10-K 1 dnr-20151231x10k.htm FORM 10-K 10-K


 

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

2015 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, 2015
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
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 $2,242,674,743.

The number of shares outstanding of the registrant’s Common Stock as of January 31, 2016, was 350,812,556.
DOCUMENTS INCORPORATED BY REFERENCE
Document:
 
Incorporated as to:
1. Notice and Proxy Statement for the Annual Meeting of Stockholders to be held May 24, 2016.
 
1.  Part III, Items 10, 11, 12, 13, 14

 




Denbury Resources Inc.

2015 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, CO2 or helium.
 
 
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, CO2 or helium 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, CO2 or helium produced 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, CO2 or helium.
 
 
MMcf/d
One million cubic feet of natural gas, CO2 or helium per day.
 
 
Noncash fair value adjustments on commodity derivatives

The net change during the period in the fair market value of commodity derivative positions. Noncash fair value adjustments 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 3 to the table included in Item 1, Estimated Net Quantities of Proved Oil and Natural Gas Reserves and Present Value of Estimated Future Net Revenues – Oil and Natural Gas Reserve Estimates.

 
 
Tcf
One trillion cubic feet of natural gas, CO2 or helium.
 
 
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 288.6 MMBOE of estimated proved oil and natural gas reserves as of December 31, 2015, of which 98% 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, 2015, we had 1,356 employees, 743 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.

2015 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 $35 to $111 per Bbl over the last three calendar years, and prices have declined dramatically since the fourth quarter of 2014 to less than $27 per Bbl in January 2016, the lowest level in over 13 years. In response to the decline in oil prices, we made adjustments to our business to preserve financial strength and flexibility. These adjustments included reducing our 2015 development capital spending levels, reducing costs, identifying new innovation and improvement ideas for our fields and suspending our quarterly cash dividend. Our 2015 business developments included the following:

Generated $864.3 million of cash flow from operations (which amount includes $511.7 million of receipts on settlements of commodity derivatives) in 2015, which was $391.7 million higher than the total of our incurred development capital expenditures ($407.2 million) and dividends ($65.4 million).



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Denbury Resources Inc.

Utilized excess cash flow from operations to pay down borrowings on our bank credit facility, with a total reduction of $220.0 million from the level outstanding as of December 31, 2014. As a result of the reduction in our average debt outstanding, cash interest expense also decreased $11.4 million between 2014 and 2015.

Increased our average tertiary oil production to 41,602 Bbls/d in 2015, a 1% increase from average tertiary oil production in 2014.

Reduced our 2015 development capital spending to approximately 39% of 2014 levels.

Generated average total production of 72,861 BOE/d in 2015, a 2% decrease from 2014 production, despite the significant reduction in our 2015 development capital spending.

Reduced our operating costs and identified new innovation and improvement ideas for our fields, which has resulted in meaningful decreases to most categories of our lease operating expenses and general and administrative expenses, and cost savings on capital projects.

Modified certain of our bank covenants applicable to the 2016, 2017 and 2018 periods to help mitigate concern around our ability to access our bank credit line if oil prices remain low for an extended period of time.

On September 21, 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 effective after payment of our third quarter dividend on September 29, 2015.

2016 BUSINESS OUTLOOK

With the further decline in early 2016 in already depressed oil and natural gas prices, as well as our reduced hedging levels in 2016 and uncertainty around future prices, we are continuing to make adjustments to our business to preserve financial strength and flexibility. To accommodate our lower projected cash flow from operations, our 2016 capital spending has been budgeted at approximately $200 million, excluding capitalized interest and acquisitions, which is less than half of 2015 levels, and is not adequate to maintain current production levels. Therefore, we currently anticipate production declines in 2016 in the range of approximately seven to twelve percent from average 2015 levels, approximately 60% of which relates to natural production declines, with the remainder related to wells that are uneconomic to either produce or repair in the current price environment. We currently expect oil prices would need to average within a per-barrel range in the upper $30’s during 2016 for cash flow from operations to balance with our anticipated $200 million development capital budget, based upon our current production forecast and hedges currently in place. We currently intend to fund any potential shortfall with incremental borrowings on our bank credit facility, and as of December 31, 2015, we had ample availability on our bank credit facility to cover any foreseeable cash flow shortfall. In light of our current 2016 capital budget, we have deferred certain development projects that are uneconomic at current prices and slowed the development pace of many fields, anticipating that we have the ability to increase our capital spending when commodity prices return to higher levels that provide an acceptable rate of return. In late 2015 and early 2016, we shut-in certain wells that have become uneconomic to either produce or repair in the current price environment.

During this period of reduced capital spending, 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 due to increased efficiency and reducing costs. These initiatives aim to increase the profitability of our assets, making them more resilient to lower oil prices, and we will continue to evaluate the timing of development of our inventory of fields and related pipelines and facilities. Therefore, planned development activities presented in the discussions that follow may be delayed or modified during the course of 2016 depending primarily upon oil prices and our level of cash flow to fund such development, as well as the availability of CO2. Our capital spending during 2016 will focus on the continued development of our current tertiary floods, with less focus on the development of unproved reserves. Together, we believe these initiatives will help us manage through this low oil price environment and provide us with liquidity for the foreseeable future.

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


6


Denbury Resources Inc.

focus is using CO2 in EOR, and 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. 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 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.

We began operations in the Rocky Mountain region in 2010 in connection with, and following, our merger with Encore Acquisition Company (“Encore”).  We completed construction of the first section of the 20-inch Greencore Pipeline (our first CO2 pipeline in the Rocky Mountain region) in late 2012. During 2013, we received our first CO2 deliveries from the ConocoPhillips-operated Lost Cabin gas plant in central Wyoming, started CO2 injection at our Bell Creek Field in Montana, and commenced tertiary oil production from this field. In addition to our current tertiary flood in the Rocky Mountain region, we currently have long-term plans to flood Hartzog Draw Field, Grieve Field, and the Cedar Creek Anticline (“CCA”) with CO2. CCA is a geological structure over 126 miles in length consisting of 14 different operating areas. Our Riley Ridge Field acquisition (completed in two stages) in 2010 and 2011, the acquisition of an interest in CO2 reserves in LaBarge Field from Exxon Mobil Corporation (“ExxonMobil”) in 2012, and the previously mentioned deliveries from the ConocoPhillips-operated Lost Cabin gas plant are expected to provide us the CO2 necessary for our current inventory of CO2 EOR projects in the Rocky Mountain region.

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, 2015, and average daily production for 2015, all based on Denbury’s net revenue interest (“NRI”).  The reserve estimates presented were prepared by DeGolyer and MacNaughton (“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.

Proved oil and natural gas reserve quantities and PV-10 Values presented in the table reflect the significant decline in commodity prices between December 31, 2015 and 2014, 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 $50.28 per Bbl at December 31, 2015, and for natural gas declined from $4.30 per MMBtu at December 31, 2014, to $2.63 per MMBtu at December 31, 2015. These commodity price changes resulted in a decline of approximately 126 MMBOE (29%) in our proved reserves from December 31, 2014, through December 31, 2015, a significant portion of which was attributable to natural gas reserves at Riley Ridge that 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. Reserve quantities and PV-10 Values presented in the table do not reflect the continued oil price declines in late 2015 and early 2016. Sustained prices at these recent or lower levels would result in additional decreases in the PV-10 Values, and to a lesser degree, additional reductions in our proved reserve volumes. Conversely, a sustained increase in commodity prices could lead to higher PV-10 Values and recovery of volumes lost due to lower prices. 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 below and Supplemental Oil and Natural Gas Disclosures (Unaudited) to the Consolidated Financial Statements.


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Denbury Resources Inc.

 
Proved Reserves as of December 31, 2015 (1)
 
2015 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 2015 NRI
Tertiary oil and gas properties
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gulf Coast region
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mature properties (3)
24,868

 

 
24,868

 
8.6
%
 
165,395

 
10,830

 

 
77.1
%
Delhi
25,870

 

 
25,870

 
8.9
%
 
216,478

 
3,688

 

 
57.3
%
Hastings
36,859

 

 
36,859

 
12.8
%
 
254,450

 
5,061

 

 
79.8
%
Heidelberg
19,053

 

 
19,053

 
6.6
%
 
189,459

 
5,785

 

 
80.8
%
Oyster Bayou
16,390

 

 
16,390

 
5.7
%
 
285,442

 
5,898

 

 
87.0
%
Tinsley
20,981

 

 
20,981

 
7.3
%
 
252,352

 
8,119

 

 
81.6
%
Total Gulf Coast region
144,021

 

 
144,021

 
49.9
%
 
1,363,576

 
39,381

 

 
77.6
%
Rocky Mountain region
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Bell Creek
20,799

 

 
20,799

 
7.2
%
 
90,889

 
2,221

 

 
85.6
%
Total Rocky Mountain region
20,799

 

 
20,799

 
7.2
%
 
90,889

 
2,221

 

 
85.6
%
Total tertiary properties
164,820

 

 
164,820

 
57.1
%
 
1,454,465

 
41,602

 

 
78.0
%
Non-tertiary oil and gas properties
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gulf Coast region
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Texas
16,178

 
9,829

 
17,816

 
6.2
%
 
139,358

 
5,233

 
7,258

 
69.3
%
Mississippi and other
5,034

 
12,241

 
7,074

 
2.4
%
 
33,177

 
1,368

 
6,954

 
23.4
%
Total Gulf Coast region
21,212

 
22,070

 
24,890

 
8.6
%
 
172,535

 
6,601

 
14,212

 
47.7
%
Rocky Mountain region
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cedar Creek Anticline (4)
89,536

 
4,197

 
90,236

 
31.3
%
 
647,379

 
17,661

 
2,018

 
82.9
%
Other
6,682

 
12,038

 
8,688

 
3.0
%
 
44,176

 
3,301

 
5,942

 
27.2
%
Total Rocky Mountain region
96,218

 
16,235

 
98,924

 
34.3
%
 
691,555

 
20,962

 
7,960

 
62.8
%
Total non-tertiary properties
117,430

 
38,305

 
123,814

 
42.9
%
 
864,090

 
27,563

 
22,172

 
57.8
%
Company Total
282,250

 
38,305

 
288,634

 
100.0
%
 
$
2,318,555

 
69,165

 
22,172

 
68.7
%

(1)
The above reserve estimates were prepared in accordance with Financial Accounting Standards Board Codification (“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 2015, which were $50.28 per Bbl for crude oil and $2.63 per MMBtu for natural gas, both of which were adjusted for market differentials by field.

(2)
PV-10 Value is a non-GAAP measure and is different from the GAAP measure, the Standardized Measure of Discounted Future Net Cash Flows (“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 $1.9 billion at December 31, 2015.  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 below. 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.

(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.



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Denbury Resources Inc.

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) 57% of our proved reserves at December 31, 2015 are proved tertiary oil reserves; (2) 57% of our 2015 production was related to tertiary oil operations (on a BOE basis); and (3) 70% of our 2015 capital expenditures (excluding acquisitions) were related to our tertiary oil operations.  At year-end 2015, the proved oil reserves in our tertiary recovery oil fields had an estimated PV-10 Value of approximately $1.5 billion, or 63% 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) an industry-competitive rate of return, depending on the specific field and area, (3) limited competition for this recovery method in our geographic regions, (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 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 5.5 Tcf as of December 31, 2015.  The proved CO2 reserve estimates are based on a gross (8/8ths) basis, of which our net revenue interest is approximately 4.4 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 1.3 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


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Denbury Resources Inc.

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.

Although our current proved CO2 reserves are sizeable, in order to continue our tertiary development of oil fields in the Gulf Coast region, incremental deliverability of CO2 is required.  In order to obtain additional CO2 deliverability, we have conducted several 3D seismic surveys in the Jackson Dome area over the past several years.

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 30% when comparing injection levels in the fourth quarter of 2015 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 88% of our average daily CO2 produced from Jackson Dome or captured from industrial sources in 2015 and 91% in 2014 and 2013 was used in our tertiary recovery operations, with the balance delivered to third-party industrial users. During 2015, we used an average of 684 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 60 MMcf/d of CO2 to our EOR operations.  Additionally, we are in ongoing discussions with other parties who have plans to construct plants near the Green Pipeline. The expansion of industrial sources of CO2 from which we could capture CO2 for use in our tertiary recovery projects has developed more slowly than we previously expected. Several projects remain in the development stage, although we continue to anticipate completion and startup of Mississippi Power’s Kemper County Energy Facility for which we have contracted, which could more than double the amount of CO2 we currently utilize from industrial sources. 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 will likely impact our ability to purchase power plant CO2 for our EOR operations due to a number of operational and legal issues. 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.

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 potential federal legislation, which could impose economic penalties for atmospheric 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 over 750 miles of CO2 pipelines, and as of December 31, 2015, 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


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Denbury Resources Inc.

the present time, most of the CO2 flowing in the Green Pipeline is delivered from the Jackson Dome area, but we began receiving CO2 from an industrial facility in Port Arthur, Texas in 2012, and are currently transporting a third party’s CO2 for a fee to the sales point at Hastings Field.  In addition, we began receiving CO2 from an industrial facility in Geismar, Louisiana in 2013. 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, 2015

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 26% of our total 2015 CO2 EOR production and approximately 15% 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 2015 averaged 3,898 Bbls/d, up from 3,743 Bbls/d in the fourth quarter of 2014.  Beginning November 1, 2014, average daily production amounts reflect the contractual reversionary assignment of approximately 25% of our interest to the seller of the field, the effectiveness, timing, and scope of which are subject to ongoing litigation, the ultimate outcome of which cannot be predicted.

Additionally, our development of Delhi Field has been impacted by a release of well fluids within an area of Delhi Field occurring in the second quarter of 2013 and our subsequent remediation of such release. During the years ended December 31, 2014 and 2013, we recorded $16.8 million and $114.0 million, respectively, of lease operating expenses related to this release and its remediation in our Consolidated Statements of Operations, bringing our total cost estimate with respect to these expenses to $130.8 million. We have received a total of $29.5 million ($27.1 million net to Denbury) in insurance reimbursements related to the Delhi Field release and remediation. These insurance reimbursements were recognized as a reduction to lease operating expenses for the years ended December 31, 2014 and 2015. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations Capital Resources and Liquidity Insurance Recoveries to Cover Costs of 2013 Delhi Field Release and Note 10, Commitments and Contingencies to the Consolidated Financial Statements for further discussion of these matters. Our development capital budget includes investing approximately $55 million in this field during 2016, primarily related to a natural gas liquids extraction plant, which we currently anticipate will be placed into service in late 2016. This plant will provide us with the ability to sell natural gas liquids from the produced stream, improve the efficiency of the flood, and utilize extracted methane to power the plant and reduce field operating expenses.

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 2015, tertiary production from Hastings Field averaged 5,082 Bbls/d, compared to 4,811 Bbls/d in the fourth quarter of 2014. Our future plans for Hastings Field include additional phased development opportunities.

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 2015, tertiary production at Heidelberg Field averaged 5,635 Bbls/d, compared to 6,164 Bbls/d in the fourth quarter of 2014.  The decrease in proved reserves at Heidelberg Field between December 31, 2015 and 2014 was primarily related to the reclassification of approximately 11 MMBbls of proved undeveloped reserves to the unproved reserves category pursuant to the five-year development rule established by the SEC due to changes in our development plans. Our future plans for Heidelberg Field include continued development of the East and West Heidelberg Units, including an expansion of our Tuscaloosa development and


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Denbury Resources Inc.

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.

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 2015, tertiary production at Oyster Bayou Field averaged 5,831 Bbls/d, compared to 5,638 Bbls/d in the fourth quarter of 2014. Production from Oyster Bayou Field is believed to have peaked in 2015, with production from the field in 2016 currently expected to be relatively flat or slightly reduced from 2015 levels. As of December 31, 2015, proved reserves at Oyster Bayou Field reflect positive performance revisions during 2015 of approximately 7 MMBOE as a result of increased recovery factors at the field, partially offset by a decrease in volumes of approximately 2 MMBOE due to a decline in the average first-day-of-the-month NYMEX oil price used in estimating our proved reserves.

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 2015, average tertiary oil production from the field was 7,522 Bbls/d, compared to 8,767 Bbls/d in the fourth quarter of 2014. Although production from Tinsley Field is believed to have peaked in 2015, with a modest production decline currently expected in 2016, we continue to evaluate future potential investment opportunities in this field. As of December 31, 2015, proved reserves at Tinsley Field reflect positive performance revisions during 2015 of approximately 7 MMBOE as a result of increased recovery factors at the field, partially offset by a decrease in volumes of approximately 6 MMBOE due to a decline in the average first-day-of-the-month NYMEX oil price used in estimating our proved reserves.

Future Tertiary Properties with No Tertiary Production or Proved Tertiary Reserves at December 31, 2015

Webster Field. We acquired our interest in Webster Field in the fourth quarter of 2012 as part of the sale and exchange transaction with ExxonMobil under which we sold to ExxonMobil our Bakken area assets in North Dakota and Montana in exchange for (1) $1.3 billion in cash, (2) operating interests in Hartzog Draw and Webster fields in Wyoming and Texas, respectively, and (3) an overriding royalty interest equivalent to an approximate one-third ownership interest in ExxonMobil’s CO2 reserves in LaBarge Field in Wyoming (the “Bakken Exchange Transaction”). The field is located in Texas, approximately eight miles northeast of our Hastings Field which we are currently flooding with CO2. At December 31, 2015, Webster Field had estimated proved non-tertiary reserves of approximately 2.2 MMBOE, net to our interest.  During the fourth quarter of 2015, non-tertiary production at Webster Field averaged 1,001 BOE/d, compared to 1,121 BOE/d in the fourth quarter of 2014.  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. We currently anticipate completing our plans for optimization of tertiary development of Webster Field during 2016, at which point we will determine the tertiary development schedule for the field, the timing of which could be delayed depending on future oil prices or revised development plans.

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 5.3 MMBOE at December 31, 2015, net to our interest, all of which are proved developed.  During the fourth quarter of 2015, production at Conroe Field averaged 2,889 BOE/d, compared to 3,386 BOE/d in the fourth quarter of 2014.

A pipeline must be constructed so that CO2 can be delivered to Conroe 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. We currently expect that over the next few years we will begin construction of this pipeline and prepare to commence CO2 injections at Conroe Field, the timing of which may change depending on future oil prices.

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


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Denbury Resources Inc.

8.4 MMBOE at December 31, 2015, net to our interest, of which approximately 82% is proved developed.  During the fourth quarter of 2015, non-tertiary production at Thompson Field averaged 1,508 BOE/d net to our interest, compared to 1,556 BOE/d in the fourth quarter of 2014.  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 currently scheduled several years in the future, the ultimate timing of which is primarily dependent upon future oil prices.

Rocky Mountain Region

CO2 Sources and Pipelines

LaBarge Field.  We acquired an overriding royalty interest equivalent to an approximate one-third ownership interest in ExxonMobil’s CO2 reserves in LaBarge Field in the fourth quarter of 2012 as part of the Bakken Exchange Transaction. Our interest at Riley Ridge (discussed below) is also produced from the LaBarge Field. LaBarge Field is located in southwestern Wyoming.

During 2015, we received an average of approximately 70 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, 2015, 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. In a series of two acquisitions in 2010 and 2011, we acquired 100% of the operating interests in Riley Ridge, as well as a gas processing facility that was under construction at the time of purchase, for $347 million. The gas processing facility separates helium and natural gas from the gas stream. During construction of the gas processing facility, we encountered issues related to contractor performance and design failure that resulted in significant delays and incremental costs to complete the facility. We placed the gas processing facility into service during the fourth quarter of 2013 and were successful in running the facility for part of 2014, but encountered additional issues in 2014, which kept the facility from running at optimum levels, as well as additional problems associated with sulfur build-up in the gas supply wells. We are currently working to correct and remedy these issues; however, we currently expect natural gas production at Riley Ridge will remain shut-in for some time due to such issues.

As of December 31, 2015, Riley Ridge natural gas, 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. Proved natural gas, CO2 and helium reserves at Riley Ridge previously totaled approximately 368 Bcf, 1.8 Tcf and 13 Bcf, respectively, as of December 31, 2014. As of December 31, 2015, our interest in Riley Ridge and minor surrounding acreage contained probable reserves of 2.8 Tcf of CO2, which reserve estimates are based upon the gross (8/8ths) basis of the CO2 reserves, and in which our net revenue interest is approximately 2.2 Tcf. As of December 31, 2015, we estimated that Riley Ridge contained probable helium reserves of approximately 12 Bcf, which volume estimate is reduced to reflect related fees we will remit to the U.S. government. We also believe there is significant CO2 reserve potential in other acreage surrounding Riley Ridge in which we also own an interest.

Initially, the gas processing facility at Riley Ridge was designed to separate for sale the natural gas and helium from the full well stream, with the remaining gases, principally CO2, re-injected into the producing formation or a deeper formation. Ultimately, our primary purpose for acquiring Riley Ridge was to gain a source of CO2 to utilize in flooding our fields in the Rocky Mountain region. We intend to construct a CO2 capture facility and will start to use CO2 from Riley Ridge following completion of the capture facility and planned CO2 pipeline connecting Riley Ridge to our existing Greencore Pipeline, the timing of which is largely dependent upon future oil prices.

Other Rocky Mountain 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. Our volumes received from the plant averaged approximately 40 MMcf/d in 2015.



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Denbury Resources Inc.

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, 2015

Bell Creek Field.  Bell Creek Field is located in southeast Montana, and we acquired our interest in this field 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 2015 averaged 2,806 Bbls/d of oil, compared to 1,659 Bbls/d in the fourth quarter of 2014, as production has steadily grown from the initial production response in the third quarter of 2013.  We expect production from this field will continue to increase during 2016; however, such growth may be at a slower rate in the future due to our slowed development pace as a result of the decline in oil prices.

Future Tertiary Properties with No Tertiary Production or Proved Tertiary Reserves at December 31, 2015

Cedar Creek Anticline.  CCA is the largest potential EOR property that we own and currently our largest producing property, contributing approximately 25% of our 2015 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 17,875 BOE/d during the fourth quarter of 2015, compared to production during the fourth quarter of 2014 of 18,553 BOE/d. This decline in production includes approximately 250 BOE/d of production that, as of December 31, 2015, we estimated to be attributable to wells shut-in as uneconomic to either produce or repair due to commodity prices at this time. The non-tertiary proved reserves associated with CCA were 90.2 MMBOE, net to our interest, as of December 31, 2015.

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 install an injection facility and 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 operations at the Riley Ridge gas processing facility.

Hartzog Draw Field. We acquired our interest in Hartzog Draw Field in the fourth quarter of 2012 as part of the Bakken Exchange Transaction. 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 4.3 MMBOE at December 31, 2015, net to our interest, 1.7 MMBOE of which relate to the natural gas producing Big George coal zone.  During the fourth quarter of 2015, non-tertiary production averaged 2,212 BOE/d, compared to 2,639 BOE/d in the fourth quarter of 2014. This decline in production includes approximately 300 BOE/d that, as of December 31, 2015, we estimated to be attributable to wells shut-in as uneconomic to either produce or repair due to commodity prices at this time. 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 commence CO2 injections at Hartzog Draw within five 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


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Denbury Resources Inc.

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. Production from these other non-tertiary properties totaled 5,340 BOE/d during the fourth quarter of 2015, compared to 5,747 BOE/d during the fourth quarter of 2014. In addition to these properties, we acquired two minor fields with future CO2 EOR potential during 2015 for a total of approximately $22 million.
 
OIL AND GAS ACREAGE, PRODUCTIVE WELLS AND DRILLING ACTIVITY

In the data below, “gross” represents the total acres or wells in which we own a working interest and “net” represents the gross acres or wells multiplied by our working interest percentage.  For the wells that produce both oil and gas, the well is typically classified as an oil or natural gas well based on the ratio of oil to natural gas production.

Oil and Gas Acreage

The following table sets forth our acreage position at December 31, 2015:
 
Developed
 
Undeveloped
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Gulf Coast region
248,466

 
201,902

 
285,830

 
17,100

 
534,296

 
219,002

Rocky Mountain region
381,890

 
331,698

 
218,204

 
100,284

 
600,094

 
431,982

Total
630,356

 
533,600

 
504,034

 
117,384

 
1,134,390

 
650,984


The percentage of our net undeveloped acreage that is subject to expiration over the next three years, if not renewed, is approximately 7% in 2016, 11% in 2017 and 12% in 2018.

Productive Wells

The following table sets forth our gross and net productive oil and natural gas wells as of December 31, 2015:
 
Producing Oil Wells
 
Producing Natural Gas Wells
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Operated wells
 
 
 
 
 
 
 
 
 
 
 
Gulf Coast region
1,318

 
1,224

 
210

 
193

 
1,528

 
1,417

Rocky Mountain region
1,091

 
987

 
290

 
148

 
1,381

 
1,135

Total
2,409

 
2,211

 
500

 
341

 
2,909

 
2,552

Non-operated wells
 

 
 

 
 

 
 

 
 

 
 

Gulf Coast region
99

 
29

 
39

 
16

 
138

 
45

Rocky Mountain region
106

 
19

 
3

 
1

 
109

 
20

Total
205

 
48

 
42

 
17

 
247

 
65

Total wells
 

 
 

 
 

 
 

 
 

 
 

Gulf Coast region
1,417

 
1,253

 
249

 
209

 
1,666

 
1,462

Rocky Mountain region
1,197

 
1,006

 
293

 
149

 
1,490

 
1,155

Total
2,614

 
2,259

 
542

 
358

 
3,156

 
2,617




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Denbury Resources Inc.

Drilling Activity

The following table sets forth the results of our drilling activities over the last three years.  As of December 31, 2015, we had 1 well in progress.
 
Year Ended December 31,
 
2015
 
2014
 
2013
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Exploratory wells (1)
 
 
 
 
 
 
 
 
 
 
 
Productive (2)

 

 

 

 

 

Non-productive (3)

 

 

 

 

 

Development wells (1)
 

 
 

 
 

 
 

 
 

 
 

Productive (2)
16

 
15

 
59

 
56

 
49

 
44

Non-productive (3)(4)

 

 

 

 
1

 
1

Total
16

 
15

 
59

 
56

 
50

 
45


(1)
An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.  Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well.  A development well is a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(2)
A productive well is an exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

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

(4)
During 2015, 2014 and 2013, an additional 6, 43 and 43 wells, respectively, were drilled for water or CO2 injection purposes.



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Denbury Resources Inc.

The following table summarizes sales volumes, sales prices and production cost information for our net oil and natural gas production for the years ended December 31, 2015, 2014 and 2013:
 
Year Ended December 31,
 
2015
 
2014
 
2013
Net sales volume
 
 
 
 
 
Gulf Coast region
 
 
 
 
 
Oil (MBbls)
16,783

 
17,259

 
16,858

Natural gas (MMcf)
5,187

 
4,855

 
5,620

Total Gulf Coast region (MBOE)
17,648

 
18,068

 
17,795

Rocky Mountain region
 

 
 

 
 

Oil (MBbls)
8,462

 
8,513

 
7,336

Natural gas (MMcf)
2,906

 
3,524

 
3,046

Total Rocky Mountain region (MBOE)
8,946

 
9,100

 
7,844

Total Company (MBOE)
26,594

 
27,168

 
25,639

 
 
 
 
 
 
Average sales prices – excluding impact of derivative settlements
 

 
 

 
 

Gulf Coast region
 

 
 

 
 

Oil (per Bbl)
$
49.34

 
$
94.67

 
$
105.34

Natural gas (per Mcf)
2.48

 
4.31

 
3.74

 
 
 
 
 
 
Rocky Mountain region
 

 
 

 
 

Oil (per Bbl)
$
43.25

 
$
82.75

 
$
89.95

Natural gas (per Mcf)
2.11

 
3.73

 
3.15

 
 
 
 
 
 
Total Company
 

 
 

 
 

Oil (per Bbl)
$
47.30

 
$
90.74

 
$
100.67

Natural gas (per Mcf)
2.35

 
4.07

 
3.53

 
 
 
 
 
 
Average production cost (per BOE sold) (1)
 

 
 

 
 

Gulf Coast region (2)
$
19.51

 
$
24.92

 
$
32.34

Rocky Mountain region
19.07

 
21.69

 
19.78

Total Company (2)
19.37

 
23.84

 
28.50


(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 have totaled $20.29, $25.31 and $25.93 for the years ended December 31, 2015, 2014 and 2013, respectively, and average production costs per BOE for the Company as a whole would have totaled $19.88, $24.10 and $24.05 for the years ended December 31, 2015, 2014 and 2013, 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.



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Denbury Resources Inc.

TITLE TO PROPERTIES

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

SIGNIFICANT OIL AND GAS PURCHASERS AND PRODUCT MARKETING

Oil and natural gas sales are made on a day-to-day basis or under short-term contracts at the current area market price. We would not expect the loss of any single purchaser to have a material adverse effect upon our operations; however, the loss of a large single purchaser could potentially reduce the competition for our oil and natural gas production, which in turn could negatively impact the prices we receive.  For the 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%). For the year ended December 31, 2013, three purchasers accounted for 10% or more of our oil and natural gas revenues: Marathon Petroleum Company (33%), Plains Marketing LP (15%), and Eighty-Eight Oil LLC (10%).

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, 2015, 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.

On December 18, 2015, Congress passed, and the President signed, legislation repealing the ban on the export of crude oil from the United States. Proponents of the legislation believe that repealing the ban should improve the market for domestic oil production by giving U.S. producers access to higher-priced international markets. Given the legislation’s recent passage, it is premature to predict the nature and extent of its impact, although oil markets are subject to many variables, including global economic conditions, exchange rates, and worldwide oil production levels.

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 2015, we sold approximately 62% 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 $3.72 per Bbl during 2015, compared to a positive $3.88 per Bbl during 2014 and a positive $11.10 per Bbl in 2013. During 2015, our light sweet crude oil production in the Gulf Coast region, on average, sold for $0.56 per Bbl over NYMEX compared to $1.80 per Bbl over NYMEX in 2014 and $7.44 per Bbl over NYMEX in 2013.  Our current markets at various sales points along the Gulf Coast have sufficient demand to accommodate our production, but there can be no assurance of future demand. We are, therefore, monitoring the marketplace for opportunities to strategically enter into long-term marketing arrangements.

The marketing of our Rocky Mountain region oil production is dependent on transportation through local pipelines to market centers in Guernsey, Wyoming; Clearbrook, Minnesota; Wood River, Illinois; and most recently Cushing, Oklahoma.  Shipments on some of the pipelines are at or near capacity and may be subject to apportionment.  We currently have access to, or have contracted for, sufficient pipeline capacity to move our oil production; however, there can be no assurance that we will be allocated sufficient pipeline capacity to move all of our oil production in the future.  Because local demand for production is small in comparison to current production levels, much of the production in the Rocky Mountain region is transported to markets outside


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Denbury Resources Inc.

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, 2015, the discount for our oil production in the Rocky Mountain region averaged $5.60 per Bbl, compared to $10.19 per Bbl during 2014 and $8.10 per Bbl during 2013.

Natural Gas Marketing

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.  In recent years, the competition for qualified technical personnel has been extensive, and our personnel costs have been escalating. There have also been periods with shortages of drilling rigs and other equipment, as demand for rigs and equipment has increased along with the number of wells being drilled.  These factors also cause significant increases in costs for equipment, services and personnel.  We cannot be certain when we will experience these issues, and these types of shortages or price increases could significantly decrease our profit margin, cash flow and operating results, and cause significant delays in our development operations.

FEDERAL AND STATE REGULATIONS

Numerous federal, state and local laws and regulations govern the oil and gas industry.  Additions or changes to these laws and regulations are often made in response to the current political or economic environment. Compliance with the evolving regulatory landscape is often difficult, and substantial penalties may be incurred for noncompliance. Additionally, the future annual cost of complying with all laws and regulations applicable to our operations is uncertain and will be ultimately determined by several factors, including future changes to legal and regulatory requirements. Management believes that continued compliance with existing laws and regulations applicable to our operations and future compliance therewith will not have a materially adverse effect on our consolidated financial position, results of operations or cash flows, although such laws and regulations, and compliance therewith, could cause significant delays or otherwise impede operations, which may, among other things, cause our expected production rates and cash flows to be less than anticipated.

The following sections describe some specific laws and regulations that may affect us.  We cannot predict the cost or impact of these or other future legislative or regulatory initiatives.

Regulation of Natural Gas and Oil Exploration and Production

Our operations are subject to various types of regulation at the federal, state and local levels.  Such regulation includes requiring permits for drilling wells; maintaining bonding requirements in order to drill or operate wells and regulating the location of wells; the method of drilling and casing wells; the surface use and restoration of properties upon which wells are drilled; the plugging and abandoning of wells; and the composition or disposal of chemicals and fluids used in connection with operations.  Our operations are also subject to various conservation laws and regulations.  These include regulation of the size of drilling, spacing or proration units and the density of wells that may be drilled in those units, and the unitization or pooling of oil and gas properties.  In addition,


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Denbury Resources Inc.

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

In early 2012, the President signed the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011. This act, among other things, updates federal pipeline safety standards, increases penalties for violations of such standards, gives the Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (the “PHMSA”) authority for new damage prevention and incident notification, and directs 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.  In the future, Congress may create new incentives for alternative energy sources and may also consider legislation to reduce emissions of CO2 or other greenhouse gases. This legislation, if enacted, could (1) impose a tax or other economic penalty on the production of fossil fuels that, when used, ultimately release CO2, (2) reduce the demand for, and uses of, oil, gas and other minerals, and/or (3) increase the costs incurred by us in our exploration and production activities.  The EPA has promulgated regulations requiring permitting for certain sources of greenhouse gas emissions, and in August 2015, proposed regulations to reduce methane and volatile organic compound emissions from the oil and gas sector.  The proposed rule, which the EPA expects to finalize in 2016, would 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. At the same time, legislation or regulation to reduce the emissions of CO2 or other greenhouse gases could also create economic incentives for technologies and practices that reduce or avoid such emissions, including processes that recognize the associated storage of CO2 in oil and gas reservoirs through CO2 EOR operations.

Natural Gas Gathering Regulations

State and federal regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory-take requirements.  With the increase in construction and operation of natural gas gathering lines in various states, natural gas gathering is receiving greater regulatory scrutiny from state and federal regulatory agencies, which is likely to continue in the future.

Federal, State or Indian Leases

Our operations on federal, state or Indian oil and gas leases, especially those in the Rocky Mountain region, are subject to numerous restrictions, including nondiscrimination statutes. Such operations must be conducted pursuant to certain on-site security regulations and other permits and authorizations issued by the Bureau of Land Management, the Bureau of Ocean Energy Management, the Bureau of Safety and Environmental Enforcement, the Bureau of Indian Affairs, and other federal and state stakeholder agencies. In 2015, the Department of Interior issued new regulations governing hydraulic fracturing on public and tribal lands, which regulations are currently enjoined pursuant to a court order and are subject to ongoing litigation, thus creating uncertainty regarding the future costs of hydraulic fracturing operations. However, our current hydraulic fracturing activity is limited.



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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.

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 2015, we fracture stimulated five existing wells at Hartzog Draw Field and one water source well at Tinsley Field utilizing water-based fluids with no diesel fuel component. We currently have plans to hydraulically fracture one additional water source well at Tinsley Field during 2016. We are familiar with the laws and regulations applicable to hydraulic fracturing operations and take steps to ensure compliance with these requirements.

ESTIMATED NET QUANTITIES OF PROVED OIL AND NATURAL GAS RESERVES AND PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES

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 Bachelor of Science degree in Petroleum Engineering at Texas A&M University in 1974, and he has in excess of 41 years of experience in oil and gas reservoir studies and evaluations.  Our Chief Operating Officer is primarily responsible for overseeing the independent petroleum engineering firm during the process.  Our Chief Operating Officer has a Bachelor of Science degree in Engineering, Civil Specialty, from the Colorado School of Mines and over 26 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


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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 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 Reserve Estimates

D&M prepared estimates of our net proved oil and natural gas reserves as of December 31, 2015, 2014 and 2013.  See the summary of D&M’s report as of December 31, 2015, 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.  During 2015, we provided oil and natural gas reserve estimates for 2014 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, 2014.

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, 2015, our estimated proved undeveloped reserves totaled approximately 59.2 MMBOE, or approximately 21% of our estimated total proved reserves, a decline of 39.7 MMBOE from December 31, 2014 levels for these reserves, which changes are discussed below.  Approximately 85% (50 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.

During 2015, we spent approximately $65 million to convert 10.7 MMBOE of proved undeveloped reserves to proved developed reserves, primarily related to continued tertiary development activities at Bell Creek, Heidelberg, and Brookhaven fields, as well as non-tertiary development at CCA. Other changes during 2015 included adding 2.2 MMBOE of proved undeveloped reserves primarily related to our non-tertiary operations at CCA; reclassifying 15.4 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 15.8 MMBOE, primarily the result of reserves that were determined to be uneconomic based on 2015 average oil and natural gas prices used in estimating our proved reserves, including approximately 35 Bcf (6 MMBOE) of Riley Ridge natural gas reserves. Included in the net downward revisions are positive performance revisions partially offsetting the decline in proved undeveloped reserves, primarily related to increased recovery factors at Tinsley and Oyster Bayou fields.

As of December 31, 2015, 30.0 MMBOE of our total proved undeveloped reserves are not scheduled to be developed within five years of initial booking, nearly 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.



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The following table provides certain estimated proved reserve information in total and by category, as well as related pricing information as of December 31, 2015, 2014 and 2013. 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 between December 31, 2015 and 2014, 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 $50.28 per Bbl at December 31, 2015, and for natural gas declined from $4.30 per MMBtu at December 31, 2014, to $2.63 per MMBtu at December 31, 2015. These commodity price changes resulted in a decline of approximately 126 MMBOE (29%) in our proved reserves from December 31, 2014, through 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,
 
2015
 
2014
 
2013
Estimated proved reserves
 
 
 
 
 
Oil (MBbls)
282,250

 
362,335

 
386,659

Natural gas (MMcf)
38,305

 
452,402

 
489,954

Oil equivalent (MBOE)
288,634

 
437,735

 
468,318

Reserve volumes categories
 
 
 
 
 
Proved developed producing
 
 
 
 
 
Oil (MBbls)
190,422

 
240,004

 
245,722

Natural gas (MMcf)
36,150

 
72,799

 
68,976

Oil equivalent (MBOE)
196,447

 
252,137

 
257,218

Proved developed non-producing
 
 
 
 
 
Oil (MBbls)
32,638

 
29,373

 
30,670

Natural gas (MMcf)
1,801

 
343,622

 
3,119

Oil equivalent (MBOE)
32,938

 
86,643

 
31,190

Proved undeveloped
 
 
 
 
 
Oil (MBbls)
59,190

 
92,958

 
110,267

Natural gas (MMcf)
354

 
35,981

 
417,859

Oil equivalent (MBOE)
59,249

 
98,955

 
179,910

Percentage of total MBOE
 
 
 
 
 
Proved developed producing
68
%
 
57
%
 
55
%
Proved developed non-producing
11
%
 
20
%
 
7
%
Proved undeveloped
21
%
 
23
%
 
38
%
Representative oil and natural gas prices (1)
 
 
 
 
 
Oil – NYMEX
$
50.28

 
$
94.99

 
$
96.94

Natural gas – Henry Hub
2.63

 
4.30

 
3.67

Present values (in thousands) (2)
 
 
 
 
 
Discounted estimated future net cash flows before income taxes (PV-10 Value) (3)
$
2,318,555

 
$
8,748,069

 
$
10,633,783

Standardized measure of discounted estimated future net cash flows after income taxes (“Standardized Measure”)
$
1,890,124

 
$
5,908,128

 
$
7,128,744


(1)
The reference prices were based on the arithmetic average of the first-day-of-the-month NYMEX commodity prices for each month during the respective year. These prices do not reflect adjustments for market differentials by field that are utilized in the preparation of our reserve report to arrive at the appropriate net price we receive, and also do not reflect the continued oil price declines in late 2015 and early 2016. In response to these price decreases, we have deferred our development spending for certain projects in 2016, which has been reflected in our December 31, 2015 reserve report.  See Item 7, Management’s


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Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Operating Results Table for details of oil and natural gas prices received, both including and excluding the impact of derivative settlements.

(2)
Determined based on the average first-day-of-the-month prices for each month, adjusted to prices received by field in accordance with standards set forth in the 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 $2.17 per Bbl below representative NYMEX oil prices as of December 31, 2015, compared to $3.10 per Bbl below NYMEX oil prices as of December 31, 2014, and $3.41 per Bbl above NYMEX oil prices as of December 31, 2013.

(3)
PV-10 Value is a non-GAAP measure and is different from the Standardized Measure in that PV-10 Value is a pre-tax number and the Standardized Measure is an after-tax number.  The information used to calculate PV-10 Value is derived directly from data determined in accordance with FASC Topic 932.  The difference between these two amounts, the discounted estimated future income tax, was $428.4 million at December 31, 2015; $2.84 billion at December 31, 2014; and $3.51 billion at December 31, 2013.  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 and to assess the potential return on investment in our 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.
 
Item 1A.  Risk Factors

Oil and natural gas prices are volatile. A sustained period of oil prices at their current low levels or their further deterioration 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 $35 to $111 per Bbl over the last three calendar years, and prices have declined dramatically since the fourth quarter of 2014 to less than $27 per Bbl in January 2016, the lowest level in over 13 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.  Oil prices currently affect us more than natural gas prices because oil comprised approximately 95% of our 2015 production and approximately 98% of our proved reserves at December 31, 2015. 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 decreases U.S. imports of crude oil;
worldwide political events and conditions, 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, 2015. If oil prices remain at current levels or 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;


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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 further 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.

If oil prices remain low, some or all of our tertiary projects could become uneconomical. We may further 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 prolonged credit crisis, further drops in economic growth rates in China, a severe economic contraction in Europe or turmoil in the global financial system, could materially affect our liquidity, business and financial condition.  In the past, such conditions 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 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.

If we cannot meet the New York Stock Exchange’s (“NYSE”) “price criteria” continued listing standard, the NYSE may delist our common shares, which could have an adverse impact on the trading volume, liquidity and market price of our common shares.

If we do not maintain an average closing price of $1.00 or more for our common stock over any consecutive 30 trading-day period, the NYSE may delist our common shares for a failure to maintain compliance with the price criteria continued listing standard. As of February 18, 2016, the average closing price of our common shares over the immediately preceding consecutive 30 trading-day period was $1.32. The NYSE Listed Company Manual sets out rules and processes to cure non-compliance with this standard. For instance, upon approval from the NYSE, an issuer generally has six months to cure the listing standard related to stock price (such as a reverse-stock split), during which time the issuer’s common stock would continue to be traded on the NYSE, subject to compliance with the other continued listing standards. A delisting of our common shares from the NYSE could negatively impact us because it could: (1) reduce the liquidity and market price of our common shares; (2) reduce the number of investors willing to hold or acquire our common shares, which could negatively impact our ability to raise equity financing; (3) limit our ability to use a registration statement to offer and sell freely tradable securities, thereby preventing us from accessing the public capital markets, and/or (4) affect our ability to provide equity incentives to our employees.

Our level of indebtedness may adversely affect operations and limit our growth.

As of December 31, 2015, our outstanding senior indebtedness consisted of $2.9 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 5.26% per annum, and $175.0 million principal amount outstanding under our bank credit facility.  As of February 19, 2016, we have a borrowing base of $2.6 billion and aggregate lender commitments of $1.5 billion under our bank credit facility and availability with respect to such commitments of $1.3 billion.  Our bank borrowing base is adjusted semi-annually 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


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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 in the future for working capital, capital expenditures, acquisitions, development activities or general corporate and other purposes;
potentially restricting us from making acquisitions or exploiting business opportunities;
lowering 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.

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, if oil and natural gas prices continue to remain at current levels for an extended period of time, our degree of leverage could increase significantly or our leverage metrics could deteriorate, potentially causing us to not be in compliance with our bank credit facility’s covenants (see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – 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, specified financial ratios and financial condition tests related to such indebtedness, including covenants in our bank credit facility, we would be in default under our debt instruments. 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


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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.

While mitigated somewhat by our significant emphasis on tertiary recovery operations in fields and reservoirs that have historically produced substantial volumes of oil under primary 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;
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


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period preceding the date of the assessment.  The representative oil and natural gas prices used in estimating our December 31, 2015 reserves were $50.28 per Bbl for crude oil and $2.63 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. 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, 2015, approximately 21% 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.

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.

During the last few years, 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.



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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 18, 2016, we have oil derivative contracts in place covering 36,000 Bbls/d for the first quarter of 2016, 34,000 Bbls/d for the second quarter of 2016, 24,000 Bbls/d for the third quarter of 2016, and 30,000 Bbls/d for the fourth quarter of 2016, with minimal hedges currently in place in early 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 oil field equipment, services and qualified personnel could reduce our cash flow and adversely affect results of operations.

The demand for qualified and experienced field personnel, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages in such personnel.  In the past, during periods of high oil and natural gas prices, we have experienced shortages of oil field and other necessary equipment, including drilling rigs, along with increased prices for such equipment, services and associated personnel.  These types of shortages or price increases could significantly decrease our profit margin, cash flow and operating results and/or restrict or delay our ability to drill wells and conduct our operations, possibly causing us to miss our forecasts and projections.

The marketability of our production is dependent upon transportation lines and other facilities, certain of which we do not control. When these facilities are unavailable, our operations can be interrupted and our revenues reduced.

The marketability of our oil and natural gas production depends, in part, upon the availability, proximity and capacity of transportation lines owned by third parties. In general, we do not control these transportation facilities, and our access to them may be limited or denied. A significant disruption in the availability of, and access to, these transportation lines or other production facilities could adversely impact our ability to deliver to market or produce our oil and thereby cause a significant interruption in our operations.

Our production will decline if our access to sufficient amounts of carbon dioxide is limited.

Our long-term strategy is primarily focused on our CO2 tertiary recovery operations. The crude oil production from our tertiary recovery projects depends, in large part, on having access to sufficient amounts of naturally occurring and industrial-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


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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, we may be forced to eliminate long-term equity grants, which would have a negative effect on 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, human resources personnel). Competition for persons with these skills is intense, and we cannot assure 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. Changes in, or additions to, environmental laws and regulations occur frequently, and any changes or additions that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or other environmental protection requirements could have a material adverse effect on our operations and financial position.

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.  Among these proposals are: (1) climate change/carbon tax legislation introduced in Congress, and EPA regulations to reduce greenhouse gas emissions; (2) Presidential proposals, along with legislation introduced in Congress (none of which have passed), to impose new fees or taxes on, or repeal various tax deductions available to, oil and gas producers, such as the current tax deductions for intangible drilling and development costs and qualified tertiary injectant expenses which deductions, if eliminated, could raise the cost of energy production, reduce energy investment and affect the economics of oil and gas exploration and production activities; (3) legislation previously considered by Congress (but not adopted) that would subject the process of hydraulic fracturing to federal regulation under the Safe Drinking Water Act, and new, proposed or anticipated Department of Interior and EPA regulations to impose new and more stringent regulatory requirements on hydraulic fracturing activities, particularly those performed on federal lands, and to require disclosure of the chemicals used in the fracturing process; and (4) the Pipeline Safety, Regulatory Certainty, and Job Creation Act enacted in 2011, which increases penalties, grants new authority to impose damage prevention and incident notification requirements, and directs the PHMSA to prescribe minimum safety standards for CO2 pipelines.

In recent years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal income tax laws, including the elimination of certain U.S. federal income tax benefits and deductions currently available to oil and gas companies. Such changes include, but are not limited to, (1) the repeal of the percentage depletion allowance for oil and gas properties, (2) the increase of the amortization period of geological and geophysical expenses, (3) the elimination of current deductions for intangible drilling and development costs and qualified tertiary injectant expenses, and (4) the elimination of the deduction for certain U.S. production activities. It is currently unclear whether any such proposals will be enacted into law and, if so, what form such laws might possibly take or impact they may have; however, the passage of such legislation or any other similar change in U.S. federal income tax law could eliminate, reduce or postpone certain tax deductions that are currently available to us or otherwise increase our taxes, and any such legislation or change could negatively affect the after-tax returns generated on our oil and gas investments and our financial condition and results of operations.



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Any of the foregoing described proposals, including other applicable proposals, could affect our operations and the costs thereof.  The trend toward stricter standards, increased oversight and regulation and more extensive permit requirements, along with any future laws and regulations, 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 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 (“CFTC”) 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. New or modified rules, regulations or requirements may increase the cost to our counterparties of their hedging and swap positions that they can provide or lower their availability. In addition, for uncleared swaps, the CFTC or federal banking regulators may require end-users to enter into credit support documentation or post margin collateral. Any changes in the regulations of swaps may result in certain market participants deciding to curtail or cease their derivative activities.

While many rules and regulations have been promulgated and are already in effect, other rules and regulations remain to be finalized or effectuated; therefore, the impact of those rules and regulations on us is uncertain at this time. The Dodd-Frank Act, and the rules promulgated thereunder, could (1) significantly increase 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) reduce 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 as a result of the Dodd-Frank Act and applicable rules and regulations, our cash flows may become more volatile and less predictable, which could adversely affect our ability to plan for and fund capital expenditures.

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, 2015, two purchasers individually accounted for 10% or more of our oil and natural gas revenues and, in the aggregate, for 43% 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.

We expect to continue to write down the carrying value of our oil and natural gas properties in 2016 if commodity prices continue to decline or remain at low levels.

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


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rolling period prior to the end of a particular reporting period. During 2015, 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) (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). During 2015, NYMEX oil prices declined significantly, from $53.27 per Bbl as of December 31, 2014, to $37.04 per Bbl as of December 31, 2015, and continued to decline further in early 2016. We currently expect that we will record an additional write-down in the first quarter of 2016 in excess of $400 million if oil and natural gas prices remain at or near late-February 2016 levels, as the 12-month average prices used in determining the full cost ceiling value would reflect lower prices in the first quarter of 2016 than in the first quarter of 2015. Any such write-down would also be affected, in part, by changes in proved oil and natural gas reserve volumes, future capital expenditures and operating costs.

As of December 31, 2015, our net property and equipment balance totaled $5.4 billion, representing approximately 91% of our total assets. 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.

In mid-2006, Denbury Onshore, LLC (“Denbury Onshore”), a subsidiary of Denbury Resources Inc., purchased its original interest in the Delhi Field in northeastern Louisiana from NGS Sub Corp. (“NGS”), a subsidiary of Evolution Petroleum Corporation (together with its subsidiaries, “Evolution”). Under the purchase documents, Denbury Onshore committed to develop the enhanced production of the Holt Bryant Unit (the “Unit”), which is a specific portion of Delhi Field, and after Denbury Onshore’s receipt of a defined level of net cash flow from the Unit (as defined in the agreements, “payout”), to assign a reversionary interest in the Unit back to NGS. After several years of dispute regarding payout calculations and related contractual terms, in December 2013, Evolution filed suit against Denbury Onshore in the 133rd Judicial District Court in Houston, Harris County, Texas for unspecified damages. Evolution’s most recent amended petition alleges breach of contract, and requests a declaratory judgment as to various provisions of the purchase documents and accompanying oil and gas conveyancing instruments, including as to the method of calculation and timing of payout, the sharing of various costs, and the timing and extent of post-payout assignments from Denbury Onshore to NGS. Evolution also brings claims for negligence and gross negligence in connection with the June-2013 Delhi Field release of well fluids. Evolution states in its amended petition that it is seeking over $200 million in damages in addition to unspecified punitive damages and attorneys’ fees. In Denbury Onshore’s answer and counterclaim, we have denied Evolution’s claims, alleged breach of contract by Evolution for failing to convey the full interest for which we paid and for violating our preferential purchase rights, and asked for a declaratory judgment as to various purchase document terms, including those pertaining to the determination of payout, the assignment provisions of the documents, and cost sharing.



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Discovery in the case is ongoing. The case is currently set for trial in April 2016, although the parties have filed a motion to move the trial setting to July 2016. We believe that Evolution’s claims in this matter are without merit and intend to vigorously defend against them and pursue our rights under the purchase documents.

Item 4.  Mine Safety Disclosures

Not applicable.


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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, 2016, 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 1,769.  On February 25, 2016, the last reported sale price of Denbury’s common stock, as reported on the NYSE, was $1.07 per share.
 
2015
 
2014
 
High
 
Low
 
Dividends Declared Per Share
 
High
 
Low
 
Dividends Declared Per Share
First Quarter
$
8.78

 
$
6.26

 
$
0.0625

 
$
16.44

 
$
15.33

 
$
0.0625

Second Quarter
9.20

 
6.16

 
0.0625

 
18.31

 
16.14

 
0.0625

Third Quarter
5.74

 
2.44

 
0.0625

 
18.12

 
14.93

 
0.0625

Fourth Quarter
4.24

 
1.89

 

 
14.41

 
6.34

 
0.0625


In all four quarters of 2014 and in each of the first three quarters of 2015, the Company’s Board of Directors declared quarterly cash dividends of $0.0625 per common share. On September 21, 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 effective after payment of our third quarter dividend on September 29, 2015. For further discussion, see Note 6, Stockholders’ Equity, to the Consolidated Financial Statements. No unregistered securities were sold by the Company during 2015.

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 2015
 
1,744,764

 
$
2.78

 
1,734,691

 
$
210.1

November 2015
 
940

 
3.64

 

 
210.1

December 2015
 
5,406

 
2.50

 

 
210.1

Total
 
1,751,110

 
 
 
1,734,691

 



(1)
Stock repurchases during the fourth quarter of 2015 other than those under our common stock repurchase program 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. The program has no pre-established ending date and may be suspended or discontinued at any time. In September 2015, the Company’s Board of Directors reinstated the ability to repurchase shares under our share repurchase program, which authorization was suspended in November of 2014. 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, 2015, 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 an additional $210.1 million remaining authorized for purchases of common stock under this repurchase program.


34


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, 2015, 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, 2010, to December 31, 2015.

COMPARISON OF 5-YEAR CUMULATIVE TOTAL RETURN
 
December 31,
 
2010
 
2011
 
2012
 
2013
 
2014
 
2015
Denbury Resources Inc.
$
100

 
$
79

 
$
85

 
$
86

 
$
43

 
$
11

S&P 500
100

 
102

 
118

 
157

 
178

 
181

Dow Jones U.S. Exploration & Production
100

 
96

 
101

 
134

 
119

 
91




35


Denbury Resources Inc.

Item 6. Selected Financial Data
 
 
Year Ended December 31,
In thousands, except per-share data or otherwise noted
 
2015
 
2014
 
2013
 
2012
 
2011
Consolidated Statements of Operations data
 
 
 
 
 
 
 
 
 
 
Revenues and other income
 
 
 
 
 
 
 
 
 
 
Oil, natural gas, and related product sales
 
$
1,213,026

 
$
2,372,473

 
$
2,466,234

 
$
2,409,867

 
$
2,269,151

Other
 
44,534

 
62,732

 
50,893

 
46,605

 
40,173

Total revenues and other income
 
$
1,257,560

 
$
2,435,205

 
$
2,517,127

 
$
2,456,472

 
$
2,309,324

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

 
409,597

 
525,360

 
573,333

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

 
1.12

 
1.36

 
1.45

Diluted (1)
 
(12.57
)
 
1.81

 
1.11

 
1.35

 
1.43

Dividends declared per common share (2)
 
0.1875

 
0.25

 

 

 

Weighted average number of common shares outstanding
 
 
 
 
 
 
 
 
 
 
Basic
 
348,802

 
348,962

 
366,659

 
385,205

 
396,023

Diluted
 
348,802

 
351,167

 
369,877

 
388,938

 
400,958

Consolidated Statements of Cash Flows data
 
 
 
 
 
 
 
 
 
 
Cash provided by (used in)
 
 
 
 
 
 
 
 
 
 
Operating activities
 
$
864,304

 
$
1,222,825

 
$
1,361,195

 
$
1,410,891

 
$
1,204,814

Investing activities
 
(550,185
)
 
(1,076,755
)
 
(1,275,309
)
 
(1,376,841
)
 
(1,605,958
)
Financing activities
 
(334,460
)
 
(135,104
)
 
(172,210
)
 
45,768

 
37,968

Production (average daily)
 
 
 
 
 
 
 
 
 
 
Oil (Bbls)
 
69,165

 
70,606

 
66,286

 
66,837

 
60,736

Natural gas (Mcf)
 
22,172

 
22,955

 
23,742

 
29,109

 
29,542

BOE (6:1)
 
72,861

 
74,432

 
70,243

 
71,689

 
65,660

Unit sales prices – excluding impact of derivative settlements
 
 
 
 
 
 
 
 
 
 
Oil (per Bbl)
 
$
47.30

 
$
90.74

 
$
100.67

 
$
97.18

 
$
100.03

Natural gas (per Mcf)
 
2.35

 
4.07

 
3.53

 
3.05

 
4.79

Unit sales prices – including impact of derivative settlements
 
 
 
 
 
 
 
 
 
 
Oil (per Bbl)
 
$
67.41

 
$
90.82

 
$
100.64

 
$
96.77

 
$
98.90

Natural gas (per Mcf)
 
2.83

 
3.99

 
3.53

 
5.67

 
7.34

Costs per BOE
 
 
 
 
 
 
 
 
 
 
Lease operating expenses (3)
 
$
19.37

 
$
23.84

 
$
28.50

 
$
20.29

 
$
21.17

Taxes other than income
 
4.13

 
6.25

 
6.87

 
6.10

 
6.16

General and administrative expenses
 
5.44

 
5.83

 
5.66

 
5.49

 
5.24

Depletion, depreciation, and amortization
 
19.99

 
21.83

 
19.89

 
19.34

 
17.07

Proved oil and natural gas reserves (4)
 
 
 
 
 
 
 
 
 
 
Oil (MBbls)
 
282,250

 
362,335

 
386,659

 
329,124

 
357,733

Natural gas (MMcf)
 
38,305

 
452,402

 
489,954

 
481,641

 
625,208

MBOE (6:1)
 
288,634

 
437,735

 
468,318

 
409,398

 
461,934

Proved carbon dioxide reserves
 
 
 
 
 
 
 
 
 
 
Gulf Coast region (MMcf) (5)
 
5,501,175

 
5,697,642

 
6,070,619

 
6,073,175

 
6,685,412

Rocky Mountain region (MMcf) (6)
 
1,237,603

 
3,035,286

 
3,272,428

 
3,495,534

 
2,195,534

Proved helium reserves associated with Denbury’s production rights (7)
 
 
 
 
 
 
 
 
 
 
Rocky Mountain region (MMcf)
 

 
13,231

 
13,251

 
12,712

 
12,004

Consolidated Balance Sheets data
 
 
 
 
 
 
 
 
 
 
Total assets
 
$
5,919,824

 
$
12,727,802

 
$
11,788,737

 
$
11,139,342

 
$
10,184,424

Total long-term liabilities
 
4,297,897

 
6,383,821

 
5,812,132

 
5,408,032

 
4,716,659

Stockholders’ equity
 
1,248,912

 
5,703,856

 
5,301,406

 
5,114,889

 
4,806,498




36


Denbury Resources Inc.


(1)
Includes pre-tax full cost pool ceiling test write-downs of $4.9 billion and an impairment of goodwill charge of $1.3 billion for the year ended December 31, 2015.

(2)
On September 21, 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 effective after payment of our third quarter dividend on September 29, 2015.

(3)
If lease operating expenses were adjusted to exclude certain costs to remediate an area of Delhi Field due to a 2013 release, related insurance recoveries and other reimbursements recorded in 2015, 2014 and 2013, 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 (see Management’s Discussion and Analysis of Financial Condition and Results of Operations Capital Resources and Liquidity Insurance Recoveries to Cover Costs of 2013 Delhi Field Release).

(4)
Estimated proved reserves as of December 31, 2012, reflect the disposition of reserves associated with our Bakken area assets sold in late 2012 (approximately 109 MMBOE), but do not include then-estimated reserves of approximately 42.2 MMBOE related to the CCA acquisition from ConocoPhillips, which closed during the first quarter of 2013. 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, and average first-day-of-the-month NYMEX natural gas price used to estimate reserves from $4.30 per MMBtu at December 31, 2014, to $2.63 per MMBtu at December 31, 2015.

(5)
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 4.4 Tcf, 4.5 Tcf, 4.8 Tcf, 4.8 Tcf and 5.3 Tcf at December 31, 2015, 2014, 2013, 2012 and 2011, respectively, and include reserves dedicated to volumetric production payments of 25.3 Bcf, 9.3 Bcf, 28.9 Bcf, 57.1 Bcf and 84.7 Bcf at December 31, 2015, 2014, 2013, 2012 and 2011, respectively (see Supplemental CO2 and Helium Disclosures (Unaudited) to the Consolidated Financial Statements).

(6)
Proved CO2 reserves in the Rocky Mountain region consist of our reserves at Riley Ridge (presented on a gross (8/8ths) basis) and our overriding royalty interest in LaBarge Field, of which our net revenue interest was approximately 1.2 Tcf, 2.6 Tcf, 2.9 Tcf, 2.9 Tcf and 1.6 Tcf at December 31, 2015, 2014, 2013, 2012 and 2011, respectively. As of December 31, 2015, Riley Ridge CO2 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.

(7)
Reserves associated with helium production rights include helium reserves located in the acreage in the Rocky Mountain region for which we have the contractual right to extract the helium on behalf of the U.S. government, which owns the helium. Our extraction agreement with the U.S. government gives us the ability to produce the helium on behalf of the U.S. government in exchange for a fee, which amount fluctuates based upon the realized sales proceeds we receive for the helium.  The estimate of helium reserves is reduced to reflect the estimated fee we will remit to the U.S. government. Our extraction agreement with the U.S. government has a minimum term extending 20 years from first production and continuing thereafter until either party terminates the contract. Reserve volumes presented herein assume that the term of this helium extraction agreement continues beyond 20 years, given the benefit to both parties to the agreement. As of December 31, 2015, there was no helium production at Riley Ridge, as the Riley Ridge gas processing facility was and continues to be shut-in. As of December 31, 2015, Riley Ridge 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.


37


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 $35 to $111 per Bbl over the last three calendar years, and prices have declined dramatically since the fourth quarter of 2014 to less than $27 per Bbl in January 2016, the lowest level in over 13 years. The following charts illustrate the fluctuations in our realized oil and natural gas prices, excluding the impact of commodity derivative settlements, during 2013, 2014 and 2015.

        

 
 
Oil price per Bbl
 
Natural gas price per Mcf
Average realized prices
 
2013
 
2014
 
2015
 
2013
 
2014
 
2015
First quarter
 
$
105.59

 
$
97.69

 
$
46.02

 
$
3.28

 
$
4.71

 
$
2.54

Second quarter
 
98.92

 
100.04

 
56.92

 
3.96

 
4.39

 
2.44

Third quarter
 
105.91

 
94.78

 
45.74

 
3.38

 
3.55

 
2.40

Fourth quarter
 
93.00

 
70.80

 
40.41

 
3.50

 
3.54

 
2.00


In response to the decline in oil prices, we made adjustments during 2015 to our business to preserve our financial strength and flexibility. These adjustments included: (1) reducing our 2015 development capital spending to approximately 39% of 2014 levels, and $457.1 million less than our 2015 cash flow from operations, (2) reducing our operating costs and identifying new innovation and improvement ideas for our fields, which has resulted in meaningful decreases to most categories of our lease operating expenses and general and administrative expenses, and cost savings on capital projects, (3) modifying certain of our bank covenants applicable to the 2016, 2017 and 2018 periods to mitigate concern around our ability to access our bank credit line if oil prices remain low for an extended period of time, (4) shutting-in wells that have become uneconomic to either produce or repair in the current price environment, and (5) suspending our quarterly cash dividend effective after payment of our third quarter dividend on September 29, 2015 (see Capital Resources and Liquidity – Dividends below for further discussion). As a result of these adjustments and the commodity hedges we had in place for 2015, our cash flow from operations in 2015 exceeded the total of our development capital expenditures and dividends by $391.7 million, with which we were able to reduce our credit facility borrowings from $395.0 million at December 31, 2014, to $175.0 million at December 31, 2015.


38


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



With the further decline in early 2016 in already depressed oil and natural gas prices, as well as our reduced hedging levels in 2016 and uncertainty around future prices, we are continuing to make adjustments to our business to preserve financial strength and flexibility. To accommodate our lower projected cash flow from operations, our 2016 capital spending has been budgeted at approximately $200 million, excluding capitalized interest and acquisitions, which is less than half of 2015 levels, and is not adequate to maintain current production levels. Therefore, we currently anticipate production declines in 2016 in the range of approximately seven to twelve percent from average 2015 levels, approximately 60% of which relates to natural production declines, with the remainder related to wells that are uneconomic to either produce or repair in the current price environment.

As more fully discussed under Capital Resources and Liquidity below, our liquidity remains high with nearly $1.3 billion of undrawn bank line availability as of February 19, 2016. Our focus is on preserving our cash and minimizing our spending as we anticipate that our bank line availability is likely to be reduced in the future as bank price decks continue to decrease, reducing the ultimate collateral value of our assets, along with tightening regulatory constraints. We have also obtained further relief on our bank covenants to avoid covenant compliance issues in the last half of 2016 after our higher valued hedges expire. Lastly, we have recently entered into oil swaps for the second half of 2016 to further protect our liquidity, so we now have hedges covering an average of 27,000 Bbls/d in the third and fourth quarters at a weighted-average price of approximately $41 per barrel, locking in prices that at least cover our total cash costs, which were within a per-barrel range in the low-to-mid $30’s in the fourth quarter of 2015, including corporate overhead and interest. As a result of these and other steps outlined above, we anticipate having sufficient liquidity to continue operations until oil prices improve, which we currently anticipate will likely be sometime during the next twelve to eighteen months.

During this period of reduced capital spending, we continue 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 due to increased efficiency and reducing costs. These initiatives aim to increase the profitability of our assets, making them more resilient to lower oil prices. We will continue to evaluate the timing of development of our inventory of fields and related pipelines and facilities, which will be largely dependent upon commodity prices.

2015 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 $47.30 per Bbl during 2015. During 2015, we recognized a net loss of $4.4 billion, or $12.57 per diluted common share, compared to net income of $635.5 million, or $1.81 per diluted common share, during 2014.  This decrease in net income between the comparative periods was principally due to a full cost pool ceiling test write-down of our oil and natural gas properties totaling $4.9 billion ($3.1 billion net of tax) (see Write-Down of Oil and Natural Gas Properties below) and a goodwill impairment charge totaling $1.3 billion ($1.2 billion net of tax) (see Impairment of Goodwill below). Other significant changes between 2015 and 2014 were a