10-K 1 dnr-20161231x10k.htm FORM 10-K Document


 

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

2016 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, 2016
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, or a small reporting company.  See the definitions of “large accelerated filer”, “accelerated filer”, and “small reporting company” in Rule 12-b2 of the Exchange Act.
Large accelerated filer þ   Accelerated filer o   Non-accelerated filer o  Smaller reporting company 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 $1,394,129,744.

The number of shares outstanding of the registrant’s Common Stock as of January 31, 2017, was 398,146,090.
DOCUMENTS INCORPORATED BY REFERENCE
Document:
 
Incorporated as to:
1. Notice and Proxy Statement for the Annual Meeting of Stockholders to be held May 24, 2017.
 
1.  Part III, Items 10, 11, 12, 13, 14

 




Denbury Resources Inc.

2016 Annual Report on Form 10-K
 Table of Contents 
 
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


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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 “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.
 
 


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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 4 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.



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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 254.5 MMBOE of estimated proved oil and natural gas reserves as of December 31, 2016, 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, 2016, we had 1,058 employees, 577 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.

2016 BUSINESS DEVELOPMENTS

Oil prices generally constitute the single largest variable in our operating results. Oil prices have historically been volatile, with NYMEX oil prices ranging from $26 to $107 per Bbl over the last three calendar years, with prices in February 2016 representing the lowest level in over 14 years. Although realized prices have increased from the lows experienced during the first quarter of 2016, our focus continues to remain on cost reductions and preserving liquidity. Our 2016 business developments included the following:

Generated $219.2 million of cash flow from operations (which amount includes $84.2 million of receipts on settlements of commodity derivatives) in 2016, which was $10.6 million higher than our incurred development capital expenditures ($208.6 million).

Reduced our cash operating costs, including corporate overhead and interest, to approximately $34 per BOE during 2016, a 7% decrease from similar levels during 2015, and reflects improved CO2 efficiency resulting in a 32% decrease in CO2 usage between 2015 and 2016.


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Denbury Resources Inc.


Completed a series of privately negotiated debt exchanges and open-market debt repurchases, contributing to a net reduction of our debt principal balance of approximately $530.4 million during 2016. As a result of the reduction in our average debt outstanding, cash interest expense also decreased $11.5 million between 2015 and 2016.

Generated average total production of 64,003 BOE/d in 2016, an 11% decrease from 2015 production levels when adjusted for asset sales, despite reducing 2016 development capital spending to approximately half of 2015 levels.

Modified certain of our financial performance covenants applicable to the 2016, 2017 and 2018 periods to provide more flexibility in managing our balance sheet, the credit extended by our lenders, and continuing compliance with financial performance covenants in this low oil price environment. In addition, maintained the $1.05 billion borrowing base under our senior secured bank credit facility, providing us with significant liquidity.

Completed construction of a natural gas liquids extraction plant at Delhi Field, providing us with the ability to sell natural gas liquids from the produced stream, improve the efficiency of the CO2 flood, and utilize extracted methane to power the plant and reduce field operating expenses.

Revised the joint venture arrangement at Grieve Field to provide for our joint venture 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 share of revenues from the first 2 million barrels of production.

Completed a process of evaluating our assets with a goal of increasing the value of both existing assets and future projects by optimizing field operational and development plans, identifying exploitation opportunities, reducing CO2 injection volumes through increased efficiency, and reducing costs.

2017 BUSINESS OUTLOOK

Beginning in mid-2016, NYMEX oil prices reversed the previous sustained downward trend, increasing to per-barrel prices in the low $50’s in late 2016 and early 2017. While these NYMEX oil prices are an improvement from the lows experienced in February 2016, we continue to exercise caution when determining capital budgets and finalizing field development plans, as our primary focus continues to be on preserving our financial strength and flexibility. Given expectations around oil prices using 2017 NYMEX oil futures and our current hedging levels, our 2017 capital spending has initially been budgeted at approximately $300 million, excluding capitalized interest and acquisitions, an increase of 44% over 2016 spending levels. With this increased capital spending level, we currently anticipate 2017 average daily production will remain relatively flat with our exit rate in 2016 of roughly 60,000 BOE/d. Based upon our current production forecast and hedges currently in place, using expected average oil prices in the mid-$50’s per barrel during 2017, we currently expect that our operations would internally fund all but a minor amount of our 2017 capital spending budget of $300 million. We currently intend to fund any potential shortfall with incremental borrowings on our senior secured bank credit facility, and as of December 31, 2016, we had ample availability on our senior secured bank credit facility to cover any foreseeable cash flow shortfall.

Our capital spending during 2017 will focus primarily on the continued development of our current tertiary floods, with less focus on the development of unproved reserves. Planned development activities presented in the discussions that follow may be delayed or modified during the course of 2017 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 improving our balance sheet, maintaining and enhancing the efficiencies achieved over the last couple of years and pursuing opportunities to increase or accelerate growth. We believe the market for acquisitions is improving and under the right conditions and terms acquisitions could provide one potential way to enhance our growth. In light of this, we are focusing on acquisition efforts directed at oil properties, preferably in our two areas of operation, in a manner that is accretive and does not significantly increase our leverage or reduce our liquidity.



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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, 2016, 2015 and 2014 (see the summary of D&M’s report as of December 31, 2016, 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.



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Denbury Resources Inc.

The following table provides estimated proved reserve information prepared by D&M as of December 31, 2016, 2015 and 2014, as well as PV-10 Values and Standardized Measures for each period. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and their values, including many factors beyond our control.  Proved oil and natural gas reserve quantities and values presented in the table reflect the significant decline in commodity prices beginning in late 2014 and continuing through 2016, whereby the average first-day-of-the-month NYMEX oil price used in estimating our proved reserves declined from $94.99 per Bbl at December 31, 2014, to $42.75 per Bbl at December 31, 2016, and for natural gas declined from $4.30 per MMBtu at December 31, 2014, to $2.55 per MMBtu at December 31, 2016. These commodity price changes contributed to the largest portion of the decline in proved reserves, including a decline of approximately 126 MMBOE (29%) in our proved reserves from December 31, 2014, to December 31, 2015, approximately half of which was attributable to natural gas reserves at Riley Ridge that were reclassified and are no longer considered proved reserves. See also Oil and Natural Gas OperationsField 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,
 
2016
 
2015
 
2014
Estimated proved reserves
 
 
 
 
 
Oil (MBbls)
247,103

 
282,250

 
362,335

Natural gas (MMcf) (1)
44,315

 
38,305

 
452,402

Oil equivalent (MBOE)
254,489

 
288,634

 
437,735

Reserve volumes categories
 
 
 
 
 
Proved developed producing
 
 
 
 
 
Oil (MBbls)
170,082

 
190,422

 
240,004

Natural gas (MMcf)
40,167

 
36,150

 
72,799

Oil equivalent (MBOE)
176,777

 
196,447

 
252,137

Proved developed non-producing
 
 
 
 
 
Oil (MBbls)
31,837

 
32,638

 
29,373

Natural gas (MMcf)
3,788

 
1,801

 
343,622

Oil equivalent (MBOE)
32,468

 
32,938

 
86,643

Proved undeveloped
 
 
 
 
 
Oil (MBbls)
45,184

 
59,190

 
92,958

Natural gas (MMcf)
360

 
354

 
35,981

Oil equivalent (MBOE)
45,244

 
59,249

 
98,955

Percentage of total MBOE
 
 
 
 
 
Proved developed producing
69
%
 
68
%
 
57
%
Proved developed non-producing
13
%
 
11
%
 
20
%
Proved undeveloped
18
%
 
21
%
 
23
%
Representative oil and natural gas prices (2)
 
 
 
 
 
Oil – NYMEX
$
42.75

 
$
50.28

 
$
94.99

Natural gas – Henry Hub
2.55

 
2.63

 
4.30

Present values (in thousands) (3)
 
 
 
 
 
Discounted estimated future net cash flows before income taxes (PV-10 Value) (4)
$
1,541,684

 
$
2,318,555

 
$
8,748,069

Standardized measure of discounted estimated future net cash flows after income taxes (“Standardized Measure”)
$
1,399,217

 
$
1,890,124

 
$
5,908,128


(1)
The significant decrease in natural gas reserves reflects the decline in commodity prices between December 31, 2014 and 2015. As a result of this decrease, natural gas reserves at Riley Ridge were reclassified and are no longer considered proved reserves, and which reserves totaled approximately 368 Bcf (61 MMBOE) as of December 31, 2014, or approximately 81% of our total proved natural gas reserves at that date.


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Denbury Resources Inc.


(2)
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.

(3)
Determined based on the average first-day-of-the-month prices for each month, adjusted to prices received by field in accordance with standards set forth in the Financial Accounting Standards Board Codification (“FASC”). PV-10 Values and the Standardized Measure are significantly impacted by the oil prices we receive relative to NYMEX oil prices (our NYMEX oil price differential). The weighted-average oil price differentials utilized were $3.39 per Bbl below representative NYMEX oil prices as of December 31, 2016, compared to $2.17 per Bbl below NYMEX oil prices as of December 31, 2015, and $3.10 per Bbl below NYMEX oil prices as of December 31, 2014.

(4)
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 $142.5 million at December 31, 2016; $428.4 million at December 31, 2015; and $2.84 billion at December 31, 2014.  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, 2016, our estimated proved undeveloped reserves totaled approximately 45.2 MMBOE, or approximately 18% of our estimated total proved reserves, a decline of 14.0 MMBOE from December 31, 2015 levels for these reserves, which changes are discussed below.  Approximately 91% (41 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, 2016, 12.6 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 2016, we spent approximately $45 million to convert 5.9 MMBOE of proved undeveloped reserves to proved developed reserves, primarily related to continued tertiary development activities at Delhi Field, as well as non-tertiary development at Cedar Creek Anticline (“CCA”). Other changes during 2016 included adding 3.9 MMBOE of proved undeveloped reserves primarily related to our tertiary operations at Heidelberg Field; reclassifying 6.7 MMBOE of proved undeveloped reserves to unproved reserves pursuant to the five-year development rule established by the SEC primarily due to changes in our development plans; and recognizing other net downward proved undeveloped reserve revisions of 5.3 MMBOE, primarily the result of reserves that were determined to be uneconomic based on 2016 average oil and natural gas prices used in estimating our proved reserves.



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Denbury Resources Inc.

During 2016, we provided oil and natural gas reserve estimates for 2015 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, 2015.

Internal Controls Over Reserve Estimates

Reserve information in this report is based on estimates prepared by D&M, an independent petroleum engineering consulting firm located in Dallas, Texas, utilizing data provided by our internal reservoir engineering team and is the responsibility of management. We rely on D&M’s expertise to ensure that our reserve estimates are prepared in compliance with SEC rules and regulations and that appropriate geologic, petroleum engineering, and evaluation principles and techniques are applied in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007)”.  The person responsible for the preparation of the reserve report is a Senior Vice President at D&M; he is a Registered Professional Engineer in the State of Texas. He received a Master of Science degree in Petroleum Engineering from the University of Texas in 1975, and he has in excess of 37 years of experience in oil and gas reservoir studies and evaluations.  Our President and Chief Operating Officer is primarily responsible for overseeing the independent petroleum engineering firm during the process.  Our President and Chief Operating Officer has a Bachelor of Science degree in Engineering, Civil Specialty, from the Colorado School of Mines and over 27 years of industry experience working with petroleum 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 President and Chief Operating Officer.  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 ExxonMobil 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.



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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 and the associated PV-10 Value of those reserves as of December 31, 2016, and average daily production for 2016, 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 virtually 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, 2016 (1)
 
2016 Average Daily Production
 
 
 
Oil
(MBbls)
 
Natural Gas
(MMcf)
 
MBOEs
 
% of Company Total
MBOEs
 
PV-10
Value
(2)(000’s)
 
Oil
(Bbls/d)
 
Natural Gas
(Mcf/d)
 
Average 2016 NRI
Tertiary oil and gas properties
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gulf Coast region
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mature properties (3)
17,466

 

 
17,466

 
6.9
%
 
92,438

 
9,040

 

 
74.1
%
Delhi
20,430

 

 
20,430

 
8.0
%
 
194,197

 
4,155

 

 
57.8
%
Hastings
32,498

 

 
32,498

 
12.8
%
 
220,883

 
4,829

 

 
79.7
%
Heidelberg
24,325

 

 
24,325

 
9.6
%
 
105,001

 
5,128

 

 
81.3
%
Oyster Bayou
15,097

 

 
15,097

 
5.9
%
 
156,315

 
5,083

 

 
87.0
%
Tinsley
20,168

 

 
20,168

 
7.9
%
 
124,502

 
7,192

 

 
81.7
%
Total Gulf Coast region
129,984

 

 
129,984

 
51.1
%
 
893,336

 
35,427

 

 
76.3
%
Rocky Mountain region
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Bell Creek
18,854

 

 
18,854

 
7.4
%
 
50,464

 
3,121

 

 
84.7
%
Total Rocky Mountain region
18,854

 

 
18,854

 
7.4
%
 
50,464

 
3,121

 

 
84.7
%
Total tertiary properties
148,838

 

 
148,838

 
58.5
%
 
943,800

 
38,548

 

 
76.9
%
Non-tertiary oil and gas properties
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gulf Coast region
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Texas
13,588

 
9,855

 
15,231

 
6.0
%
 
106,393

 
4,153

 
4,516

 
75.9
%
Mississippi and other
4,385

 
12,474

 
6,464

 
2.5
%
 
18,172

 
781

 
3,583

 
19.5
%
Total Gulf Coast region
17,973

 
22,329

 
21,695

 
8.5
%
 
124,565

 
4,934

 
8,099

 
49.8
%
Rocky Mountain region
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cedar Creek Anticline (4)
78,157

 
15,314

 
80,709

 
31.7
%
 
456,764

 
16,051

 
1,630

 
79.3
%
Other
2,135

 
6,672

 
3,247

 
1.3
%
 
16,555

 
1,082

 
4,571

 
60.2
%
Total Rocky Mountain region
80,292

 
21,986

 
83,956

 
33.0
%
 
473,319

 
17,133

 
6,201

 
77.5
%
Total non-tertiary properties
98,265

 
44,315

 
105,651

 
41.5
%
 
597,884

 
22,067

 
14,300

 
68.2
%
Total continuing properties
247,103

 
44,315

 
254,489

 
100.0
%
 
$
1,541,684

 
60,615

 
14,300

 
73.6
%
Property sales
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Williston Assets

 

 

 

 

 
825

 
233

 
 
Other properties divested

 

 

 

 

 

 
845

 
 
Company Total
247,103

 
44,315

 
254,489

 
100.0
%
 
1,541,684

 
61,440

 
15,378

 
 

(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 2016, which were $42.75 per Bbl for crude oil and $2.55 per MMBtu for natural gas.

(2)
PV-10 Value is a non-GAAP measure and is different from the GAAP measure, the Standardized Measure, in that PV-10 Value is a pre-tax number and the Standardized Measure is an after-tax number.  The Standardized Measure was $1.4 billion at December 31, 2016.  A comparison of PV-10 Value to the Standardized Measure is included in the reserves table in Estimated Net Quantities of Proved Oil and Natural Gas Reserves and Present Value of Estimated Future Net Revenues above. The information used to calculate the PV-10 Value is derived directly from data determined in accordance with FASC Topic 932.  See the definition of PV-10 Value in the Glossary and Selected Abbreviations.


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Denbury Resources Inc.


(3)
Mature properties include Brookhaven, Cranfield, Eucutta, Little Creek, Mallalieu, Martinville, McComb and Soso fields in Mississippi and Lockhart Crossing Field in Louisiana.

(4)
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 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, 2016 are proved tertiary oil reserves; (2) 60% of our 2016 total production was related to tertiary oil operations (on a BOE basis); and (3) 80% of our 2016 capital expenditures (excluding acquisitions) were related to our tertiary oil operations.  At year-end 2016, the proved oil reserves in our tertiary recovery oil fields had an estimated PV-10 Value of approximately $943.8 million, or 61% 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) reasonable return metrics at our anticipated long-term prices, (3) 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, (4) 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 (5) 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


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Denbury Resources Inc.

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 5.3 Tcf as of December 31, 2016.  The proved CO2 reserve estimates are based on a gross (8/8ths) basis, of which our net revenue interest is approximately 4.2 Tcf, and is included in the evaluation of proved CO2 reserves prepared by D&M, an independent petroleum engineering consulting firm.  In discussing our available CO2 reserves, we make reference to the gross amount of proved and probable reserves, as this is the amount that is available both for our own tertiary recovery programs and for industrial users who are customers of Denbury and others, as we are responsible for distributing the entire CO2 production stream.

In addition to our proved reserves, we estimate that we have 1.2 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 continue to expand our processing and dehydration capacities, and we continue to install pipelines and/or pumping stations necessary to transport the CO2 through our controlled pipeline network. As part of our innovation and improvement initiative, we have identified fields where we have been able to reduce CO2 injections without significantly impacting production. As such, we have been able to reduce injected CO2 volumes in the Gulf Coast region by 23% when comparing injection levels in the fourth quarter of 2016 to those in the prior year fourth quarter. 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 85% of our average daily CO2 produced from Jackson Dome or captured from industrial sources in 2016 was used in our tertiary recovery operations, compared to 88% in 2015 and 91% in 2014, with the balance delivered to third-party industrial users. During 2016, we used an average of 462 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 three 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 55 MMcf/d of CO2 to our EOR operations.  We currently expect to begin purchasing CO2 from Mississippi Power’s Kemper County Energy Facility during the first half of 2017, which could more than double the amount of CO2 we currently utilize from industrial sources. Additionally, we are in ongoing discussions with other parties who have plans to construct plants near the Green Pipeline. One of these projects includes construction of a methanol plant in Lake Charles, Louisiana, which is currently in the project financing stage of development. If the project is successfully financed in 2017, we would not expect first deliveries of CO2 from the plant until 2021 at the earliest.

In October 2015, the Environmental Protection Agency (“EPA”) finalized a rule – Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units (also known or commonly referred to as the “Clean Power Plan”) – that would impose limits on greenhouse gas emissions from new and existing U.S. electric generation units.  The Clean Power Plan in its current form contains requirements which would likely impact our ability to purchase power plant CO2 for our EOR operations from Mississippi Power’s Kemper County Energy Facility. The Clean Power Plan has been challenged by various states, trade associations, companies (including Denbury) and environmental groups.  On February 9, 2016, the U.S. Supreme Court stayed the implementation of the Clean Power Plan pending resolution of various challenges to the rule. On September 27, 2016, an en banc panel of the U.S. Court of Appeals for the District of Columbia Circuit heard oral argument on the merits of the various challenges to the Clean Power Plan. A decision could be issued at any time. In the meantime, the Supreme Court’s stay of the rule is in place and is expected to remain so until it grants certiorari and issues its own decision on the Plan, possibly as late as summer 2018. Additionally, the Trump administration has announced its intention to revise or rescind the Clean Power Plan. Given the Clean Power Plan’s status as a “final rule,” any change or revocation would likely involve a new rule-making process or Congressional action, the timing and details of which cannot be predicted. Although we do not believe the Clean Power Plan will impact our ability to take CO2 from Mississippi Power’s Kemper County Energy Facility in the near term, it could limit our ability to take CO2 in the future if upheld and maintained in effect.


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Denbury Resources Inc.


In addition to the potential CO2 sources discussed above, we continue to have ongoing discussions with owners of existing plants of various types that emit CO2 that we may be able to purchase and/or transport. 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.  Most of these existing plants emit relatively small volumes of CO2, generally less than our contracted sources, but such volumes may still be attractive if the source is located near CO2 pipelines.  The capture of CO2 could also be influenced by possible legislation or regulatory orders pertaining to CO2 emissions.  We believe that we are a likely purchaser of CO2 captured in our areas of operation because of the scale of our tertiary operations and our CO2 pipeline infrastructure.

Gulf Coast CO2 Pipelines. We acquired the 183-mile NEJD CO2 pipeline that runs from Jackson Dome to near Donaldsonville, Louisiana, as part of the 2001 acquisition of our Jackson Dome CO2 source.  Since 2001, we have acquired or constructed nearly 750 miles of CO2 pipelines, and as of December 31, 2016, we have access to nearly 950 miles of CO2 pipelines, which gives us the ability to deliver CO2 throughout the Gulf Coast region.  In addition to the NEJD CO2 pipeline, the major pipelines in the Gulf Coast region are the Free State Pipeline (90 miles), the Delta Pipeline (110 miles), the Green Pipeline Texas (120 miles), and the 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 expect the volume of CO2 transported through the Green Pipeline to increase in future years as we develop our inventory of CO2 EOR projects in this area.

Tertiary Properties with Tertiary Production and Proved Tertiary Reserves at December 31, 2016

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 23% of our total 2016 CO2 EOR production and approximately 12% of our year-end proved tertiary reserves.  These fields have been producing for some time, and their production is generally declining. Many of these fields contain multiple reservoirs that are amenable to CO2 EOR.

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 2016 averaged 4,387 Bbls/d, up from 3,898 Bbls/d in the fourth quarter of 2015.  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 methane to power the plant and reduce field operating expenses. Our 2017 development capital budget includes investing approximately $20 million in this field, 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 2016, tertiary production from Hastings Field averaged 4,552 Bbls/d, compared to 5,082 Bbls/d in the fourth quarter of 2015. Our 2017 development capital budget includes investing approximately $30 million in this field primarily related to continued tertiary development opportunities and conformance work.

Heidelberg Field.  Heidelberg Field is located in Mississippi 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


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Denbury Resources Inc.

2016, tertiary production at Heidelberg Field averaged 4,924 Bbls/d, compared to 5,635 Bbls/d in the fourth quarter of 2015.  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 2017 development capital budget includes investing approximately $35 million in this field, primarily related to developing portions of the Christmas Yellow sand in East Heidelberg and conformance work.

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 2016, tertiary production at Oyster Bayou Field averaged 4,988 Bbls/d, compared to 5,831 Bbls/d in the fourth quarter of 2015. Production from Oyster Bayou Field is believed to have peaked during 2015.

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 2016, average tertiary oil production from the field was 6,786 Bbls/d, compared to 7,522 Bbls/d in the fourth quarter of 2015. Although production from Tinsley Field is believed to have peaked in 2015, we continue to evaluate future potential investment opportunities in this field. Our 2017 development capital budget includes investing approximately $15 million in this field, primarily related to improvements at the recycle facility.

Future Tertiary Properties with No Tertiary Production or Proved Tertiary Reserves at December 31, 2016

Webster Field. We acquired our interest in Webster Field in the fourth quarter of 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, 2016, Webster Field had estimated proved non-tertiary reserves of approximately 2.6 MMBOE, net to our interest.  During the fourth quarter of 2016, non-tertiary production at Webster Field averaged 828 BOE/d, compared to 1,001 BOE/d in the fourth quarter of 2015.  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 will eventually deliver CO2 to the field. The timing of CO2 injections at Webster Field is primarily dependent upon 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 7.0 MMBOE at December 31, 2016, net to our interest, all of which are proved developed.  During the fourth quarter of 2016, production at Conroe Field averaged 2,281 BOE/d, compared to 2,889 BOE/d in the fourth quarter of 2015.

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 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 4.0 MMBOE at December 31, 2016, net to our interest, all of which are proved developed.  During the fourth quarter of 2016, non-tertiary production at Thompson Field averaged 1,344 BOE/d net to our interest, compared to 1,508 BOE/d in the fourth quarter of 2015.  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 future oil prices.



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Denbury Resources Inc.

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 the sale and exchange transaction with ExxonMobil. Our interest at Riley Ridge (discussed below) is also produced from the LaBarge Field. LaBarge Field is located in southwestern Wyoming.

During 2016, we received an average of approximately 63 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, 2016, our interest in LaBarge Field consisted of approximately 1.2 Tcf of proved CO2 reserves.

Riley Ridge. The Riley Ridge Federal Unit is also located in southwestern Wyoming and produces gas from the same LaBarge Field. We own 100% of the operating interests in Riley Ridge, as well as a gas processing facility. We acquired the Riley Ridge Federal Unit and the associated gas processing facility with the intent to separate for sale the natural gas and helium from the full well stream after construction of the gas processing facility was completed, and ultimately for the purpose of gaining a source of CO2 to utilize in flooding our fields in the Rocky Mountain region. Subsequently, issues arose related to contractor performance and design failure that caused significant delays and incremental costs to complete the facility. We placed the gas processing facility into service during the fourth quarter of 2013, and we were successful in running the facility for part of 2014 before additional issues arose related to optimal operation of the facility and sulfur build-up in the gas supply wells. In mid-2014, the gas processing facility was shut-in and to date remains shut-in. We plan to continue engineering work and analysis in 2017 to determine if there are alternative options to remediate the sulfur build-up in the gas supply wells and to assess our ability to reduce the costs thereof; however, the time of completion and results of such analysis are currently uncertain.

Other Rocky Mountain CO2 Sources.  While Riley Ridge 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 (see Rocky Mountain Region CO2 Sources and Pipelines above) 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.

Tertiary Properties with Tertiary Production and Proved Tertiary Reserves at December 31, 2016

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 2016 averaged 3,269 Bbls/d of oil, compared to 2,806 Bbls/d in the fourth quarter of 2015, as production has steadily grown from the initial production response in the third quarter of 2013.  Our 2017 development capital budget includes investing approximately $25 million in this field primarily related to expansion of the flood into new phases. We expect production from this field will continue to increase during 2017.



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Denbury Resources Inc.

Future Tertiary Properties with No Tertiary Production or Proved Tertiary Reserves at December 31, 2016

Cedar Creek Anticline.  CCA is the largest potential EOR property that we own and currently our largest producing property, contributing approximately 26% of our 2016 total production. The field is primarily located in Montana but covers 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 15,186 BOE/d during the fourth quarter of 2016, compared to production during the fourth quarter of 2015 of 17,875 BOE/d. The non-tertiary proved reserves associated with CCA were 80.7 MMBOE, net to our interest, as of December 31, 2016.

CCA is located approximately 110 miles north of Bell Creek Field, and we currently expect to ultimately connect this field to our Greencore Pipeline.  In the future, we plan to perform minor conformance work at the field to minimize production declines, the timing of which will depend on future oil prices. Our current plan for initiating a CO2 flood at CCA is scheduled several years from now, the timing of which may change depending on future oil prices, pipeline permitting and sources and availability of CO2. In addition to the future plans to flood CCA with CO2, we are also creating plans for exploitation opportunities that exist across the field. Our 2017 development capital budget includes investing approximately $25 million in this field primarily related to field infrastructure upgrades.

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 will accelerate the remaining development of the facility and fieldwork, and we currently anticipate first tertiary production by the middle of 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 3.2 MMBOE at December 31, 2016, net to our interest, 1.0 MMBOE of which relate to the natural gas producing Big George coal zone.  During the fourth quarter of 2016, non-tertiary production averaged 1,665 BOE/d, compared to 2,212 BOE/d in the fourth quarter of 2015. We successfully completed 5 wells in Hartzog Draw Field in 2014; however, we have temporarily suspended the non-tertiary development of Hartzog Draw Field in light of the recent oil price environment. 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 future oil prices.

Other Non-Tertiary Oil Properties

Despite the majority of our oil and natural gas properties discussed above consisting of either existing or planned future tertiary floods, we 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 2,035 BOE/d during the fourth quarter of 2016, compared to 3,444 BOE/d during the fourth quarter of 2015.
 
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.



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Oil and Gas Acreage

The following table sets forth our acreage position at December 31, 2016:
 
Developed
 
Undeveloped
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Gulf Coast region
245,869

 
199,089

 
284,606

 
16,712

 
530,475

 
215,801

Rocky Mountain region
324,489

 
298,336

 
190,129

 
75,041

 
514,618

 
373,377

Total
570,358

 
497,425

 
474,735

 
91,753

 
1,045,093

 
589,178


The percentage of our net undeveloped acreage that is subject to expiration over the next three years, if not renewed, is approximately 2% in 2017, 11% in 2018 and 25% in 2019.

Productive Wells

The following table sets forth our gross and net productive oil and natural gas wells as of December 31, 2016:
 
Producing Oil Wells
 
Producing Natural Gas Wells
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Operated wells
 
 
 
 
 
 
 
 
 
 
 
Gulf Coast region
1,262

 
1,174

 
161

 
149

 
1,423

 
1,323

Rocky Mountain region
945

 
898

 
281

 
144

 
1,226

 
1,042

Total
2,207

 
2,072

 
442

 
293

 
2,649

 
2,365

Non-operated wells
 

 
 

 
 

 
 

 
 

 
 

Gulf Coast region
38

 
2

 

 

 
38

 
2

Rocky Mountain region
22

 
5

 
3

 
1

 
25

 
6

Total
60

 
7

 
3

 
1

 
63

 
8

Total wells
 

 
 

 
 

 
 

 
 

 
 

Gulf Coast region
1,300

 
1,176

 
161

 
149

 
1,461

 
1,325

Rocky Mountain region
967

 
903

 
284

 
145

 
1,251

 
1,048

Total
2,267

 
2,079

 
445

 
294

 
2,712

 
2,373


Drilling Activity

The following table sets forth the results of our drilling activities over the last three years.  As of December 31, 2016, we had 2 wells in progress.
 
Year Ended December 31,
 
2016
 
2015
 
2014
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Exploratory wells (1)
 
 
 
 
 
 
 
 
 
 
 
Productive (2)

 

 

 

 

 

Non-productive (3)

 

 

 

 

 

Development wells (1)
 

 
 

 
 

 
 

 
 

 
 

Productive (2)

 

 
16

 
15

 
59

 
56

Non-productive (3)(4)

 

 

 

 

 

Total

 

 
16

 
15

 
59

 
56


(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


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Denbury Resources Inc.

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 2016, 2015 and 2014, an additional 1, 6 and 43 wells, respectively, were drilled for water or CO2 injection purposes.

The following table summarizes sales volumes, sales prices and production cost information for our net oil and natural gas production for the years ended December 31, 2016, 2015 and 2014:
 
Year Ended December 31,
 
2016
 
2015
 
2014
Net sales volume
 
 
 
 
 
Gulf Coast region
 
 
 
 
 
Oil (MBbls)
14,772

 
16,783

 
17,259

Natural gas (MMcf)
3,274

 
5,187

 
4,855

Total Gulf Coast region (MBOE)
15,318

 
17,648

 
18,068

Rocky Mountain region
 

 
 

 
 

Oil (MBbls)
7,715

 
8,462

 
8,513

Natural gas (MMcf)
2,354

 
2,906

 
3,524

Total Rocky Mountain region (MBOE)
8,107

 
8,946

 
9,100

Total Company (MBOE)
23,425

 
26,594

 
27,168

 
 
 
 
 
 
Average sales prices – excluding impact of derivative settlements
 

 
 

 
 

Gulf Coast region
 

 
 

 
 

Oil (per Bbl)
$
41.99

 
$
49.34

 
$
94.67

Natural gas (per Mcf)
2.04

 
2.48

 
4.31

 
 
 
 
 
 
Rocky Mountain region
 

 
 

 
 

Oil (per Bbl)
$
39.44

 
$
43.25

 
$
82.75

Natural gas (per Mcf)
1.90

 
2.11

 
3.73

 
 
 
 
 
 
Total Company
 

 
 

 
 

Oil (per Bbl)
$
41.12

 
$
47.30

 
$
90.74

Natural gas (per Mcf)
1.98

 
2.35

 
4.07

 
 
 
 
 
 
Average production cost (per BOE sold) (1)
 

 
 

 
 

Gulf Coast region (2)
$
18.42

 
$
19.51

 
$
24.92

Rocky Mountain region
16.38

 
19.07

 
21.69

Total Company (2)
17.71

 
19.37

 
23.84


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

(2)
Production costs include certain special items, comprised of (1) lease operating expenses and related insurance recoveries recorded to remediate an area of Delhi Field, (2) a reimbursement for a retroactive utility rate adjustment, and (3) other insurance recoveries. If these amounts were excluded, average production costs per BOE for the Gulf Coast region would


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have totaled $20.29 and $25.31 for the years ended December 31, 2015 and 2014, respectively, and average production costs per BOE for the Company as a whole would have totaled $19.88 and $24.10 for the years ended December 31, 2015 and 2014, respectively.

PRODUCTION AND UNIT PRICES

Further information regarding average production rates, unit sales prices and unit costs per BOE are set forth under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Operating Results Table, included herein.

TITLE TO PROPERTIES

As is customary in the oil and natural gas industry, Denbury conducts a limited title examination at the time of its acquisition of properties or leasehold interests targeted for enhanced recovery, and curative work is performed with respect to significant defects on higher-value properties of the greatest significance.  We believe that title to our oil and natural gas properties is good and defensible, subject only to such exceptions that we believe do not materially interfere with the use of such properties, including encumbrances, easements, restrictions and royalty, overriding royalty and other similar interests.

SIGNIFICANT OIL AND GAS PURCHASERS AND PRODUCT MARKETING

Oil and natural gas sales are made on a day-to-day basis or under short-term contracts at the current area market price. We would not expect the loss of any single purchaser to have a material adverse effect upon our operations; however, the loss of a large single purchaser could potentially reduce the competition for our oil and natural gas production, which in turn could negatively impact the prices we receive.  For the year ended December 31, 2016, two purchasers accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP (20%) and Marathon Petroleum Company (14%). For the year ended December 31, 2015, two purchasers accounted for 10% or more of our oil and natural gas revenues: Marathon Petroleum Company (28%) and Plains Marketing LP (15%). For the year ended December 31, 2014, three purchasers accounted for 10% or more of our oil and natural gas revenues: Marathon Petroleum Company (31%), Plains Marketing LP (13%), and ConocoPhillips (12%).

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, 2016, 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 2016, we sold approximately 60% of our crude oil at prices based on, or partially tied to, the LLS index price, and the balance at prices based on various other indexes tied to NYMEX prices, primarily in the Rocky Mountain region. The average LLS-to-NYMEX differential (on a trade-month basis) was a positive $1.70 per Bbl during 2016, compared to a positive $3.72 per Bbl during 2015 and a positive $3.88 per Bbl in 2014. During 2016, our light sweet crude oil production in the Gulf Coast region, on average, sold for $1.38 per Bbl below NYMEX, compared to $0.56 per Bbl over NYMEX in 2015 and $1.80 per Bbl over NYMEX in 2014.  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


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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, 2016, the discount for our oil production in the Rocky Mountain region averaged $3.97 per Bbl, compared to $5.60 per Bbl during 2015 and $10.19 per Bbl during 2014.

Natural Gas Marketing

We have minimal natural gas production, as 96% of our 2016 average daily production was oil. Virtually all of our natural gas production in the Gulf Coast region is close to existing pipelines; consequently, we generally have a variety of options to market our natural gas.  However, our natural gas production in the Rocky Mountain region, like our oil production, is dependent on, among other factors, limited transportation options that can affect our ability to find markets for it.  We sell the majority of our natural gas on one-year contracts, with prices fluctuating month to month based on published pipeline indices and with slight premiums or discounts to the index.

COMPETITION AND MARKETS

We face competition from other oil and natural gas companies in all aspects of our business, including acquisition of producing properties, oil and gas leases, drilling rights, and CO2 properties; marketing of oil and natural gas; and obtaining and maintaining goods, services and labor.  Many of our competitors have substantially larger financial and other resources.  Factors that affect our ability to acquire producing properties include available liquidity, available information about prospective properties and our expectations for earning a minimum projected return on our investments.  Because of the primary nature of our core assets (our tertiary operations) and our ownership of relatively uncommon significant natural sources of CO2 in the Gulf Coast and Rocky Mountain regions, we believe that we are effective in competing in the market and have less competition than our peers in certain aspects of our business.

The demand for qualified and experienced field personnel to drill wells and conduct field operations and for geologists, geophysicists, engineers and other professionals in the oil and gas industry can fluctuate significantly, often in correlation with commodity prices, causing periodic shortages in such personnel.  Prior to the 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;


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Denbury Resources Inc.

the method of drilling and casing wells; the surface use and restoration of properties upon which wells are drilled; the plugging and abandoning of wells; and the composition or disposal of chemicals and fluids used in connection with operations.  Our operations are also subject to various conservation laws and regulations.  These include regulation of the size of drilling, spacing or proration units and the density of wells that may be drilled in those units, and the unitization or pooling of oil and gas properties.  In addition, federal and state conservation laws, which establish maximum rates of production from oil and gas wells, generally prohibit or restrict the venting or flaring of natural gas and impose certain requirements regarding the ratability of production.  The effect of these laws and regulations may limit the amount of oil and natural gas we can produce from our wells and may limit the number of wells or the locations at which we can drill.  Regulatory requirements and compliance relative to the oil and gas industry increase our costs of doing business and, consequently, affect our profitability.

Federal Regulation of Sales Prices and Transportation

The transportation of, and certain sales with respect to, natural gas in interstate commerce are heavily regulated by agencies of the U.S. federal government and are affected by, among other things, the availability, terms and cost of transportation.  Notably, the price and terms of access to pipeline transportation are subject to extensive U.S. federal and state regulation.  The Federal Energy Regulatory Commission (“FERC”) is continually proposing and implementing new and/or modified rules and regulations affecting the natural gas industry, some of which may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines.  While our sales of crude oil, condensate and natural gas liquids are not currently subject to FERC regulation, our ability to transport and sell such products is dependent on certain pipelines whose rates, terms and conditions of service are subject to FERC regulation.  Additional proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, FERC, state regulatory bodies and the courts, and we cannot predict when or if any such proposals or proceedings might become effective and their effect or impact, if any, on our operations.

Federal Energy and Climate Change Legislation and Regulation

The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, among other things, updated federal pipeline safety standards, increased penalties for violations of such standards, gave the Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (the “PHMSA”) authority for new damage prevention and incident notification, and directed the PHMSA to prescribe new minimum safety standards for CO2 pipelines, which safety standards could affect our operations and the costs thereof. While the PHMSA has adopted or proposed to adopt a number of new regulations to implement this act, no new minimum safety standards have been proposed or adopted for CO2 pipelines.

Both federal and state authorities have in recent years proposed new regulations to limit the emission of greenhouse gasses as part of climate change initiatives.  For example, both the EPA and BLM have issued regulations for the control of methane emissions. The EPA has promulgated regulations requiring permitting for certain sources of greenhouse gas emissions, and in May 2016, promulgated final regulations to reduce methane and volatile organic compound emissions from the oil and gas sector. 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. Conversely, on February 3, 2017, the U.S. House of Representatives approved a resolution to void a Bureau of Land Management rule restricting methane venting and flaring, which must be approved by the U.S. Senate and signed by the President to take effect.

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.



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Denbury Resources Inc.

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.

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. Given the Trump administration’s announced intention to revise or rescind federal regulations promulgated during the Obama administration and to promote fossil fuel development on federal lands, it is possible that there could be an increase in litigation initiated by environmental or citizens groups, state attorneys general, or other elected or appointed officials.

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 2016, we fracture stimulated one water source well at Tinsley Field utilizing water-based fluids with no diesel fuel component. We are currently evaluating the potential to refrac approximately five wells at Hartzog Draw Field during 2017. We are familiar with the laws and regulations applicable to hydraulic fracturing operations and take steps to ensure compliance with these requirements.



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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 have historically been volatile, with NYMEX oil prices ranging from $26 to $107 per Bbl over the last three calendar years, with prices in February 2016 representing the lowest level in over 14 years. Even if oil prices recover for a period of time, volatility will remain, and prices could move downward or upward on a rapid or repeated basis, which can make transactions, valuations and business strategies difficult. Our cash flow from operations is highly dependent on the prices that we receive for oil, as oil comprised approximately 96% of our 2016 production and approximately 97% of our proved reserves at December 31, 2016. The prices for oil and natural gas are subject to a variety of factors that are beyond our control.  These factors include the supply of, and demand for, these commodities, which fluctuate with changes in market and economic conditions and other factors, including:

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.

Due to the sustained period of low oil prices, the PV-10 Value of our estimated proved reserves was less than our outstanding indebtedness as of December 31, 2016. If oil prices decline further for an extended period of time, we could be harmed 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 be forced to increase our level of indebtedness, issue additional equity, or sell assets;
we could have difficulty repaying or refinancing our indebtedness;
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;
construction of plants that produce CO2 as a byproduct that we can purchase could be delayed or cancelled, thus limiting the amount of industrial-source CO2 available for use in our tertiary operations; 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 liquidity, business and financial condition.

Liquidity is essential to our business.  Our liquidity could be substantially negatively affected by an inability to obtain capital in the long-term or short-term debt capital markets or equity capital markets or an inability to access bank financing.  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 liquidity, business and financial condition.  In the past, conditions such as these have adversely impacted financial markets and have created substantial volatility and uncertainty with the related negative impact on global economic activity. Negative credit market conditions could inhibit our lenders from fully funding our bank credit facility


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Denbury Resources Inc.

or cause them to 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.

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

As of December 31, 2016, our outstanding indebtedness consisted of $614.9 million principal amount of 9% Senior Secured Second Lien Notes due 2021, $1.6 billion principal amount of subordinated notes, virtually 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 5.28% per annum, and $301.0 million principal amount outstanding under our bank credit facility.  As of February 22, 2017, we have a borrowing base and aggregate lender commitments of $1.05 billion under our bank credit facility and availability with respect to such commitments of $674.7 million.  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. 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.

The level of our indebtedness could have important consequences, including but not limited to the following:

increasing our vulnerability to general adverse economic and industry conditions;
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;
reducing our available cash flow if market interest rates increase or if the level of our indebtedness significantly increases;
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, pay dividends, fund share repurchases and make certain investments; and/or
placing us at a competitive disadvantage as compared to our competitors that have less debt.

Additionally, rising interest rates would, among other things, affect our interest costs under our bank credit facility, increase the cost of any new debt financings, or limit our ability to otherwise borrow additional funds on favorable terms.

The debt covenants contained in the agreements governing our outstanding indebtedness may also affect our flexibility in reacting to changes in the economy and in our industry. For example, as our cash flow from operations is highly dependent on the prices that we receive for oil and natural gas, our leverage metrics deteriorated during 2015 and 2016. Between May 2015 and April 2016, we modified certain of our financial performance covenants under our senior secured bank credit facility applicable to the 2016, 2017 and 2018 periods to support continuing compliance with these covenants in this low oil price environment. If oil and natural gas prices remain at current levels 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, 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.

Any failure to meet our debt obligations or comply with the debt covenants contained in the agreements governing our outstanding indebtedness could harm our business, financial condition and results of operations.

We expect our cash flows to vary significantly from year to year due to the cyclical nature of our business. A sustained period of low oil prices or their further deterioration may cause us to be unable to make required payments on our indebtedness. If we are unable to generate sufficient cash flows or otherwise obtain funds necessary to make required payments on our indebtedness, or if we otherwise fail to comply with the various covenants governing such indebtedness, especially those in our bank credit


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Denbury Resources Inc.

facility, we could be in default under such indebtedness. Any such default, if not cured or waived, could permit the holders of such indebtedness to accelerate the maturity of such indebtedness and could cause defaults under other indebtedness, which could have a material adverse effect on us. In addition, any failure to make scheduled payments of interest and principal on our outstanding indebtedness would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms. Our ability to meet our obligations under our debt instruments will depend, in part, upon our future performance, which will be subject to prevailing economic conditions, commodity prices, and financial, business and other factors, including factors beyond our control.

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 estimate quantities of oil and natural gas reserves; process and record financial and operating data; analyze seismic and drilling information; process wire transfers and store our banking information; monitor and control pipeline and plant equipment; process and store personally identifiable information of our employees and royalty owners; and communicate with employees, stakeholders and business associates. 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. For example, unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our drilling or production operations.

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.

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, well blowouts; cratering and explosions; 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. 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. If these costs were to increase significantly, it could have an adverse effect upon the profitability of these 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;
title problems;
pressure or irregularities in formations;
equipment failures or accidents;


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Denbury Resources Inc.

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; and
the cost of, or shortages or delays in the availability of, drilling rigs, equipment, pipelines and services.

Estimating our reserves, production and future net cash flows is difficult to do with any certainty.

Estimating quantities of proved oil and natural gas reserves is a complex process.  It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors such as future commodity prices, production costs, severance and excise taxes, capital expenditures and workover and remedial costs, and the assumed effect of governmental rules and regulations.  There are numerous uncertainties about when a property may have proved reserves as compared to potential or probable reserves, particularly relating to our tertiary recovery operations.  Forecasting the amount of oil reserves recoverable from tertiary operations, and the production rates anticipated therefrom, requires estimates, one of the most significant being the oil recovery factor.  Actual results most likely will vary from our estimates.  Also, the use of a 10% discount factor for reporting purposes, as prescribed by the SEC, may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business, and the oil and natural gas industry in general, are subject.  Any significant inaccuracies in these interpretations or assumptions, or changes of conditions, could result in a revision of the quantities and net present value of our reserves.

The reserves data included in documents incorporated by reference represent estimates only.  Quantities of proved reserves are estimated based on economic conditions, including first-day-of-the-month average oil and natural gas prices for the 12-month period preceding the date of the assessment.  The representative oil and natural gas prices used in estimating our December 31, 2016 reserves were $42.75 per Bbl for crude oil and $2.55 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, 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, further 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, 2016, approximately 18% 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


27


Denbury Resources Inc.

permitting delays, 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. 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, heightening potential capital constraints.  If capital expenditures remain at reduced levels, or if outside capital resources become limited, we will not be able to maintain our current production levels.

We have acquired several fields at a substantial cost because we believe that they have significant additional production potential through tertiary flooding, and we may have the opportunity to acquire other oil fields that we believe are tertiary flood candidates, some of which may require significant amounts of capital.  If we are unable to successfully develop and produce the potential oil in any acquired fields, it would negatively affect our return on investment relative to these acquisitions and could significantly reduce our ability to obtain additional capital for the future or fund future acquisitions, and also negatively affect our financial results to a significant degree.

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 22, 2017, we have oil derivative contracts in place covering 39,000 Bbls/d for the first quarter of 2017, 29,000 Bbls/d for the second quarter of 2017, 16,500 Bbls/d for the third quarter of 2017, and 13,000 Bbls/d for the fourth quarter of 2017. 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


28


Denbury Resources Inc.

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-sourced 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.

We may lose executive officers, key management personnel or other talented 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 and other key management personnel. Our employees, including our executive officers, are employed at will and do not have employment agreements. If one or more members of our management team dies, becomes disabled or voluntarily terminates employment with us, there is no assurance that we will find a suitable or comparable substitute. We believe that our future success depends, in large part, upon our ability to hire and retain highly skilled managerial personnel. Historically, a significant portion of the compensation paid to our executive officers and key management personnel has been through long-term grants of Company stock under our 2004 Omnibus Stock and Incentive Plan (the “2004 Plan”). If the shares reserved under the 2004 Plan are depleted and not replenished, we may be forced to eliminate long-term equity grants, which would negatively impact our ability to attract and retain highly skilled managerial personnel. Replacing long-term equity grants with cash compensation would reduce the cash available to fund capital expenditures. Additionally, in a low oil price environment, we could be susceptible to losing talented non-industry professionals (e.g., accountants, attorneys and human resources personnel). Competition for persons with these skills is intense, and there is no assurance that we will be successful in attracting and retaining such skilled and talented personnel.

Governmental laws and regulations relating to environmental protection 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 environment, including 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. In addition, 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. While the President has indicated that his administration will relax enforcement of and work to repeal certain federal environmental regulations that affect the oil and gas industry, we are currently unable to predict what, if any, changes will be made or their timing.



29


Denbury Resources Inc.

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 have been introduced, are anticipated to be introduced, or are otherwise under consideration, by the President, Congress, state legislatures and various federal and state agencies.  While it is currently anticipated that the President and Congress will 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. However, until such legislation or regulations are enacted or adopted into law and thereafter implemented, it is not possible to gauge their impact on our future operations or our results of operations and financial condition.

The new Presidential administration and Congress have stated that comprehensive U.S. tax reform is a priority and have discussed their intent to pursue major federal tax reform. If major tax revisions are made, it is possible that a number of special tax provisions affecting the oil and gas industry could be changed. The passage of legislation or any other change in U.S. federal income tax law that eliminates, reduces or postpones certain tax deductions that are currently available to us or otherwise increases our taxes could negatively affect the after-tax returns generated on our oil and gas investments, our cash flow or our financial condition and results of operations, even if reduced corporate tax rates are enacted.

The derivatives market regulations promulgated under the Dodd-Frank Act could have an adverse effect on our ability to hedge risks associated with our business.

The Dodd-Frank Act requires the Commodities Futures Trading Commission and the SEC to promulgate rules and regulations establishing federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market, including swap clearing and trade execution requirements. Our derivative transactions are not currently subject to such swap clearing and trade execution requirements; however, in the event our derivative transactions potentially become subject to such requirements, we believe that our derivative transactions would qualify for the “end-user” exception. The Dodd-Frank Act, rules promulgated thereunder or new legislation or regulations, could (1) affect the cost, or decrease the liquidity, of energy-related derivatives available to us to hedge against commodity price fluctuations (including through requirements to post collateral), (2) materially alter the terms of derivative contracts, (3) affect the availability of derivatives to protect against risks we encounter, and (4) increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives due to changes in the derivatives market, our cash flows could become more volatile and less predictable, which could adversely affect our ability to plan for and fund capital expenditures. On the other hand, there is significant uncertainty as to the status of the Dodd-Frank Act, and its regulations and enforcement, growing out of widespread discussion of repealing or scaling back the Dodd-Frank Act – either through legislative or regulatory action; however, it is not possible to determine at this time whether such changes will take place, in what form or to what extent.

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, 2016, two purchasers individually accounted for 10% or more of our oil and natural gas revenues and, in the aggregate, for 34% of such revenues.  The loss of a large single purchaser could adversely impact the prices we receive or the transportation costs we incur.

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 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 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.


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Denbury Resources Inc.


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 (see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations Results of OperationsWrite-Down of Oil and Natural Gas Properties and Critical Accounting Policies and EstimatesFull Cost Method of Accounting, Depletion and Depreciation and Oil and Natural Gas Properties). 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.

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 10, 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.

Potential Mississippi Environmental Administrative Proceeding

For the past two years, the Company has been in negotiations with the Mississippi Department of Environmental Quality (“MDEQ”) that began following receipt of a February 2015 notice from the MDEQ related to a discharge of materials at the West Heidelberg Field in Jasper County, Mississippi in the third quarter of 2013. Based upon recent discussions with the MDEQ, it is currently anticipated that a settlement related to the discharge providing for a monetary fine as a civil penalty will be reached, thus eliminating the need for an administrative proceeding. The Company expects any such fine will not be material to the Company’s business or financial condition.

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, we assumed a 20-year helium supply contract under which we agreed to supply to a third-party purchaser the helium separated from the full well stream by operation of the gas processing facility.  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 capped at $8.0 million per contract year and are capped at an aggregate of $46.0 million over the remaining


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Denbury Resources Inc.

term of the contract. As the gas processing facility has been shut-in since mid-2014, we have not been able to supply helium to the third-party purchaser under the helium supply contract.  In a case originally filed in November 2014 by APMTG Helium, LLC, the third-party helium purchaser, in the Ninth Judicial District Court of Sublette County, Wyoming, after a week of trial on the third-party purchaser’s claim for multiple years of liquidated damages for non-delivery of volumes of helium specified under the helium supply contract, and on our claim that the contractual obligation is excused by virtue of events that fall within the force majeure provisions in the helium supply contract, the trial was stayed in late February 2017 until a later date yet to be determined by the District Court. 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.


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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 well as dividends declared within those periods.  Prior to 2014, we had not historically declared or paid dividends on our common stock. As of January 31, 2017, based on information from the Company’s transfer agent, American Stock Transfer and Trust Company, the number of holders of record of Denbury’s common stock was 1,993.  On February 28, 2017, the last reported sale price of Denbury’s common stock, as reported on the NYSE, was $2.71 per share.
 
2016
 
2015
 
High
 
Low
 
Dividends Declared Per Share
 
High
 
Low
 
Dividends Declared Per Share
First Quarter
$
3.66

 
$
0.95

 
$

 
$
8.78

 
$
6.26

 
$
0.0625

Second Quarter
4.68

 
2.01

 

 
9.20

 
6.16

 
0.0625

Third Quarter
3.67

 
2.62

 

 
5.74

 
2.44

 
0.0625

Fourth Quarter
4.03

 
2.39

 

 
4.24

 
1.89

 


During the first three quarters of 2015, the Company’s Board of Directors declared quarterly cash dividends of $0.0625 per common share. 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. For further discussion, see Note 6, Stockholders’ Equity, to the Consolidated Financial Statements. No unregistered securities were sold by the Company during 2016.

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 2016
 
3,350

 
$
2.74

 

 
$
210.1

November 2016
 
11,169

 
2.95

 

 
210.1

December 2016
 
3,061

 
3.88

 

 
210.1

Total
 
17,580

 
 
 

 



(1)
Stock repurchases during the fourth quarter of 2016 were made in connection with delivery by our employees of shares to us 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 current 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.

Between early October 2011, when we announced the commencement of a common share repurchase program, and December 31, 2016, we repurchased 64.4 million shares of Denbury common stock (approximately 16.0% of our outstanding shares of common stock at September 30, 2011) for $951.8 million, with no repurchases made since October 2015.



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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, 2016, 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, 2011, to December 31, 2016.

COMPARISON OF 5-YEAR CUMULATIVE TOTAL RETURN
dnr-201612_chartx34797.jpg
 
December 31,
 
2011
 
2012
 
2013
 
2014
 
2015
 
2016
Denbury Resources Inc.
$
100

 
$
107

 
$
109

 
$
55

 
$
14

 
$
26

S&P 500
100

 
116

 
154

 
175

 
177

 
198

Dow Jones U.S. Exploration & Production
100

 
106

 
140

 
124

 
95

 
118




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Denbury Resources Inc.

Item 6. Selected Financial Data
 
 
Year Ended December 31,
In thousands, except per-share data or otherwise noted
 
2016
 
2015
 
2014
 
2013
 
2012
Consolidated Statements of Operations data
 
 
 
 
 
 
 
 
 
 
Revenues and other income
 
 
 
 
 
 
 
 
 
 
Oil, natural gas, and related product sales
 
$
935,751

 
$
1,213,026

 
$
2,372,473

 
$
2,466,234

 
$
2,409,867

Other
 
39,845

 
44,534

 
62,732

 
50,893

 
46,605

Total revenues and other income
 
$
975,596

 
$
1,257,560

 
$
2,435,205

 
$
2,517,127

 
$
2,456,472

Net income (loss) (1)
 
(976,177
)
 
(4,385,448
)
 
635,491

 
409,597

 
525,360

Net income (loss) per common share
 
 
 
 
 
 
 
 
 
 
Basic (1)
 
(2.61
)
 
(12.57
)
 
1.82

 
1.12

 
1.36

Diluted (1)
 
(2.61
)
 
(12.57
)
 
1.81

 
1.11

 
1.35

Dividends declared per common share (2)
 

 
0.1875

 
0.25

 

 

Weighted average number of common shares outstanding
 
 
 
 
 
 
 
 
 
 
Basic
 
373,859

 
348,802

 
348,962

 
366,659

 
385,205

Diluted
 
373,859

 
348,802

 
351,167

 
369,877

 
388,938

Consolidated Statements of Cash Flows data
 
 
 
 
 
 
 
 
 
 
Cash provided by (used in)
 
 
 
 
 
 
 
 
 
 
Operating activities
 
$
219,223

 
$
864,304

 
$
1,222,825

 
$
1,361,195

 
$
1,410,891

Investing activities
 
(205,417
)
 
(550,185
)
 
(1,076,755
)
 
(1,275,309
)
 
(1,376,841
)
Financing activities
 
(15,012
)
 
(334,460
)
 
(135,104
)
 
(172,210
)
 
45,768

Production (average daily)
 
 
 
 
 
 
 
 
 
 
Oil (Bbls)
 
61,440

 
69,165

 
70,606

 
66,286

 
66,837

Natural gas (Mcf)
 
15,378

 
22,172

 
22,955

 
23,742

 
29,109

BOE (6:1)
 
64,003

 
72,861

 
74,432

 
70,243

 
71,689

Unit sales prices – excluding impact of derivative settlements
 
 
 
 
 
 
 
 
 
 
Oil (per Bbl)
 
$
41.12

 
$
47.30

 
$
90.74

 
$
100.67

 
$
97.18

Natural gas (per Mcf)
 
1.98

 
2.35

 
4.07

 
3.53

 
3.05

Unit sales prices – including impact of derivative settlements
 
 
 
 
 
 
 
 
 
 
Oil (per Bbl)
 
$
44.86

 
$
67.41

 
$
90.82

 
$
100.64

 
$
96.77

Natural gas (per Mcf)
 
1.98

 
2.83

 
3.99

 
3.53

 
5.67

Costs per BOE
 
 
 
 
 
 
 
 
 
 
Lease operating expenses (3)
 
$
17.71

 
$
19.37

 
$
23.84

 
$
28.50

 
$
20.29

Taxes other than income
 
3.33

 
4.13

 
6.25

 
6.87

 
6.10

General and administrative expenses
 
4.69

 
5.44

 
5.83

 
5.66

 
5.49

Depletion, depreciation, and amortization (4)
 
36.12

 
19.99

 
21.83

 
19.89

 
19.34

Proved oil and natural gas reserves (5)
 
 
 
 
 
 
 
 
 
 
Oil (MBbls)
 
247,103

 
282,250

 
362,335

 
386,659

 
329,124

Natural gas (MMcf)
 
44,315

 
38,305

 
452,402

 
489,954

 
481,641

MBOE (6:1)
 
254,489

 
288,634

 
437,735

 
468,318

 
409,398

Proved carbon dioxide reserves
 
 
 
 
 
 
 
 
 
 
Gulf Coast region (MMcf) (6)
 
5,332,576

 
5,501,175

 
5,697,642

 
6,070,619

 
6,073,175

Rocky Mountain region (MMcf) (7)
 
1,214,428

 
1,237,603

 
3,035,286

 
3,272,428

 
3,495,534

Consolidated Balance Sheets data (8)
 
 
 
 
 
 
 
 
 
 
Total assets
 
$
4,274,578

 
$
5,885,533

 
$
12,690,156

 
$
11,698,406

 
$
11,083,839

Total long-term liabilities
 
3,372,634

 
4,263,606

 
6,503,194

 
5,902,463

 
5,405,223

Stockholders’ equity
 
468,448

 
1,248,912

 
5,703,856

 
5,301,406

 
5,114,889





35


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 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 (see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Depletion, Depreciation, and Amortization).

(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 4.2 Tcf, 4.4 Tcf, 4.5 Tcf, 4.8 Tcf and 4.8 Tcf at December 31, 2016, 2015, 2014, 2013 and 2012, respectively, and include reserves dedicated to volumetric production payments of 12.3 Bcf, 25.3 Bcf, 9.3 Bcf, 28.9 Bcf and 57.1 Bcf at December 31, 2016, 2015, 2014, 2013 and 2012, 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, 2.6 Tcf, 2.9 Tcf and 2.9 Tcf at December 31, 2016, 2015, 2014, 2013 and 2012, 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.

(8)
The consolidated balance sheet data presented in this table reflect the adoption of Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) 2016-09, Improvements to Employee Share-Based Payment Accounting, ASU 2015-17, Income Taxes, and ASU 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs. See Note 1, Significant Accounting Policies – Recent Accounting Pronouncements to the consolidated financial statements for further discussion.



36


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 Decline and Impact on Our Business. Oil prices generally constitute the single largest variable in our operating results. Oil prices have historically been volatile, with NYMEX oil prices ranging from $26 to $107 per Bbl over the last three calendar years, with prices in February 2016 representing the lowest level in over 14 years. The following chart illustrates the fluctuations in our realized oil prices, excluding the impact of commodity derivative settlements, during 2014, 2015 and 2016.

realizedoilprice.jpg

 
 
Oil price per Bbl
Average realized prices
 
2014
 
2015
 
2016
First quarter
 
$
97.69

 
$
46.02

 
$
30.71

Second quarter
 
100.04

 
56.92

 
43.38

Third quarter
 
94.78

 
45.74

 
43.45

Fourth quarter
 
70.80

 
40.41

 
48.03


Although realized oil prices during the second half of 2016 increased from the lows experienced in the first quarter of 2016, our focus continues to remain on cost reductions and preserving liquidity. Cost reductions have been realized in 2016 in all categories of our business. Our 2016 capital development expenditures totaled $208.6 million, which were fully funded with cash flows from operations, thus preserving our liquidity. One advantage we have in this environment is that our oil assets have relatively low decline rates even with our significantly reduced planned capital spending level, and therefore our average daily production declined by less than 10% in 2016, excluding the impact of weather-related downtime at Conroe and Thompson fields, completed asset sales, and production shut in for economic reasons. Lastly, we have hedged a portion of our estimated oil production through 2017 in order to cover our current level of cash operating costs and to help mitigate any future price declines or sustained low oil prices (see Results of Operations – Commodity Derivative Contracts below). Our 2017 capital spending has been budgeted at


37


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


approximately $300 million, excluding capitalized interest and acquisitions, a 44% increase over the 2016 capital spending level. It is expected that the projected cash flow from operations, based on current NYMEX futures prices in late-February 2017, will fund all but a minor amount of this capital spending. With this increased capital spending level, we currently anticipate our 2017 average daily production remaining relatively flat with our exit rate in 2016 of roughly 60,000 BOE/d.

During 2016, we have continued to evaluate our assets with a goal of increasing the value of both existing assets and future projects by optimizing field operational and development plans, reducing CO2 injection volumes through increased efficiency, and reducing costs such as power and workovers. We have reduced our overall CO2 injection volumes by 32% and our total lease operating expenses by $113.8 million (22%) on a normalized basis (see Results of Operations – Production Expenses – Lease Operating Expenses) when comparing the years ended December 31, 2016 and 2015. These initiatives aim to increase the profitability of our operations and make them more resilient to lower oil prices.

2016 Operating Highlights. Our financial results have been significantly impacted by the decrease in realized oil prices as highlighted above, which decreased from an average of $90.74 per Bbl during 2014 to $41.12 per Bbl during 2016. During 2016, we recognized a net loss of $976.2 million, compared to a net loss of $4.4 billion during 2015.  Our net loss in 2016 decreased due to the substantial decrease in noncash impairments, primarily because oil prices, a significant driver of our full-cost ceiling test write-downs, stabilized and began to increase during the course of 2016, which resulted in the trailing 12-month average price (the primary driver of the value of our proved reserves and therefore any full cost pool ceiling test write-downs) flattening, rather than declining each quarter as was the case in 2015. Impairments of assets totaled $810.9 million ($508.2 million net of tax) in 2016, compared to $6.2 billion ($4.3 billion net of tax) in 2015 (see Results of Operations – Write-Down of Oil and Natural Gas Properties and 2015 Impairment of Goodwill below). Additionally, the effect of the reduction in asset impairments in 2016 was partially offset by an accelerated depreciation charge of $591.0 million recorded in 2016 related to the Riley Ridge gas processing facility and related assets (see Results of Operations – Depletion, Depreciation, and Amortization below).

We generated $219.2 million of cash flow from operating activities during 2016, compared to $864.3 million during 2015, due primarily to a $427.5 million decline in derivative settlements and $277.3 million reduction in revenues due to the lower oil prices and less sales volumes, partially offset by reductions in operating expenses.

During 2016, our oil and natural gas production, which was 96% oil, averaged 64,003 BOE/d, compared to an average of 72,861 BOE/d produced during 2015.  This 12% decrease in production was primarily due to weather-related shut-in production, production shut in due to economics, facility downtime, maintenance and repair work, and natural production declines based on our lower capital spending level. Total production in 2015 also includes production related to certain non-core assets in the Williston Basin of North Dakota and Montana (the “Williston Assets”), which were sold during the third quarter of 2016, and other property divestitures. Production related to the Williston Assets and other property divestitures averaged 1,005 BOE/d in 2016, compared to 1,993 in 2015. These production decreases were partially offset by increases in production due to continued CO2 enhanced oil recovery response at Delhi Field in the Gulf Coast region and Bell Creek Field in the Rocky Mountain region. See Results of Operations – Production for further discussion.

Our average realized oil price per barrel, excluding the impact of commodity derivative contracts, was $41.12 per Bbl during 2016, a decrease of 13% compared to $47.30 per Bbl realized during 2015.  The oil price we realized relative to NYMEX oil prices (our NYMEX oil price differential) was $2.29 per Bbl below NYMEX prices during 2016, a $0.74 per Bbl decline compared to realized prices of $1.55 per Bbl below NYMEX in 2015, primarily due to weakening of our Gulf Coast region LLS price differentials, offset in part by improvement in the Rocky Mountain region discount in 2016 relative to NYMEX oil prices.

One of our primary focuses in the past few years has been to reduce costs throughout the organization through a number of internal initiatives. As a result of these efforts, we have been able to achieve reductions in our lease operating expenses, with total lease operating expenses of $414.9 million during 2016, a 19% reduction when compared to 2015 levels. Excluding special or unusual amounts reported in 2015, total lease operating expenses per BOE during 2016 were $17.71, compared to $19.88 during 2015, with decreases realized in most categories of lease operating expenses. General and administrative expenses per BOE decreased 14% when comparing the year-ended December 31, 2016 to 2015, primarily due to lower employee-related costs such as salaries, bonus accruals and long-term incentives.

2016 Debt Reduction Transactions. During 2016, we completed a series of privately negotiated debt exchanges and open-market debt repurchases, contributing to a net reduction of our debt principal balance of approximately $530.4 million between December 31, 2015 and 2016. In May 2016, we exchanged $1,057.8 million of existing senior subordinated notes with a limited


38


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


number of holders for $614.9 million of our new 9% Senior Secured Second Lien Notes due 2021 (the “2021 Senior Secured Notes”) plus 40.7 million shares of Denbury common stock, resulting in a net reduction from these exchanges of $442.9 million in our debt principal. During 2016, we purchased $181.9 million of our existing senior subordinated notes for $76.7 million in open-market transactions, for a net reduction of $105.2 million of our debt principal. See Capital Resources and Liquidity – 2016 Debt Reduction Transactions for further discussion.

2016 Divestiture of Non-Core Assets. On August 31, 2016, we completed the sale of the Williston Assets for $58 million (before closing adjustments). The sale had an effective date of April 1, 2016, and proceeds realized after closing adjustments totaled $53.6 million. Approximately $9 million of proceeds from the sale of Williston Assets was paid by the purchaser directly to a qualified intermediary to facilitate a like-kind exchange, and are therefore not reflected as an investing activity in our Consolidated Statements of Cash Flows.

Grieve Field Revised Joint Venture. On August 4, 2016, the Company and its joint venture partner in Grieve Field, located in Wyoming, reached an agreement to revise the joint venture arrangement between the parties for the continued development of such 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 will accelerate the remaining development of the facility and fieldwork, and we currently anticipate first tertiary production by the middle of 2018.

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. As a result of the significant reduction in oil prices discussed above and less advantageous hedge positions, our cash flow from operations has significantly decreased, from $864.3 million during 2015 to $219.2 million during 2016.

The preservation of cash and liquidity remains a significant priority for us in the current oil price environment. We have taken steps to lower our costs in all categories of our business, and we have made significant progress in that regard. Over the past year, we have also amended our senior secured bank credit facility to relax certain financial performance covenants through 2018 (see Senior Secured Bank Credit Facility below). As of December 31, 2016, we had $301.0 million drawn on our $1.05 billion senior secured bank credit facility, leaving us $673.7 million of current liquidity after consideration of $75.3 million of outstanding letters of credit. This liquidity, coupled with our other cost saving and liquidity preservation measures and the improvement in oil prices, should be sufficient to cover any foreseeable cash flow shortfall and fund our capital and operating cash outflows.

In order to provide a level of price protection to a portion of our oil production, we have entered into a combination of oil swaps, collars, and three-way collars through the fourth quarter of 2017 (see Results of Operations – Commodity Derivative Contracts