Enter Agreement, Leave Agreement, Regulation FD, Exhibits
Regulation FD, Other Events, Exhibits
Regulation FD, Other Events, Exhibits
Regulation FD, Exhibits
Regulation FD, Other Events, Exhibits
Regulation FD, Other Events, Exhibits
Enter Agreement, Regulation FD, Other Events, Exhibits
Diamond Hill Investment Group
Sunlink Health Systems
Rorine International Holding
Item 1. Business and Properties
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2. Properties
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosures
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6. Selected Financial Data
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Information
Note 1. Significant Accounting Policies
Note 2. Revenue Recognition
Note 3. Potential Asset Sales
Note 4. Asset Retirement Obligations
Note 5. Unevaluated Property
Note 6. Long-Term Debt
Note 7. Income Taxes
Note 8. Stockholders' Equity
Note 9. Stock Compensation
Note 10. Commodity Derivative Contracts
Note 11. Fair Value Measurements
Note 12. Commitments and Contingencies
Note 13. Additional Balance Sheet Details
Note 14. Supplemental Cash Flow Information
Note 15. Subsequent Events
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14. Principal Accountant Fees and Services
Item 15. Exhibits and Financial Statement Schedules
Item 16. Form 10-K Summary
Denbury Resources Earnings 2018-12-31
DNR 10K Annual Report
10-K 1 dnr-20181231x10k.htm FORM 10-K Document
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
2018 FORM 10-K
þ Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2018
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 1-12935
DENBURY RESOURCES INC.
(Exact name of Registrant as specified in its charter)
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
5320 Legacy Drive,
(Address of principal executive offices)
Registrant’s telephone number, including area code:
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class:
Name of Each Exchange on Which Registered:
Common Stock $.001 Par Value
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ
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 every Interactive Data File required to be submitted pursuant to Rule 405 (§232.405 of this chapter) of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
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 12-b2 of the Exchange Act.
Large accelerated filer þ Accelerated filer o Non-accelerated filer o Smaller reporting company o Emerging growth company o
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 Act). Yes o No þ
The aggregate market value of the registrant’s common stock held by non-affiliates, based on the closing price of the registrant’s common stock as of the last business day of the registrant’s most recently completed second fiscal quarter was $2,178,055,595.
The number of shares outstanding of the registrant’s Common Stock as of January 31, 2019, was 460,442,251.
DOCUMENTS INCORPORATED BY REFERENCE
Incorporated as to:
1. Notice and Proxy Statement for the Annual Meeting of Stockholders to be held May 22, 2019.
One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.
Barrels of oil or other liquid hydrocarbons produced per day.
One billion cubic feet of natural gas or CO2.
One barrel of oil equivalent, using the ratio of one barrel of crude oil, condensate or natural gas liquids to 6 Mcf of natural gas.
BOEs produced per day.
British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit (°F).
Enhanced oil recovery. In the context of our oil and natural gas production, EOR is also referred to as tertiary recovery.
Finding and development costs
The average cost per BOE to find and develop proved reserves during a given period. It is calculated by dividing (a) costs, which include the sum of (i) the total acquisition, exploration and development costs incurred during the period plus (ii) future development and abandonment costs related to the specified property or group of properties, by (b) the sum of (i) the change in total proved reserves during the period plus (ii) total production during that period.
Accounting principles generally accepted in the United States of America.
One thousand barrels of crude oil or other liquid hydrocarbons.
One thousand BOEs.
One thousand cubic feet of natural gas or CO2 at a temperature base of 60 degrees Fahrenheit (°F) and at the legal pressure base (14.65 to 15.025 pounds per square inch absolute) of the state or area in which the reserves are located or sales are made.
One thousand cubic feet of natural gas or CO2 per day.
One million barrels of crude oil or other liquid hydrocarbons.
One million BOEs.
One million Btus.
One million cubic feet of natural gas or CO2.
One million cubic feet of natural gas or CO2 produced per day.
Noncash fair value gains (losses) on commodity derivatives
The net change during the period in the fair market value of commodity derivative positions. Noncash fair value gains (losses) on commodity derivatives is a non-GAAP measure and makes up only a portion of “Commodity derivatives expense (income)” in the Consolidated Statements of Operations, which also includes the impact of settlements on commodity derivatives during the period. Its use is further discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Operating Results Table.
The New York Mercantile Exchange. In the context of our oil and natural gas sales, NYMEX pricing represents the West Texas Intermediate benchmark price for crude oil and Henry Hub benchmark price for natural gas.
Reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
Proved Developed Reserves*
Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Denbury Resources Inc.
Reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved Undeveloped Reserves*
Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells, in each case where a relatively major expenditure is required.
The estimated future gross revenue to be generated from the production of proved reserves, net of estimated future production, development and abandonment costs, and before income taxes, discounted to a present value using an annual discount rate of 10%. PV-10 Values were prepared using average hydrocarbon prices equal to the unweighted arithmetic average of hydrocarbon prices on the first day of each month within the 12-month period preceding the reporting date. PV-10 Value is a non-GAAP measure and does not purport to represent the fair value of our oil and natural gas reserves; its use is further discussed in Item 1, Business and Properties – Non-GAAP Financial Measures and Reconciliations.
One trillion cubic feet of natural gas or CO2.
A term used to represent techniques for extracting incremental oil out of existing oil fields (as opposed to primary and secondary recovery or “non-tertiary” recovery). In the context of our oil and natural gas production, tertiary recovery is also referred to as EOR.
* This definition is an abbreviated version of the complete definition set forth in Rule 4-10(a) of Regulation S-X. For the complete definition see:
Denbury Resources Inc., a Delaware corporation, is an independent oil and natural gas company with 262.2 MMBOE of estimated proved oil and natural gas reserves as of December 31, 2018, of which 97% is oil. Our operations are 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.
As part of our corporate strategy, we are committed to strong financial discipline, efficient operations and creating long-term value for our shareholders through the following key principles:
target specific regions where we either have, or believe we can create, a competitive advantage as a result of our ownership or use of CO2 reserves, oil fields and CO2 infrastructure;
secure properties where we believe additional value can be created through tertiary recovery operations and a combination of other exploitation, development, exploration and marketing techniques;
acquire properties that give us a majority working interest and operational control or where we believe we can ultimately obtain it;
maximize the value and cash flow generated from our operations by increasing production and reserves while controlling costs;
optimize the timing and allocation of capital among our investment opportunities to maximize the rates of return on our investments;
exercise financial discipline by attempting to balance our development capital expenditures with our cash flows from operations; and
attract and maintain a highly competitive team of experienced and incentivized personnel.
Denbury has been publicly traded on the New York Stock Exchange since 1997. Our corporate headquarters is located at 5320 Legacy Drive, Plano, Texas 75024, and our phone number is 972-673-2000. At December 31, 2018, we had 847 employees, 484 of whom were employed in field operations or at our field offices. We make our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports, filed or furnished pursuant to section 13(a) or 15(d) of the Securities Exchange Act of 1934, available free of charge on or through our website, www.denbury.com, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. The SEC also maintains a website, http://www.sec.gov, which contains periodic reports on Forms 8-K, 10-Q and 10-K filed with the SEC, along with other reports, proxy and information statements and other information filed by Denbury. Throughout this Annual Report on Form 10-K (“Form 10-K”) we use the terms “Denbury,” “Company,” “we,” “our” and “us” to refer to Denbury Resources Inc. and, as the context may require, its subsidiaries.
DEFINITIVE MERGER AGREEMENT TO ACQUIRE PENN VIRGINIA CORPORATION
On October 28, 2018, we entered into a definitive Agreement and Plan of Merger (the “Merger Agreement”) with Penn Virginia Corporation (NASDAQ: PVAC) (“Penn Virginia”). The Merger Agreement provides for us to acquire Penn Virginia in a stock and cash transaction (the “Merger”). The Merger is subject to approval by shareholders of Penn Virginia and approval by Denbury’s stockholders of the issuance of Denbury common stock in the Merger and an amendment to Denbury’s charter to increase its authorized shares. Consummation of the Merger is also subject to other customary mutual closing conditions, which are described in the Form 8-K references below. A Form S-4 Registration Statement pertaining to the Merger has been filed with the SEC, and we and Penn Virginia intend to provide to our respective equity holders an updated version of the Joint Proxy Statement/Prospectus contained therein in connection with solicitation of approval by Denbury stockholders and Penn Virginia shareholders of those matters described above. Based upon Denbury’s per share closing price on the NYSE on October 26, 2018, the transaction value is approximately $1.7 billion, including the assumption of Penn Virginia debt outstanding as of the date of the Merger Agreement. For further information, see “Overview – Agreement to Acquire Penn Virginia Corporation” in Management’s Discussion and Analysis of Financial Condition and Results of Operations, which is 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 Securities and Exchange Commission (the “Commission” or the “SEC”) on October 29, 2018.
In connection with the Merger Agreement, Denbury has 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 to be available to the extent Denbury does not secure alternate financing prior to April 30, 2019. The commitment letter is an exhibit to our Form 10-Q Report for the third quarter of 2018 filed with the SEC on November 9, 2018. These two new debt financings are expected to be used to fully or partially fund the $400 million cash portion of the consideration in the Merger, potentially retire and replace Penn Virginia’s $200 million second lien term loan, replace Penn Virginia’s existing bank credit facility, which had $321 million drawn and outstanding as of December 31, 2018, and pay fees and expenses.
Consummation of the Merger 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 business and financial condition.
2018 BUSINESS DEVELOPMENTS
Since our production is 97% oil, oil prices generally constitute the single largest variable in our operating results. Over the last few years, NYMEX oil prices have been volatile, decreasing to a low of $26 in early 2016 and gradually improving to hit a three-year peak of $76 in October 2018, before retreating to the low-$40’s in late December 2018 and then moving upward again to an average of approximately $53 per Bbl during the first two months of 2019. During the period of lower oil prices, our focus primarily has been on preservation of cash and liquidity, together with cost reductions and debt management, rather than concentration on expansion and growth. Our 2018 key accomplishments and business developments included the following:
Sanctioned our CO2 enhanced oil recovery development project at Cedar Creek Anticline, Denbury’s largest oil field, a project to access the potential for significant long-term oil production and cash flow of this key asset, which will require capital outlay for the initial phase of the project of approximately $300 million through 2022.
Generated $529.7 million of cash flow from operations in 2018 ($443.6 million after reducing for interest payments treated as debt reduction), significantly exceeding our incurred development capital expenditures in 2018 of $322.7 million.
Reduced our debt principal by $243.2 million during 2018, with $144.1 million of that reduction coming from the conversion of our 5% Convertible Senior Notes due 2023 and 3½% Convertible Senior Notes due 2024 into shares of Denbury common stock.
Extended the maturity date of our senior secured bank credit facility from December 9, 2019 to December 9, 2021.
Issued $450.0 million of 7½% Senior Secured Second Lien Notes due 2024 in August 2018, with a portion of the proceeds utilized to fully repay outstanding borrowings on our senior secured bank credit facility.
Improved the ratio of net debt (debt principal less cash and cash equivalents) to 2018 Adjusted EBITDAX (a non-GAAP measure) to 4.2x (including hedge settlements) and 3.3x (excluding hedge settlements) from 6.6x (including hedge settlements) and 5.9x (excluding hedge settlements) utilizing the comparable 2017 measures (see Item 1, Business and Properties – Non-GAAP Financial Measures and Reconciliations).
Reduced 2018 general and administrative expenses by $30.3 million to $71.5 million, a 30% reduction from 2017 amounts, reflective of our reductions in personnel and our efforts to reduce costs during the oil price downturn.
Increased proved reserves at December 31, 2018 to 262.2 MMBOE, from 259.7 MMBOE at December 31, 2017, representing a 111% replacement of 2018 annual production.
2019 BUSINESS OUTLOOK
As we approached the end of 2018, we experienced another significant downward move in oil prices, which dropped from over $76 per barrel in early October 2018 to lows in the $40 per barrel range by the end of 2018. In light of this, we remained diligent in determining our capital budget for 2019, exercising the flexibility we have with our asset base and focusing on both short-term and long-term projects that maximize value while meeting one of our key objectives of spending within cash flow. For 2019, we have initially budgeted our development capital spending at $240 million to $260 million, excluding capitalized interest
and acquisitions, a decrease of roughly 23% from 2018 actual capital spending levels. We utilized a NYMEX oil price estimate of $50 per Bbl in developing our 2019 budget, which based on our current projections would generate a level of cash flow that would more than fully fund our development capital spending plans, with any excess cash flow potentially used for debt reduction, acquisitions, and/or additional capital spending, among other things. At this decreased capital spending level, we currently anticipate 2019 average daily production to average between 56,000 and 60,000 BOE/d, compared to our 2018 average production rate of 60,341 BOE/d.
Our capital spending during 2019 will focus primarily on the continued development of our current tertiary floods, certain exploitation projects within our existing fields and approximately $30 million of the cost for the CO2 pipeline needed for the Cedar Creek Anticline enhanced oil recovery project. Planned development activities presented in the discussions that follow may be modified during the course of 2019 depending primarily upon oil prices and our level of cash flow to fund such development, and we will continue to evaluate the timing of the development of our inventory of fields and related pipelines and facilities. Additionally, we plan to continue our focus on strengthening our financial condition by opportunistically taking steps to reduce our remaining debt levels and/or extend debt maturities, maintaining and enhancing the efficiencies achieved over the last couple of years, and pursuing opportunities to increase or accelerate growth through organic projects such as accretive acquisitions.
Along with Denbury’s 2019 development plans, we are continuing to market for sale approximately 4,000 acres of surface land with no active oil and gas operations in the Houston area. We remain focused on a strategy that we believe will ultimately yield the highest value for the land, and we expect most of that value to be realized over the next couple of years. During 2018, we consummated approximately $5 million of land sales and currently have signed agreements covering another $9 million that we expect to close in 2019. In early 2018, we began the process of portfolio optimization through the marketing of mature properties located in Mississippi and Louisiana and Citronelle Field in Alabama, and completed the sale of Lockhart Crossing Field for net proceeds of $4.1 million during the third quarter of 2018. The decline in oil prices and our focus on the Penn Virginia transaction stalled our process in the fourth quarter of 2018, but we plan to continue to evaluate our options with these fields as oil prices improve. In aggregate, these fields produced an average of approximately 7,228 BOE/d during the fourth quarter of 2018. In aggregate, these fields accounted for 12% of our total 2018 production and approximately 8% of our year-end proved reserves.
We believe the acquisition of Penn Virginia would enhance Denbury’s operating results and balance sheet by creating a combination of short-cycle investment opportunities in Penn Virginia’s Eagle Ford Shale acreage and Denbury’s lower-declining EOR focused asset base, with the opportunity to apply Denbury’s technical EOR knowledge and capabilities to enhance the long-term development potential of Penn Virginia’s Eagle Ford acreage. As a combined entity, Denbury plans to continue to spend within cash flow and remain focused on the same core objectives. If the merger is not approved by the shareholders of both companies, Denbury will execute its 2019 plans on a stand-alone basis and remain focused on these same key objectives.
ESTIMATED NET QUANTITIES OF PROVED OIL AND NATURAL GAS RESERVES AND PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES
Oil and Natural Gas Reserve Estimates
DeGolyer and MacNaughton (“D&M”) prepared estimates of our net proved oil and natural gas reserves as of December 31, 2018, 2017 and 2016 (see the summary of D&M’s report as of December 31, 2018, included as an exhibit to this Form 10-K). These estimates of reserves were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices on the first day of each month within the 12-month period in accordance with rules and regulations of the SEC. These oil and natural gas reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties.
The following table provides estimated proved reserve information prepared by D&M as of December 31, 2018, 2017 and 2016, as well as PV-10 Values and Standardized Measures for each period. During 2018, total proved reserves increased by 24.5 MMBOE (9%) excluding 2018 production of 22.0 MMBOE, representing a 111% replacement of 2018 annual production. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and their values, including many factors beyond our control, which are further discussed in Item 1A, Risk Factors – Estimating our reserves, production and future net cash flows is difficult to do with any certainty. See also Oil and Natural Gas Operations – Field Summary Table and Supplemental Oil and Natural Gas Disclosures (Unaudited) to the Consolidated Financial Statements for further discussion of reserve inputs and changes between periods.
Estimated proved reserves
Natural gas (MMcf)
Oil equivalent (MBOE)
Reserve volumes categories
Proved developed producing
Natural gas (MMcf)
Oil equivalent (MBOE)
Proved developed non-producing
Natural gas (MMcf)
Oil equivalent (MBOE)
Natural gas (MMcf)
Oil equivalent (MBOE)
Percentage of total MBOE
Proved developed producing
Proved developed non-producing
Representative oil and natural gas prices(1)
Oil (NYMEX price per Bbl)
Natural gas (Henry Hub price per MMBtu)
Present values (in thousands)(2)
Discounted estimated future net cash flows before income taxes (PV-10 Value)(3)
Standardized measure of discounted estimated future net cash flows after income taxes (“Standardized Measure”)
The reference prices were based on the arithmetic average of the first-day-of-the-month NYMEX commodity prices for each month during the respective year. These prices do not reflect adjustments for market differentials by field that are utilized in the preparation of our reserve report to arrive at the appropriate net price we receive. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Operating Results Table for details of oil and natural gas prices received, both including and excluding the impact of derivative settlements.
Determined based on the average first-day-of-the-month prices for each month, adjusted to prices received by field in accordance with standards set forth in the Financial Accounting Standards Board Codification (“FASC”). PV-10 Values and the Standardized Measure are significantly impacted by the oil prices we receive relative to NYMEX oil prices (our NYMEX
oil price differential). The weighted-average oil price differentials utilized were $0.24 per Bbl below representative NYMEX oil prices as of December 31, 2018, compared to $2.25 per Bbl below NYMEX oil prices as of December 31, 2017, and $3.39 per Bbl below NYMEX oil prices as of December 31, 2016.
PV-10 Value is a non-GAAP measure and is different from the Standardized Measure in that PV-10 Value is a pre-tax number and the Standardized Measure is an after-tax number. See Item 1, Business and Properties – Non-GAAP Financial Measures and Reconciliations for further discussion.
Our proved non-producing reserves primarily relate to reserves that are to be recovered from productive zones that currently require a response to performance modifications before they can be classified as proved developed producing. Since a majority of our properties are in areas with multiple pay zones, these properties may have both proved producing and proved non-producing reserves.
As of December 31, 2018, our estimated proved undeveloped reserves totaled approximately 32.3 MMBOE, or approximately 12% of our estimated total proved reserves, an increase of 2.2 MMBOE (7%) from December 31, 2017 levels for these reserves, which changes are discussed below. Approximately 88% (28.3 MMBOE) of our proved undeveloped oil reserves relate to planned future development within our CO2 tertiary operating fields. We generally consider the CO2 tertiary proved undeveloped reserves to be lower risk than other proved undeveloped reserves that require drilling at locations offsetting existing production, because all of these proved undeveloped reserves are associated with tertiary recovery operations in fields and reservoirs that historically produced substantial volumes of oil under primary production. As of December 31, 2018, 19.8 MMBOE of our total proved undeveloped reserves are not scheduled to be developed within five years of initial booking, all of which are part of CO2 EOR projects. We believe these reserves satisfy the conditions to be included as proved reserves because (1) we have established and continue to follow the previously adopted development plan for each of these projects; (2) we have significant ongoing development activities in each of these CO2 EOR projects and (3) we have a historical record of completing the development of comparable long-term projects.
During 2018, we spent approximately $20 million to convert 1.1 MMBOE of proved undeveloped reserves to proved developed reserves, primarily related to continued tertiary development activities at Delhi Field and non-tertiary development activities at Cedar Creek Anticline through our Mission Canyon drilling program. Other changes in proved undeveloped reserves during 2018 included improved recovery additions of 2.3 MMBOE related to our non-tertiary operations at Cedar Creek Anticline; adding an additional 2.0 MMBOE primarily related to our tertiary operations at Hastings Field and Salt Creek Field; and recognizing net downward revisions of our proved undeveloped reserves of 1.0 MMBOE, primarily the result of reserves that were reclassified to unproved based on changes in our waterflood development plans that would now extend beyond the five-year development timeframe.
During 2018, we provided oil and natural gas reserve estimates for 2017 to the United States Energy Information Agency that were substantially the same as the reserve estimates included in our Form 10-K for the year ended December 31, 2017.
Internal Controls Over Reserve Estimates
Reserve information in this report is based on estimates prepared by D&M, an independent petroleum engineering consulting firm located in Dallas, Texas, utilizing data provided by our internal reservoir engineering team and is the responsibility of management. We rely on D&M’s expertise to ensure that our reserve estimates are prepared in compliance with SEC rules and regulations and that appropriate geologic, petroleum engineering, and evaluation principles and techniques are applied in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007)”. The person responsible for the preparation of the reserve report is a Senior Vice President at D&M; he is a Registered Professional Engineer in the State of Texas. He received a Master of Science degree in Petroleum Engineering from the University of Texas in 1984, and he has in excess of 34 years of experience in oil and gas reservoir studies and evaluations. Our Senior Vice President – Business Development and Technology is primarily responsible for overseeing the independent petroleum engineering firm during the process. Our Senior Vice President – Business Development and Technology has a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines and over 34 years of industry experience working with petroleum engineering and reserve estimates. D&M relies on various data provided by our internal reservoir engineering team in preparing its reserve estimates, including such items as oil and natural gas prices, ownership interests, production information, operating costs, planned capital expenditures and other technical data. Our internal reservoir engineering team consists of qualified petroleum engineers who maintain the Company’s internal evaluation of reserves and compare the Company’s information to the reserves
prepared by D&M. Management is responsible for designing the internal control procedures used in the preparation of our oil and gas reserves, which include verification of data input into reserve forecasting and economics evaluation software, as well as multi-discipline management reviews. The internal reservoir engineering team reports directly to our Senior Vice President – Business Development and Technology. In addition, our Board of Directors’ Reserves and Health, Safety and Environmental (“HSE”) Committee, on behalf of the Board of Directors, oversees the qualifications, independence, performance and hiring of our independent petroleum engineering firm and reviews the final report and subsequent reporting of our oil and natural gas reserve estimates. The Chairman of the Reserves and HSE Committee holds a Ph.D. in Chemical Engineering from the Massachusetts Institute of Technology and bachelor’s degrees in Chemistry and Mathematics from Capital University in Ohio. He has more than 35 years of industry experience, with responsibilities including reserves preparation and approval.
OIL AND NATURAL GAS OPERATIONS
Summary. Our oil and natural gas properties are concentrated in the Gulf Coast and Rocky Mountain regions of the United States. Currently our properties with proved and producing reserves in the Gulf Coast region are situated in Mississippi, Texas, Louisiana and Alabama, and in the Rocky Mountain region are situated in Montana, North Dakota and Wyoming. Our primary focus is increasing the value of our properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to CO2 EOR operations. Our current portfolio of CO2 EOR projects provides us significant oil production and reserve growth potential in the future, assuming crude oil prices are at levels that support the development of those projects.
We have been conducting and expanding EOR operations on our assets in the Gulf Coast region since 1999, and as a result, we currently have many more CO2 EOR projects in this region than in the Rocky Mountain region. We began operations in the Rocky Mountain region in 2010 in connection with, and following, our merger with Encore Acquisition Company (“Encore”). In the Gulf Coast region, we own what is, to our knowledge, the region’s only significant naturally occurring source of CO2, and these large volumes of naturally occurring CO2 give us a significant competitive advantage in this area. In the Rocky Mountain region, we own an overriding royalty interest equivalent to an approximate one-third ownership interest in Exxon Mobil Corporation’s (“ExxonMobil’s”) CO2 reserves in LaBarge Field in southwestern Wyoming. In addition to the sources of CO2 we currently own, we purchase and use CO2 captured from industrial sources which could otherwise be released into the atmosphere (sometimes referred to as anthropogenic, man-made or industrial-source CO2) in our tertiary operations. These industrial sources of CO2 help us recover additional oil from mature oil fields and, we believe, also provide an economical way to reduce atmospheric CO2 emissions through the concurrent underground storage of CO2 which occurs as part of our oil-producing EOR operations.
Field Summary Table. The following table provides a summary by field and region of selected proved oil and natural gas reserve information, including total proved reserve quantities as of December 31, 2018, and average daily production for 2018, all based on Denbury’s net revenue interest (“NRI”). The reserve estimates presented were prepared by D&M, independent petroleum engineers located in Dallas, Texas. We serve as operator of nearly all of our significant properties, in which we also own most of the interests, although typically less than a 100% working interest, and a lesser NRI due to royalties and other burdens. For additional oil and natural gas reserves information, see Estimated Net Quantities of Proved Oil and Natural Gas Reserves and Present Value of Estimated Future Net Revenues above and Supplemental Oil and Natural Gas Disclosures (Unaudited) to the Consolidated Financial Statements.
Proved Reserves as of December 31, 2018(1)
2018 Average Daily Production
% of Company Total
Average 2018 NRI
Tertiary oil and gas properties
Gulf Coast region
West Yellow Creek
Total Gulf Coast region
Rocky Mountain region
Salt Creek and other
Total Rocky Mountain region
Total tertiary properties
Non-tertiary oil and gas properties
Gulf Coast region
Mississippi and other
Total Gulf Coast region
Rocky Mountain region
Cedar Creek Anticline(3)
Total Rocky Mountain region
Total non-tertiary properties
Total continuing properties
The above reserve estimates were prepared in accordance with FASC Topic 932, Extractive Industries – Oil and Gas, using the arithmetic averages of the first-day-of-the-month NYMEX commodity price for each month during 2018, which were $65.56 per Bbl for crude oil and $3.10 per MMBtu for natural gas.
Mature properties include Brookhaven, Cranfield, Eucutta, Little Creek, Mallalieu, Martinville, McComb and Soso fields in Mississippi.
The Cedar Creek Anticline consists of a series of 14 different operating areas.
Includes production from Lockhart Crossing Field sold in the third quarter of 2018, the majority of which was previously included in ‘Mature properties’ in the Gulf Coast region.
Enhanced Oil Recovery Overview. CO2 used in EOR is one of the most efficient tertiary recovery mechanisms for producing crude oil. When injected under pressure into underground, oil-bearing rock formations, CO2 acts somewhat like a solvent as it travels through the reservoir rock, mixing with and modifying the characteristics of the oil so it can be produced and sold. The terms “tertiary flood,” “CO2 flood” and “CO2 EOR” are used interchangeably throughout this document.
While enhanced oil recovery projects utilizing CO2 have been successfully performed by numerous oil and gas companies in a wide range of oil-bearing reservoirs in different oil-producing basins, we believe our investments, experience and acquired knowledge give us a strategic and competitive advantage in the areas in which we operate. We apply what we have learned and developed over the years to improve and increase sweep efficiency within the CO2 EOR projects we operate.
We began our CO2 operations in August 1999, when we acquired Little Creek Field, followed by our acquisition of Jackson Dome CO2 reserves and the NEJD pipeline in 2001. Based upon our success at Little Creek and the ownership of the CO2 reserves, we began to transition our capital spending and acquisition efforts to focus more heavily on CO2 EOR and, over time, transformed our strategy to focus primarily on owning and operating oil fields that are well suited for CO2 EOR projects. Prior to tertiary flooding, we strive to maximize the currently sizeable primary and secondary production from our prospective tertiary fields and from fields in which tertiary floods have commenced but still contain significant non-tertiary production. Our asset base today almost entirely consists of, or otherwise relates to, oil fields that we are currently flooding with CO2 or plan to flood with CO2 in the future, or assets that produce CO2.
Our tertiary operations have grown so that (1) 58% of our proved reserves at December 31, 2018 are proved tertiary oil reserves; (2) 63% of our 2018 total production was related to tertiary oil operations (on a BOE basis); and (3) 62% of our 2018 capital expenditures (excluding acquisitions) were related to our tertiary oil operations. At year-end 2018, the proved oil reserves in our tertiary recovery oil fields had an estimated PV-10 Value of approximately $2.7 billion, or 67% of our total PV-10 Value. In addition, there are significant probable and possible reserves at several other fields for which tertiary operations are underway or planned.
Although the up-front cost of tertiary production infrastructure and time to construct pipelines and production facilities is greater than in primary oil recovery in most circumstances, we believe tertiary recovery has several favorable, offsetting and unique attributes, including (1) a lower exploration risk, as we are operating oil fields that have significant historical production and reservoir and geological data, (2) lower production decline rates than unconventional development, (3) reasonable return metrics at our anticipated long-term prices, (4) limited competition for this recovery method in our geographic regions and a strategic advantage due to our ownership of the CO2 reserves and CO2 pipeline infrastructure, (5) our EOR operations are generally less disruptive to new habitats in comparison to other oil and natural gas development because we further develop existing (as opposed to new) oil fields, and (6) through our oil-producing EOR operations, we concurrently store CO2 captured from industrial sourcesin the same underground formations that previously trapped and stored oil and natural gas.
Tertiary Oil Properties
Gulf Coast Region
CO2 Sources and Pipelines
Jackson Dome. Our primary Gulf Coast CO2 source, Jackson Dome, located near Jackson, Mississippi, was discovered during the 1970s by oil and gas companies that were exploring for hydrocarbons. This large and relatively pure source of naturally occurring CO2 (98% CO2) is, to our knowledge, the only significant underground deposit of CO2 in the United States east of the Mississippi River. Together with the related CO2 pipeline infrastructure, Jackson Dome provides us a significant strategic advantage in the acquisition of properties in Mississippi, Louisiana and southeastern Texas that are well suited for CO2 EOR.
We acquired Jackson Dome in February 2001 in a purchase that also gave us ownership and control of the NEJD CO2 pipeline and provided us with a reliable supply of CO2 at a reasonable and predictable cost for our Gulf Coast CO2 tertiary recovery operations. Since February 2001, we have acquired and drilled numerous CO2-producing wells, significantly increasing our
estimated proved Gulf Coast CO2 reserves from approximately 800 Bcf at the time of acquisition of Jackson Dome to approximately 5.0 Tcf as of December 31, 2018. The proved CO2 reserve estimates are based on a gross (8/8ths) basis, of which our net revenue interest is approximately 4.0 Tcf, and is included in the evaluation of proved CO2 reserves prepared by D&M, an independent petroleum engineering consulting firm. In discussing our available CO2 reserves, we make reference to the gross amount of proved and probable reserves, as this is the amount that is available both for our own tertiary recovery programs and for industrial users who are customers of Denbury and others, as we are responsible for distributing the entire CO2 production stream.
In addition to our proved reserves, we estimate that we have 910.1 Bcf of probable CO2 reserves at Jackson Dome. While the majority of these probable reserves are located in structures that have been drilled and tested, such reserves are still considered probable reserves because (1) the original well is plugged; (2) they are located in fault blocks that are immediately adjacent to fault blocks with proved reserves; or (3) they are reserves associated with increasing the ultimate recovery factor from our existing reservoirs with proved reserves. In addition, a significant portion of these probable reserves at Jackson Dome are located in undrilled structures where we have sufficient subsurface and seismic data indicating geophysical attributes that, coupled with our historically high drilling success rate, provide a reasonably high degree of certainty that CO2 is present.
In addition to our drilling at Jackson Dome, we have the capability to expand our processing and dehydration capacities, and install additional pipelines and/or pumping stations necessary to transport the CO2 through our controlled pipeline network. We expect our current proved reserves of CO2, coupled with a risked drilling program at Jackson Dome and CO2 expected to be captured from industrial sources, to provide sufficient quantities of CO2 for us to develop our proved and probable EOR reserves in the Gulf Coast region. In the future, we believe that once a CO2 flood in a field reaches its productive economic limit, we could recycle a portion of the CO2 that remains in that field’s reservoir and utilize it for oil production in another field’s tertiary flood.
In the Gulf Coast region, approximately 83% of our average daily CO2 produced from Jackson Dome or captured from industrial sources in 2018 was used in our tertiary recovery operations, compared to 87% in 2017 and 85% in 2016, with the balance delivered to third-party industrial users. During 2018, we used an average of 466 MMcf/d of CO2 (including CO2 captured from industrial sources) for our tertiary activities.
Gulf Coast CO2 Captured from Industrial Sources. In addition to our natural source of CO2, we are currently party to two long-term contracts to purchase CO2 from industrial plants. We have purchased CO2 from an industrial facility in Port Arthur, Texas since 2012 and from an industrial facility in Geismar, Louisiana since 2013, which supplied an average of approximately 53 MMcf/d of CO2 to our EOR operations during 2018. Additionally, we are in ongoing discussions with other parties regarding plans to construct plants near the Green Pipeline. In order to capture such volumes, we (or the plant owner) would need to install additional equipment, which includes, at a minimum, compression and dehydration facilities.
Gulf Coast CO2 Pipelines. We acquired the 183-mile NEJD CO2 pipeline that runs from Jackson Dome to near Donaldsonville, Louisiana, as part of the 2001 acquisition of our Jackson Dome CO2 source. Since 2001, we have acquired or constructed nearly 750 miles of CO2 pipelines, and as of December 31, 2018, we have access to nearly 950 miles of CO2 pipelines, which gives us the ability to deliver CO2 throughout the Gulf Coast region. In addition to the NEJD CO2 pipeline, the major pipelines in the Gulf Coast region are the Free State Pipeline (90 miles), Delta Pipeline (110 miles), Green Pipeline Texas (120 miles), and Green Pipeline Louisiana (200 miles).
Completion of the Green Pipeline allowed for the first CO2 injection into Hastings Field, located near Houston, Texas, in 2010, and gives us the ability to deliver CO2 to oil fields all along the Gulf Coast from Baton Rouge, Louisiana, to Alvin, Texas. At the present time, most of the CO2 flowing in the Green Pipeline is delivered from the Jackson Dome area, but also includes the CO2 we are receiving from the industrial facilities in Port Arthur, Texas and Geismar, Louisiana, and we are currently transporting a third party’s CO2 for a fee to the sales point at Hastings Field. We currently have ample capacity within the Green Pipeline to handle additional volumes that may be required to develop our inventory of CO2 EOR projects in this area.
Tertiary Properties with Tertiary Production and Proved Tertiary Reserves at December 31, 2018
Delhi Field. Delhi Field is located east of Monroe, Louisiana. In May 2006, we purchased our initial interest in Delhi for $50 million. We began well and facility development in 2008, began delivering CO2 to the field in 2009 via the Delta Pipeline, which runs from Tinsley Field to Delhi Field, and first tertiary production occurred at Delhi Field in 2010. Production from Delhi Field in the fourth quarter of 2018 averaged 4,526 Bbls/d, compared to 4,906 Bbls/d in the fourth quarter of 2017. During 2016, we completed construction of a natural gas liquids extraction plant, which provides us with the ability to sell natural gas liquids from the produced stream, improve the efficiency of the CO2 flood, and utilize extracted methane to power the plant and reduce
field operating expenses. Our 2019 development plans for Delhi Field are primarily related to facility improvement and conformance work.
Hastings Field. Hastings Field is located south of Houston, Texas. We acquired a majority interest in this field in February 2009 for $247 million. We initiated CO2 injection in the West Hastings Unit during 2010 upon completion of the construction of the Green Pipeline. Due to the large vertical oil column that exists in the field, we are developing the Frio reservoir using dedicated CO2 injection and producing wells for each of the major sand intervals. We began producing oil from our EOR operations at Hastings Field in 2012, and we booked initial proved tertiary reserves for the West Hastings Unit in 2012. The Company also has future plans for continued tertiary development of existing proved undeveloped reserves at the field. During the fourth quarter of 2018, tertiary production from Hastings Field averaged 5,480 Bbls/d, compared to 5,747 Bbls/d in the fourth quarter of 2017.
Heidelberg Field. Heidelberg Field is located in Mississippi off of the Free State Pipeline and consists of an East Unit and a West Unit. Construction of the CO2 facility, connecting pipeline and well work commenced on the West Heidelberg Unit during 2008, with our first CO2 injections into the Eutaw zone in 2008. Our first tertiary oil production occurred in 2009, and we began flooding the Christmas and Tuscaloosa zones in 2013 and 2014, respectively. During the fourth quarter of 2018, tertiary production at Heidelberg Field averaged 4,269 Bbls/d, compared to 4,751 Bbls/d in the fourth quarter of 2017. Our 2019 development plans for Heidelberg Field include continued development of the Christmas zone and conformance work, with future plans for continued tertiary development of existing proved undeveloped reserves at the field.
Oyster Bayou Field. We acquired a majority interest in Oyster Bayou Field in 2007. The field is located in southeast Texas, east of Galveston Bay, and is somewhat unique when compared to our other CO2 EOR projects because the field covers a relatively small area of 3,912 acres. We began CO2 injections into Oyster Bayou Field in 2010, commenced tertiary production in 2011 from the Frio A-1 zone, and booked initial proved tertiary reserves for the field in 2012. In 2014, we completed development of the Frio A-2 zone. During the fourth quarter of 2018, tertiary production at Oyster Bayou Field averaged 4,785 Bbls/d, compared to 4,868 Bbls/d in the fourth quarter of 2017.
Tinsley Field. We acquired Tinsley Field in 2006. This Mississippi field was discovered and first developed in the 1930s and is separated by different fault blocks. As is the case with the majority of fields in Mississippi, Tinsley Field produces from multiple reservoirs. Our CO2 enhanced oil recovery operations at Tinsley Field have thus far targeted the Woodruff formation, although there is additional potential in the Perry sandstone and other smaller reservoirs. We commenced tertiary oil production from Tinsley Field in 2008 and substantially completed development of the Woodruff formation during 2014. During the fourth quarter of 2018, tertiary oil production from the field averaged 5,033 Bbls/d, compared to 6,241 Bbls/d in the fourth quarter of 2017. Although production from Tinsley Field is believed to have peaked in 2015 and is generally on decline, we continue to evaluate future potential investment opportunities in this field.
In addition to our tertiary operations at Tinsley Field, we recently conducted exploitation drilling in other oil-bearing formations in the field. We completed a total of two wells in the Perry Sand interval during 2018 and the first quarter of 2019. Overall, the two Perry wells were successful; however, we plan to evaluate the economics and performance of these wells before drilling any additional wells. In December 2018, we spudded our first well in the Cotton Valley interval and currently expect to complete this well during the first quarter of 2019. We continue to evaluate exploitation opportunities in additional horizons underlying the existing CO2 EOR flood.
West Yellow Creek Field. We acquired an approximate 48% non-operated working interest in West Yellow Creek Field in Mississippi in March 2017 for approximately $16 million, a field in which the operator had previously invested significant capital converting the field to a CO2 EOR flood. Under our arrangement with the operator, we supply CO2 to the field for a fee. West Yellow Creek Field is in close proximity to and analogous to Eucutta Field, a very successful CO2 flood that we developed and continue to operate. We booked initial proved tertiary oil reserves at West Yellow Creek Field as of year-end 2017 and commenced tertiary production in early 2018. During the fourth quarter of 2018, tertiary oil production from the field averaged 375 Bbls/d. Development of the field is ongoing, with 2019 development plans including continued tertiary development of the initial formation within the field.
Mature properties. Mature properties include our longest-producing properties which are generally located along our NEJD CO2 pipeline in southwest Mississippi and Louisiana and our Free State Pipeline in east Mississippi. This group of properties includes our initial CO2 field, Little Creek, as well as several other fields (Brookhaven, Cranfield, Eucutta, Mallalieu, Martinville, McComb and Soso fields). These fields accounted for 18% of our total 2018 CO2 EOR production and approximately 6% of our
year-end proved reserves. These fields have been producing under CO2 flood for many years, in many cases more than a decade, and their production is generally declining.
Future Tertiary Properties with No Tertiary Production or Proved Tertiary Reserves at December 31, 2018
Webster Field. We acquired our interest in Webster Field in 2012. The field is located southeast of Houston, Texas, approximately eight miles northeast of our Hastings Field which we are currently flooding with CO2. At December 31, 2018, Webster Field had estimated proved non-tertiary reserves of approximately 2.5 MMBOE, net to our interest. During the fourth quarter of 2018, non-tertiary production at Webster Field averaged 841 BOE/d, compared to 834 BOE/d in the fourth quarter of 2017. Webster Field is geologically similar to our Hastings Field, producing oil from the Frio zone at similar depths; as a result, we believe it is well suited for CO2 EOR. In 2014, we completed a nine-mile lateral between the Green Pipeline and Webster Field, which we plan will eventually deliver CO2 to the field. The timing of the development of a CO2 flood at Webster Field is primarily dependent upon capital availability and priorities and future oil prices.
Conroe Field. Conroe Field, our largest potential tertiary flood in the Gulf Coast region, is located north of Houston, Texas. We acquired a majority interest in this field in 2009 for $271 million in cash and 11.6 million shares of Denbury common stock, for a total aggregate value of $439 million. Conroe Field had estimated proved non-tertiary reserves of approximately 9.9 MMBOE at December 31, 2018, net to our interest, all of which are proved developed. During the fourth quarter of 2018, production at Conroe Field averaged 1,970 BOE/d, compared to 2,140 BOE/d in the fourth quarter of 2017.
To initiate a CO2 flood at Conroe Field, a pipeline must be constructed so that CO2 can be delivered to the field. This pipeline, which is planned as an extension of our Green Pipeline, is preliminarily estimated to cover approximately 90 miles at a cost of approximately $220 million. Our current plan for initiating a CO2 flood at Conroe Field is scheduled several years from now, the timing of which may change depending on capital availability and priorities, future oil prices and pipeline construction.
In addition to the currently-producing oil-bearing formations at Conroe Field, we are evaluating exploitation opportunities in other formations, and currently plan to drill a test well within the 2A Sand interval during 2019.
Thompson Field. We acquired our interest in Thompson Field in June 2012 for $366 million. The field is located in Texas, approximately 18 miles west of our Hastings Field. Thompson Field had estimated proved non-tertiary reserves of approximately 3.9 MMBOE at December 31, 2018, net to our interest, all of which are proved developed. During the fourth quarter of 2018, non-tertiary production at Thompson Field averaged 942 BOE/d net to our interest, compared to 987 BOE/d in the fourth quarter of 2017. Thompson Field is geologically similar to Hastings Field, producing oil from the Frio zone at similar depths, and we therefore believe it has CO2 EOR potential. Under the terms of the Thompson Field acquisition agreement, after the initiation of CO2 injection, the seller will retain approximately a 5% gross revenue interest (less severance taxes) once average monthly oil production exceeds 3,000 Bbls/d. The timing of the development of a CO2 flood at Thompson Field is primarily dependent upon capital availability and priorities and future oil prices.
Rocky Mountain Region
CO2 Sources and Pipelines
LaBarge Field. We acquired an overriding royalty interest equivalent to an approximate one-third ownership interest in ExxonMobil’s CO2 reserves in LaBarge Field in the fourth quarter of 2012 as part of a sale and exchange transaction with ExxonMobil. LaBarge Field is located in southwestern Wyoming, and as of December 31, 2018, our interest in LaBarge Field consisted of approximately 1.2 Tcf of proved CO2 reserves.
During 2018, we received an average of approximately 88 MMcf/d of CO2 from the Shute Creek gas processing plant at LaBarge Field that we used in our Rocky Mountain region CO2 floods. Based on current capacity, and subject to availability of CO2, we currently expect our CO2 volumes from Shute Creek to increase in future years. We pay ExxonMobil a fee to process and deliver the CO2, which we use in our Rocky Mountain region CO2 floods.
Other Rocky Mountain CO2 Sources. We currently have a contract to receive CO2 from the ConocoPhillips-operated Lost Cabin gas plant in central Wyoming that provides us as much as 50 MMcf/d of CO2 for use in our Rocky Mountain region CO2 floods. We currently estimate that our existing CO2 sources, plus additional CO2 from those or other CO2 sources in the region, are sufficient to carry out our base Rocky Mountain region EOR development plans.
Rocky Mountain CO2 Pipelines. The 20-inch Greencore Pipeline in Wyoming is the first CO2 pipeline we constructed in the Rocky Mountain region. We plan to use the pipeline as our trunk line in the Rocky Mountain region, eventually connecting our various Rocky Mountain region CO2 sources to the Cedar Creek Anticline in eastern Montana and western North Dakota. The 232-mile pipeline begins at the ConocoPhillips-operated Lost Cabin gas plant in Wyoming and terminates at Bell Creek Field in Montana. We completed construction of the pipeline in 2012 and received our first CO2 deliveries from the ConocoPhillips-operated Lost Cabin gas plant during 2013. During 2014, we completed construction of an interconnect between our Greencore Pipeline and an existing third-party CO2 pipeline in Wyoming, which enables us to transport CO2 from LaBarge Field to our Bell Creek Field.
In mid-2018, we sanctioned the CO2 enhanced oil recovery development project at Cedar Creek Anticline, which requires a 110-mile extension of the Greencore CO2 pipeline to CCA from Bell Creek Field. The capital outlay for the pipeline is projected to be approximately $150 million, of which approximately $20 million was incurred in 2018 with an additional $30 million currently expected to be incurred in 2019, with the remainder expected in 2020 and early 2021.
Tertiary Properties with Tertiary Production and Proved Tertiary Reserves at December 31, 2018
Bell Creek Field. We acquired our interest in Bell Creek Field in southeast Montana as part of the Encore merger in 2010. The oil-producing reservoir in Bell Creek Field is a sandstone reservoir with characteristics similar to those we have successfully flooded with CO2 in the Gulf Coast region. During 2013, we began first CO2 injections into Bell Creek Field, recorded our first tertiary oil production, and booked initial proved tertiary reserves. Tertiary production, net to our interest, during the fourth quarter of 2018 averaged 4,421 Bbls/d of oil, compared to 3,571 Bbls/d in the fourth quarter of 2017. During 2018, we completed the phase five expansion at the field, and our 2019 development plans are primarily related to phase six expansion of the flood.
Salt Creek Field. We acquired our 23% non-operated working interest in Salt Creek Field in Wyoming for approximately $72 million in June 2017. Tertiary production, net to our interest, during the fourth quarter of 2018 averaged 2,107 Bbls/d of oil, compared to 2,172 Bbls/d in the fourth quarter of 2017.
Future Tertiary Properties with No Tertiary Production or Proved Tertiary Reserves at December 31, 2018
Cedar Creek Anticline. CCA is the largest potential EOR property that we own and currently our largest producing property, contributing approximately 25% of our 2018 total production. Historical production from the property has primarily been from the Red River interval. The field is primarily located in Montana but extends over such a large area (approximately 126 miles) that it also extends into North Dakota. CCA is a series of 14 different operating areas on a common geological trend, each of which could be considered a field by itself. We acquired our initial interest in CCA as part of the Encore merger in 2010 and acquired additional interests (the “CCA Acquisition”) from a wholly-owned subsidiary of ConocoPhillips in 2013 for $1.0 billion, adding 42.2 MMBOE of incremental proved reserves at that date. Production from CCA, net to our interest, averaged 14,961 BOE/d during the fourth quarter of 2018, compared to production during the fourth quarter of 2017 of 14,302 BOE/d. The non-tertiary proved reserves associated with CCA were 85.0 MMBOE, net to our interest, as of December 31, 2018.
In addition to the Red River interval, CCA contains other oil-bearing intervals including Mission Canyon and Charles B. We began pursuing these additional exploitation opportunities in late 2017. We have drilled seven successful Mission Canyon exploitation wells and a successful initial test well in Cabin Creek’s Charles B formation. We continue to evaluate the Charles B formation and believe it has characteristics that would make it a good candidate for secondary or tertiary flooding. Our 2019 development plans for CCA include up to four additional Mission Canyon wells and a potential Charles B follow-up well.
CCA is located approximately 110 miles north of Bell Creek Field, and our current plan is to connect this field to our Greencore Pipeline by the end of 2020. In June 2018, we announced the sanctioning of the CO2 enhanced oil recovery development project at Cedar Creek Anticline. The capital outlay for the initial phase of the project is currently estimated at $300 million through 2022, which includes $150 million for a 110-mile extension of the Greencore CO2 pipeline from Bell Creek Field discussed above and $150 million for development in the Red River formation at East Lookout Butte and Cedar Hills South fields in CCA. First tertiary production from CCA is currently expected in the second half of 2022 or early 2023. Additional phases of development are expected to target the Interlake, Stony Mountain and Red River formations at Cabin Creek Field beginning in 2024.
Grieve Field. Under a 2011 farm-in agreement, we obtained a 65% working interest in Grieve Field, located in Natrona County, Wyoming, in exchange for developing the Grieve Field CO2 flood. During 2016, the Company and its joint venture partner
in Grieve Field revised their development arrangement for the field so that our partner funded $55 million of the remaining estimated capital to complete development of the facility and fieldwork in exchange for a 14% higher working interest and a disproportionate sharing of revenue from the first 2 million barrels of production. Thus, our working interest in the field was reduced from 65% to 51%, and our net revenue interest on the first million barrels of production is approximately 20%. This arrangement accelerated the remaining development of the facility and fieldwork, and we currently anticipate first tertiary production in early 2019.
Hartzog Draw Field. We acquired our interest in Hartzog Draw Field in 2012 in conjunction with the Bakken exchange transaction with ExxonMobil. The field is located in the Powder River Basin of northeastern Wyoming, approximately 12 miles from our Greencore Pipeline. Hartzog Draw Field had estimated proved reserves of approximately 2.9 MMBOE at December 31, 2018, net to our interest, 0.7 MMBOE of which relate to the natural gas producing Big George coal zone. During the fourth quarter of 2018, non-tertiary production averaged 1,327 BOE/d, compared to 1,518 BOE/d in the fourth quarter of 2017. Industry activity around this field has been increasing for the last several years, with several operators testing various formations such as the Turner, Niobrara, Shannon, Parkman and Mowry for potential development. We believe the oil reservoir characteristics of Hartzog Draw Field make it well suited for CO2 EOR in the future. We currently plan to initiate a CO2 flood at Hartzog Draw Field several years from now, the timing of which is dependent on capital availability and priorities and future oil prices.
Other Non-Tertiary Oil Properties
Despite the majority of our oil and natural gas properties discussed above consisting of either existing or planned future tertiary floods, we also produce oil and natural gas either from fields in both our Gulf Coast and Rocky Mountain regions that are not amenable to EOR or from specific reservoirs (within an existing tertiary field) that are not amenable to EOR. For example, at Heidelberg Field, we produce natural gas from the Selma Chalk reservoir, which is separate from the Christmas and Eutaw reservoirs currently being flooded with CO2. Continuing production from these other non-tertiary properties totaled 2,062 BOE/d during the fourth quarter of 2018, compared to 1,864 BOE/d during the fourth quarter of 2017.
OIL AND GAS ACREAGE, PRODUCTIVE WELLS AND DRILLING ACTIVITY
In the data below, “gross” represents the total acres or wells in which we own a working interest and “net” represents the gross acres or wells multiplied by our working interest percentage. For the wells that produce both oil and gas, the well is typically classified as an oil or natural gas well based on the ratio of oil to natural gas production.
Oil and Gas Acreage
The following table sets forth our acreage position at December 31, 2018:
Gulf Coast region
Rocky Mountain region
The percentage of our net undeveloped acreage that is subject to expiration over the next three years, if not renewed, is approximately 37% in 2019, 3% in 2020 and 4% in 2021.
The following table sets forth our gross and net productive oil and natural gas wells as of December 31, 2018:
Producing Oil Wells
Producing Natural Gas Wells
Gulf Coast region
Rocky Mountain region
Gulf Coast region
Rocky Mountain region
Gulf Coast region
Rocky Mountain region
The following table sets forth the results of our drilling activities over the last three years. As of December 31, 2018, we had six wells in progress.
Year Ended December 31,
An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well. A development well is a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
A productive well is an exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
A non-productive well is an exploratory or development well that is not a productive well.
During 2018, 2017 and 2016, an additional 4, 3 and 1 wells, respectively, were drilled for water or CO2 injection purposes.
The following table summarizes sales volumes, sales prices and production cost information for our net oil and natural gas production for the years ended December 31, 2018, 2017 and 2016:
Year Ended December 31,
Net sales volume
Gulf Coast region
Natural gas (MMcf)
Total Gulf Coast region (MBOE)
Rocky Mountain region
Natural gas (MMcf)
Total Rocky Mountain region (MBOE)
Total Company (MBOE)
Average sales prices – excluding impact of derivative settlements
Gulf Coast region
Oil (per Bbl)
Natural gas (per Mcf)
Rocky Mountain region
Oil (per Bbl)
Natural gas (per Mcf)
Oil (per Bbl)
Natural gas (per Mcf)
Average production cost (per BOE sold)(1)
Gulf Coast region
Rocky Mountain region
Excludes oil and natural gas ad valorem and production taxes.
PRODUCTION AND UNIT PRICES
Further information regarding average production rates, unit sales prices and unit costs per BOE are set forth under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Operating Results Table, included herein.
TITLE TO PROPERTIES
As is customary in the oil and natural gas industry, Denbury conducts a limited title examination at the time of its acquisition of properties or leasehold interests targeted for enhanced recovery, and curative work is performed with respect to significant defects on higher-value properties of the greatest significance. We believe that title to our oil and natural gas properties is good and defensible, subject only to such exceptions that we believe do not materially interfere with the use of such properties, including encumbrances, easements, restrictions and royalty, overriding royalty and other similar interests.
SIGNIFICANT OIL AND GAS PURCHASERS AND PRODUCT MARKETING
Oil and natural gas sales are made on a day-to-day basis or under short-term contracts at the current area market price. We would not expect the loss of any single purchaser to have a material adverse effect upon our operations; however, the loss of a large single purchaser could potentially reduce the competition for our oil and natural gas production, which in turn could negatively impact the prices we receive. For the year ended December 31, 2018, two purchasers accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP (24%) and Hunt Crude Oil Supply Company (10%). For the years ended December 31, 2017 and 2016, two purchasers accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP (22% and 20% in 2017 and 2016, respectively) and Marathon Petroleum Company (10% and 14% in 2017 and 2016, respectively).
Our ability to market oil and natural gas depends on many factors beyond our control, including the extent of domestic production and imports of oil and natural gas, the proximity of our oil and natural gas production to pipelines and corresponding markets, the available capacity in such pipelines, the demand for oil and natural gas, the effects of weather, and the effects of state and federal regulation. As of December 31, 2018, we have not experienced significant difficulty in finding a market for all of our production as it becomes available or in transporting our production to those markets; however, there is no assurance that we will always be able to market all of our production or obtain favorable prices.
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. The oil differentials we received in the Gulf Coast and Rocky Mountain regions are discussed in further detail below.
Crude oil prices in the Gulf Coast region are impacted significantly by the changes in prices received for our crude oil sold under Light Louisiana Sweet (“LLS”) index prices relative to the change in NYMEX prices. Overall, during 2018 and 2017, we sold approximately 60% and 65%, respectively, 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. The average LLS-to-NYMEX trade-month differential was a positive $4.91 per Bbl during 2018, compared to a positive $2.85 per Bbl during 2017 and a positive $1.70 per Bbl in 2016. Our average NYMEX oil differential in the Gulf Coast region was a positive $2.94 per Bbl and a positive $0.22 per Bbl during 2018 and 2017, respectively, and $1.42 per Bbl below NYMEX in 2016. Our current markets at various sales points along the Gulf Coast have sufficient demand to accommodate our production, but there can be no assurance of future demand. We are, therefore, monitoring the marketplace for opportunities to strategically enter into long-term marketing arrangements.
The marketing of our Rocky Mountain region oil production is dependent on transportation through local pipelines to market centers in Guernsey, Wyoming; Clearbrook, Minnesota; Wood River, Illinois; and most recently Cushing, Oklahoma. Shipments on some of the pipelines are at or near capacity and may be subject to apportionment. We currently have access to, or have contracted for, sufficient pipeline capacity to move our oil production; however, there can be no assurance that we will be allocated sufficient pipeline capacity to move all of our oil production in the future. Because local demand for production is small in comparison to current production levels, much of the production in the Rocky Mountain region is transported to markets outside of the region. Therefore, prices in the Rocky Mountain region are further influenced by fluctuations in prices (primarily Brent and LLS) in coastal markets and by available pipeline capacity in the Midwest and Cushing markets. For the year ended December 31, 2018, the discount for our oil production in the Rocky Mountain region averaged $1.50 per Bbl, compared to $1.39 per Bbl during 2017 and $3.97 per Bbl during 2016.
COMPETITION AND MARKETS
We face competition from other oil and natural gas companies in all aspects of our business, including acquisition of producing properties, oil and gas leases, drilling rights, and CO2 properties; marketing of oil and natural gas; and obtaining and maintaining goods, services and labor. Many of our competitors have substantially larger financial and other resources. Factors that affect our ability to acquire producing properties include available liquidity, available information about prospective properties and our expectations for earning a minimum projected return on our investments. Because of the primary nature of our core assets (our tertiary operations) and our ownership of relatively uncommon significant natural sources of CO2 in the Gulf Coast and Rocky Mountain regions, we believe that we are effective in competing in the market and have less competition than our peers in certain aspects of our business.
The demand for qualified and experienced field personnel to drill wells and conduct field operations and for geologists, geophysicists, engineers and other professionals in the oil and gas industry can fluctuate significantly, often in correlation with commodity prices, causing periodic shortages in such personnel. Prior to the downturn in oil prices, the competition for qualified technical personnel had been extensive, and our personnel costs escalated. There were also periods with shortages of drilling rigs and other equipment, as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. We cannot be certain when we will experience these issues, and these types of shortages or price increases could significantly decrease our profit margin, cash flow and operating results, and cause significant delays in our development operations.
FEDERAL AND STATE REGULATIONS
Numerous federal, state and local laws and regulations govern the oil and gas industry. Additions or changes to these laws and regulations are often made in response to the current political or economic environment. Compliance with the evolving regulatory landscape is often difficult, and substantial penalties may be incurred for noncompliance. Additionally, the future annual cost of complying with all laws and regulations applicable to our operations is uncertain and will be ultimately determined by several factors, including future changes to legal and regulatory requirements. Management believes that continued compliance with existing laws and regulations applicable to our operations and future compliance therewith will not have a materially adverse effect on our consolidated financial position, results of operations or cash flows, although such laws and regulations, and compliance therewith, could cause significant delays or otherwise impede operations, which may, among other things, cause our expected production rates and cash flows to be less than anticipated.
The following sections describe some specific laws and regulations that may affect us. We cannot predict the cost or impact of these or other future legislative or regulatory initiatives.
Regulation of Oil and Gas Exploration and Production
Our operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for drilling wells; maintaining bonding requirements in order to drill or operate wells and regulating the location of wells; the method of drilling and casing wells; the surface use and restoration of properties upon which wells are drilled; the plugging and abandoning of wells; and the composition or disposal of chemicals and fluids used in connection with operations. Our operations are also subject to various conservation laws and regulations. These include regulation of the size of drilling, spacing or proration units and the density of wells that may be drilled in those units, and the unitization or pooling of oil and gas properties. In addition, federal and state conservation laws, which establish maximum rates of production from oil and gas wells, generally prohibit or restrict the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these laws and regulations may limit the amount of oil and natural gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. Regulatory requirements and compliance relative to the oil and gas industry increase our costs of doing business and, consequently, affect our profitability.
Federal Regulation of Sales Prices and Transportation
The transportation of, and certain sales with respect to, natural gas in interstate commerce are heavily regulated by agencies of the U.S. federal government and are affected by, among other things, the availability, terms and cost of transportation. Notably, the price and terms of access to pipeline transportation are subject to extensive U.S. federal and state regulation. The Federal Energy Regulatory Commission (“FERC”) is continually proposing and implementing new and/or modified rules and regulations affecting the natural gas industry, some of which may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. While our sales of crude oil, condensate and natural gas liquids are not currently subject to FERC regulation, our ability to transport and sell such products is dependent on certain pipelines whose rates, terms and conditions of service are subject to FERC regulation. Additional proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, FERC, state regulatory bodies and the courts, and we cannot predict when or if any such proposals or proceedings might become effective and their effect or impact, if any, on our operations.
Federal Energy and Climate Change Legislation and Regulation
The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, among other things, updated federal pipeline safety standards, increased penalties for violations of such standards, gave the Department of Transportation’s Pipeline and Hazardous
Materials Safety Administration (the “PHMSA”) authority for new damage prevention and incident notification, and directed the PHMSA to prescribe new minimum safety standards for CO2 pipelines, which safety standards could affect our operations and the costs thereof. While the PHMSA has adopted or proposed to adopt a number of new regulations to implement this act, no new minimum safety standards have been proposed or adopted for CO2 pipelines.
Both federal and state authorities have in recent years proposed new regulations to limit the emission of greenhouse gasses as part of climate change initiatives. For example, both the EPA and BLM have issued regulations for the control of methane emissions. The EPA has promulgated regulations requiring permitting for certain sources of greenhouse gas emissions, and in May 2016, promulgated final regulations to reduce methane and volatile organic compound emissions from the oil and gas sector. In July 2017, a federal appeals court rejected an attempt by the EPA to delay implementation of the rule. In September 2018, the EPA proposed amendments to the rule that are targeted at reducing regulatory requirements and streamlining the rule’s implementation. Enforcement of these regulations may impose additional costs related to compliance with new emission limits, as well as inspections and maintenance of several types of equipment used in our operations.
Natural Gas Gathering Regulations
State and federal regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory-take requirements. With the increase in construction and operation of natural gas gathering lines in various states, natural gas gathering is receiving greater regulatory scrutiny from state and federal regulatory agencies, which is likely to continue in the future.
Federal, State or Indian Leases
Our operations on federal, state or Indian oil and gas leases, especially those in the Rocky Mountain region, are subject to numerous restrictions, including nondiscrimination statutes. Such operations must be conducted pursuant to certain on-site security regulations and other permits and authorizations issued by the Bureau of Land Management, the Bureau of Ocean Energy Management, the Bureau of Safety and Environmental Enforcement, the Bureau of Indian Affairs, and other federal and state stakeholder agencies.
Our oil and natural gas production, saltwater disposal operations, injection of CO2, and the processing, handling and disposal of materials such as hydrocarbons and naturally occurring radioactive materials (“NORM”) are subject to stringent regulation. We could incur significant costs, including cleanup costs resulting from a release of product, third-party claims for property damage and personal injuries, or penalties and other sanctions as a result of any violations or liabilities under environmental laws and regulations or other laws and regulations applicable to our operations. Changes in, or more stringent enforcement of, environmental laws and other laws applicable to our operations could also result in delays or additional operating costs and capital expenditures.
Various federal, state and local laws and regulations controlling the discharge of materials into the environment, or otherwise relating to the protection of the environment and human health, directly impact our oil and gas exploration, development and production operations. These include, among others, (1) regulations adopted by the EPA and various state agencies regarding approved methods of disposal for certain hazardous and nonhazardous wastes; (2) the Comprehensive Environmental Response, Compensation, and Liability Act and analogous state laws that regulate the removal or remediation of previously disposed wastes (including wastes disposed of or released by prior owners or operators), property contamination (including groundwater contamination), and remedial plugging operations to prevent future contamination; (3) the Clean Air Act and comparable state and local requirements already applicable to our operations and new restrictions on air emissions from our operations, including greenhouse gas emissions and those that could discourage the production of fossil fuels that, when used, ultimately release CO2; (4) the Oil Pollution Act of 1990, which contains numerous requirements relating to the prevention of, and response to, oil spills into waters of the United States; (5) the Resource Conservation and Recovery Act, which is the principal federal statute governing the treatment, storage and disposal of hazardous wastes; (6) the Endangered Species Act and counterpart state legislation, which protects certain species (and their related habitats), including certain species that could be present on our leases, as threatened or endangered; and (7) state regulations and statutes governing the handling, treatment, storage and disposal of NORM and other wastes.
In the Rocky Mountain Region, federal agencies’ actions based upon their environmental review responsibilities under the National Environmental Policy Act can significantly impact the scope and timing of hydrocarbon development by slowing the
timing of individual applications for permits to drill and requests for rights-of-way, and delaying large scale planning associated with region-level resource management plans and project-level master development plans.
Management believes that we are currently in substantial compliance with existing applicable environmental laws and regulations, and does not currently anticipate that future compliance will have a materially adverse effect on our consolidated financial position, results of operations or cash flows, although such laws and regulations, and compliance therewith, could cause significant delays or otherwise impede operations, which may, among other things, cause our expected production rates and cash flows to be less than anticipated.
During 2018, we fracture stimulated five wells at Bell Creek Field and two wells at Tinsley Field utilizing water-based fluids. We currently have plans to potentially hydraulically fracture one well during 2019. We are familiar with the laws and regulations applicable to hydraulic fracturing operations and take steps to ensure compliance with these requirements.
NON-GAAP FINANCIAL MEASURES AND RECONCILIATIONS
Reconciliation of Standardized Measure to PV-10 Value
PV-10 Value is a non-GAAP measure and is different from the Standardized Measure in that PV-10 Value is a pre-tax number and the Standardized Measure is an after-tax number. The information used to calculate PV-10 Value is derived directly from data determined in accordance with FASC Topic 932. We believe that PV-10 Value is a useful supplemental disclosure to the Standardized Measure because the Standardized Measure can be impacted by a company’s unique tax situation, and it is not practical to calculate the Standardized Measure on a property-by-property basis. Because of this, PV-10 Value is a widely used measure within the industry and is commonly used by securities analysts, banks and credit rating agencies to evaluate the estimated future net cash flows from proved reserves on a comparative basis across companies or specific properties. PV-10 Value is commonly used by us and others in our industry to evaluate properties that are bought and sold, to assess the potential return on investment in our oil and natural gas properties, and to perform our impairment testing of oil and natural gas properties. PV-10 Value is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for the Standardized Measure. Our PV-10 Value and the Standardized Measure do not purport to represent the fair value of our oil and natural gas reserves. See also Glossary and Selected Abbreviations for the definition of “PV-10 Value” and Supplemental Oil and Natural Gas Disclosures (Unaudited) to the Consolidated Financial Statements for additional disclosures about the Standardized Measure.
The following table provides a reconciliation of the Standardized Measure to PV-10 Value for the periods indicated:
Year Ended December 31,
Standardized Measure (GAAP measure)
Discounted estimated future income tax
PV-10 Value (non-GAAP measure)
Reconciliation of Net Income to Adjusted EBITDAX
Adjusted EBITDAX is a non-GAAP financial measure which management uses and is calculated based upon (but not identical to) a financial covenant related to “Consolidated EBITDAX” in our senior secured bank credit facility, which excludes certain items that are included in net income, the most directly comparable GAAP financial measure. Items excluded include interest, income taxes, depletion, depreciation, and amortization, and items that the Company believes affect the comparability of operating results such as items whose timing and/or amount cannot be reasonably estimated or are non-recurring. Management believes Adjusted EBITDAX may be helpful to investors in order to assess our operating performance as compared to that of other companies in our industry, without regard to financing methods, capital structure or historical costs basis. It is also commonly used by third parties to assess the Company’s leverage and ability to incur and service debt and fund capital expenditures. Adjusted EBITDAX should not be considered in isolation, as a substitute for, or more meaningful than, net income, cash flows from operations, or any other measure reported in accordance with GAAP. The Company’s Adjusted EBITDAX may not be comparable to similarly titled
Oil and natural gas prices are volatile. A sustained period of deterioration of oil prices is likely to adversely affect our future financial condition, results of operations, cash flows and the carrying value of our oil and natural gas properties.
Oil prices are the most important determinant of our operational and financial success. Oil prices are highly impacted by worldwide oil supply, demand and prices, and have historically been subject to significant price changes over short periods of time. Over the last few years, NYMEX oil prices have been volatile, decreasing to a low of $26 in early 2016 and gradually improving to hit a three-year peak of $76 in October 2018, before retreating to the low-$40’s in late December 2018 and then moving upward again to an average of approximately $53 per Bbl during the first two months of 2019. Based on past commodity cycles, volatility will remain, and prices could move downward or upward on a rapid or repeated basis, which can make planning and budgeting, acquisition and divestiture transactions, capital raising, valuations and sustained business strategies more difficult. Our cash flow from operations is highly dependent on the prices that we receive for oil, as oil comprised approximately 97% of our 2018 production and approximately 97% of our proved reserves at December 31, 2018. The prices for oil and natural gas are subject to a variety of factors that are beyond our control. These factors include:
the level of worldwide consumer demand for oil and natural gas and the domestic and foreign supply of oil and natural gas and levels of domestic oil and natural gas storage;
the degree to which members of the Organization of Petroleum Exporting Countries maintain oil price and production controls;
the degree to which domestic oil and natural gas production affects worldwide supply of crude oil or its price;
worldwide political events, conditions and policies, including actions taken by foreign oil and natural gas producing nations; and
worldwide economic conditions.
Negative movements in oil prices could harm us in a number of ways, including:
lower cash flows from operations may require reduced levels of capital expenditures;
reduced levels of capital expenditures in turn could lower our present and future production levels, and lower the quantities and value of our oil and gas reserves, which constitute our major asset;
our lenders could reduce our borrowing base, and we may not be able to raise capital at attractive rates in the public markets;
we could have difficulty repaying or refinancing our indebtedness;
we could be forced to increase our level of indebtedness, issue additional equity, or sell assets;
we could be required to impair various assets, including a further write-down of our oil and natural gas assets or the value of other tangible or intangible assets; and/or
our potential cash flows from our commodity derivative contracts that include sold puts could be limited to the extent that oil prices are below the prices of those sold puts.
Furthermore, some or all of our tertiary projects could remain or become uneconomical. We may also decide to suspend future expansion projects, and if prices were to drop below our operating cash break-even points for an extended period of time, we may decide to shut-in existing production, both of which could have a material adverse effect on our operations, financial condition and reduce our production.
A financial downturn in one or more of the world’s major markets could negatively affect our business and financial condition.
In addition to the impact on the demand for oil, drops in domestic or foreign economic growth rates, regional or worldwide increases in tariffs or other trade restrictions, significant international currency fluctuations, a sustained credit crisis, a severe economic contraction either regionally or worldwide or turmoil in the global financial system, could materially affect our business and financial condition, or impact our ability to finance operations. Negative credit market conditions could inhibit our lenders from funding our senior secured bank credit facility or cause them to restrict our borrowing base or make the terms of our senior secured bank credit facility more costly and more restrictive. Negative economic conditions could also adversely affect the collectability of our trade receivables or performance by our suppliers or cause our commodity hedging arrangements to be ineffective if our counterparties are unable to perform their obligations.
Constraints on liquidity could affect our ability to maintain or increase cash flow from operations.
In recent years, sources and levels of liquidity for the oil and gas industry have become more restrictive, in part due to the tightening of commercial lenders. Although our liquidity was sufficient to support our capital expenditures during 2018, future additional liquidity restrictions could negatively affect our level of capital expenditures, and thus our maintenance or growth in production and operational cash flow. Additionally, our liquidity could be affected by payments made upon finalization of ongoing litigation (see Item 3, Legal Proceedings). We require continued access to capital. As a result, we may seek to access the public or private capital markets whenever conditions are favorable, even if we do not have an immediate need for additional capital at that time.
Our level of indebtedness could adversely affect the level of our operating activities.
As of December 31, 2018, our outstanding indebtedness consisted of $1.5 billion aggregate principal amount of senior indebtedness and $826.2 million aggregate principal amount of subordinated indebtedness. Our outstanding senior indebtedness consisted of $614.9 million principal amount of 9% Senior Secured Second Lien Notes due 2021, $455.7 million principal amount of 9¼% Senior Secured Second Lien Notes due 2022, and $450.0 million principal amount of 7½% Senior Secured Second Lien Notes due 2024. Our subordinated indebtedness consisted of $826.2 million principal amount of subordinated notes, all of which have maturity dates between 2021 and 2023 at interest rates ranging from 4.625% to 6.375% per annum at a weighted average interest rate of 5.39% per annum. As of December 31, 2018, we had no outstanding borrowings on our senior secured bank credit facility, a borrowing base and aggregate lender commitments of $615 million under our senior secured bank credit facility and availability with respect to such commitments of $553.0 million after considering letters of credit outstanding. Although the merger is currently expected to increase our debt levels while improving our leverage metrics and cash flow, consummation of the merger would further increase our exposure to economic or oil price downturns and the negative effects thereof.
Our debt could have important consequences for us, including but not limited to the following:
increasing our vulnerability to general adverse economic and industry conditions, including falling crude oil prices;
impairing our ability to obtain additional financing for working capital, capital expenditures, acquisitions, development activities or general corporate and other purposes;
potentially restricting us from making acquisitions or exploiting business opportunities;
requiring dedication of a substantial portion of our cash flows from operations to servicing our indebtedness (so that such cash flows would not be available for capital expenditures or other purposes);
limiting our ability to borrow additional funds, dispose of assets and make certain investments; and/or
placing us at a competitive disadvantage as compared to our competitors that have less debt.
Increases in interest rates could adversely affect our business.
Our business and operating results can be harmed by increases in interest rates. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow, affect our interest costs under our senior secured bank credit facility, or increase the cost of any new debt financings.
Inability to meet financial performance covenants in our bank agreements may require us to seek modification of covenants, force a reduction in our borrowing base, or cause repayment of amounts outstanding under our bank credit facility.
Between May 2015 and August 2018, we modified certain of our financial performance covenants under our senior secured bank credit facility to support continuing compliance with these covenants through the lower oil price environment we have experienced over the last several years. In August 2018, we extended the maturity of our bank credit facility to December 2021 and reset certain financial performance covenants based on projections and oil price expectations that existed at that time. Oil prices subsequent to August 2018 have been volatile, and if oil and natural gas prices decrease for an extended period of time, these metrics could deteriorate further, potentially causing us to not be in compliance with our senior secured bank credit facility’s covenants. As such, we may be required to seek modifications of these covenants, the banks could force a reduction in our bank borrowing base and repayment of amounts outstanding under our bank credit facility, or provide a waiver at a significant cost to the Company. As of December 31, 2018, we had no bank debt outstanding, but we did have $62.0 million in letters of credit outstanding. Also, we may seek to reduce our debt by, among other things, purchasing our debt in the open market, completing cash tenders for our debt or public or privately negotiated debt exchanges, issuing equity or completing asset sales and other cash-generating activities. We cannot assure you, however, that we will be able to successfully modify these covenants or reduce our
debt in the future. For more information on our senior secured bank credit facility, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – Senior Secured Bank Credit Facility.
Our bank borrowing base is determined semiannually, and upon requested unscheduled special redeterminations, in each case at the banks’ discretion, and the amount is established and based, in part, upon certain external factors, such as commodity prices. We do not know, nor can we control, the results of such redeterminations or the effect of then-current oil and natural gas prices on any such redetermination. A future redetermination lowering our borrowing base could limit availability under our senior secured bank credit facility or require us to seek different forms of financing arrangements. If the outstanding debt under our senior secured bank credit facility were to ever exceed the borrowing base, we would be required to repay the excess amount over a period not to exceed six months.
Certain of our operations may be limited during certain periods due to severe weather conditions and other regulations.
Our operations in the Gulf Coast region may be subjected to adverse weather conditions such as hurricanes, flooding and tropical storms in and around the Gulf of Mexico that can damage oil and natural gas facilities and delivery systems and disrupt operations, which can also increase costs and have a negative effect on our results of operations. Certain of our operations in North Dakota, Montana and Wyoming, including the construction of CO2 pipelines, the drilling of new wells and production from existing wells, are conducted in areas subject to extreme weather conditions, including severe cold, snow and rain, which conditions may cause such operations to be hindered or delayed, or otherwise require that they be conducted only during non-winter months, and depending on the severity of the weather, could have a negative effect on our results of operations in these areas. Further, certain of our operations in these areas are confined to certain time periods due to environmental regulations, federal restrictions on when drilling can take place on federal lands, and lease stipulations designed to protect certain wildlife, which regulations, restrictions and limitations could slow down our operations, cause delays, increase costs and have a negative effect on our results of operations.
Oil and natural gas development and producing operations involve various risks.
Our operations are subject to all of the risks normally incident and inherent to the operation and development of oil and natural gas properties and the drilling of oil and natural gas wells, including, without limitation, pipe failure; fires; formations with abnormal pressures; uncontrollable flows of oil, natural gas, brine or well fluids; release of contaminants into the environment and other environmental hazards and risks and well blowouts, cratering or explosions. In addition, our operations are sometimes near populated commercial or residential areas, which add additional risks. The nature of these risks is such that some liabilities could exceed our insurance policy limits or otherwise be excluded from, or limited by, our insurance coverage, as in the case of environmental fines and penalties, for example, which are excluded from coverage as they cannot be insured.
We could incur significant costs related to these risks that could have a material adverse effect on our results of operations, financial condition and cash flows or could have an adverse effect upon the profitability of our operations. Additionally, a portion of our production activities involves CO2 injections into fields with wells plugged and abandoned by prior operators. However, it is often difficult (or impracticable) to determine whether a well has been properly plugged prior to commencing injections and pressuring the oil reservoirs. We may incur significant costs in connection with remedial plugging operations to prevent environmental contamination and to otherwise comply with federal, state and local regulations relative to the plugging and abandoning of our oil, natural gas and CO2 wells. In addition to the increased costs, if wells have not been properly plugged, modification to those wells may delay our operations and reduce our production.
Development activities are subject to many risks, including the risk that we will not recover all or any portion of our investment in such wells. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Further, our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including:
unexpected drilling conditions;
pressure or irregularities in formations;
equipment failures or accidents;
adverse weather conditions, including hurricanes and tropical storms in and around the Gulf of Mexico that can damage oil and natural gas facilities and delivery systems and disrupt operations, and winter conditions and forest fires in the Rocky Mountain region that can delay or impede operations;
compliance with environmental and other governmental requirements;
the cost of, or shortages or delays in the availability of, drilling rigs, equipment, pipelines and services; and
Estimating our reserves, production and future net cash flows is difficult to do with any certainty.
Estimating quantities of proved oil and natural gas reserves is a complex process. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors such as future commodity prices, production costs, severance and excise taxes, capital expenditures and workover and remedial costs, and the assumed effect of governmental rules and regulations. There are numerous uncertainties about when a property may have proved reserves as compared to potential or probable reserves, particularly relating to our tertiary recovery operations. Forecasting the amount of oil reserves recoverable from tertiary operations, and the production rates anticipated therefrom, requires estimates, one of the most significant being the oil recovery factor. Actual results most likely will vary from our estimates. Also, the use of a 10% discount factor for reporting purposes, as prescribed by the SEC, may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business, and the oil and natural gas industry in general, are subject. Any significant inaccuracies in these interpretations or assumptions, or changes of conditions, could result in a revision of the quantities and net present value of our reserves.
The reserves data included in documents incorporated by reference represent estimates only. Quantities of proved reserves are estimated based on economic conditions, including first-day-of-the-month average oil and natural gas prices for the 12-month period preceding the date of the assessment. The representative oil and natural gas prices used in estimating our December 31, 2018 reserves were $65.56 per Bbl for crude oil and $3.10 per MMBtu for natural gas, both of which were adjusted for market differentials by field. Rapid crude oil price declines beginning in late 2014 have resulted in a significant decrease in our proved reserve value from 2014 levels, and to a lesser degree, a reduction in our proved reserve volumes, which has caused us to record write-downs due to the full cost ceiling test in 2015 and 2016. As discussed in greater detail below, significant declines in oil prices could result in additional write-downs. Our reserves and future cash flows may be subject to revisions based upon changes in economic conditions, including oil and natural gas prices, as well as due to production results, results of future development, operating and development costs, and other factors. Downward revisions of our reserves could have an adverse effect on our financial condition and operating results. Actual future prices and costs may be materially higher or lower than the prices and costs used in our estimates.
As of December 31, 2018, approximately 12% of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and may require successful drilling operations. The reserves data assumes that we can and will make these expenditures and conduct these operations successfully, but these assumptions may not be accurate, and these expenditures and operations may not occur.
Our planned tertiary operations and the related construction of necessary CO2 pipelines could be delayed by difficulties in obtaining pipeline rights-of-way and/or permits, and/or by the listing of certain species as threatened or endangered.
The production of crude oil from our planned tertiary operations is dependent upon having access to pipelines to transport available CO2 to our oil fields at a cost that is economically viable. Our future construction of CO2 pipelines will require us to obtain rights-of-way from private landowners, state and local governments and the federal government in certain areas. Certain states where we operate have considered or may again consider the adoption of laws or regulations that could limit or eliminate the ability of a pipeline owner or of a state, state’s legislature or its administrative agencies to exercise eminent domain over private property, in addition to possible judicially imposed constraints on, and additional requirements for, the exercise of eminent domain. We also conduct operations on federal and other oil and natural gas leases inhabited by species that could be listed as threatened or endangered under the Endangered Species Act, which listing could lead to tighter restrictions as to federal land use and other land use where federal approvals are required. These laws and regulations, together with any other changes in law related to the use of eminent domain or the listing of certain species as threatened or endangered, could inhibit or eliminate our ability to secure rights-of-way or otherwise access land for current or future pipeline construction projects and may require additional regulatory and environmental compliance, and increased costs in connection therewith, which could delay our CO2 pipeline construction schedule and initiation of our pipeline operations, and/or increase the costs of constructing our pipelines.
Our future performance depends upon our ability to effectively develop our existing oil and natural gas reserves and find or acquire additional oil and natural gas reserves that are economically recoverable.
Unless we can successfully develop our existing reserves and/or replace the reserves that we produce, our reserves will decline, resulting eventually in a decrease in oil and natural gas production and lower revenues and cash flows from operations. We have historically replaced reserves through both acquisitions and internal organic growth activities. For internal organic growth activities, the magnitude of proved reserves that we can book in any given year depends on our progress with new floods and the timing of the production response, as well as the success of exploitation projects. In the future, we may not be able to continue to replace reserves at acceptable costs. The business of exploring for, developing or acquiring reserves is capital intensive. We may not be able to make the necessary capital investment to maintain or expand our oil and natural gas reserves if our cash flows from operations are reduced, whether due to current oil or natural gas prices or otherwise, or if external sources of capital become limited or unavailable. Further, the process of using CO2 for tertiary recovery, and the related infrastructure, requires significant capital investment prior to any resulting and associated production and cash flows from these projects, heightening potential capital constraints. If our capital expenditures are restricted, or if outside capital resources become limited, we will not be able to maintain our current production levels.
Commodity derivative contracts may expose us to potential financial loss.
To reduce our exposure to fluctuations in the prices of oil and natural gas, we enter into commodity derivative contracts in order to economically hedge a portion of our forecasted oil and natural gas production. As of February 26, 2019, we have oil derivative contracts in place covering 39,500 Bbls/d for the remainder of 2019 and 4,000 Bbls/d for 2020. Such derivative contracts expose us to risk of financial loss in some circumstances, including when there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received, when the cash benefit from hedges including a sold put is limited to the extent oil prices fall below the price of our sold puts, or when the counterparty to the derivative contract is financially constrained and defaults on its contractual obligations. In addition, these derivative contracts may limit the benefit we would otherwise receive from increases in the prices for oil and natural gas.
Shortages of or delays in the availability of oil field equipment, services and qualified personnel could reduce our cash flow and adversely affect results of operations.
The demand for qualified and experienced field personnel, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages in such personnel. In the past, during periods of higher oil and natural gas prices, there have been shortages of oil field and other necessary equipment, including drilling rigs, along with increased prices for such equipment, services and associated personnel. These types of shortages or price increases could significantly decrease our profit margin, cash flow and operating results and/or restrict or delay our ability to drill wells and conduct our operations, possibly causing us to miss our forecasts and projections.
The marketability of our production is dependent upon transportation lines and other facilities, certain of which we do not control. When these facilities are unavailable, our operations can be interrupted and our revenues reduced.
The marketability of our oil and natural gas production depends, in part, upon the availability, proximity and capacity of transportation lines owned by third parties. In general, we do not control these transportation facilities, and our access to them may be limited or denied. A significant disruption in the availability of, and access to, these transportation lines or other production facilities could adversely impact our ability to deliver to market or produce our oil and thereby cause a significant interruption in our operations.
Our production will decline if our access to sufficient amounts of carbon dioxide is limited.
Our long-term strategy is primarily focused on our CO2 tertiary recovery operations. The crude oil production from our tertiary recovery projects depends, in large part, on having access to sufficient amounts of naturally occurring and industrial-source CO2. Our ability to produce oil from these projects would be hindered if our supply of CO2 was limited due to, among other things, problems with our current CO2 producing wells and facilities, including compression equipment, catastrophic pipeline failure or our ability to economically purchase CO2 from industrial sources. This could have a material adverse effect on our financial condition, results of operations and cash flows. Our anticipated future crude oil production from tertiary operations is also dependent on the timing, volumes and location of CO2 injections and, in particular, on our ability to increase our combined purchased and
produced volumes of CO2 and inject adequate amounts of CO2 into the proper formation and area within each of our tertiary oil fields.
The development of our naturally occurring CO2 sources involves the drilling of wells to increase and extend the CO2 reserves available for use in our tertiary fields. These drilling activities are subject to many of the same drilling and geological risks of drilling and producing oil and gas wells (see Oil and natural gas development and producing operations involve various risks above). Furthermore, recent market conditions may cause the delay or cancellation of construction of plants that produce industrial-source CO2 as a byproduct that we can purchase, thus limiting the amount of industrial-source CO2 available for our use in our tertiary operations.
A cyber incident could occur and result in information theft, data corruption, operational disruption, and/or financial loss.
Our business has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain of our exploration, development and production activities. We depend on digital technology, among other things, to process and record financial and operating data; analyze seismic and drilling information; monitor and control pipeline and plant equipment; and process and store personally identifiable information of our employees and royalty owners. Our technologies, systems and networks may become the target of cyber attacks or information security breaches that could result in the disruption of our business operations and/or financial loss.
Although we utilize various procedures and controls to monitor and protect against these threats and to mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing and causing us to suffer such losses in the future. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our procedures and controls or to investigate and remediate any cyber vulnerabilities.
We may lose key executive officers or specialized technical employees, which could endanger the future success of our operations.
Our success depends to a significant degree upon the continued contributions of our executive officers, other key management and specialized technical personnel. Our employees, including our executive officers, are employed at will and do not have employment agreements. We believe that our future success depends, in large part, upon our ability to hire and retain highly skilled personnel.
Environmental laws and regulations are costly and stringent.
Our exploration, production, and marketing operations are subject to complex and stringent federal, state, and local laws and regulations governing, among other things, the discharge of substances into the environment or otherwise relating to the protection of human health and the protection of endangered species. These laws and regulations and related public policy considerations affect the costs, manner, and feasibility of our operations and require us to make significant expenditures in order to comply. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial obligations, and the issuance of injunctions that could limit or prohibit our operations. Some of these laws and regulations may impose joint and several, strict liability for contamination resulting from spills, discharges, and releases of substances, including petroleum hydrocarbons and other wastes, without regard to fault, or the legality of the original conduct. Under such laws and regulations, we could be required to remove or remediate previously disposed substances and property contamination, including wastes disposed or released by prior owners or operators.
Enactment of executive, legislative or regulatory proposals under consideration could negatively affect our business.
While it is currently anticipated that the President will attempt to move away from the trend of proposing stricter standards and increasing oversight and regulation at the federal level, it is possible that other proposals affecting the oil and gas industry could be enacted or adopted in the future, including state or local regulations, any of which could result in increased costs or additional operating restrictions that could have an effect on demand for oil and natural gas or prices at which it can be sold.
The loss of one or more of our large oil and natural gas purchasers could have an adverse effect on our operations.
For the year ended December 31, 2018, two purchasers individually accounted for 10% or more of our oil and natural gas revenues and, in the aggregate, for 34% of such revenues. The loss of a large single purchaser could adversely impact the prices we receive or the transportation costs we incur.
If commodity prices decline appreciably, we may be required to write down the carrying value of our oil and natural gas properties.
Under full cost accounting rules related to our oil and natural gas properties, we are required each quarter to perform a ceiling test calculation, with the net capitalized costs of our oil and natural gas properties limited to the lower of unamortized cost or the cost center ceiling. The present value of estimated future net revenues from proved oil and natural gas reserves included in the cost center ceiling is based on the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period prior to the end of a particular reporting period. During 2016, we recorded a full cost pool ceiling test write-down of our oil and natural gas properties totaling $810.9 million ($508.2 million net of tax). We did not record any ceiling test write-downs during 2017 or 2018. Future material write-downs of our oil and natural gas properties, as well as future impairment of other long-lived assets, could significantly reduce earnings during the period in which such write-down and/or impairment occurs and would result in a corresponding reduction to long-lived assets and equity. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Estimates.
Failure to complete the pending acquisition of Penn Virginia Corporation could negatively impact the price of our common stock and our future business and financial results.
Failure to consummate the Penn Virginia acquisition may cause negative reactions from the financial markets, including a downturn in the price of Denbury’s common stock; may negatively affect the manner in which costumers, lenders, business partners and other third parties perceive Denbury; and may lead to adverse effects on Denbury’s business and financial results from having expended time and resources on the pending acquisition rather than on Denbury’s existing businesses and pursuit of other opportunities.
Closing of the pending acquisition of Penn Virginia would present a variety of possible business challenges to Denbury.
In addition to the possible negative effect on Denbury’s common stock price of the dilution resulting from issuance of shares to Penn Virginia shareholders and the higher debt levels used to finance the merger, Denbury might be negatively affected on an ongoing basis by the attention required to integrate Penn Virginia and its assets. Consummating the acquisition may also fail to be as accretive as anticipated by Denbury and carry higher costs than anticipated, inclusive of the employee retention costs, fees paid to legal, financial and accounting advisors and severance benefits and costs. Lastly, the anticipated synergies and economic benefits from the transaction may not be realized.
The combined company debt may limit Denbury’s financial flexibility.
Denbury’s approximate total debt of $2.5 billion at December 31, 2018 would increase upon consummation of the Penn Virginia acquisition. This additional debt may carry less favorable terms than Denbury’s current debt and may bear higher interest rates; impose additional cash requirements to support interest payments and repay the debt obligations; and increase Denbury’s exposure to general economic downturns, falling oil prices and rising interest rates.
Item 1B. Unresolved Staff Comments
There are no unresolved written SEC staff comments regarding our periodic or current reports under the Securities Exchange Act of 1934 received 180 days or more before the end of the fiscal year to which this annual report on Form 10-K relates.
Item 2. Properties
Information regarding the Company’s properties called for by this item is included in Item 1, Business and Properties – Oil and Natural Gas Operations. We also have various operating leases for rental of office space, office and field equipment, and vehicles. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources
and Liquidity – Off-Balance Sheet Arrangements, and Note 12, Commitments and Contingencies, to the Consolidated Financial Statements for the future minimum rental payments. Such information is incorporated herein by reference.
Item 3. 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. We 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 (“APMTG”). The helium supply contract provides for the delivery of a minimum contracted quantity of helium 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 due to significant technical issues, we have not been able to supply helium under the helium supply contract. In a case filed in November 2014 in the Ninth Judicial District Court of Sublette County, Wyoming, APMTG claimed 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.
On January 21, 2019, the Company received notice of the trial court’s ruling that a force majeure condition did exist, but the Company’s performance was only excused by the force majeure provisions of the contract for a 35-day period in 2014, and as a result the Company should pay APMTG liquidated damages and interest thereon for those time periods from contract commencement to the close of evidence (November 29, 2017) when the Company’s performance was not excused as provided in the contract. The trial court has not yet entered a final judgment based upon its decision. The Company currently estimates the contractual liquidated damages to be $31.8 million, representing the amount due for the contract years for which evidence was submitted at the trial ending November 29, 2017. However, absent reversal of the trial court’s factual or legal conclusions on appeal, the Company anticipates total liquidated damages will equal the $46.0 million aggregate cap under the helium supply contract (which includes an additional $14.2 million of liquidated damages for the contract years ending July 31, 2018 and July 31, 2019) and other costs associated with the settlement of approximately $3.4 million, the total of which the Company has included in “Other liabilities” in our Consolidated Balance Sheets as of December 31, 2018 and “Other expenses” in our Consolidated Statements of Operations for the year ended December 31, 2018. The Company’s position continues to be that its contractual obligations have been and continue to be excused by events that fall within the force majeure provisions in the helium supply contract. The Company intends to continue to vigorously defend its position and pursue all of its rights, which may include an appeal of the trial court’s ruling, the results of which cannot be currently predicted.
Environmental Protection Agency Matter Concerning Citronelle and Other Fields
The Company has entered into a series of tolling agreements (effective through May 30, 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 have 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 ongoing discussions with the EPA, the Company currently anticipates that in the coming 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. Based upon these discussions, the Company expects that such civil penalty will not be material to the Company’s business or financial condition.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information and Holders of Record
Denbury’s common stock is listed on the New York Stock Exchange under the symbol “DNR.” As of January 31, 2019, based on information from the Company’s transfer agent, Broadridge Stock Transfer Agent, the number of holders of record of Denbury’s common stock was 1,411.
We have not paid dividends on our common stock since the fourth quarter of 2015 and have no current plans to resume common stock dividends. Our Bank Credit Agreement and senior secured second lien and senior subordinated note indentures require us to meet certain financial covenants at the time dividend payments are made. For further discussion, see Note 6, Long-Term Debt, to the Consolidated Financial Statements.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
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
Shares purchased during the fourth 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 shares.
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.
The following Performance Graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filings under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filings.
The following graph illustrates changes over the five-year period ended December 31, 2018, in cumulative total stockholder return on our common stock as measured against the cumulative total return of the S&P 500 Index and the Dow Jones U.S. Exploration and Production Index. The graph tracks the performance of a $100 investment in our common stock and in each index (with the reinvestment of all dividends for the index securities) from December 31, 2013, to December 31, 2018.
Includes pre-tax impairments of assets of $810.9 million and $6.2 billion for the years ended December 31, 2016 and 2015, respectively, and an accelerated depreciation charge of $591.0 million related to the Riley Ridge gas processing facility and related assets for the year ended December 31, 2016.
In September 2015, in light of the low oil price environment and our desire to maintain our financial strength and flexibility, the Company’s Board of Directors suspended our quarterly cash dividend.
Reflects the adoption of Financial Accounting Standards Board Accounting Standards Update (“ASU”) 2016-18, Statement of Cash Flows (“ASU 2016-18”), whereby changes in restricted cash are now included in the consolidated statements of cash flows. We adopted ASU 2016-18 effective January 1, 2018, which has been applied retrospectively to all periods presented.
Lease operating expenses reported in this table include certain special items comprised of (1) lease operating expenses and related insurance recoveries recorded to remediate an area of Delhi Field in 2014 and 2015, (2) a reimbursement for a retroactive utility rate adjustment in 2015, and (3) other insurance recoveries in 2015. If these special items are excluded, lease operating expenses would have totaled $528.8 million and $654.7 million for the years ended December 31, 2015 and 2014, respectively, and lease operating expenses per BOE would have averaged $19.88 and $24.10 for the years ended December 31, 2015 and 2014, respectively.
Depletion, depreciation, and amortization during the year ended December 31, 2016 includes an accelerated depreciation charge of $591.0 million, or $25.23 per BOE, associated with the Riley Ridge gas processing facility and related assets.
Estimated proved reserves as of December 31, 2015, reflect negative reserve revisions of approximately 126 MMBOE (29%) in 2015 due to declines in the average first-day-of-the-month NYMEX oil price used to estimate reserves from $94.99 per Bbl at December 31, 2014, to $50.28 per Bbl at December 31, 2015. In addition, the average first-day-of-the-month NYMEX natural gas price used to estimate reserves declined from $4.30 per MMBtu at December 31, 2014, to $2.63 per MMBtu at December 31, 2015.
Proved CO2 reserves in the Gulf Coast region consist of reserves from our reservoirs at Jackson Dome and are presented on a gross or 8/8ths working interest basis, of which our net revenue interest was approximately 4.0 Tcf, 4.1 Tcf, 4.2 Tcf, 4.4 Tcf and 4.5 Tcf at December 31, 2018, 2017, 2016, 2015 and 2014, respectively, and include reserves dedicated to volumetric production payments of 3.1 Bcf, 7.6 Bcf, 12.3 Bcf, 25.3 Bcf and 9.3 Bcf at December 31, 2018, 2017, 2016, 2015 and 2014, respectively (see Supplemental CO2 Disclosures (Unaudited) to the Consolidated Financial Statements).
Proved CO2 reserves in the Rocky Mountain region consist of our overriding royalty interest in LaBarge Field and at year-end 2014 our reserves at Riley Ridge (presented on a gross (8/8ths) basis), of which our net revenue interest was approximately 1.2 Tcf, 1.2 Tcf, 1.2 Tcf, 1.2 Tcf and 2.6 Tcf at December 31, 2018, 2017, 2016, 2015 and 2014, respectively. As of December 31, 2015, Riley Ridge CO2 and helium reserves were reclassified and are no longer considered proved reserves primarily as a result of the decline in average first-day-of-the-month natural gas prices utilized in preparing our December 31, 2015 reserve report.