10-K 1 dnr-20171231x10k.htm FORM 10-K Document


 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

2017 FORM 10-K
(Mark One)
þ   Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2017
OR

o   Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from _________ to________

Commission file number   1-12935
logo.jpg
DENBURY RESOURCES INC.
(Exact name of Registrant as specified in its charter)
Delaware
 
20-0467835
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
 
 
 
5320 Legacy Drive,
Plano, TX
 
 
75024
(Address of principal executive offices)
 
(Zip Code)
Registrant’s telephone number, including area code:
 
(972) 673-2000

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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ   No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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 $603,083,628.

The number of shares outstanding of the registrant’s Common Stock as of January 31, 2018, was 401,918,775.
DOCUMENTS INCORPORATED BY REFERENCE
Document:
 
Incorporated as to:
1. Notice and Proxy Statement for the Annual Meeting of Stockholders to be held May 23, 2018.
 
1.  Part III, Items 10, 11, 12, 13, 14

 




Denbury Resources Inc.

2017 Annual Report on Form 10-K
 Table of Contents 
 
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


2



Denbury Resources Inc.

Glossary and Selected Abbreviations
Bbl
One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.
 
 
Bbls/d
Barrels of oil or other liquid hydrocarbons produced per day.
 
 
Bcf
One billion cubic feet of natural gas or CO2.
 
 
BOE
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.
 
 
BOE/d
BOEs produced per day.
 
 
Btu
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).
 
 
CO2
Carbon dioxide.
 
 
EOR
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.
 
 
GAAP
Accounting principles generally accepted in the United States of America.
 
 
MBbls
One thousand barrels of crude oil or other liquid hydrocarbons.
 
 
MBOE
One thousand BOEs.
 
 
Mcf
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.
 
 
Mcf/d
One thousand cubic feet of natural gas or CO2 per day.
 
 
MMBbls
One million barrels of crude oil or other liquid hydrocarbons.
 
 
MMBOE
One million BOEs.
 
 
MMBtu
One million Btus.
 
 
MMcf
One million cubic feet of natural gas or CO2.
 
 
MMcf/d
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.
 
 
NYMEX
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.
 
 
Probable Reserves*
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.
 
 


3



Denbury Resources Inc.

Proved Reserves*
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.
 
 
PV-10 Value
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 footnote 3 to the table included in Item 1, Estimated Net Quantities of Proved Oil and Natural Gas Reserves and Present Value of Estimated Future Net Revenues – Oil and Natural Gas Reserve Estimates.

 
 
Tcf
One trillion cubic feet of natural gas or CO2.
 
 
Tertiary Recovery
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:
http://www.ecfr.gov/cgi-bin/text-idx?SID=2d916841db86d079fa060fa63b08d34e&mc=true&node=se17.3.210_14_610&rgn=div8.



4


Denbury Resources Inc.

PART I

Item 1. Business and Properties

GENERAL

Denbury Resources Inc., a Delaware corporation, is an independent oil and natural gas company with 259.7 MMBOE of estimated proved oil and natural gas reserves as of December 31, 2017, 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, 2017, we had 879 employees, 530 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 public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains a website, http://www.sec.gov, which contains 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.

2017 BUSINESS DEVELOPMENTS

Oil prices generally constitute the single largest variable in our operating results. Although NYMEX oil prices hit a three-year peak of $66 in January 2018, over the last few years we have experienced a period of lower oil prices during which NYMEX oil prices have generally averaged in the $40 to $50 per Bbl range, which is roughly 50% lower than the price range over the 2011 through 2014 period. As a result of the lower oil price environment and its impact on our business, our focus has primarily been on preservation of cash and liquidity, together with cost reductions and debt management, rather than concentration on expansion and growth. Our 2017 key accomplishments and business developments included the following:

Generated average total production of 60,298 BOE/d in 2017, and although a decline of 4% from continuing production in 2016, we successfully arrested the declines in our production that have been ongoing since the end of 2014 with quarter-to-quarter production increases in the second half of 2017.

Successfully and safely managed the impacts of Hurricane Harvey, limiting our downtime and incremental costs to a full-year production impact of approximately 500 BOE/d and incremental lease operating expenses of approximately $4 million.


5


Denbury Resources Inc.


Completed our first successful exploitation well at Mission Canyon in the Cedar Creek Anticline with a gross 30-day initial production rate of 1,050 Bbls/d.

Increased proved reserves at December 31, 2017 to 259.7 MMBOE, from 254.5 MMBOE at December 31, 2016, representing a 127% replacement of 2017 annual production.
 
Generated $267.1 million of cash flow from operations in 2017, an annual increase of 22%, and greater than our incurred development capital expenditures in 2017 of $240.8 million.

Reduced general and administrative expenses to $101.8 million, a 7% reduction from 2016 and a 36% reduction from 2014, reflective of our reductions in personnel and our efforts to reduce costs during the oil price downturn.

Completed acquisitions of non-operated working interests in West Yellow Creek Field in Mississippi and Salt Creek Field in Wyoming, replacing a significant portion of our current year production through the addition of proved tertiary oil reserves totaling approximately 10.7 MMBbls.

Completed a series of debt exchanges in December 2017 and early January 2018, resulting in a net reduction of our debt principal balance of $184.4 million, which debt reduction could increase to a reduction of up to $329 million, assuming the new convertible notes issued in those exchanges fully convert into shares of common stock.

Modified certain of our financial performance covenants through the remaining term of the Bank Credit Agreement to provide more flexibility in managing our balance sheet, credit extended by our lenders, and continuing compliance with financial performance covenants. In addition, maintained the $1.05 billion borrowing base under our senior secured bank credit facility, providing us with significant liquidity.

2018 BUSINESS OUTLOOK

We remain diligent in determining our capital budgets in a manner that allows us to maximize value while meeting one of our key objectives of spending within cash flow. For 2018, we have initially budgeted our development capital spending at $300 million to $325 million, excluding capitalized interest and acquisitions, an increase of roughly 30% over 2017 actual capital spending levels. We utilized a NYMEX oil price estimate of $55 per Bbl in developing our 2018 budget, which based on our current projections would generate a level of cash flow that would fully fund our development capital spending plans, with any potential shortfall covered by incremental borrowings on our senior secured bank credit facility, under which we had more than $500 million of availability as of December 31, 2017. With this increased capital spending level, we currently anticipate 2018 average daily production to average between 60,000 and 64,000 BOE/d, from our 2017 average production rate of 60,298 BOE/d.

Our capital spending during 2018 will continue to focus primarily on the continued development of our current tertiary floods, while also increasing our focus on execution of exploitation projects within our existing fields. Planned development activities presented in the discussions that follow may be delayed or modified during the course of 2018 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 through extension of the maturity of our bank credit facility and 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.

In addition to the Company’s 2018 development plans, the Company is currently engaged in two asset sale processes that could be completed in 2018. In mid-2017, we began actively marketing for sale certain non-productive surface acreage in the Houston area, targeted to receive bids during the second quarter of 2018. In late-February 2018, we initiated a sales process of our mature EOR properties located in Mississippi and Louisiana (discussed under Oil and Natural Gas Operations – Tertiary Oil Properties – Mature properties below), and Citronelle Field located in Alabama as part of our overall portfolio management. These fields produced an average of approximately 7,600 BOE/d during the fourth quarter of 2017. In aggregate, these fields accounted for 13% of our total 2017 production and approximately 7% of our year-end proved reserves.  The timing and outcome of the sales process cannot be predicted at this time.



6


Denbury Resources Inc.

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, 2017, 2016 and 2015 (see the summary of D&M’s report as of December 31, 2017, 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.



7


Denbury Resources Inc.

The following table provides estimated proved reserve information prepared by D&M as of December 31, 2017, 2016 and 2015, as well as PV-10 Values and Standardized Measures for each period. During 2017, total proved reserves increased by 27.3 MMBOE on a gross basis, more than replacing 2017 production, or a 5.3 MMBOE net increase after 2017 production. The increase was primarily due to 14.8 MMBOE of positive revisions of previous estimates associated with changes in commodity prices, operating costs and performance, and 10.6 MMBOE added by property acquisitions during the year. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and their values, including many factors beyond our control.  See also Oil and Natural Gas Operations Field Summary Table, Item 1A, Risk Factors – Estimating our reserves, production and future net cash flows is difficult to do with any certainty, and Supplemental Oil and Natural Gas Disclosures (Unaudited) to the Consolidated Financial Statements for further discussion of reserve inputs and changes between periods.
 
December 31,
 
2017
 
2016
 
2015
Estimated proved reserves
 
 
 
 
 
Oil (MBbls)
252,625

 
247,103

 
282,250

Natural gas (MMcf)
42,721

 
44,315

 
38,305

Oil equivalent (MBOE)
259,745

 
254,489

 
288,634

Reserve volumes categories
 
 
 
 
 
Proved developed producing
 
 
 
 
 
Oil (MBbls)
189,166

 
170,082

 
190,422

Natural gas (MMcf)
38,184

 
40,167

 
36,150

Oil equivalent (MBOE)
195,530

 
176,777

 
196,447

Proved developed non-producing
 
 
 
 
 
Oil (MBbls)
33,365

 
31,837

 
32,638

Natural gas (MMcf)
4,251

 
3,788

 
1,801

Oil equivalent (MBOE)
34,073

 
32,468

 
32,938

Proved undeveloped
 
 
 
 
 
Oil (MBbls)
30,094

 
45,184

 
59,190

Natural gas (MMcf)
286

 
360

 
354

Oil equivalent (MBOE)
30,142

 
45,244

 
59,249

Percentage of total MBOE
 
 
 
 
 
Proved developed producing
75
%
 
69
%
 
68
%
Proved developed non-producing
13
%
 
13
%
 
11
%
Proved undeveloped
12
%
 
18
%
 
21
%
Representative oil and natural gas prices (1)
 
 
 
 
 
Oil (NYMEX price per Bbl)
$
51.34

 
$
42.75

 
$
50.28

Natural gas (Henry Hub price per MMBtu)
2.98

 
2.55

 
2.63

Present values (in thousands) (2)
 
 
 
 
 
Discounted estimated future net cash flows before income taxes (PV-10 Value) (3)
$
2,533,798

 
$
1,541,684

 
$
2,318,555

Standardized measure of discounted estimated future net cash flows after income taxes (“Standardized Measure”)
$
2,232,429

 
$
1,399,217

 
$
1,890,124


(1)
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.

(2)
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


8


Denbury Resources Inc.

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 $2.25 per Bbl below representative NYMEX oil prices as of December 31, 2017, compared to $3.39 per Bbl below NYMEX oil prices as of December 31, 2016, and $2.17 per Bbl below NYMEX oil prices as of December 31, 2015.

(3)
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.  The difference between these two amounts, the discounted estimated future income tax, was $301.4 million at December 31, 2017; $142.5 million at December 31, 2016; and $428.4 million at December 31, 2015.  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 Glossary and Selected Abbreviations for the definition of “PV-10 Value” and see Supplemental Oil and Natural Gas Disclosures (Unaudited) to the Consolidated Financial Statements for additional disclosures about the Standardized Measure.

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, 2017, our estimated proved undeveloped reserves totaled approximately 30.1 MMBOE, or approximately 12% of our estimated total proved reserves, a decline of 15.1 MMBOE from December 31, 2016 levels for these reserves, which changes are discussed below.  Approximately 86% (26.0 MMBOE) of our proved undeveloped oil reserves relate to our CO2 tertiary operations.  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, 2017, 19.1 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 2017, we spent approximately $50 million to convert 19.2 MMBOE of proved undeveloped reserves to proved developed reserves, primarily related to continued tertiary development activities at Hastings and Bell Creek fields. Other changes in proved undeveloped reserves during 2017 included adding an additional 2.4 MMBOE primarily related to our tertiary operations at Hastings Field and non-tertiary operations at Cedar Creek Anticline (“CCA”); improved recovery additions of 1.2 MMBOE related to our non-operated working interest at West Yellow Creek Field, acquired in March 2017; and recognizing other net additions of proved undeveloped reserve revisions of 0.5 MMBOE, primarily the result of reserves that were determined to be economic based on 2017 average oil and natural gas prices used in estimating our proved reserves.

During 2017, we provided oil and natural gas reserve estimates for 2016 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, 2016.

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


9


Denbury Resources Inc.

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 33 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 33 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.



10


Denbury Resources Inc.

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, 2017, and average daily production for 2017, 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, 2017 (1)
2017 Average Daily Production
 
 
 
Oil
(MBbls)
 
Natural Gas
(MMcf)
 
MBOEs
 
% of Company Total
MBOEs
 
Oil
(Bbls/d)
 
Natural Gas
(Mcf/d)
 
Average 2017 NRI
Tertiary oil and gas properties
 
 
 
 
 
 
 
 
 
 
 
 
 
Gulf Coast region
 
 
 
 
 
 
 
 
 
 
 
 
 
Mature properties (2)
15,121

 

 
15,121

 
5.8
%
 
7,629

 

 
74.5
%
Delhi
18,205

 

 
18,205

 
7.0
%
 
4,869

 

 
58.4
%
Hastings
33,538

 

 
33,538

 
12.9
%
 
4,830

 

 
80.0
%
Heidelberg
24,162

 

 
24,162

 
9.3
%
 
4,851

 

 
81.4
%
Oyster Bayou
15,148

 

 
15,148

 
5.8
%
 
5,007

 

 
87.0
%
Tinsley
19,313

 

 
19,313

 
7.5
%
 
6,430

 

 
81.8
%
West Yellow Creek
1,936

 

 
1,936

 
0.8
%
 

 

 
44.0
%
Total Gulf Coast region
127,423

 

 
127,423

 
49.1
%
 
33,616

 

 
76.2
%
Rocky Mountain region
 
 
 
 
 
 
 
 
 
 
 
 
 
Bell Creek
17,263

 

 
17,263

 
6.6
%
 
3,313

 

 
84.7
%
Salt Creek
8,755

 

 
8,755

 
3.4
%
 
1,115

 

 
29.5
%
Total Rocky Mountain region
26,018

 

 
26,018

 
10.0
%
 
4,428

 

 
57.8
%
Total tertiary properties
153,441

 

 
153,441

 
59.1
%
 
38,044

 

 
73.5
%
Non-tertiary oil and gas properties
 
 
 
 
 
 
 
 
 
 
 
 
 
Gulf Coast region
 
 
 
 
 
 
 
 
 
 
 
 
 
Texas
13,846

 
7,876

 
15,159

 
5.9
%
 
4,114

 
2,279

 
80.5
%
Mississippi and other
4,075

 
8,836

 
5,547

 
2.1
%
 
939

 
3,185

 
20.1
%
Total Gulf Coast region
17,921

 
16,712

 
20,706

 
8.0
%
 
5,053

 
5,464

 
50.8
%
Rocky Mountain region
 
 
 
 
 
 
 
 
 
 
 
 
 
Cedar Creek Anticline (3)
79,281

 
19,118

 
82,467

 
31.7
%
 
14,418

 
2,017

 
78.7
%
Other
1,982

 
6,891

 
3,131

 
1.2
%
 
895

 
3,848

 
59.2
%
Total Rocky Mountain region
81,263

 
26,009

 
85,598

 
32.9
%
 
15,313

 
5,865

 
76.9
%
Total non-tertiary properties
99,184

 
42,721

 
106,304

 
40.9
%
 
20,366

 
11,329

 
67.6
%
Company Total
252,625

 
42,721

 
259,745

 
100.0
%
 
58,410

 
11,329

 
71.3
%

(1)
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 2017, which were $51.34 per Bbl for crude oil and $2.98 per MMBtu for natural gas.

(2)
Mature properties include Brookhaven, Cranfield, Eucutta, Little Creek, Mallalieu, Martinville, McComb and Soso fields in Mississippi and Lockhart Crossing Field in Louisiana.

(3)
The Cedar Creek Anticline consists of a series of 14 different operating areas.

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


11


Denbury Resources Inc.

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) 59% of our proved reserves at December 31, 2017 are proved tertiary oil reserves; (2) 63% of our 2017 total production was related to tertiary oil operations (on a BOE basis); and (3) 71% of our 2017 capital expenditures (excluding acquisitions) were related to our tertiary oil operations.  At year-end 2017, the proved oil reserves in our tertiary recovery oil fields had an estimated PV-10 Value of approximately $1.7 billion, or 66% 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 sources in 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 5.2 Tcf as of December 31, 2017.  The proved CO2 reserve estimates are based on a gross (8/8ths) basis, of which our net revenue interest is approximately 4.1 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.



12


Denbury Resources Inc.

In addition to our proved reserves, we estimate that we have 1.0 Tcf 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 87% of our average daily CO2 produced from Jackson Dome or captured from industrial sources in 2017 was used in our tertiary recovery operations, compared to 85% in 2016 and 88% in 2015, with the balance delivered to third-party industrial users. During 2017, we used an average of 493 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 currently supply approximately 63 MMcf/d of CO2 to our EOR operations.  Additionally, we are in ongoing discussions with other parties who have 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 over 750 miles of CO2 pipelines, and as of December 31, 2017, we have access to over 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, 2017

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, Lockhart Crossing, Mallalieu, Martinville, McComb and Soso fields).  These fields accounted for 20% of our total 2017 CO2 EOR production and approximately 6% of our year-end proved reserves.  These fields have been producing for some time, and their production is generally declining.

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 and began delivering CO2 to the field in the fourth quarter of 2009 via the Delta Pipeline, which runs from Tinsley Field to Delhi Field. First tertiary production occurred at Delhi Field in the first quarter of 2010.  Production from Delhi Field in the fourth quarter of 2017 averaged 4,906 Bbls/d, up from 4,387 Bbls/d in the fourth quarter of 2016.  During late 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


13


Denbury Resources Inc.

methane to power the plant and reduce field operating expenses. Our 2018 development plans are primarily related to continued phase development and infill drilling.

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 the fourth quarter of 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 the first quarter of 2012, and we booked initial proved tertiary reserves for the West Hastings Unit in 2012.  During the fourth quarter of 2017, tertiary production from Hastings Field averaged 5,747 Bbls/d, compared to 4,552 Bbls/d in the fourth quarter of 2016 with the increase in production mainly attributable to the 2017 Fault Block B/C redevelopment project.

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 the fourth quarter of 2008.  Our first tertiary oil production occurred in the second quarter of 2009, and we began flooding the Christmas and Tuscaloosa zones in 2013 and 2014, respectively.  During the fourth quarter of 2017, tertiary production at Heidelberg Field averaged 4,751 Bbls/d, compared to 4,924 Bbls/d in the fourth quarter of 2016.  Our future plans for Heidelberg Field include continued development of the East and West Heidelberg Units, including an expansion of our Tuscaloosa development and Christmas zone and adjustments to our CO2 floods of existing zones to better direct the CO2 through the zones and optimize oil recovery from the field, the ultimate timing of which will depend upon future oil prices or revised development plans. Our 2018 development plans are primarily related to conformance work or behind pipe opportunities, and facilities improvements.

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 the second quarter of 2010, commenced tertiary production in the fourth quarter of 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 2017, tertiary production at Oyster Bayou Field averaged 4,868 Bbls/d, compared to 4,988 Bbls/d in the fourth quarter of 2016. Production from Oyster Bayou Field is believed to have peaked during 2015; however, production during 2018 is currently expected to increase slightly from 2017 levels due to recycle facility expansion in late 2017 and early 2018.

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 the second quarter of 2008 and substantially completed development of the Woodruff formation during 2014.  During the fourth quarter of 2017, tertiary oil production from the field averaged 6,241 Bbls/d, compared to 6,786 Bbls/d in the fourth quarter of 2016. Although production from Tinsley Field is believed to have peaked in 2015, we continue to evaluate future potential investment opportunities in this field. Our 2018 development plans are primarily related to improvements at the recycle facility. In addition to our CO2 EOR flood at Tinsley Field, during 2018 we plan to evaluate certain exploitation opportunities that exist across the field, specifically opportunities in the Perry Sand and Cotton Valley horizons underlying the existing CO2 EOR flood.

West Yellow Creek Field. We acquired our non-operated working interest in West Yellow Creek Field in Mississippi in March 2017 for approximately $16 million, a field in which the operator has invested significant capital converting the field to a CO2 EOR flood. As of December 31, 2017, we booked initial proved tertiary oil reserves of approximately 1.9 MMBbls, net to our interest, with first tertiary production expected from the field in early 2018. Development of the field is ongoing, with 2018 development plans including continued tertiary development of the initial formation within the field, and development of an additional formation in future periods. Based upon our current arrangement with the operator of the field, we sell CO2 to the operator for a fee.

Future Tertiary Properties with No Tertiary Production or Proved Tertiary Reserves at December 31, 2017

Webster Field. We acquired our interest in Webster Field in 2012. The field is located in Texas, approximately eight miles northeast of our Hastings Field which we are currently flooding with CO2. At December 31, 2017, Webster Field had estimated


14


Denbury Resources Inc.

proved non-tertiary reserves of approximately 2.1 MMBOE, net to our interest.  During the fourth quarter of 2017, non-tertiary production at Webster Field averaged 834 BOE/d, compared to 828 BOE/d in the fourth quarter of 2016.  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 CO2 injections at Webster Field is primarily dependent upon capital availability 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 7.3 MMBOE at December 31, 2017, net to our interest, all of which are proved developed.  During the fourth quarter of 2017, production at Conroe Field averaged 2,140 BOE/d, compared to 2,281 BOE/d in the fourth quarter of 2016.

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, future oil prices and pipeline construction.

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 4.1 MMBOE at December 31, 2017, net to our interest, all of which are proved developed.  During the fourth quarter of 2017, non-tertiary production at Thompson Field averaged 987 BOE/d net to our interest, compared to 1,344 BOE/d in the fourth quarter of 2016.  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 CO2 injections at Thompson Field is primarily dependent upon capital availability 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.

During 2017, we received an average of approximately 73 MMcf/d of CO2 from ExxonMobil’s Shute Creek gas processing plant at LaBarge Field. Based on current capacity, and subject to availability of CO2, we currently expect that we could receive up to 115 MMcf/d of CO2 by 2021 from such plant. We pay ExxonMobil a fee to process and deliver the CO2, which we use in our Rocky Mountain region CO2 floods. As of December 31, 2017, our interest in LaBarge Field consisted of approximately 1.2 Tcf of proved CO2 reserves.

Other Rocky Mountain CO2 Sources.  While LaBarge Field is a potential source of CO2 for flooding our fields in the Rocky Mountain region, we have formed alternative plans to develop our future CO2 EOR floods, which CO2 volumes we currently anticipate could be supplied through existing CO2 sources. We began purchasing and receiving CO2 from the ConocoPhillips-operated Lost Cabin gas plant in central Wyoming in the first quarter of 2013, under a contract that provides us as much as 50 MMcf/d of CO2 for use in our Rocky Mountain region CO2 floods.

Greencore Pipeline.  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 initial 232-mile section of the Greencore Pipeline begins at the ConocoPhillips-operated Lost Cabin gas plant in Wyoming and terminates at Bell Creek Field in Montana.  We completed construction of this section of the pipeline in the fourth quarter of 2012 and received our first CO2 deliveries from the ConocoPhillips-operated Lost Cabin gas plant during the first quarter of 2013.  During the first quarter of 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.


15


Denbury Resources Inc.


Tertiary Properties with Tertiary Production and Proved Tertiary Reserves at December 31, 2017

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 2017 averaged 3,571 Bbls/d of oil, compared to 3,269 Bbls/d in the fourth quarter of 2016.  Our 2018 development plans are primarily related to phase six expansion of the flood. We expect production from this field will continue to increase during 2018.

Salt Creek Field.  We acquired our 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 2017 averaged 2,172 Bbls/d of oil and is expected to increase over the next several years with minimal capital spending.

Future Tertiary Properties with No Tertiary Production or Proved Tertiary Reserves at December 31, 2017

Cedar Creek Anticline.  CCA is the largest potential EOR property that we own and currently our largest producing property, contributing approximately 24% of our 2017 total production. 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, 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 the first quarter of 2013 for $1.0 billion, adding 42.2 MMBOE of incremental proved reserves at that date. Production from CCA, net to our interest, averaged 14,302 BOE/d during the fourth quarter of 2017, compared to production during the fourth quarter of 2016 of 15,186 BOE/d. The non-tertiary proved reserves associated with CCA were 82.5 MMBOE, net to our interest, as of December 31, 2017. Our 2018 development plans for CCA primarily include exploitation and development of six additional wells in the Mission Canyon formation and waterflood infill projects. Our first Mission Canyon exploitation well was drilled during the fourth quarter of 2017 in the Pennel Field in the Cedar Creek Anticline, and began producing on December 30, 2017. Average gross production over the initial 30-day production period was 1,050 Bbls/d of oil.

CCA is located approximately 110 miles north of Bell Creek Field, and we currently expect to ultimately connect this field to our Greencore Pipeline.  Our current plan for initiating a CO2 flood at CCA is several years from now, the timing of which may change depending on future oil prices, pipeline permitting and sources and availability of CO2. We are targeting an investment decision in the first half of 2018 regarding a path forward for CO2 flooding at CCA.

Grieve Field. In the second quarter of 2011, we entered into a farm-in agreement, under which we obtained a 65% working interest in Grieve Field, located in Natrona County, Wyoming, in exchange for developing the Grieve Field CO2 flood. We completed a three-mile CO2 pipeline to deliver CO2 from an existing CO2 pipeline to Grieve Field in the fourth quarter of 2012. During the third quarter of 2016, the Company and its joint venture partner in Grieve Field reached an agreement to revise the joint venture arrangement between the parties for the continued development of the field. The revised agreement provides for our partner to fund up to $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. As a result of this agreement, our working interest in the field was reduced from 65% to 51%. This arrangement accelerated the remaining development of the facility and fieldwork, and we currently anticipate first tertiary production in mid-2018.

Hartzog Draw Field. We acquired our interest in Hartzog Draw Field in the fourth quarter of 2012. 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 3.1 MMBOE at December 31, 2017, net to our interest, 1.1 MMBOE of which relate to the natural gas producing Big George coal zone.  During the fourth quarter of 2017, non-tertiary production averaged 1,518 BOE/d, compared to 1,665 BOE/d in the fourth quarter of 2016. After successfully completing 5 wells in Hartzog Draw Field in 2014, we suspended the non-tertiary development of Hartzog Draw Field in light of the oil price environment. Activity around this field has continued to increase over the past year, with several operators testing various formations for potential development. In 2018, we currently have plans to drill one well testing the deeper formations that exist on our acreage. 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 future oil prices.



16


Denbury Resources Inc.

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 do 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 1,875 BOE/d during the fourth quarter of 2017, compared to 2,035 BOE/d during the fourth quarter of 2016.
 
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, 2017:
 
Developed
 
Undeveloped
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Gulf Coast region
251,770

 
201,579

 
285,682

 
16,648

 
537,452

 
218,227

Rocky Mountain region
360,213

 
316,010

 
169,908

 
58,041

 
530,121

 
374,051

Total
611,983

 
517,589

 
455,590

 
74,689

 
1,067,573

 
592,278


The percentage of our net undeveloped acreage that is subject to expiration over the next three years, if not renewed, is approximately 13% in 2018, 31% in 2019 and 3% in 2020.

Productive Wells

The following table sets forth our gross and net productive oil and natural gas wells as of December 31, 2017:
 
Producing Oil Wells
 
Producing Natural Gas Wells
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Operated wells
 
 
 
 
 
 
 
 
 
 
 
Gulf Coast region
1,276

 
1,187

 
155

 
143

 
1,431

 
1,330

Rocky Mountain region
938

 
902

 
279

 
180

 
1,217

 
1,082

Total
2,214

 
2,089

 
434

 
323

 
2,648

 
2,412

Non-operated wells
 

 
 

 
 

 
 

 
 

 
 

Gulf Coast region
31

 
12

 

 

 
31

 
12

Rocky Mountain region
573

 
126

 
5

 
2

 
578

 
128

Total
604

 
138

 
5

 
2

 
609

 
140

Total wells
 

 
 

 
 

 
 

 
 

 
 

Gulf Coast region
1,307

 
1,199

 
155

 
143

 
1,462

 
1,342

Rocky Mountain region
1,511

 
1,028

 
284

 
182

 
1,795

 
1,210

Total
2,818

 
2,227

 
439

 
325

 
3,257

 
2,552




17


Denbury Resources Inc.

Drilling Activity

The following table sets forth the results of our drilling activities over the last three years.  As of December 31, 2017, we did not have any wells in progress.
 
Year Ended December 31,
 
2017
 
2016
 
2015
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Exploratory wells (1)
 
 
 
 
 
 
 
 
 
 
 
Productive (2)

 

 

 

 

 

Non-productive (3)

 

 

 

 

 

Development wells (1)
 

 
 

 
 

 
 

 
 

 
 

Productive (2)
2

 
2

 

 

 
16

 
15

Non-productive (3)(4)

 

 

 

 

 

Total
2

 
2

 

 

 
16

 
15


(1)
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.

(2)
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.

(3)
A non-productive well is an exploratory or development well that is not a productive well.

(4)
During 2017, 2016 and 2015, an additional 3, 1 and 6 wells, respectively, were drilled for water or CO2 injection purposes.



18


Denbury Resources Inc.

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, 2017, 2016 and 2015:
 
Year Ended December 31,
 
2017
 
2016
 
2015
Net sales volume
 
 
 
 
 
Gulf Coast region
 
 
 
 
 
Oil (MBbls)
14,114

 
14,772

 
16,783

Natural gas (MMcf)
1,995

 
3,274

 
5,187

Total Gulf Coast region (MBOE)
14,447

 
15,318

 
17,648

Rocky Mountain region
 

 
 

 
 

Oil (MBbls)
7,205

 
7,715

 
8,462

Natural gas (MMcf)
2,141

 
2,354

 
2,906

Total Rocky Mountain region (MBOE)
7,562

 
8,107

 
8,946

Total Company (MBOE)
22,009

 
23,425

 
26,594

 
 
 
 
 
 
Average sales prices – excluding impact of derivative settlements
 

 
 

 
 

Gulf Coast region
 

 
 

 
 

Oil (per Bbl)
$
51.19

 
$
41.99

 
$
49.34

Natural gas (per Mcf)
2.98

 
2.04

 
2.48

 
 
 
 
 
 
Rocky Mountain region
 

 
 

 
 

Oil (per Bbl)
$
49.58

 
$
39.44

 
$
43.25

Natural gas (per Mcf)
1.88

 
1.90

 
2.11

 
 
 
 
 
 
Total Company
 

 
 

 
 

Oil (per Bbl)
$
50.64

 
$
41.12

 
$
47.30

Natural gas (per Mcf)
2.41

 
1.98

 
2.35

 
 
 
 
 
 
Average production cost (per BOE sold) (1)
 

 
 

 
 

Gulf Coast region (2)
$
20.48

 
$
18.42

 
$
19.51

Rocky Mountain region
20.09

 
16.38

 
19.07

Total Company (2)
20.35

 
17.71

 
19.37


(1)
Excludes oil and natural gas ad valorem and production taxes.

(2)
Production costs include certain special items, comprised of a reimbursement for a retroactive utility rate adjustment and other insurance recoveries. If these amounts were excluded, average production cost per BOE for the Gulf Coast region would have totaled $20.29 for the year ended December 31, 2015 and average production cost per BOE for the Company as a whole would have totaled $19.88 for the year ended December 31, 2015.

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.



19


Denbury Resources Inc.

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 years ended December 31, 2017, 2016 and 2015, two purchasers accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP (22%, 20% and 15% in 2017, 2016 and 2015, respectively) and Marathon Petroleum Company (10%, 14% and 28% in 2017, 2016 and 2015, 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, 2017, 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.

Oil Marketing

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 2017, we sold approximately 65% 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 differential (on a trade-month basis) was a positive $2.85 per Bbl during 2017, compared to a positive $1.70 per Bbl during 2016 and a positive $3.72 per Bbl in 2015. During 2017, our light sweet crude oil production in the Gulf Coast region, on average, sold for $0.26 per Bbl above NYMEX, compared to $1.38 per Bbl below NYMEX in 2016 and $0.56 per Bbl over NYMEX in 2015.  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, 2017, the discount for our oil production in the Rocky Mountain region averaged $1.39 per Bbl, compared to $3.97 per Bbl during 2016 and $5.60 per Bbl during 2015.

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


20


Denbury Resources Inc.

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 recent 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 Natural Gas and Oil 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.



21


Denbury Resources Inc.

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. A federal appeals courts in July 2017 rejected an attempt by the EPA to delay implementation of the rule, and the EPA has indicated that it may conduct a rulemaking to revise or rescind the rule. 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.

Environmental Regulations

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.



22


Denbury Resources Inc.

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.

Hydraulic Fracturing

During 2017, we fracture stimulated eleven wells at Hartzog Draw and Bell Creek fields utilizing water-based fluids with no diesel fuel component. We are currently evaluating the potential to refrac additional wells at Bell Creek Field during 2018. We are familiar with the laws and regulations applicable to hydraulic fracturing operations and take steps to ensure compliance with these requirements.



23


Denbury Resources Inc.

Item 1A.  Risk Factors

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. While over the last few years we have been in a period of low oil prices, oil prices have recently increased, with NYMEX prices averaging $64 per barrel during the month of January 2018, roughly 15% higher than average WTI crude oil prices in the fourth quarter of 2017. Despite this recent increase, volatility will remain, and prices could move downward or upward on a rapid or repeated basis, which can make transactions, 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 2017 production and approximately 97% of our proved reserves at December 31, 2017. 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 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 continued or further 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 further 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, a sustained credit crisis, further drops in economic growth rates in China, regional or worldwide increases in tariffs or other trade restrictions, significant international currency fluctuations, 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 bank credit facility or cause them to restrict our borrowing base or make the terms of our 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 or otherwise seek bankruptcy protection.



24


Denbury Resources Inc.

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 has been sufficient to support our capital expenditures during 2017, future additional liquidity restrictions could negatively affect our level of capital expenditures, and thus our maintenance or growth in production and operational cash flow. 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.

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 bank credit facility, or increase the cost of any new debt financings.

Our level of indebtedness could adversely affect the level of our production activities if not materially reduced.

As of December 31, 2017, our outstanding indebtedness consisted of $475.0 million principal amount outstanding under our bank credit facility, $1.1 billion aggregate principal amount of other senior indebtedness, and $1.0 billion 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, $381.6 million principal amount of 9¼% Senior Secured Second Lien Notes due 2022 (the “2022 Senior Secured Notes”), and $84.7 million principal amount of 3½% Convertible Senior Notes due 2024. Our subordinated indebtedness consisted of $1.0 billion 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 5.36% per annum.

In January 2018, we issued an additional $74.1 million principal amount of 2022 Senior Secured Notes and $59.4 million of 5% Convertible Senior Notes due 2023 in exchange for a reduction of $174.3 million in subordinated indebtedness. As of December 31, 2017, we had a borrowing base and aggregate lender commitments of $1.05 billion under our senior secured bank credit facility and availability with respect to such commitments of $512.8 million.

The PV-10 Value of our estimated proved reserves at year-end 2017, which is based on the average first-day-of-the-month prices in 2017, was less than our outstanding indebtedness as of December 31, 2017. Our substantial 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.

Inability to meet financial performance covenants in our bank agreements may require borrowing base reductions.

Between May 2015 and May 2017, we modified certain of our financial performance covenants under our senior secured bank credit facility applicable through the remaining term of the facility to support continuing compliance with these covenants in the current oil price environment. 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 bank credit facility’s covenants. In the future, we may be required to seek further modifications of these covenants, or to further reduce our debt by, among other things, reducing our bank borrowing base, purchasing our subordinated 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 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.


25


Denbury Resources Inc.


Our bank borrowing base is adjusted semiannually in May and November of each year, 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 bank credit facility or require us to seek different forms of financing arrangements. If the outstanding debt under our 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.

Oil and natural gas development and producing operations involve various risks.

Our operations are subject to all 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
title problems.

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


26


Denbury Resources Inc.

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, 2017 reserves were $51.34 per Bbl for crude oil and $2.98 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, 2017, 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 current and 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.  As a result, obtaining rights-of-way or other means of access 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. Pipeline projects are also subject to heightened levels of scrutiny as a result of public opposition to projects like the Keystone XL and Dakota Access pipelines. This scrutiny has the potential to result in delays in permitting, enhanced and prolonged environmental review for pipeline projects, and litigation challenges to regulatory agencies’ authorizations of pipeline projects.

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 continue to be 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,


27


Denbury Resources Inc.

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 21, 2018, we have oil derivative contracts in place covering 40,500 Bbls/d for 2018, 8,500 Bbls/d for the first half of 2019 and 5,000 Bbls/d for the second half of 2019. 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 high oil and natural gas prices, we have experienced 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.



28


Denbury Resources Inc.

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.

Numerous executive, legislative and regulatory proposals affecting the oil and gas industry could be introduced by various federal and state authorities.  While it is currently anticipated that the President and Congress 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, 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, 2017, two purchasers individually accounted for 10% or more of our oil and natural gas revenues and, in the aggregate, for 32% of such revenues.  The loss of a large single purchaser could adversely impact the prices we receive or the transportation costs we incur.

Certain of our operations may be limited during certain periods due to severe weather conditions and other regulations.

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


29


Denbury Resources Inc.

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. Our operations in the coastal areas of 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.

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 2015 and 2016, we recorded full cost pool ceiling test write-downs of our oil and natural gas properties totaling $4.9 billion ($3.1 billion net of tax) and $810.9 million ($508.2 million net of tax), respectively. We did not have a ceiling test write-down during 2017. 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.

Conversion into common stock of the 3½% Convertible Senior Notes due 2024 or the 5% Convertible Senior Notes due 2023 may dilute the ownership interest of existing stockholders, and might depress the market price of our common stock.

The conversion of some or all of the 3½% Convertible Senior Notes due 2024 or the 5% Convertible Senior Notes due 2023 (see Note 5, Long-Term Debt, to the Consolidated Financial Statements) may dilute the ownership interests of existing stockholders of our common stock. Any sales in the public market of the shares of our common stock issuable upon such conversion could adversely affect prevailing market prices of our common stock. In addition, the existence of the 3½% Convertible Senior Notes due 2024 and the 5% Convertible Senior Notes due 2023 may encourage short selling by market participants because the conversion of both series of notes could be used to satisfy short positions, and anticipated conversion of both series of notes into shares of our common stock could depress the market price of our common stock.

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 11, 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. Although a single or multiple adverse rulings or settlements could possibly have a material adverse effect on our business or finances, we only accrue for losses from litigation and claims if we determine that a loss is probable and the amount can be reasonably estimated.



30


Denbury Resources Inc.

Riley Ridge Helium Supply Contract Claim

As part of our 2010 and 2011 acquisitions of the Riley Ridge Unit and associated gas processing facility that was under construction, the Company assumed a 20-year helium supply contract under which we agreed to supply the helium separated from the full well stream by operation of the gas processing facility to a third-party purchaser, APMTG Helium, LLC.  The helium supply contract provides for the delivery of a minimum contracted quantity of helium, subject to adjustment after startup of the Riley Ridge gas processing facility, with liquidated damages payable if specified quantities of helium are not supplied in accordance with the terms of the contract. The liquidated damages are specified in the contract at up to $8.0 million per contract year and are capped at an aggregate of $46.0 million over the term of the contract. As the gas processing facility has been shut-in since mid-2014, we have not been able to supply helium under the helium supply contract.  APMTG Helium, LLC filed a case in November 2014 in the Ninth Judicial District Court of Sublette County, Wyoming, claiming multiple years of liquidated damages for non-delivery of volumes of helium specified under the helium supply contract. In response, we are taking the position that our contractual obligations are excused by virtue of events that fall within the force majeure provisions in the helium supply contract. The evidentiary phase of the trial closed on November 29, 2017. The parties submitted written closing briefs to the District Court on February 23, 2018 and have agreed to submit written rebuttals to such closing briefs by March 30, 2018. Following those submissions, the case will be fully submitted for determination by the District Court. We currently expect a ruling to be made in the second or third quarter of 2018. The Company plans to continue to vigorously defend its position, but we are unable to predict at this time the outcome of this dispute.

Item 4.  Mine Safety Disclosures

Not applicable.


31


Denbury Resources Inc.

PART II

Item 5.  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Common Stock Trading Summary

The following table summarizes the high and low reported sales prices on days in which there were trades of Denbury’s common stock on the New York Stock Exchange (“NYSE”) for each quarterly period for the last two fiscal years.  As of January 31, 2018, 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 1,582.  On February 27, 2018, the last reported sale price of Denbury’s common stock, as reported on the NYSE, was $2.29 per share.
 
2017
 
2016
 
High
 
Low
 
High
 
Low
First Quarter
$
3.88

 
$
2.21

 
$
3.66

 
$
0.95

Second Quarter
2.53

 
1.30

 
4.68

 
2.01

Third Quarter
1.67

 
0.96

 
3.67

 
2.62

Fourth Quarter
2.21

 
1.07

 
4.03

 
2.39


The Company has not declared a dividend on our common stock during the two most recent fiscal years. No unregistered securities were sold by the Company during 2017.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers
Month
 
Total Number
of Shares
Purchased (1)
 
Average Price Paid per Share
 
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
 
Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
 (in millions) (2)
October 2017
 
45,148

 
$
1.26

 

 
$
210.1

November 2017
 
21,729

 
1.51

 

 
210.1

December 2017
 
7,580

 
1.67

 

 
210.1

Total
 
74,457

 
 
 

 



(1)
Shares purchased during the fourth quarter of 2017 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.

(2)
In October 2011, we commenced a common share repurchase program, which has been approved for up to an aggregate of $1.162 billion of Denbury common shares by the Company’s Board of Directors. This program has effectively been suspended and we do not anticipate repurchasing shares of our common stock as long as industry commodity pricing and general economic conditions persist. 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.



32


Denbury Resources Inc.

Share Performance Graph

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, 2017, 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, 2012, to December 31, 2017.

COMPARISON OF 5-YEAR CUMULATIVE TOTAL RETURN
dnr-201712_chartx34797a01.jpg
 
December 31,
 
2012
 
2013
 
2014
 
2015
 
2016
 
2017
Denbury Resources Inc.
$
100

 
$
101

 
$
51

 
$
13

 
$
24

 
$
14

S&P 500
100

 
132

 
151

 
153

 
171

 
208

Dow Jones U.S. Exploration & Production
100

 
132

 
118

 
90

 
112

 
113




33


Denbury Resources Inc.

Item 6. Selected Financial Data
 
 
Year Ended December 31,
In thousands, except per-share data or otherwise noted
 
2017
 
2016
 
2015
 
2014
 
2013
Consolidated Statements of Operations data
 
 
 
 
 
 
 
 
 
 
Revenues and other income
 
 
 
 
 
 
 
 
 
 
Oil, natural gas, and related product sales
 
$
1,089,666

 
$
935,751

 
$
1,213,026

 
$
2,372,473

 
$
2,466,234

Other
 
40,120

 
39,845

 
44,534

 
62,732

 
50,893

Total revenues and other income
 
$
1,129,786

 
$
975,596

 
$
1,257,560

 
$
2,435,205

 
$
2,517,127

Net income (loss) (1)
 
163,152

 
(976,177
)
 
(4,385,448
)
 
635,491

 
409,597

Net income (loss) per common share
 
 
 
 
 
 
 
 
 
 
Basic (1)
 
0.42

 
(2.61
)
 
(12.57
)
 
1.82

 
1.12

Diluted (1)
 
0.41

 
(2.61
)
 
(12.57
)
 
1.81

 
1.11

Dividends declared per common share (2)
 

 

 
0.1875

 
0.25

 

Weighted average number of common shares outstanding
 
 
 
 
 
 
 
 
 
 
Basic
 
390,928

 
373,859

 
348,802

 
348,962

 
366,659

Diluted
 
395,921

 
373,859

 
348,802

 
351,167

 
369,877

Consolidated Statements of Cash Flows data
 
 
 
 
 
 
 
 
 
 
Cash provided by (used in)
 
 
 
 
 
 
 
 
 
 
Operating activities
 
$
267,143

 
$
219,223

 
$
864,304

 
$
1,222,825

 
$
1,361,195

Investing activities
 
(357,304
)
 
(205,417
)
 
(550,185
)
 
(1,076,755
)
 
(1,275,309
)
Financing activities
 
88,613

 
(15,012
)
 
(334,460
)
 
(135,104
)
 
(172,210
)
Production (average daily)
 
 
 
 
 
 
 
 
 
 
Oil (Bbls)
 
58,410

 
61,440

 
69,165

 
70,606

 
66,286

Natural gas (Mcf)
 
11,329

 
15,378

 
22,172

 
22,955

 
23,742

BOE (6:1)
 
60,298

 
64,003

 
72,861

 
74,432

 
70,243

Unit sales prices – excluding impact of derivative settlements
 
 
 
 
 
 
 
 
 
 
Oil (per Bbl)
 
$
50.64

 
$
41.12

 
$
47.30

 
$
90.74

 
$
100.67

Natural gas (per Mcf)
 
2.41

 
1.98

 
2.35

 
4.07

 
3.53

Unit sales prices – including impact of derivative settlements
 
 
 
 
 
 
 
 
 
 
Oil (per Bbl)
 
$
48.40

 
$
44.86

 
$
67.41

 
$
90.82

 
$
100.64

Natural gas (per Mcf)
 
2.41

 
1.98

 
2.83

 
3.99

 
3.53

Costs per BOE
 
 
 
 
 
 
 
 
 
 
Lease operating expenses (3)
 
$
20.35

 
$
17.71

 
$
19.37

 
$
23.84

 
$
28.50

Taxes other than income
 
3.96

 
3.33

 
4.13

 
6.25

 
6.87

General and administrative expenses
 
4.63

 
4.69

 
5.44

 
5.83

 
5.66

Depletion, depreciation, and amortization (4)
 
9.44

 
36.12

 
19.99

 
21.83

 
19.89

Proved oil and natural gas reserves (5)
 
 
 
 
 
 
 
 
 
 
Oil (MBbls)
 
252,625

 
247,103

 
282,250

 
362,335

 
386,659

Natural gas (MMcf)
 
42,721

 
44,315

 
38,305

 
452,402

 
489,954

MBOE (6:1)
 
259,745

 
254,489

 
288,634

 
437,735

 
468,318

Proved carbon dioxide reserves
 
 
 
 
 
 
 
 
 
 
Gulf Coast region (MMcf) (6)
 
5,164,741

 
5,332,576

 
5,501,175

 
5,697,642

 
6,070,619

Rocky Mountain region (MMcf) (7)
 
1,187,787

 
1,214,428

 
1,237,603

 
3,035,286

 
3,272,428

Consolidated Balance Sheets data
 
 
 
 
 
 
 
 
 
 
Total assets
 
$
4,471,299

 
$
4,274,578

 
$
5,885,533

 
$
12,690,156

 
$
11,698,406

Total long-term liabilities
 
3,365,077

 
3,372,634

 
4,263,606

 
6,503,194

 
5,902,463

Stockholders’ equity
 
648,165

 
468,448

 
1,248,912

 
5,703,856

 
5,301,406





34


Denbury Resources Inc.

(1)
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.

(2)
In September 2015, in light of the continuing 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.

(3)
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 2013, 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, $654.7 million and $616.6 million for the years ended December 31, 2015, 2014 and 2013, respectively, and lease operating expenses per BOE would have averaged $19.88, $24.10 and $24.05 for the years ended December 31, 2015, 2014 and 2013, respectively.

(4)
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.

(5)
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.

(6)
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 4.1 Tcf, 4.2 Tcf, 4.4 Tcf, 4.5 Tcf and 4.8 Tcf at December 31, 2017, 2016, 2015, 2014 and 2013, respectively, and include reserves dedicated to volumetric production payments of 7.6 Bcf, 12.3 Bcf, 25.3 Bcf, 9.3 Bcf and 28.9 Bcf at December 31, 2017, 2016, 2015, 2014 and 2013, respectively (see Supplemental CO2 Disclosures (Unaudited) to the Consolidated Financial Statements).

(7)
Proved CO2 reserves in the Rocky Mountain region consist of our overriding royalty interest in LaBarge Field and 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, 2.6 Tcf and 2.9 Tcf at December 31, 2017, 2016, 2015, 2014 and 2013, 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.



35


Denbury Resources Inc. 
Management’s Discussion and Analysis of Financial Condition and Results of Operations


Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements and Notes thereto included in Item 8, Financial Statements and Supplementary Information.  Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with Risk Factors under Item 1A of this Form 10-K, along with Forward-Looking Information at the end of this section for information on the risks and uncertainties that could cause our actual results to be materially different from our forward-looking statements.

OVERVIEW

Denbury is an independent oil and natural gas company with operations focused in two key operating areas: the Gulf Coast and Rocky Mountain regions. Our goal is to increase the value of our properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to CO2 enhanced oil recovery operations.

Oil Price Impact on Our Business. Our financial results are significantly impacted by changes in oil prices, as 97% of our production is oil. Oil prices are highly impacted by worldwide oil supply and demand and have historically been subject to significant price changes over short periods of time, including the mid-January 2018 move of NYMEX oil prices over $66 per Bbl for the first time in over three years. Over the last few years, we have been in a period of lower oil prices during which oil prices have generally been in a range of $40-$50 per Bbl, which is roughly 50% lower than the oil price range over the 2011 through 2014 period. As a result of the lower oil price environment and its impact on our business, our focus has primarily been on preservation of cash and liquidity, together with cost reductions and debt management, rather than concentration on expansion and growth. We generated $267.1 million of cash flow from operations in 2017, an annual increase of 22%, and greater than our incurred development capital expenditures in 2017 of $240.8 million, thus preserving our liquidity. We have hedged a portion of our estimated oil production through 2019 in order to protect our current level of cash operating costs, as well as our planned 2018 capital spending. Our 2018 capital spending has been budgeted at approximately $300 million to $325 million, excluding capitalized interest and acquisitions, roughly a 30% increase over 2017 capital spending levels. We utilized a NYMEX oil price estimate of $55 per Bbl in developing our 2018 budget, which based on our current projections would generate a level of cash flow that would fully fund our development capital spending plans. With this capital spending level, we currently anticipate our 2018 production to average between 60,000 and 64,000 BOE/d.

2017 Operating Highlights. The primary drivers of our change in operating results between 2017 and 2016 were the following:

Oil and natural gas revenues increased by $153.9 million, or 16%, in 2017, principally driven by 22% higher realized commodity prices, offset in part by a 6% decrease in average daily production volumes ($56.6 million). Net realized oil price differentials improved by $1.97 per Bbl from the prior-year period.
Expenses in 2017 were significantly lower than in 2016, as in 2017 we had no ceiling test write-downs, while in 2016, we had both an $810.9 million ($508.2 million net of tax) full cost pool ceiling test write-down for our oil and natural gas properties and an accelerated depreciation charge of $591.0 million ($379.2 million net of tax) related to the Riley Ridge gas processing facility and related assets, offset to a degree by a $115.1 million gain on debt extinguishment.
Commodity derivative expense decreased by $50.4 million as a result of a $182.3 million decrease in losses from noncash fair value adjustments between the periods, largely offset by a $132.0 million decrease in derivative settlements ($47.8 million in payments on settlements during 2017 compared to $84.2 million in receipts on settlements during 2016).

During 2017, we recognized net income of $163.2 million, or $0.41 per diluted common share, compared to a net loss of $976.2 million, or $2.61 per diluted common share, during 2016. Our 2017 net income includes the effect of a one-time deferred tax benefit of $132.2 million in the fourth quarter of 2017 resulting from the reduction of the federal income tax rate from 35% to 21% as enacted by the Tax Cut and Jobs Act (the “Act”) in December 2017.

We generated $267.1 million of cash flow from operating activities during 2017, compared to $219.2 million during 2016, due primarily to a $153.9 million increase in oil and natural gas revenues and a net decrease in expenses, largely offset by a $132.0 million decline in derivative settlements.

Mission Canyon Exploitation. Denbury’s first Mission Canyon exploitation well was drilled during the fourth quarter in the Pennel Field in the Cedar Creek Anticline, and the well began production on December 30, 2017. Average gross production over the initial 30-day production period was 1,050 Bbls/d of oil, with total costs to drill and complete the well of $3.6 million.


36


Denbury Resources Inc. 
Management’s Discussion and Analysis of Financial Condition and Results of Operations


The success of the initial well de-risks additional locations, and the Company mobilized a rig in early February to begin drilling on a two-well pad, with first production from these wells expected in the second quarter. A total of six Mission Canyon wells are planned for 2018, including four development wells and two wells designed to test other Mission Canyon opportunities. The program is expected to continue beyond 2018 as the Company fully develops the play.

Debt Reduction Transactions. During December 2017, in privately negotiated transactions, institutional holders of our subordinated debt exchanged $609.8 million aggregate principal amount of our existing senior subordinated notes for $381.6 million aggregate principal amount of new 9¼% Senior Secured Second Lien Notes due 2022 (the “2022 Senior Secured Notes”) and $84.7 million aggregate principal amount of new 3½% Convertible Senior Notes due 2024 (the “2024 Convertible Senior Notes”). In early January 2018, we closed additional transactions in which $174.3 million aggregate principal amount of our existing senior subordinated notes were exchanged for $74.1 million aggregate principal amount of 2022 Senior Secured Notes and $59.4 million aggregate principal amount of new 5% Convertible Senior Notes due 2023 (the “2023 Convertible Senior Notes”). (see Capital Resources and Liquidity – Recent Debt Reduction Transactions for further discussion). These two combined transactions resulted in a total debt principal reduction of $184.4 million with potential for further reduction if some or all of the $144.1 million of new convertible debt is converted into equity.

Hurricane Harvey Impact. Due to conditions associated with Hurricane Harvey, in late-August 2017 the Company suspended operations and temporarily shut-in all production at its Houston area fields for approximately 10 days. The impacted fields included Hastings, Oyster Bayou, Conroe, Thompson, Webster and Manvel. The impact of Hurricane Harvey on 2017 production was approximately 500 BOE/d, and included incremental lease operating expenses of approximately $4 million for cleanup and repair costs.

Salt Creek Field Acquisition. On June 30, 2017, we acquired a 23% non-operated working interest in Salt Creek Field in Wyoming for cash consideration of approximately $72 million (before customary closing adjustments). Salt Creek Field is an ongoing CO2 flood, and tertiary production from the field averaged just under 2,200 Bbls/d, net to our interest, during the fourth quarter of 2017. As of December 31, 2017, net to our interest, we estimated the field had proved oil reserves of approximately 8.8 MMBbls, all of which are proved developed reserves.

West Yellow Creek Acquisition. In March 2017, we acquired an approximate 48% non-operated working interest in West Yellow Creek Field in Mississippi for approximately $16 million (before closing adjustments), a field in which the operator has invested significant capital converting the field to a CO2 EOR flood. As of December 31, 2017, we estimate West Yellow Creek Field currently has approximately 1.9 MMBbls of proved oil reserves, net to our interest, and first tertiary production is expected from this field in early 2018. Having available CO2 was a primary factor in our being able to enter into this transaction, in which we will sell CO2 to the operator.

CAPITAL RESOURCES AND LIQUIDITY

Overview. Our primary sources of capital and liquidity are our cash flows from operations and availability of borrowing capacity under our senior secured bank credit facility. During 2017, we generated cash flows from operations of $267.1 million, after giving effect to $62.2 million of cash outflows for working capital changes, which were impacted significantly by increasing revenues during 2017 due to oil price increases and the timing of certain payments.

The preservation of cash and liquidity remains a significant priority for us in the current oil price environment. As of December 31, 2017, we had $475.0 million drawn on our $1.05 billion senior secured bank credit facility, leaving us $512.8 million of borrowing base availability after consideration of $62.2 million of outstanding letters of credit, compared to $495.0 million of borrowings outstanding as of September 30, 2017 and $301.0 million as of December 31, 2016. The $174.0 million increase in bank debt since December 31, 2016 is primarily due to $88.9 million of oil and natural gas property acquisitions, $62.2 million of cash outflows for working capital changes, and repayments of other non-bank debt of $80.3 million (the majority of which was interest on second lien notes which was classified as debt), partially offset by operating cash flow in excess of development capital expenditures.

We have historically tried to match our development capital spending with our cash flow from operations and we currently expect to fund our planned capital expenditures with our projected cash flow from operations in 2018. We believe the approximate $500 million of liquidity available under our bank credit facility is sufficient to cover any excess working capital needs or any foreseeable cash flow shortfall between our cash flows from operations and capital spending. With the maturity of our bank credit


37


Denbury Resources Inc. 
Management’s Discussion and Analysis of Financial Condition and Results of Operations


facility set for December 2019, the Company intends to proactively work with its bank group during 2018 on extension of that maturity date while remaining focused upon maintaining our current level of available liquidity through that process. The Company may also raise funds through asset sales or joint ventures, or issuance of debt and/or equity, which would enable us to further increase our available liquidity. Related to this, the Company is currently engaged in two asset sale processes that could be completed in 2018. In mid-2017, we began actively marketing for sale certain non-productive surface acreage in the Houston area, targeted to receive bids during the second quarter of 2018. Also, in late-February 2018, we initiated a sale process for our mature EOR properties located in Mississippi and Louisiana and Citronelle Field located in Alabama. In aggregate, these fields accounted for 13% of our total 2017 production and approximately 7% of our year-end proved reserves.  The success, timing and outcome of these processes cannot be predicted at this time, but if successful could provide additional funds to pay down debt or add liquidity for financial or operational uses.

Since we do not expect oil prices to return in the foreseeable future to recent historical highs of 2014, we have adjusted, and continue to adjust, our business through efficiencies and cost reductions. Most recently, we completed a reduction in force in the third quarter of 2017, resulting in a reduction of approximately 15% of the Company’s workforce, principally comprised of personnel at the Company’s headquarters. With this reduction in force, coupled with other recent cost savings measures identified or implemented in 2017, we expect to exceed an annualized $50 million in targeted cost reductions in 2018, and we continue to believe we have additional opportunities to reduce costs.

In addition to reductions in our cost structure, we have reduced our debt principal levels by $836 million (including the debt exchange completed in January 2018) since December 31, 2014, primarily through opportunistic debt exchanges and open market debt repurchases. The movements in the market price of our debt and equity securities may provide opportunities for debt refinancing or additional debt reduction, and we may have discussions with bondholders from time to time regarding potential debt reduction transactions of various types. Potential transactions could include purchases of our subordinated debt in the open market, exchange offers, cash tenders for our debt, or future potential debt reduction with proceeds of issuances of equity, asset sales, joint ventures and other cash-generating activities. Any equity that we issue could lead to dilution of our current stockholders and affect our common stock price.

Senior Secured Bank Credit Facility. Our Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (the “Bank Credit Agreement”) is a senior secured revolving credit facility with a maturity date of December 9, 2019. As part of our fall 2017 semiannual borrowing base redetermination, the borrowing base and lender commitments for our Bank Credit Agreement were reaffirmed at $1.05 billion, with our next borrowing base redetermination scheduled for May 2018.

In May 2017, we entered into a Fourth Amendment to the Bank Credit Agreement, pursuant to which the lenders agreed to amend certain terms and financial performance covenants through the remaining term of the Bank Credit Agreement in order to provide more flexibility in managing the credit extended by our lenders, including eliminating the consolidated total net debt to EBITDAX financial performance covenants that were scheduled to go into effect starting in 2018. In addition, the amendment increased the applicable margin for ABR Loans and LIBOR Loans by 50 basis points, such that the margin for ABR Loans now ranges from 1.5% to 2.5% per annum and the margin for LIBOR Loans now ranges from 2.5% to 3.5% per annum. In November 2017, we entered into a Fifth Amendment to the Bank Credit Agreement, pursuant to which the lenders agreed to increase the amount of junior lien (i.e., second lien or third lien) debt we incur from $1.0 billion to $1.2 billion outstanding in the aggregate at any one time, facilitating our December 2017 and January 2018 debt exchanges. After taking these exchanges into account, $129.4 million of junior lien debt capacity (as defined in the Bank Credit Agreement) remains available to us under this covenant in that agreement.

The Bank Credit Agreement contains certain financial performance covenants through the maturity of the facility, including the following:

A consolidated senior secured debt to consolidated EBITDAX covenant, with such ratio not to exceed 3.0 to 1.0 through the first quarter of 2018, and thereafter not to exceed 2.5 to 1.0. Currently, only debt under our Bank Credit Agreement is considered consolidated senior secured debt for purposes of this ratio;
A minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 1.25 to 1.0; and
A requirement to maintain a current ratio of 1.0 to 1.0.



38


Denbury Resources Inc. 
Management’s Discussion and Analysis of Financial Condition and Results of Operations


Under these financial performance covenant calculations, as of December 31, 2017, our ratio of consolidated senior secured debt to consolidated EBITDAX was 1.12 to 1.0 (based upon a maximum permitted ratio of 3.0 to 1.0), our ratio of consolidated EBITDAX to consolidated interest charges was 2.40 to 1.0 (based upon a required ratio of not less than 1.25 to 1.0), and our current ratio was 2.82 to 1.0 (based upon a required ratio of not less than 1.0 to 1.0). Based upon our currently forecasted levels of production and costs, hedges in place as of February 21, 2018, and current oil commodity futures prices, we currently anticipate continuing to be in compliance with our financial performance covenants during the foreseeable future.

The above description of our Bank Credit Agreement is qualified by the express language and defined terms contained in the Bank Credit Agreement and the amendments thereto, each of which are filed as exhibits to our periodic reports filed with the SEC.

Recent Debt Reduction Transactions. During December 2017 and January 2018, we completed exchange transactions resulting in a net debt reduction of $184.4 million. During December 2017, in privately negotiated transactions, institutional holders of our subordinated debt exchanged $364.0 million aggregate principal amount of our 5½% Senior Subordinated Notes due 2022 (“2022 Notes”) and $245.8 million aggregate principal amount of our 4⅝% Senior Subordinated Notes due 2023 (“2023 Notes”) for $381.6 million aggregate principal amount of new 2022 Senior Secured Notes and $84.7 million aggregate principal amount of new 2024 Convertible Senior Notes, resulting in a net reduction of $143.6 million in our debt principal. During January 2018, we closed additional transactions in which $11.6 million aggregate principal amount of our 6⅜% Senior Subordinated Notes due 2021 (the “2021 Notes”), $94.2 million aggregate principal amount of our 2022 Notes and $68.5 million aggregate principal amount of our 2023 Notes were exchanged for $74.1 million aggregate principal amount of 2022 Senior Secured Notes and $59.4 million aggregate principal amount of 2023 Convertible Senior Notes, resulting in a net reduction of $40.8 million in our debt principal or an aggregate $184.4 million debt principal reduction in the two sets of exchanges. This aggregate net debt reduction could increase to approximately $269 million if all of the 2024 Convertible Senior Notes convert to Company common stock (based upon issuance of up to 38,563,154 shares at the current conversion rate for such notes), and could increase further to approximately $329 million if all of the 2023 Convertible Senior Notes also convert into Company common stock (based upon issuance of up to 16,743,372 shares at the current conversion rate for such notes).

2018 Capital Spending. We currently anticipate that our full-year 2018 capital budget, excluding capitalized interest and acquisitions, will be approximately $300 million to $325 million, roughly a 30% increase over 2017 capital spending levels of $240.8 million. Capitalized interest is currently estimated at approximately $30 million for 2018. The 2018 capital budget, excluding capitalized interest and acquisitions, provides for approximate spending as follows:

$155 million allocated for tertiary oil field expenditures;
$95 million allocated for other areas, primarily non-tertiary oil field expenditures including exploitation;
$20 million to be spent on CO2 sources and pipelines; and
$45 million for other capital items such as capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.

Based upon our currently forecasted levels of production and costs, commodity hedges in place, and current oil commodity futures prices, we intend to fund our development capital spending with cash flow from operations, with any shortfall funded with incremental borrowings under our Bank Credit Agreement, under which as of December 31, 2017, we had ample available borrowing capacity to cover any foreseeable cash flow shortfall. If prices were to decrease or changes in operating results were to cause a reduction in anticipated 2018 cash flows significantly below our currently forecasted operating cash flows, we would likely reduce our capital expenditures. If we reduce our capital spending due to lower cash flows, any sizeable reduction would likely lower our anticipated production levels in future years.



39


Denbury Resources Inc. 
Management’s Discussion and Analysis of Financial Condition and Results of Operations


Capital Expenditure Summary.  The following table reflects incurred capital expenditures (including accrued capital) for the years ended December 31, 2017, 2016 and 2015:
 
 
Year Ended December 31,
In thousands
 
2017
 
2016
 
2015
Capital expenditures by project
 
 
 
 
 
 
Tertiary oil fields
 
$
129,458

 
$
119,117

 
$
199,923

Non-tertiary fields
 
53,647

 
31,034

 
101,667

Capitalized internal costs (1)
 
52,616

 
56,260

 
66,308

Oil and natural gas capital expenditures
 
235,721

 
206,411

 
367,898

CO2 pipelines, sources and other
 
5,105

 
2,235

 
39,264

Capital expenditures, before acquisitions and capitalized interest
 
240,826

 
208,646

 
407,162

Acquisitions of oil and natural gas properties
 
88,777

 
11,706

 
25,765

Capital expenditures, before capitalized interest
 
329,603

 
220,352

 
432,927

Capitalized interest
 
30,762

 
25,982

 
32,146

Capital expenditures, total
 
$
360,365

 
$
246,334

 
$
465,073


(1)
Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.

Our 2017 cash flows from operations of $267.1 million exceeded 2017 capital expenditures. Acquisitions of $88.8 million constituted the single largest use of additional funds provided by borrowings on our Bank Credit Agreement.

Commitments and Obligations. A summary of our obligations at December 31, 2017, is presented in the following table:
 
 
Payments Due by Period
In thousands
 
2018
 
2019 and 2020
 
2021 and 2022
 
Thereafter
 
Total
Contractual obligations
 
 
 
 
 
 
 
 
 
 
Bank Credit Agreement
 
$

 
$
475,000

 
$

 
$

 
$
475,000

Estimated interest payments on senior secured bank credit facility, senior secured second lien notes, senior notes and subordinated debt
 
171,153

 
316,929

 
144,181

 
13,144

 
645,407

Senior secured debt (principal balance)
 

 

 
996,487

 

 
996,487

Convertible senior debt (principal balance)