Condensed Consolidated Financial Statements for details regarding our long-term debt.
Commodity Derivative Contracts
We enter into oil derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil production and to provide more certainty to our future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps. The production that we hedge has varied from year to year depending on our levels of debt, financial strength, and expectation of future commodity prices. In order to provide a level of price protection to a portion of our oil production, we have hedged a portion of our estimated oil production through 2020 using both NYMEX and LLS fixed-price swaps and three-way collars. Depending on market conditions, we may continue to add to our existing 2019 and 2020 hedges. See also Note 5, Commodity Derivative Contracts, and Note 6, Fair Value Measurements, to the Unaudited Condensed Consolidated Financial Statements for additional information regarding our commodity derivative contracts.
All of the mark-to-market valuations used for our commodity derivatives are provided by external sources. We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification. All of our commodity derivative contracts are with parties that are lenders under our senior secured bank credit facility (or affiliates of such lenders). We have included an estimate of nonperformance risk in the fair value measurement of our commodity derivative contracts, which we have measured for nonperformance risk based upon credit default swaps or credit spreads.
For accounting purposes, we do not apply hedge accounting treatment to our commodity derivative contracts. This means that any changes in the fair value of these commodity derivative contracts will be charged to earnings instead of charging the effective portion to other comprehensive income and the ineffective portion to earnings.
At September 30, 2018, our commodity derivative contracts were recorded at their fair value, which was a net liability of $138.9 million, a $17.1 million decrease from the $156.0 million net liability recorded at June 30, 2018, and a $39.8 million increase from the $99.1 million net liability recorded at December 31, 2017. These changes are primarily related to the expiration
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of commodity derivative contracts during the three and nine months ended September 30, 2018, new commodity derivative contracts entered into during 2018 for future periods, and to the changes in oil futures prices between December 31, 2017 and September 30, 2018.
Commodity Derivative Sensitivity Analysis
Based on NYMEX and LLS crude oil futures prices as of September 30, 2018, and assuming both a 10% increase and decrease thereon, we would expect to make payments on our crude oil derivative contracts as shown in the following table:
Receipt / (Payment) | ||||
In thousands | Crude Oil Derivative Contracts | |||
Based on: | ||||
Futures prices as of September 30, 2018 | $ | (110,992 | ) | |
10% increase in prices | (208,483 | ) | ||
10% decrease in prices | (48,434 | ) | ||
Our commodity derivative contracts are used as an economic hedge of our exposure to commodity price risk associated with anticipated future production. As a result, changes in receipts or payments of our commodity derivative contracts due to changes in commodity prices as reflected in the above table would be mostly offset by a corresponding increase or decrease in the cash receipts on sales of our oil production to which those commodity derivative contracts relate.
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Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures. As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2018, to ensure that information that is required to be disclosed in the reports the Company files and submits under the Securities Exchange Act of 1934 is recorded, that it is processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and that information that is required to be disclosed under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.
Evaluation of Changes in Internal Control over Financial Reporting. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we have determined that, during the third quarter of fiscal 2018, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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PART II. OTHER INFORMATION
Item 1. Legal Proceedings
We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses. While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our business or finances, litigation is subject to inherent uncertainties. Although a single or multiple adverse rulings or settlements could possibly have a material adverse effect on our business or finances, we only accrue for losses from litigation and claims if we determine that a loss is probable and the amount can be reasonably estimated.
Riley Ridge Helium Supply Contract Claim
As part of our 2010 and 2011 acquisitions of the Riley Ridge Unit and associated gas processing facility that was under construction, the Company assumed a 20-year helium supply contract under which we agreed to supply the helium separated from the full well stream by operation of the gas processing facility to a third-party purchaser, APMTG Helium, LLC. The helium supply contract provides for the delivery of a minimum contracted quantity of helium, subject to adjustment after startup of the Riley Ridge gas processing facility, with liquidated damages payable if specified quantities of helium are not supplied in accordance with the terms of the contract. The liquidated damages are specified in the contract at up to $8.0 million per contract year and are capped at an aggregate of $46.0 million over the term of the contract. As the gas processing facility has been shut-in since mid-2014, we have not been able to supply helium under the helium supply contract. APMTG Helium, LLC filed a case in November 2014 in the Ninth Judicial District Court of Sublette County, Wyoming, claiming multiple years of liquidated damages for non-delivery of volumes of helium specified under the helium supply contract. The Company’s position is that our contractual obligations are excused by virtue of events that fall within the force majeure provisions in the helium supply contract. The evidentiary phase of the trial concluded on November 29, 2017. The parties submitted written closing briefs and rebuttal briefs to the District Court during February and April of 2018. We are currently awaiting a ruling from the District Court, and we are unable to predict at this time the outcome of this dispute.
Environmental Protection Agency Matter Concerning Citronelle and Other Fields
The Company has entered into a series of tolling agreements (effective through March 31, 2019) with the Environmental Protection Agency (“EPA”), and has been in discussions with the agency over the past several years regarding the EPA’s contention that it has causes of action under the Clean Water Act (“CWA”) related to releases (principally between 2008 and 2013) of oil and produced water containing small amounts of oil in the Citronelle Field in southern Alabama and several fields in Mississippi. The EPA has taken the position that these releases were in violation of the CWA. Discussions are focused upon actions taken or to be taken by Denbury, including enhancements to the Company’s mechanical integrity program designed to minimize the occurrence and impact of any future releases in these fields.
Based upon recent discussions with the EPA, the Company currently anticipates that in the next several months it will reach agreement with the EPA as to a consent decree regarding the EPA’s claims, which consent decree will provide for a monetary fine as a civil penalty. The Company anticipates that any such civil penalty would not be material to the Company’s business or financial condition.
Item 1A. Risk Factors
Information with respect to the Company’s risk factors has been incorporated by reference to Item 1A of the Form 10-K. In addition, additional risks may arise in connection with consummation of the transactions contemplated by the definitive merger agreement with Penn Virginia dated October 28, 2018, which risks will be described in detail in a registration statement on Form S-4 to be filed with the SEC that will include a joint proxy statement of the Company and Penn Virginia and a prospectus of the Company, and which will be submitted to the Company’s stockholders and Penn Virginia’s shareholders for their consideration.
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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Issuer Purchases of Equity Securities
The following table summarizes purchases of our common stock during the third quarter of 2018:
Month | Total Number of Shares Purchased(1) | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (in millions)(2) | ||||||||||
July 2018 | 1,046,305 | $ | 4.99 | — | $ | 210.1 | ||||||||
August 2018 | 749 | 4.43 | — | 210.1 | ||||||||||
September 2018 | 40,510 | 5.08 | — | 210.1 | ||||||||||
Total | 1,087,564 | — | ||||||||||||
(1) | Shares purchased during the third quarter of 2018 were made in connection with the surrender of shares by our employees to satisfy their tax withholding requirements related to the vesting of restricted and performance shares. |
(2) | In October 2011, we commenced a common share repurchase program, which has been approved for up to an aggregate of $1.162 billion of Denbury common shares by the Company’s Board of Directors. This program has effectively been suspended and we do not anticipate repurchasing shares of our common stock in the near future. The program has no pre-established ending date and may be suspended or discontinued at any time. We are not obligated to repurchase any dollar amount or specific number of shares of our common stock under the program. |
Item 3. Defaults Upon Senior Securities
None.
Item 4. Mine Safety Disclosures
None.
Item 5. Other Information
None.
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Item 6. Exhibits
Exhibit No. | Exhibit | |
4 | ||
10(a) | ||
10(b) | ||
10(c) | ||
10(d)* | ||
31(a)* | ||
31(b)* | ||
32* | ||
101* | Interactive Data Files. | |
* | Included herewith. |
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
DENBURY RESOURCES INC. | ||
November 9, 2018 | /s/ Mark C. Allen | |
Mark C. Allen Executive Vice President and Chief Financial Officer | ||
November 9, 2018 | /s/ Alan Rhoades | |
Alan Rhoades Vice President and Chief Accounting Officer | ||
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