10-K 1 dnr-20131231x10k.htm FORM 10-K DNR - 2013.12.31 - 10K


 

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

2013 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, 2013
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 definition 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 Exchange Act Rule 12b-2).  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 $5,625,842,252.

The number of shares outstanding of the registrant’s Common Stock as of January 31, 2014, was 355,982,927.
DOCUMENTS INCORPORATED BY REFERENCE
Document:
 
Incorporated as to:
1. Notice and Proxy Statement for the Annual Meeting of Stockholders to be held May 20, 2014.
 
1.  Part III, Items 10, 11, 12, 13, 14

 




Denbury Resources Inc.

2013 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.
 
 
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.
 
 
Mbtu
One thousand Btus.
 
 
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 cash settlements on commodity derivatives during the period. Its use is further discussed in Management’s Discussion and Analysis of Financial Condition – 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.
 
 

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Denbury Resources Inc.

Proved Developed Reserves*
Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
 
 
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 its use is further discussed in footnote 4 to the table included in Item 1, Estimated Net Quantities of Proved Oil and Natural Gas Reserves and Present Value of Estimated Future Net Revenues – Oil and Natural Gas Reserve Estimates.

 
 
Tcf
One trillion cubic feet of natural gas, 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?c=ecfr&rgn=div5&view=text&node=17:2.0.1.1.8&idno=17.

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Denbury Resources Inc.

PART I

Item 1. Business and Properties

GENERAL

Denbury Resources Inc., a Delaware corporation, is a growing, dividend-paying, domestic oil and natural gas company with 468.3 MMBOE of estimated proved oil and natural gas reserves as of December 31, 2013, of which 83% is oil.  Our primary focus is on enhanced oil recovery utilizing CO2, and our operations are focused in two key operating areas: the Gulf Coast and Rocky Mountain regions.  Our goal is to increase the value of acquired properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to tertiary recovery operations.

As part of our corporate strategy, we believe in the following fundamental principles:

focus in 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;
acquire 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;
return a portion of the cash flow generated from our operations to shareholders through regular quarterly dividend payments, and repurchases of our common stock made from time to time; 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, 2013, we had 1,501 employees, 807 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 Internet website, www.denbury.com, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.  The SEC also maintains a website, 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.

2012 AND 2013 MAJOR PROPERTY EXCHANGES AND ACQUISITIONS

We set the stage for our 2013 business developments with two major transactions. In December 2012, we closed a sale and exchange transaction with Exxon Mobil Corporation and its wholly-owned subsidiary XTO Energy Inc, (collectively, "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"). We utilized cash received in this exchange to fund our March 2013 acquisition of producing assets in the Cedar Creek Anticline ("CCA") in Montana and North Dakota from ConocoPhillips Company ("ConocoPhillips") for $1.05 billion in cash, before closing adjustments.

Taken together, these two asset transactions nearly replaced the production of the sold assets with production from the acquired assets, exchanged proved reserves with a high proved undeveloped component in the Bakken for reserves that were nearly all proved developed in CCA, increased our Rocky Mountain CO2 reserves by 1.3 Tcf and our CO2 deliverability by up to 115 MMcf/d, and positioned us to provide dividends to our stockholders as discussed below.


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Denbury Resources Inc.

2013 BUSINESS DEVELOPMENTS

In the fourth quarter of 2013, following a comprehensive review of our long-term plans, we announced our intention to expand our shareholder value proposition to include both growth and income. The expansion includes the initiation of regular quarterly cash dividend payments to our shareholders starting with $0.0625 per share (a rate of $0.25 per share on an annualized basis). The first quarterly cash dividend of $0.0625 was declared on January 28, 2014, payable March 25, 2014, to shareholders of record as of the close of business on February 25, 2014. Based on our current financial projections and commodity price outlook, we expect to grow our annual dividend rate to between $0.50 per share and $0.60 per share in 2015 and at a sustainable rate thereafter. All dividends are discretionary and subject to declaration by Denbury’s Board of Directors.

To expand our free cash flow, we adjusted certain of our development plans and timelines for various capital projects, principally in the Rocky Mountain region, in order to reduce our spending on certain major infrastructure projects over the next few years. These adjustments allowed us to accelerate our plan of providing a return to our shareholders through a growing cash dividend, while still growing our reserves and production. Our focused strategy, significant inventory of development projects and proven track record of value creation give us confidence that we can deliver a long-term cash flow profile that is unique among independent oil companies and successfully execute on our value-driven growth and income strategy in 2014 and beyond.

2013 business developments also include the following:

Increased our average tertiary oil production to 38,477 Bbls/d in 2013, a 9% increase from average tertiary production in 2012, primarily due to continued field development and expansion of facilities in our existing CO2 floods at Delhi, Hastings, Heidelberg and Oyster Bayou fields.

Added total proved reserves of 84.6 MMBOE including estimated proved tertiary reserves of 34.0 MMBbls at Bell Creek Field, proved non-tertiary reserves of 42.2 MMBOE (added through our 2013 acquisition of interests at CCA) and 8.4 MMBOE of other additions or revisions.

Added estimated proved CO2 reserves of 350 Bcf as a result of successful drilling in the Jackson Dome area, our primary source of CO2 for the Gulf Coast region.

Continued our share repurchase program, under which we repurchased a total of 16.5 million shares of Denbury common stock for $277.8 million during 2013. We have purchased a total of 59.4 million shares of Denbury common stock (approximately 14.8% of our outstanding shares of common stock at September 30, 2011) for $931.2 million, or an average of $15.68 per share, since commencement of the share repurchase program in October 2011 and continuing through February 20, 2014. As of February 20, 2014, we had $230.7 million remaining for future purchases under our authorized share repurchase program.

Commenced injection of CO2 into our first two tertiary floods in the Rocky Mountain region, Bell Creek Field in Montana and Grieve Field in Wyoming during the first half of 2013, and commenced our first tertiary oil production in that region from Bell Creek Field during the third quarter of 2013.

Placed our Riley Ridge gas processing facility into service in the fourth quarter of 2013.

Commenced a horizontal oil drilling program at Hartzog Draw Field in the Powder River Basin of Wyoming targeting the Shannon formation. We expect the horizontal wells to increase the field's non-tertiary oil production and reserves and to eventually be utilized in our planned future CO2 flood of the field.

Issued $1.2 billion of 4 5/8% Senior Subordinated Notes due 2023 in February 2013. The net proceeds of approximately $1.18 billion were used to repurchase or redeem our 9½% Senior Subordinated Notes due 2016 and our 9¾% Senior Subordinated Notes due 2016, and to pay down a portion of outstanding borrowings on our bank credit facility.

Closed our acquisition of producing assets in the CCA in Montana and North Dakota in March 2013 from a wholly-owned subsidiary of ConocoPhillips for $1.05 billion in cash, before closing adjustments. The assets purchased include both additional interests in certain of our existing operated fields in CCA, as well as operating interests in other CCA fields.

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Denbury Resources Inc.


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 in Montana, North Dakota and Wyoming.  Our primary focus is using CO2 in EOR, and we expect the development plan for our current portfolio of CO2 EOR projects will allow us to grow our oil production for the remainder of the decade.

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, its only significant naturally occurring source of CO2. These large volumes of naturally occurring CO2 have allowed us to significantly grow our production in that region. In addition to the sources of CO2 we currently own, in 2013 we began to purchase and use anthropogenic (man-made) CO2 in our tertiary operations. We believe these man-made sources of CO2 will help us recover additional oil from mature oil fields while also providing an economical way to reduce atmospheric CO2 emissions through the concurrent underground storage of CO2 from our oil-producing EOR operations, and expect the amount of anthropogenic CO2 we use in such operations to grow in the future.

Through December 31, 2013, we have invested a total of $3.5 billion in our tertiary fields in the Gulf Coast region (including allocated acquisition costs and amounts assigned to goodwill), have recovered all of these costs, and have generated $1.5 billion of excess net cash flow (revenue less operating expenses and capital expenditures, excluding capital expenditures related to pipelines and CO2 source fields).  Of this total invested amount, approximately $206.7 million (6%) has been spent on fields that did not yet have any appreciable proved reserves at December 31, 2013.  The proved oil reserves in our Gulf Coast tertiary oil fields have a year-end 2013 PV-10 Value of $6.1 billion.  Including the Green Pipeline, which currently serves our Hastings and Oyster Bayou fields, we have invested a total of $2.1 billion in CO2-producing assets and pipelines in the Gulf Coast region.

We began operations in the Rocky Mountain region in 2010 as part of our merger with Encore Acquisition Company ("Encore").  In late 2012, we completed construction of the first section of the 20-inch Greencore Pipeline, our first CO2 pipeline in the Rocky Mountain region, and received our first CO2 deliveries from the Lost Cabin gas plant in central Wyoming during the first quarter of 2013. We also began injecting CO2 into Grieve Field in Wyoming early in 2013 and currently expect initial tertiary oil production from Grieve Field in 2015.  We started injections at our Bell Creek Field in Montana during the second quarter of 2013, with tertiary oil production from this field commencing in the third quarter of 2013. In addition to our current tertiary floods in the Rocky Mountain region, we currently have long-term plans to flood Hartzog Draw Field and CCA after we perform additional non-tertiary development of these fields. CCA is a geological structure over 126 miles in length consisting of 14 different operating areas. Our Riley Ridge Field acquisitions in 2010 and 2011 and acquisition of an interest in CO2 reserves from ExxonMobil in 2012 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, 2013, and average daily production and net revenue interest ("NRI") for 2013.  The reserve estimates for all years presented were prepared by DeGolyer and MacNaughton, independent petroleum engineers located in Dallas, Texas.  We serve as operator of virtually all of our significant properties, in which we also own most of the interests, although typically less than a 100% working interest, and a lesser NRI due to royalties and other burdens.  For additional oil and natural gas reserves information, see Estimated Net Quantities of Proved Oil and Natural Gas Reserves and Present Value of Estimated Future Net Revenues below.

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Denbury Resources Inc.

 
Proved Reserves as of December 31, 2013 (1)
 
2013 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 2013 NRI
Tertiary oil and gas properties
 
 
 
 
 
 
 
 
 
 
Gulf Coast region
 
 
 
 
 
 
 
 
 
 
Mature properties:
 
 
 
 
 
 
 
 
 
 
Brookhaven
10,069


10,069

2.2
%
$
363,644

 
2,223


 
81.2
%
Eucutta
8,074


8,074

1.7
%
267,583

 
2,514


 
83.6
%
Mallalieu
5,700


5,700

1.2
%
220,759

 
2,050


 
78.0
%
Other mature properties (3)
24,756


24,756

5.3
%
747,767

 
7,016


 
73.8
%
Total mature properties
48,599


48,599

10.4
%
1,599,753

 
13,803


 
77.2
%
Delhi
26,449

17,856

29,425

6.3
%
747,334

 
5,149


 
76.3
%
Hastings
43,424


43,424

9.3
%
1,106,246

 
3,984


 
81.7
%
Heidelberg
34,496


34,496

7.3
%
1,097,130

 
4,466


 
81.4
%
Oyster Bayou
15,132


15,132

3.2
%
550,025

 
2,968


 
87.0
%
Tinsley
25,344


25,344

5.4
%
1,018,938

 
8,051


 
81.1
%
Total Gulf Coast region
193,444

17,856

196,420

41.9
%
6,119,426

 
38,421


 
79.5
%
Rocky Mountain region
 
 
 
 
 
 
 
 
 
 
Bell Creek
34,015


34,015

7.3
%
739,019

 
56


 
84.8
%
Total Rocky Mountain region
34,015


34,015

7.3
%
739,019

 
56


 
84.8
%
Total tertiary oil properties
227,459

17,856

230,435

49.2
%
6,858,445

 
38,477


 
79.5
%
Non-tertiary oil and gas properties
 
 
 
 
 
 
 
 
 
 
Gulf Coast region
 
 
 
 
 
 
 
 
 
 
Mississippi
4,514

33,290

10,062

2.1
%
195,138

 
1,234

8,766

 
26.1
%
Texas
30,988

18,105

34,006

7.3
%
814,609

 
5,549

5,946

 
79.1
%
Other
6,609

1,386

6,840

1.5
%
147,406

 
983

686

 
26.4
%
Total Gulf Coast region
42,111

52,781

50,908

10.9
%
1,157,153

 
7,766

15,398

 
48.7
%
Rocky Mountain region
 
 
 
 
 
 
 
 
 
 
Cedar Creek Anticline (4)
105,396

6,043

106,403

22.7
%
2,335,966

 
16,406

997

 
79.6
%
Riley Ridge

399,373

66,562

14.2
%
27,810

 

64

 
61.4
%
Other
11,693

13,901

14,010

3.0
%
254,409

 
3,637

7,283

 
29.4
%
Total Rocky Mountain region
117,089

419,317

186,975

39.9
%
2,618,185

 
20,043

8,344

 
60.5
%
Total non-tertiary oil and gas properties
159,200

472,098

237,883

50.8
%
3,775,338

 
27,809

23,742

 
56.2
%
Company Total
386,659

489,954

468,318

100
%
$
10,633,783

 
66,286

23,742

 
68.2
%

(1)
The reserves were prepared in accordance with Financial Accounting Standards Board Codification ("FASC") Topic 932, Extractive Industries – Oil and Gas, using the arithmetic average of the first-day-of-the-month NYMEX commodity price for each month during 2013. These prices were $96.94 per Bbl for crude oil and $3.67 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 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 $7.1 billion at December 31, 2013.  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 PV-10 Value is derived directly from data determined in accordance with FASC Topic 932.  See the definition of PV-10 Value in the Glossary and Selected Abbreviations.


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Denbury Resources Inc.

(3)
Other mature properties include Cranfield, Little Creek, Lockhart Crossing, Martinville, McComb and Soso fields in Mississippi and Lockhart Crossing 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 at 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.  CO2 tertiary floods are unique in that they require large volumes of CO2. The terms "tertiary flood," "CO2 flood" and "CO2 EOR" are used interchangeably throughout this document.

While enhanced oil recovery projects utilizing CO2 have been successfully performed by numerous oil and gas companies in a wide range of oil-bearing reservoirs in different oil-producing basins, we apply what we have learned and developed over the years to fields to improve and increase sweep efficiency within the CO2 EOR projects we operate, which include (1) well evaluation and monitoring methods, (2) monitoring the flood and striving to direct the CO2 to all economically recoverable portions of the oil-bearing reservoirs, (3) new completion techniques, (4) varied operating equipment and operating methods, and (5) application of intense reservoir management and production techniques.  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 a greater percentage on CO2 EOR and, over time, transformed our strategy to focus primarily, and now almost exclusively, on owning and operating oil fields that are well suited for CO2 EOR projects, although 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.  With the sale of our Bakken area assets in 2012, 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.  We believe our investments, experience and acquired knowledge give us a strategic and competitive advantage in the areas in which we operate.

Our tertiary operations have grown so that (1) 49% of our proved reserves at December 31, 2013 are proved tertiary oil reserves; (2) 55% of our 2013 production was related to tertiary oil operations (on a BOE basis); and (3) 77% of our 2013 capital expenditures (excluding acquisitions) were related to our tertiary oil operations.  At year-end 2013, the proved oil reserves in our tertiary recovery oil fields had an estimated PV-10 Value of approximately $6.9 billion, or 64% 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 these pipelines and production facilities is greater than in primary oil recovery, 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) a reasonable rate of return at relatively low oil prices (we currently estimate our economic break-even point before corporate-related overhead, based on currently estimated expenses, occurs at oil prices in the low-to-mid $40-per-barrel range, 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 anthropogenic CO2 in the same underground formations that had 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, and we believe that it, together with the related CO2 pipeline infrastructure, provides us a significant strategic advantage in the acquisition of other properties in Mississippi, Louisiana and southeastern Texas that are well suited for CO2 EOR.


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Denbury Resources Inc.

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 to approximately 6.1 Tcf as of December 31, 2013.  The CO2 reserve estimates are based on a gross working interest of the CO2 reserves, of which our net revenue interest is approximately 4.8 Tcf, and is included in the evaluation of proved CO2 reserves prepared by our outside reserves engineer, DeGolyer and MacNaughton.  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 the proved reserves, we estimate that we have 2.5 Tcf of probable CO2 reserves at Jackson Dome.  The majority of our probable reserves at Jackson Dome are located in structures that have been drilled and tested in the area but are not currently capable of producing or are not considered proved 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; (3) they are in undrilled structures where we have sufficient subsurface data, and seismic and geophysical attributes that provide a high degree of certainty that CO2 is present; or (4) they are reserves associated with increasing the ultimate recovery factor from our existing reservoirs with proved reserves.  Our historically high drilling success rate, coupled with our seismic data across the undrilled structures, provide us with a reasonably high degree of certainty that additional proved CO2 reserves will be discovered and developed.

Although our current proved CO2 reserves are quite large, 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, and anticipate drilling one development well in 2014 that is intended to increase the area's productive capacity.

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. We expect our current proved reserves of CO2, coupled with a risked drilling program at Jackson Dome and expected anthropogenic sources, to provide sufficient quantities of CO2 for us to develop our proved and probable EOR reserves in the Gulf Coast region. Additionally, in the future, we believe that once a CO2 flood in a field reaches its productive economic limit, we could recycle a portion of any CO2 that remains in that reservoir and utilize it for oil production in another tertiary flood.

In the Gulf Coast region, we also currently sell CO2 to third-party industrial users under contracts of various terms and currently have three CO2 volumetric production payment contracts.  Approximately 91% of our average daily CO2 produced or acquired from anthropogenic sources in 2013, 2012 and 2011 was used in our tertiary recovery operations, with the balance delivered to third-party industrial users.  During 2013, we used an average of 913 MMcf/d of CO2 (including CO2 from anthropogenic sources) for our tertiary activities.

Gulf Coast Anthropogenic CO2 Sources.  In addition to our natural source of CO2, we are currently party to four long-term contracts to purchase man-made CO2 from four plants.  We currently purchase anthropogenic CO2 from an industrial facility in Port Arthur, Texas and from a plant in Geismar, Louisiana, and we anticipate taking deliveries in late 2014 from Mississippi Power's Kemper County Energy Facility. We estimate these three sources will supply, in the aggregate, approximately 185 MMcf/d of CO2 to our EOR operations, although under certain circumstances they could provide higher or lower volumes.  If the fourth plant for which we have a long-term CO2 purchase contract were also to be built (targeted for the 2018 time frame), we currently estimate this source in Lake Charles, Louisiana could potentially add another 200 MMcf/d of CO2 volumes to our anthropogenic sources.  Construction of this remaining plant is considered probable, although such construction is contingent on the satisfactory resolution of various matters, including financing.  Additionally, we are in ongoing discussions with other parties who have plans to construct plants near the Green Pipeline.

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

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Denbury Resources Inc.

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 source.  Since 2001 we have acquired or constructed nearly 750 miles of CO2 pipelines, which give us the ability to deliver CO2 throughout the Gulf Coast region.  As of December 31, 2013, we have access to over 940 miles of CO2 pipelines in the Gulf Coast region. In addition to the NEJD CO2 pipeline, the major pipelines are the Free State Pipeline (90 miles), the Delta Pipeline (110 miles), the Green Pipeline Texas (120 miles), and the Green Pipeline Louisiana (200 miles).

Completion of the Green Pipeline allowed for the first CO2 injection into Hastings Field, located near Houston, Texas, in 2010, and gives us the ability to deliver CO2 to oil fields all along the Gulf Coast from Baton Rouge, Louisiana, to Alvin, Texas.  At the present time, most of the CO2 flowing in the Green Pipeline is delivered from the Jackson Dome area, but we began receiving anthropogenic 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.  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 the Houston area.

Tertiary Properties with Tertiary Production and Proved Tertiary Reserves at December 31, 2013

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 36% of our total 2013 CO2 EOR production and approximately 21% 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. In 2014, we plan to invest approximately $115 million to further develop our mature tertiary properties.

In order to improve the oil recovery of our more mature CO2 EOR projects, we have experimented with various techniques such as cement squeezes (injection and producing wells), chemical squeezes, perforation design, mechanical isolation assemblies and operating pressure controls.  We have also utilized water-alternating-gas injections, where water is substituted for the CO2 for a given volume and then CO2 is injected behind the water. Each one of these processes has had some success, and we plan to continue to utilize them in the future where appropriate.

From the time we originally acquired these properties through December 31, 2013, we have recovered all our costs relating to our mature properties, and the excess net cash flow (revenue less operating expenses and capital expenditures, including the acquisition costs) from the mature properties through that date was $1.9 billion.  As of December 31, 2013, the estimated PV-10 Value of our mature properties was $1.6 billion.

Delhi Field. Delhi Field is located east of Monroe, Louisiana.  During May 2006, we purchased Delhi for $50 million, plus an approximate 25% reversionary interest to the seller after we receive $200 million in "total net cash flow," as defined.  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 in the fourth quarter of 2013 averaged 4,793 Bbls/d, down from 5,237 Bbls/d in the fourth quarter of 2012.  This decline in production is primarily related to our efforts to remediate a release of well fluids within an area of Delhi Field in the second quarter of 2013, consisting of a mixture of carbon dioxide, saltwater, natural gas and oil. During 2013, we recorded $114.0 million of lease operating expenses in our Consolidated Statement of Operations related to this incident. Costs incurred as a result of the release, together with lower production levels, are currently expected to delay the effective date of the reversionary interest into 2014, the specific timing of which is dependent upon, among other things, the amount and timing of any potential insurance proceeds received and their application to the calculation of "total net cash flow," as well as oil prices, production, and production costs. We currently estimate that the reversionary date could occur as late as the fourth quarter of 2014. See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations Overview Delhi Field Release and Note 11, Commitments and Contingencies to the Consolidated Financial Statements for further discussion of this matter. In 2014, we plan to invest approximately $40 million in this field, primarily to install a natural gas liquids extraction plant, which we anticipate will be operational in 2015.

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Denbury Resources Inc.


From inception through December 31, 2013, we had not yet recovered our investment in this field, and the remaining investment to be recovered (revenue less operating expenses and capital expenditures, including acquisition costs) from Delhi Field was $111 million. As of December 31, 2013, the estimated PV-10 Value of Delhi Field was $747.3 million.

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 2013, tertiary production from Hastings Field averaged 4,270 Bbls/d, compared to 3,409 Bbls/d in the fourth quarter of 2012. In 2014, we plan to invest approximately $75 million to continue developing the West Hastings Unit, including the development of additional patterns and expansion of the processing facilities.

From inception through December 31, 2013, we had not yet recovered our investment in this field, and the remaining investment to be recovered (revenue less operating expenses and capital expenditures, including the acquisition cost) from Hastings Field was $336 million.  As of December 31, 2013, the estimated PV-10 Value of Hastings Field was $1.1 billion.

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 during 2010, we added injection patterns and expanded the central processing facility. In 2013, we began flooding the Christmas zone.  During the fourth quarter of 2013, tertiary production at Heidelberg Field averaged 5,206 Bbls/d, compared to 3,930 Bbls/d in the fourth quarter of 2012.  In 2014, we plan to invest approximately $120 million to continue developing the East and West Heidelberg Units, including an expansion of our development of the Eutaw and Christmas zones and adjustments to our CO2 floods of existing zones to better direct the CO2 through the zones and optimize oil recovery from the field.

From inception through December 31, 2013, we had not yet recovered our costs relating to the CO2 flood at Heidelberg Field, and the remaining investment to be recovered (revenue less operating expenses and capital expenditures, including the acquisition costs) from the field was $10 million.  As of December 31, 2013, the estimated PV-10 Value of Heidelberg Field was $1.1 billion.

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.  We began CO2 injections into Oyster Bayou in the second quarter of 2010.  Oyster Bayou Field is somewhat unique when compared to our other CO2 EOR projects because the field covers a relatively small area of 3,912 acres.  We commenced tertiary production from Oyster Bayou Field in the fourth quarter of 2011 from the Frio A-1 zone and booked initial proved tertiary reserves for the field in 2012.  During the fourth quarter of 2013, tertiary production at Oyster Bayou Field averaged 3,869 Bbls/d, compared to 1,826 Bbls/d in the fourth quarter of 2012. In 2014, we plan to invest approximately $50 million to develop the Frio A-2 zone and optimize our Frio A-1 zone development.

From inception through December 31, 2013, we had not yet recovered our investment in this field, and the remaining investment to be recovered (revenue less operating expenses and capital expenditures, including the acquisition costs) from Oyster Bayou Field was $98 million.  As of December 31, 2013, the estimated PV-10 Value of Oyster Bayou Field was $550.0 million.

Tinsley Field.  We acquired Tinsley Field in 2006. The field is located in Mississippi, was discovered and first developed in the 1930s and is separated into different fault blocks.  As is the case with the majority of fields in Mississippi, Tinsley produces from multiple reservoirs.  Our CO2 enhanced oil recovery operations at Tinsley 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.  In 2014, we expect to invest approximately $50 million to continue our development of the North Fault Block and to develop dedicated injection wells in the East Fault Block.  We currently expect our development of the Woodruff to be substantially complete by the end of 2014. During the fourth quarter of 2013, the average tertiary oil production was 7,809 Bbls/d, compared to 8,166 Bbls/d in the fourth quarter of 2012.


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Denbury Resources Inc.

From inception through December 31, 2013, we have recovered all our costs in this field, and our tertiary operations at Tinsley Field have generated excess net cash flow (revenue less operating expenses and capital expenditures, including the acquisition costs) of $340 million.  As of December 31, 2013, the estimated PV-10 Value of Tinsley Field was $1.0 billion.

Future Tertiary Properties with No Tertiary Production or Proved Tertiary Reserves at December 31, 2013

Webster Field. We acquired our interest in Webster Field in the fourth quarter of 2012 as part of 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, 2013, Webster Field had estimated proved non-tertiary reserves of approximately 3.2 MMBOE, net to our acquired interest.  During the fourth quarter of 2013, non-tertiary production at Webster Field averaged 1,036 BOE/d.  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 plan to invest approximately $105 million to drill or recomplete injection and production wells and begin water injections to re-pressurize the reservoir. We currently expect to commence CO2 injections at Webster Field in 2015, with first tertiary production expected late that same year.

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 12.3 MMBOE at December 31, 2013, net to our interest, nearly all of which are proved developed.  During the fourth quarter of 2013, production at Conroe Field averaged 2,697 BOE/d, compared to 2,745 BOE/d in the fourth quarter of 2012.  Given the size of the Conroe Field (approximately 20,000 acres), the volume of CO2 that could be injected is quite sizable, and much larger than any field we have developed to date.  Therefore, the pace of development will be dictated in part by the amount of available CO2.

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 to begin construction of this pipeline in 2016 and to commence CO2 injections at Conroe Field in 2017, with first tertiary production currently expected in 2018. In 2014, we plan to continue work on pipeline route selection, right-of-way acquisition, engineering, and regulatory permits while building our CO2 EOR development plan for Conroe Field. In 2014, we also plan to invest approximately $30 million on non-tertiary well recompletions and to begin water injections into the area of the field in which we plan to commence CO2 injections to begin building reservoir pressure.

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 15.4 MMBOE at December 31, 2013, net to our interest, of which approximately 54% are proved developed.  During the fourth quarter of 2013, non-tertiary production at Thompson Field averaged 1,331 BOE/d net to our interest, compared to 1,517 BOE/d in the fourth quarter of 2012.  Thompson Field is geologically similar to Hastings Field, producing oil from the Frio zone at similar depths and we therefore believe it is well suited for CO2 EOR. 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. In 2014, we plan to invest approximately $15 million on non-tertiary drilling opportunities and facility upgrades. We currently plan to commence CO2 injections at Thompson Field in 2018, with first tertiary production expected in 2020.

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. LaBarge Field is located in southwestern Wyoming. The gas composition from LaBarge Field is expected to be approximately 65% CO2, approximately 18% to 20% methane, less than one percent helium, and the remainder various other gases.

During December 2013, we received approximately 41 MMcf/d from ExxonMobil's Shute Creek gas processing plant at LaBarge Field. Based on current capacity, and subject to availability of CO2, we currently expect to ultimately receive up to 65 MMcf/d of CO2 in 2014, rising to approximately 115 MMcf/d of CO2 by 2021 from such plant. We pay ExxonMobil a fee to

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Denbury Resources Inc.

process and deliver the CO2, which we plan to use in our Rocky Mountain region CO2 floods. As of December 31, 2013, our interest in LaBarge Field consisted of approximately 1.3 Tcf of proved CO2 reserves.

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 for $347 million.  These purchases included a gas processing facility that was under construction at the purchase dates to separate the helium and natural gas from the gas stream.  We placed our gas processing facility at Riley Ridge into service in the fourth quarter of 2013.

As of December 31, 2013, our interest in Riley Ridge and minor surrounding acreage contained net proved reserves of 399 Bcf (67 MMBOE) of natural gas and 2.0 Tcf of CO2 reserves.  The CO2 reserve estimates are based on the gross working interest of the CO2 reserves, in which our net revenue interest is approximately 1.6 Tcf.  The helium reserves at Riley Ridge are owned primarily by the U.S. government; however, we have the right to produce and sell the helium reserves to a third party on behalf of the government. In exchange for this right, we pay the U.S. government a fee that fluctuates based upon realized sales proceeds.  Our helium 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, 2013, we estimate that Riley Ridge contains proved helium reserves of 13.3 Bcf, which volume estimate is reduced to reflect the related fee we will remit to the U.S. government.  In addition, we believe there is significant reserve potential in other acreage surrounding Riley Ridge in which we also own an interest.

The gas processing facility at Riley Ridge will separate for sale the natural gas and helium from the full well stream, and the remaining gases, including CO2, will be re-injected into the producing formation or a deeper formation until we complete construction of a planned CO2 capture facility and pipeline later this decade.  We currently project that we will start to use CO2 from Riley Ridge around 2020, following completion of the capture facility and planned CO2 pipeline connecting Riley Ridge to our existing Greencore Pipeline.

Other Rocky Mountain CO2 Sources.  We began purchasing and receiving CO2 from the Lost Cabin 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 22 MMcf/d in 2013.  We plan to continue to pursue additional sources for CO2 supply in the Rocky Mountain region.

Greencore Pipeline.  The 20-inch Greencore Pipeline in Wyoming is the first CO2 pipeline we have constructed in the Rocky Mountain region.  We plan to use the pipeline as our trunk line in the Rocky Mountain region, eventually connecting our Lost Cabin, LaBarge and Riley Ridge CO2 sources (see Rocky Mountain Region CO2 Sources and Pipelines above) to the Cedar Creek Anticline in eastern Montana. The initial 232-mile section of the Greencore Pipeline begins at the 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 Lost Cabin gas plant during the first quarter of 2013.  In 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 will enable us to transport CO2 from LaBarge Field to our Bell Creek Field.

Tertiary Properties with Tertiary Production and Proved Tertiary Reserves at December 31, 2013

Bell Creek Field.  Bell Creek Field is located in southeast Montana.  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; as a result, we believe it is well suited for CO2 EOR. We acquired our interest in Bell Creek Field through the Encore merger in 2010 and have worked since that time to commence a CO2 EOR project in the field. We began first CO2 injections during the second quarter of 2013, recorded our first tertiary oil production in the third quarter of 2013, and booked initial proved tertiary reserves in the fourth quarter of 2013. Tertiary production, net to our interest, during the fourth quarter of 2013 averaged 177 Bbls/d.  In 2014, we plan to invest approximately $55 million to expand our CO2 flood of Bell Creek Field.

From inception through December 31, 2013, we had not yet recovered our investment in this field, and the remaining investment to be recovered (revenue less operating expenses and capital expenditures, including the acquisition costs) from Bell Creek Field was $432 million. As of December 31, 2013, the estimated PV-10 Value of Bell Creek Field was $739.0 million.


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Denbury Resources Inc.

Future Tertiary Properties with No Tertiary Production or Proved Tertiary Reserves at December 31, 2013

Cedar Creek Anticline.  CCA is the largest potential EOR property that we own and currently our largest producing property. 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 producing 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. See 2013 Business Developments above and Note 2, Acquisitions and Divestitures, to the Consolidated Financial Statements for further discussion of this transaction and information as to other recent acquisitions and divestitures by Denbury. The 2013 CCA Acquisition added 42.2 MMBOE of incremental proved reserves. Production from CCA, net to our interest, averaged 18,601 BOE/d during the fourth quarter of 2013, compared to pro forma production during the fourth quarter of 2012 of 19,493 BOE/d (including production associated with our newly acquired CCA assets of approximately 11,000 BOE/d and production from our previously owned CCA assets of 8,493 BOE/d). The non-tertiary proved reserves associated with CCA were 105.4 MMBbls of oil and 6.0 Bcf of gas as of December 31, 2013.

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 2014, we plan to invest approximately $110 million to improve waterfloods, drill new wells, and recomplete existing wells. We currently plan to commence CO2 injections at CCA after 2020.

Grieve Field. In the second quarter of 2011, we entered into a farm-in agreement, under which we will obtain a 65% working interest in Grieve Field, located in Natrona County, Wyoming, in exchange for developing the Grieve Field CO2 flood.  We completed a three-mile CO2 pipeline to deliver CO2 from an existing CO2 pipeline to the Grieve Field in the fourth quarter of 2012, and are preparing for construction of the field's CO2 recycle facility.  We began injecting CO2 into Grieve Field during the first quarter of 2013 and currently expect tertiary production to commence in 2015.

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 5.2 MMBOE at December 31, 2013, net to our acquired interest, 1.9 MMBOE of which relate to the natural gas producing Big George coal zone.  During the fourth quarter of 2013, non-tertiary production averaged 2,204 BOE/d. We believe the oil reservoir characteristics of Hartzog Draw Field make it well suited for CO2 EOR. In 2014, we plan to invest approximately $40 million to drill and complete six horizontal wells in the Shannon formation and re-frac eight existing wells. We anticipate drilling additional horizontal wells in the Shannon formation over the next several years. The drilling of these wells is expected to generate near-term cash flow, as well as complement our planned future CO2 EOR project in the field. We must obtain regulatory approval and construct a CO2 pipeline from our existing Greencore Pipeline to Hartzog Draw Field before we can commence our planned CO2 EOR project. We currently plan to commence CO2 injections at Hartzog Draw Field after 2020.

Other Non-Tertiary Oil Properties

Although almost all of our oil and natural gas properties are either existing or planned future tertiary floods (discussed above), we also produce oil and natural gas either from fields that are not amenable to EOR or out of 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 6,994 BOE/d during the fourth quarter of 2013, compared to 18,615 BOE/d during the fourth quarter of 2012. Production during the fourth quarter of 2012 includes 10,064 BOE/d of production from our Bakken area assets that were sold during that period.
 
OIL AND GAS ACREAGE, PRODUCTIVE WELLS AND DRILLING ACTIVITY

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


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Denbury Resources Inc.

Oil and Gas Acreage

The following table sets forth our acreage position at December 31, 2013:
 
Developed
 
Undeveloped
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Gulf Coast region
250,732

 
211,058

 
390,678

 
40,383

 
641,410

 
251,441

Rocky Mountain region
362,163

 
311,687

 
188,055

 
83,647

 
550,218

 
395,334

Total
612,895

 
522,745

 
578,733

 
124,030

 
1,191,628

 
646,775


The percentage of our net undeveloped acreage that is subject to expiration over the next three years, if not renewed, is approximately 3% in 2014, 12% in 2015 and 12% in 2016.

Productive Wells

The following table sets forth our gross and net productive oil and natural gas wells as of December 31, 2013:
 
Producing Oil Wells
 
Producing Natural Gas Wells
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Operated wells:
 
 
 
 
 
 
 
 
 
 
 
Gulf Coast region
1,233

 
1,140.1

 
212

 
192.6

 
1,445

 
1,332.7

Rocky Mountain region
1,160

 
1,039.0

 
201

 
111.2

 
1,361

 
1,150.2

Total
2,393

 
2,179.1

 
413

 
303.8

 
2,806

 
2,482.9

Non-operated wells:
 

 
 

 
 

 
 

 
 

 
 

Gulf Coast region
33

 
0.9

 

 

 
33

 
0.9

Rocky Mountain region
72

 
8.7

 
101

 
37.5

 
173

 
46.2

Total
105

 
9.6

 
101

 
37.5

 
206

 
47.1

Total wells:
 

 
 

 
 

 
 

 
 

 
 

Gulf Coast region
1,266

 
1,141.0

 
212

 
192.6

 
1,478

 
1,333.6

Rocky Mountain region
1,232

 
1,047.7

 
302

 
148.7

 
1,534

 
1,196.4

Total
2,498

 
2,188.7

 
514

 
341.3

 
3,012

 
2,530.0


Drilling Activity

The following table sets forth the results of our drilling activities over the last three years.  As of December 31, 2013, we had 5 gross (4.8 net) wells in progress.
 
Year Ended December 31,
 
2013
 
2012
 
2011
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Exploratory wells: (1)
 
 
 
 
 
 
 
 
 
 
 
Productive (2)

 

 
1

 

 

 

Non-productive (3)

 

 

 

 
1

 
0.7

Development wells: (1)
 

 
 

 
 

 
 

 
 

 
 

Productive (2)
49

 
44.3

 
201

 
87.4

 
221

 
116.6

Non-productive (3)(4)
1

 
1.0

 
5

 
3.2

 

 

Total
50

 
45.3

 
207

 
90.6

 
222

 
117.3



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Denbury Resources Inc.

(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 2013, 2012 and 2011, an additional 43, 56 and 46 wells, respectively, were drilled for water or CO2 injection purposes.

The following table summarizes sales volumes, sales prices and production cost information for our net oil and natural gas production for the years ended December 31, 2013, 2012 and 2011:
 
Year Ended December 31,
 
2013
 
2012
 
2011
Net sales volume:
 
 
 
 
 
Gulf Coast region
 
 
 
 
 
Oil (MBbls)
16,858

 
15,621

 
14,635

Natural gas (MMcf)
5,620

 
5,907

 
7,934

Total Gulf Coast region (MBOE)
17,795

 
16,606

 
15,957

Rocky Mountain region
 

 
 

 
 

Oil (MBbls)
7,336

 
8,841

 
7,534

Natural gas (MMcf)
3,046

 
4,747

 
2,849

Total Rocky Mountain region (MBOE)
7,844

 
9,632

 
8,009

Total Company (MBOE)
25,639

 
26,238

 
23,966

 
 
 
 
 
 
Average sales price:
 

 
 

 
 

Gulf Coast region
 

 
 

 
 

Oil (per Bbl)
$
105.34

 
$
105.59

 
$
105.23

Natural gas (per Mcf)
3.74

 
2.79

 
4.31

 
 
 
 
 
 
Rocky Mountain region
 

 
 

 
 

Oil (per Bbl)
$
89.95

 
$
82.33

 
$
89.93

Natural gas (per Mcf)
3.15

 
3.38

 
6.12

 
 
 
 
 
 
Total Company
 

 
 

 
 

Oil (per Bbl)
$
100.67

 
$
97.18

 
$
100.03

Natural gas (per Mcf)
3.53

 
3.05

 
4.79

 
 
 
 
 
 
Average production cost (per BOE sold): (1)
 

 
 

 
 

Gulf Coast region (2)
$
32.34

 
$
24.96

 
$
24.51

Rocky Mountain region
19.78

 
12.23

 
14.52

Total Company (2)
28.50

 
20.29

 
21.17


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

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Denbury Resources Inc.


(2)
Production costs include $114 million of lease operating expenses recorded during 2013 to remediate an area of Delhi Field. Excluding estimated Delhi Field remediation costs, average production costs in 2013 totaled $25.93 per BOE for the Gulf Coast Region and $24.05 per BOE for the Company as a whole.


PRODUCTION AND UNIT PRICES

Further information regarding average production rates, unit sale prices and unit costs per BOE are set forth under Item 7, Management's Discussion and Analysis of Financial Condition and Results of OperationsResults of OperationsOperating Results Table, included herein.

TITLE TO PROPERTIES

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

SIGNIFICANT OIL AND GAS PURCHASERS AND PRODUCT MARKETING

Oil and gas sales are made on a day-to-day basis under short-term contracts at the current area market price. The loss of any single purchaser would not be expected 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, 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%). For the years ended December 31, 2012 and 2011, two purchasers accounted for 10% or more of our oil and natural gas revenues: Marathon Petroleum Company (39% and 43% in 2012 and 2011, respectively) and Plains Marketing LP (17% and 16% in 2012 and 2011, respectively).

Our ability to market oil and natural gas depends on many factors beyond our control, including the extent of domestic production and imports of oil and gas, the proximity of our oil and natural gas production to pipelines, 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.  Our production in the Gulf Coast region is primarily from developed fields close to major pipelines or refineries and established infrastructure.  Our production in the Rocky Mountain region is dependent on, among other factors, limited transportation options caused by oversubscribed pipelines and market centers that are distant from producing properties.  As of December 31, 2013, we have not experienced significant difficulty in finding a market for all of our production as it becomes available or in transporting our production to those markets; however, there is no assurance that we will always be able to market all of our production or obtain favorable prices.

Oil Marketing

Over the past couple of years, the oil produced in the Gulf Coast region has benefited from strong pricing differentials in relation to NYMEX and, where possible, we have attached our production to Louisiana Light Sweet ("LLS") pricing. During 2013, LLS pricing and NYMEX pricing have been much closer together, with the fourth quarter of 2013 quarterly average LLS-to-NYMEX differential (on a trade-month basis) narrowing to a positive $2.58 per Bbl, suggesting a return to historical spreads compared to the wider-than-normal positive LLS-to-NYMEX spreads we experienced during 2012 and 2011. During 2013, our light sweet oil production in this area, on average, sold for $7.44 per Bbl over NYMEX compared to more than $11.50 per Bbl over NYMEX in 2012 and 2011.  The pricing of other Gulf Coast grades was relatively consistent with NYMEX pricing in 2013, with our light and medium sour crude production selling at a premium to NYMEX of $0.08 per Bbl.  The market dynamics of the region suggest the possibility that differentials to NYMEX will narrow due to the influx of light sweet crude and condensate from producing regions outside of the Gulf Coast region by rail and publicly announced major pipeline projects.  Our current markets, at various sales points along the Gulf Coast, have sufficient demand to accommodate our production, but there can be no assurance

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Denbury Resources Inc.

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; and Wood River, Illinois.  Shipments on some of the pipelines are oversubscribed and subject to apportionment.  We currently have access to 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.  Expansion of pipeline and newly built rail infrastructure in the Rocky Mountain region is ongoing and, we believe, has improved the overall stability of oil differentials in the area. However, 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 coastal markets. Therefore, prices in the Rocky Mountain region are further influenced by fluctuations in prices (primarily Brent and LLS) in those coastal markets.  For the year ended December 31, 2013, the discount for our oil production in the Rocky Mountain region averaged $8.10 per Bbl, compared to $11.86 per Bbl during 2012 and $5.15 per Bbl during 2011. Excluding the Bakken area assets that we sold during the fourth quarter of 2012, our oil production in the Rocky Mountain region sold at a discount to NYMEX of $8.43 per Bbl during the year ended December 31, 2012.

Overall, during 2013, we sold approximately 46% of our crude oil at prices based on the LLS index price, approximately 23% at prices 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.

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.  We currently receive near NYMEX or Henry Hub prices for most of our natural gas sales in Mississippi.  For the year ended December 31, 2013, the amount received for our Mississippi natural gas production averaged $0.12 per Mcf over NYMEX prices.  In the Texas Gulf Coast region, due primarily to its location, the price we received for the year ended December 31, 2013 averaged $0.12 per Mcf below NYMEX prices.  The CCA natural gas production in the Rocky Mountain region is sold at the wellhead on a percent-of-proceeds basis.  We receive a percentage of proceeds on both the residue natural gas volumes and the natural gas liquids volumes.  The natural gas has a significant component of propane, butanes and other higher-density hydrocarbons, resulting in a measurable natural gas liquids stream.  In addition, we have coal bed methane production in the Hartzog Draw that is sold at the Cheyenne Hub. For the year ended December 31, 2013, we averaged $0.57 per Mcf below NYMEX prices for our Rocky Mountain region natural gas production due primarily to its location, the natural gas liquids extracted from the CCA gas stream (resulting in a decreased net price), and the quality of the coal bed methane gas in Wyoming.

Helium Marketing

We placed the Riley Ridge gas processing facility in service in the fourth quarter of 2013. During 2014, we expect to begin to supply helium to a third party purchaser under a 20-year helium supply arrangement.  Helium will be sold under the contract at a price that will fluctuate based on helium deliveries, CPI and other factors over the 20-year term.

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.

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Denbury Resources Inc.


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 this evolving regulatory burden 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, 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.  The regulatory burden on the oil and gas industry increases our costs of doing business and, consequently, affects 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.


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Denbury Resources Inc.

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 (the "DOT") authority for new damage prevention and incident notification, and directs the DOT to prescribe new minimum safety standards for CO2 pipelines, which safety standards could affect our operations and the costs thereof. While the DOT has adopted or proposed to adopt a number of new regulations to implement this act, no such 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 which 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 Environmental Protection Agency ("EPA") has promulgated regulations requiring permitting for certain sources of greenhouse gas emissions, along with requirements for wells used for geologic sequestration.  At the same time, legislation 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 sequester CO2 in geologic formations such as depleted oil and gas reservoirs.

Natural Gas Gathering Regulations

State 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 regulatory agencies, which is likely to continue in the future.

Federal, State or Indian Leases

Our operations on federal, state or Indian oil and gas leases, especially those in the Rocky Mountain region, are subject to numerous restrictions, including nondiscrimination statutes. Such operations must be conducted pursuant to certain on-site security regulations and other permits and authorizations issued by the Bureau of Land Management, the Bureau of Ocean Energy Management, the Bureau of Safety and Environmental Enforcement, the Bureau of Indian Affairs, and other federal and state stakeholder agencies.

Environmental Regulations

Our oil and natural gas production, saltwater disposal operations, injection of CO2, and the processing, handling and disposal of materials such as hydrocarbons and naturally occurring radioactive materials ("NORM") are subject to stringent regulation.  We could incur significant costs, including cleanup costs resulting from a release of product, third-party claims for property damage and personal injuries, or penalties and other sanctions as a result of any violations or liabilities under environmental or other laws 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, 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 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

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Denbury Resources Inc.

(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.

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 2013, we fracture stimulated one operated well at Hartzog Draw and two CO2 source wells at Jackson Dome, in each case utilizing water-based fluids with no diesel fuel component. In 2014, we currently plan to hydraulically fracture approximately seven additional wells at Hartzog Draw using similar techniques. 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 DeGolyer and MacNaughton ("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 39 years of experience in oil and gas reservoir studies and evaluations.  Our Senior Vice President – Planning, Technology and CO2 Supply is primarily responsible for overseeing the independent petroleum engineering firm during the process.  Our Senior Vice President – Planning, Technology and CO2 Supply has a Bachelor of Science degree in Petroleum Engineering from Louisiana State University and over 32 years of industry experience working with petroleum reserve estimates.  D&M relies on various data provided by our internal reservoir engineering team in preparing its reserve estimates, including such items as oil and natural gas prices, ownership interests, production information, operating costs, planned capital expenditures and other technical data. Our internal reservoir engineering team consists of qualified petroleum engineers who maintain the Company's internal evaluation of reserves and compare the Company's information to the reserves prepared by D&M. Management is responsible for designing the internal control procedures used in the preparation of our oil and gas reserves, which include verification of data input into reserve forecasting and economics evaluation software, as well as multi-discipline management reviews.  The internal reservoir engineering team reports directly to our Senior Vice President – Planning, Technology and CO2 Supply.  In addition, our Board of Directors’ Reserves and Health, Safety and Environment ("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 34 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, 2013, 2012 and 2011.  See the summary of D&M’s report as of December 31, 2013, 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

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Denbury Resources Inc.

reserve estimates represent our net revenue interest in our properties.  During 2013, we provided oil and gas reserve estimates for 2012 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, 2012.

Our proved nonproducing reserves primarily relate to reserves that are to be recovered from productive zones that are currently behind pipe.  Since a majority of our properties are in areas with multiple pay zones, these properties typically have both proved producing and proved nonproducing reserves.

As of December 31, 2013, our estimated proved undeveloped reserves totaled approximately 179.9 MMBOE, or approximately 38% of our estimated total proved reserves, an increase of 17.2 MMBOE from December 31, 2012 levels.  Our proved undeveloped oil reserves primarily relate to our CO2 tertiary operations (92.8 MMBOE), and our proved undeveloped natural gas reserves are primarily located in our Riley Ridge Field (66.6 MMBOE).  We 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 2013, we spent approximately $260 million to convert 16.7 MMBOE of proved undeveloped reserves to proved developed reserves, primarily as a result of tertiary development activities at Heidelberg, Hastings, and Tinsley fields. During 2013, we added 30.0 MMBOE of proved undeveloped reserves, including 27.3 MMBOE related to our tertiary operations at Bell Creek Field, and recognized net positive proved undeveloped reserve revisions of 3.9 MMBOE.

As of December 31, 2013, 26.7 MMBOE of our total proved undeveloped reserves are not scheduled to be developed within five years of initial booking, 26.1 MMBOE 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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Denbury Resources Inc.

 
December 31,
 
2013
 
2012
 
2011
Estimated proved reserves (1)
 
 
 
 
 
Oil (MBbls)
386,659

 
329,124

 
357,733

Natural gas (MMcf)
489,954

 
481,641

 
625,208

Oil equivalent (MBOE)
468,318

 
409,398

 
461,934

Reserve volumes categories
 
 
 
 
 
Proved developed producing:
 
 
 
 
 
Oil (MBbls)
245,722

 
208,745

 
189,904

Natural gas (MMcf)
68,976

 
60,832

 
116,562

Oil equivalent (MBOE)
257,218

 
218,884

 
209,331

Proved developed non-producing:
 
 
 
 
 
Oil (MBbls)
30,670

 
27,264

 
49,837

Natural gas (MMcf)
3,119

 
3,359

 
9,408

Oil equivalent (MBOE)
31,190

 
27,824

 
51,405

Proved undeveloped:
 
 
 
 
 
Oil (MBbls)
110,267

 
93,115

 
117,992

Natural gas (MMcf)
417,859

 
417,450

 
499,238

Oil equivalent (MBOE)
179,910

 
162,690

 
201,198

Percentage of total MBOE:
 
 
 
 
 
Proved developed producing
55
%
 
53
%
 
45
%
Proved developed non-producing
7
%
 
7
%
 
11
%
Proved undeveloped
38
%
 
40
%
 
44
%
Representative oil and natural gas prices: (2)
 
 
 
 
 
Oil – NYMEX
$
96.94

 
$
94.71

 
$
96.19

Natural gas – Henry Hub
3.67

 
2.85

 
4.16

Present values (thousands): (3)
 
 
 
 
 
Discounted estimated future net cash flow before income taxes (PV-10 Value) (4)
$
10,633,783

 
$
9,909,592

 
$
10,559,139

Standardized measure of discounted estimated future net cash flow after income taxes ("Standardized Measure")
$
7,128,744

 
$
6,414,380

 
$
7,007,605


(1)
Estimated proved reserves as of December 31, 2012 reflect the sale of reserves associated with our Bakken area assets sold in 2012 (approximately 109 MMBOE). Year-end 2012 reserves reflect CCA reserves acquired in 2010 as part of the Encore merger, but do not include reserves of 42.2 MMBOE related to the CCA Acquisition, which closed during the first quarter of 2013.

(2)
The reference prices were based on the arithmetic average of the first-day-of-the-month NYMEX commodity prices for each month during the respective year. These prices do not reflect adjustments for market differentials by field that are utilized in the preparation of our reserve report to arrive at the appropriate net price we receive.  See Management's Discussion and Analysis of Financial Condition and Results of OperationsResults of OperationsOperating Results Table for details of oil and natural gas prices received, both including and excluding the impact of derivative settlements.

(3)
Determined based on the average first-day-of-the-month prices for each month, adjusted to prices received by field in accordance with standards set forth in the FASC.


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Denbury Resources Inc.

(4)
PV-10 Value is a non-GAAP measure and is different from the Standardized Measure in that PV-10 Value is a pre-tax number and the Standardized Measure is an after-tax number.  The information used to calculate PV-10 Value is derived directly from data determined in accordance with FASC Topic 932.  The difference between these two amounts, the discounted estimated future income tax was $3.505 billion at December 31, 2013; $3.495 billion at December 31, 2012; and $3.552 billion at December 31, 2011.  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 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.
 
There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and their values, including many factors beyond our control.  See Item 1A, Risk Factors – Estimating our reserves, production and future net cash flows is difficult to do with any certainty.  See also Supplemental Oil and Natural Gas Disclosures (Unaudited), to the Consolidated Financial Statements.

Item 1A.  Risk Factors

Oil and natural gas prices are volatile.  A substantial decrease in oil and natural gas prices could adversely affect our financial results.

Our future financial condition, results of operations, cash flows and the carrying value of our oil and natural gas properties depend primarily upon the prices we receive for our oil and natural gas production.  Oil and natural gas prices historically have been volatile and may continue to be volatile in the future. Substantial decreases in commodity prices in the future could require us to record full cost ceiling test write-downs.  The amount of any future write-down is difficult to predict and will depend upon oil and natural gas prices, the incremental proved reserves that might be added during each period and additional capital spent.

Our cash flow from operations is highly dependent on the prices that we receive for oil.  This price volatility also affects the amount of our cash flow available for capital expenditures and our ability to borrow money or raise additional capital.  Oil prices currently affect us more than natural gas prices because oil comprised approximately 94% of our 2013 production and 83% of our proved reserves at December 31, 2013.

The prices for oil and natural gas are subject to a variety of additional 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;
the domestic and foreign supply of oil and natural gas;
the degree to which domestic oil and natural gas production decreases U.S. imports of crude oil;
the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
domestic governmental regulations and taxes;
the price and availability of alternative fuel sources;
storage levels of oil and natural gas;
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 Mountains that can delay or impede operations;
market uncertainty;
worldwide political events and conditions, including actions taken by foreign oil and natural gas producing nations; and

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Denbury Resources Inc.

worldwide economic conditions.

These factors and the volatility of the energy markets generally make it extremely difficult to predict future oil and natural gas price movements.  Also, prices for oil and prices for natural gas do not necessarily move in tandem.  Declines in oil or natural gas prices would not only reduce revenue but could reduce the amount of oil and natural gas that we can produce economically.  If the oil and natural gas industry experiences significant price declines, we may, among other things, be unable to meet all of our financial obligations or make planned expenditures.

Over the past six years oil prices have fluctuated significantly, reaching record highs of approximately $145 per Bbl in July 2008, declining precipitously during the last half of 2008, and ending that year at a NYMEX price of $44.60 per Bbl. Since 2008, oil prices have continued to fluctuate, ending 2013 at a NYMEX price of $98.42 per Bbl.  If substantial volatility of oil prices continues, oil prices could decline to a level that makes some or all of our tertiary projects uneconomical.  If that were to happen, we may decide to suspend future expansion projects, and if prices were to drop below our cash break-even point 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.  We may also be required to reduce our capital expenditures in the event of declining commodity prices in order to compensate for diminished cash flow, which could reduce or eliminate our growth. Since operating costs do not decrease as quickly as commodity prices, it is difficult to determine a precise break-even point for our tertiary projects; however, based on prior history, we currently estimate our economic break-even point (before corporate-related overhead and based on currently estimated expenses relative to these tertiary projects) occurs at oil prices in the low-to-mid $40-per-barrel range, depending on the specific field and area.

We have a current practice of hedging approximately 18 months to two years (from the current quarter) of forecasted production to mitigate the risks associated with price fluctuations (see Management's Discussion and Analysis of Financial Condition and Results of OperationsMarket Risk Management and Note 9, Commodity Derivative Contracts, to the Consolidated Financial Statements for details regarding our commodity derivative contracts).  As of February 20, 2014, we have oil derivative contracts in place covering 58,000 Bbls/d during 2014 and 58,000 Bbls/d during the first three quarters of 2015.  

The prices we receive for our crude oil often do not correlate with NYMEX prices and can vary from such prices depending on, among other factors, the quality of the crude oil we sell, the location of our crude oil production and the related markets to which we sell, variations in prices paid based upon different indices used, and the pricing contracts and indices at which we sell production.  Our NYMEX differentials on a field-by-field basis over the last few years have ranged from approximately $25 per Bbl above NYMEX to approximately $25 per Bbl below NYMEX.  On a corporate-wide basis, our NYMEX differentials over the last few years have ranged from approximately $11 per Bbl above NYMEX oil prices to approximately $5 per Bbl below NYMEX oil prices.  These variances have been due to various factors and are difficult to forecast or anticipate, but they have a direct impact on the net oil price we receive.

Natural gas price volatility has been severe over the last few years as a result of, among other things, weak demand, increased production of natural gas, and significant natural gas storage in place, leading to excess gas supply.  NYMEX natural gas prices averaged $4.03 per MMBtu during 2011, $2.82 per MMBtu during 2012, and $3.72 per MMBtu during 2013, and ended 2013 at $4.23 per MMBtu.  As of February 20, 2014, we have natural gas derivative contracts in place covering 14,000 MMBtu/d during 2014 and 6,000 MMBtu/d during 2015 (see Management's Discussion and Analysis of Financial Condition and Results of OperationsMarket Risk Management and Note 9, Commodity Derivative Contracts, to the Consolidated Financial Statements for details regarding our commodity derivative contracts).

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

Our long-term strategy is 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 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, or catastrophic pipeline failure.  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.

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Denbury Resources Inc.


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 and from the federal government in certain areas.  Certain states where we operate are considering the adoption of laws and regulations that would limit or eliminate a state’s (and, accordingly, its legislative delegates') ability 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, such as the sage grouse, that could be listed as threatened or endangered under the Endangered Species Act, which listing could lead to material restrictions as to federal land use.  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 level of indebtedness may adversely affect operations and limit our growth.

As of December 31, 2013, our outstanding senior indebtedness consisted of $2.6 billion principal amount of subordinated notes, virtually all of which have maturity dates between 2020 and 2023 at interest rates ranging from 4.625% to 8.25% per annum at a weighted average interest rate of 6.29% per annum, and $340.0 million principal amount outstanding under our bank credit facility.  We currently have a borrowing base of $1.6 billion under our bank credit facility and, at December 31, 2013, availability with respect to such borrowing base of $1.2 billion.  Our bank borrowing base is adjusted semi-annually and upon requested special redeterminations, in each case at the banks’ discretion, and the amount is established and based, in part, upon certain external factors, such as commodity prices, over which we have no control.  If the outstanding credit under our bank credit facility exceeds the then effective and redetermined borrowing base, we will be required to repay the excess amount over a period not to exceed four months.

We may incur additional indebtedness in the future under our bank credit facility in connection with, among other things, our acquisition and development of oil and natural gas properties.  Further, 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 decrease substantially and remain at depressed levels for an extended period of time, our degree of leverage could increase significantly.  The level of our indebtedness could have important consequences, including but not limited to the following:

our level of indebtedness may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or general corporate and other purposes;
our vulnerability to general adverse economic and industry conditions may be greater as a result of our level of indebtedness, and increases in interest rates thereon, potentially restricting us from making acquisitions, introducing new technologies or exploiting business opportunities;
our interest expense may increase in the event of increases in market interest rates;
a substantial portion of our cash flows from operations may be dedicated to servicing our indebtedness and would not be available for capital expenditures or other purposes;
our ability to, among other things, borrow additional funds, dispose of assets, pay dividends and make certain investments may be limited by the covenants contained in the agreements governing our outstanding indebtedness; and
our debt covenants contained in the agreements governing our outstanding indebtedness may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry, and our failure to comply with such covenants could result in an event of default under such debt instruments which, if not cured or waived, could have a material adverse effect on us.

If we are unable to generate sufficient cash flow or otherwise obtain funds necessary to make required payments on our indebtedness, or if we otherwise fail to comply with the various covenants related to such indebtedness, including covenants in our bank credit facility, we would be in default under our debt instruments. This default could permit the holders of such indebtedness

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Denbury Resources Inc.

to accelerate the maturity of such indebtedness and could cause defaults under other indebtedness, which could have a material adverse effect on us. 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.

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 substantial portion of our oil and natural gas production.  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, or when the counterparty to the derivative contract 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.  Information as to these activities is set forth under Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations – Market Risk Management, and in Note 9, Commodity Derivative Contracts, to the Consolidated Financial Statements.

There are no assurances of our ability to pay dividends in the future and at what level.

On January 28, 2014, we declared our first quarterly cash common stock dividend of $0.0625 per share, payable March 25, 2014, to shareholders of record on February 25, 2014. We currently intend to pay regular quarterly cash dividends in the future; however, our ability to pay dividends may be adversely affected if certain of the risks described herein were to occur. Our payment of dividends is subject to, and conditioned upon, among other things, compliance with the covenants and restrictions contained in our bank credit facility and the indentures governing our subordinated notes. All dividends will be paid at the discretion of our Board of Directors and will depend upon many factors, including our earnings, financial condition and such other factors as our Board of Directors may deem relevant from time to time. There are no assurances as to our ability to pay dividends in the future or the level thereof.

A worldwide financial downturn or negative credit market conditions may have lasting effects on our liquidity, business and financial condition that we cannot control or predict.

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, including a sovereign debt crisis in Europe or turmoil in the global financial system, could materially affect our liquidity, business and financial condition.  These conditions have adversely impacted financial markets and have created substantial volatility and uncertainty, and may continue to do so, with the related negative impact on global economic activity and the financial markets.  Negative credit market conditions could materially affect our liquidity and may 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.  We are subject to semiannual, as well as unscheduled, reviews and redeterminations of our borrowing base under our bank credit facility, and 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 negative economic situation could also adversely affect the collectability of our trade receivables or performance by our suppliers and cause our commodity hedging arrangements to be ineffective if our counterparties are unable to perform their obligations or otherwise seek bankruptcy protection.  Additionally, negative economic conditions could lead to reduced demand for oil and natural gas, or lower prices for oil and natural gas, which could have a negative impact on our revenues.

Our future performance depends upon our ability to find or acquire additional oil and natural gas reserves that are economically recoverable.

Unless we can successfully 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.  In the future, we may not be able to continue to replace reserves at acceptable costs.  The business of exploring for, developing or acquiring reserves is capital intensive.  We may not be able to make the necessary capital investment to maintain or expand our oil and natural gas reserves if our cash flows from operations are reduced, whether due to lower oil or natural gas prices or otherwise, or if external sources of capital become limited or

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Denbury Resources Inc.

unavailable.  Further, the process of using CO2 for tertiary recovery, and the related infrastructure, requires significant capital investment up to five years prior to any resulting and associated production and cash flows from these projects, heightening potential capital constraints.  If we do not continue to make significant capital expenditures, or if outside capital resources become limited, we may not be able to maintain our growth rate or otherwise meet expectations.

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 plan to continue acquiring other oil fields that we believe are tertiary flood candidates.  We are investing significant amounts of capital as part of this strategy.  If we are unable to successfully develop and produce the potential oil in these 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.

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.

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.

Our CO2 tertiary recovery projects require a significant amount of electricity to operate the related facilities.  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.  Although 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 have budgeted $50 million for this effort for 2014. We may incur significant costs in connection with remedial plugging operations to prevent environmental contamination and to otherwise comply with federal, state and local regulation 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 new wells drilled by us will not result in the discovery of commercially productive reservoirs or 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 governmental requirements; and
the cost of, or shortages or delays in the availability of, drilling rigs, equipment, pipelines and services.


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Denbury Resources Inc.

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.

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 recent years, the competition for qualified technical personnel has been fierce, and our personnel costs have been escalating at a rate higher than general inflation. During periods of high oil and natural gas prices, we have experienced shortages of oil field and other necessary equipment, as well as drilling rigs, as demand for equipment and rigs has increased in tandem with higher commodity prices.  Additionally, higher oil and natural gas prices generally stimulate increased demand, which results in increased prices for drilling rigs, crews and associated supplies, oilfield equipment and services, and personnel in our exploration and production operations.  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 those operations that we currently have planned and budgeted, 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.

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 environmental protection. 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 legislative or regulatory proposals under consideration could negatively affect our business.

Numerous legislative and regulatory proposals affecting the oil and gas industry have been introduced, are anticipated to be introduced, or are otherwise under consideration, by Congress and various federal agencies.  Among these proposals are: (1) climate change/carbon tax legislation introduced in Congress, and EPA regulations to reduce greenhouse gas emissions; (2)

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Denbury Resources Inc.

proposals contained in the President's budget, along with legislation introduced in Congress (none of which have passed), to impose new 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 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 Department of Transportation to prescribe minimum safety standards for CO2 pipelines. Any of the foregoing described 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.

Certain federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated, and additional state taxes on natural gas extraction may be imposed, as a result of future legislation.

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, and any such legislation or change could negatively affect our financial condition and results of operations.

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 and availability to our counterparties of their hedging and swap positions that they can make available to us, and may further require the counterparties to our derivative instruments to spin off some of their derivative activities to separate entities that may not be as creditworthy as the current counterparties. 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, including the proposed margin rules, 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 we use 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 flow may become more volatile and less predictable, which could adversely affect our ability to plan for and fund capital expenditures.

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Denbury Resources Inc.


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, 2013, three purchasers individually accounted for 10% or more of our oil and natural gas revenues and, in the aggregate, for 58% of such revenues.  The loss of a large single purchaser could adversely impact the prices we receive or the transportation costs we incur.

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 reduction of the quantities and net present value of our reserves.

The reserves data included in documents incorporated by reference represent estimates only.  Quantities of proved reserves are estimated based on economic conditions, including first-day-of-the-month average oil and natural gas prices for the 12-month period preceding the date of the assessment.  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, 2013, approximately 38% 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.

Significant acquisitions or other transactions could require substantial external capital and could change our risk and property profile.

To finance acquisitions, we may need to substantially alter or increase our capitalization through the use of our bank credit facility, the issuance of debt or equity securities, the sale of production payments, or by other means.  Such changes in capitalization could significantly affect our risk profile.  Additionally, significant acquisitions or other transactions can change the character of our operations and business.  The character of the new properties may be substantially different in operating or geological characteristics or geographic location from that of our existing properties.

Our results of operations could be negatively affected as a result of goodwill impairments.

At December 31, 2013, the Company's goodwill balance totaled $1.3 billion and represented approximately 10.9% of our total assets. Goodwill is not amortized; rather it is tested for impairment annually during the fourth quarter and when facts or circumstances indicate that the carrying value of the Company's goodwill may be impaired, requiring an estimate of the fair values of the reporting unit's assets and liabilities. An impairment of goodwill could significantly reduce earnings during the period in which the impairment occurs and would result in a corresponding reduction to goodwill and equity. See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations Critical Accounting Policies and Estimates Impairment Assessment of Goodwill.


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Denbury Resources Inc.

We may lose executive officers or other key management personnel, which could endanger the future success of our operations.

Our success depends to a significant degree upon the continued contributions of our executive officers and other key management personnel. Our employees, including our executive officers, are employed at will and do not have employment agreements. If one or more members of our management team dies, becomes disabled or voluntarily terminates employment with us, there is no assurance that we will find a suitable or comparable substitute. We believe that our future success depends, in large part, upon our ability to hire and retain highly skilled managerial personnel. Competition for persons with these skills is intense, and we cannot assure that we will be successful in attracting and retaining such skilled personnel. The loss of any of our management personnel could adversely affect our operations.

A cyber incident could occur and result in information theft, data corruption, operational disruption, and/or financial loss.

Our business has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain of our exploration, development and production activities.  We depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information and in many other activities related to our business.  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.  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.

To date we have not experienced any material losses relating to cyber attacks, but there can be no assurance that we will not suffer such losses in the future.  As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any cyber vulnerabilities.

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 Agreements, and Note 11, Commitments and Contingencies, to the Consolidated Financial Statements for the future minimum rental payments.  Such information is incorporated herein by reference.

Item 3.  Legal Proceedings

We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses.  While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our consolidated financial position or overall trends in results of operations or cash flows, litigation is subject to inherent uncertainties.  If an unfavorable ruling in one of these lawsuits or proceedings were to occur, there exists the possibility of a material adverse impact on our net income in the period in which the ruling occurs.  We provide accruals for litigation and claims if we determine that we may have a range of legal exposure that would require accrual.

Item 4.  Mine Safety Disclosures

Not applicable.

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Denbury Resources Inc.

PART II

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

Common Stock Trading Summary

The following table summarizes the high and low reported sales prices on days in which there were trades of Denbury’s common stock on the New York Stock Exchange ("NYSE") for each quarterly period for the last two fiscal years.  As of January 31, 2014, 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 1,687.  On February 27, 2014, the last reported sale price of Denbury’s common stock, as reported on the NYSE, was $16.22 per share.
 
2013
 
2012
 
High
 
Low
 
High
 
Low
First Quarter
$
19.11

 
$
16.50

 
$
20.91

 
$
16.29

Second Quarter
19.48

 
16.68

 
19.50

 
13.46

Third Quarter
18.55

 
16.90

 
17.65

 
13.74

Fourth Quarter
19.44

 
15.98

 
16.76

 
14.32


On January 28, 2014, the Board of Directors declared a dividend of $0.0625 per share on our common stock, to stockholders of record at the close of business on February 25, 2014. While we currently expect to continue to pay a regular quarterly dividend on our common stock, the declaration and payment of dividends are at the discretion of our Board of Directors and will depend on our results of operations, financial condition, capital requirements, level of indebtedness, and other factors deemed relevant by the Board of Directors. Our Bank Credit Agreement and senior subordinated note indentures require us to meet certain financial covenants at the time dividend payments are made. For further discussion, see Note 5, Long-Term Debt, to the Consolidated Financial Statements. Prior to 2014, we had not historically paid dividends on our common stock.  No unregistered securities were sold by the Company during 2013.

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 2013
 
7,567

 
$
18.83

 

 
$
109.3

November 2013
 
18,636

 
19.11

 

 
250.0

December 2013
 
4,801,979

 
16.22

 
4,793,461

 
422.3 (3)

Total
 
4,828,182

 
 
 
4,793,461

 



(1)
Stock repurchases during the fourth quarter of 2013 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 and the exercise of stock appreciation rights.

(2)
In October 2011, the Company's Board of Directors approved a common stock repurchase program for up to $500 million of Denbury's common stock, which was increased by an additional $271.2 million in November 2012, $140.7 million in November 2013, and $250.0 million in December 2013, for a total authorization under the program of $1.162 billion. The program has no pre-established ending date and may be suspended or discontinued at any time.  We are not obligated to repurchase any dollar amount or specific number of shares of our common stock under the program.

(3)
Amounts shown do not give effect to the repurchase of an additional 11.8 million shares of Denbury common stock from January 1, 2014 through February 20, 2014 under the share repurchase program for $191.6 million, or $16.17 per share.

- 34 -


Denbury Resources Inc.


Between early October 2011, when we announced the commencement of a common share repurchase program, and December 31, 2013, we repurchased 47,559,266 shares of Denbury common stock (approximately 11.8% of our outstanding shares of common stock at September 30, 2011) for $739.7 million, or $15.55 per share.


- 35 -


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, 2013, 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, 2008 to December 31, 2013.

COMPARISON OF 5-YEAR CUMULATIVE TOTAL RETURN
 
December 31,
 
2008
 
2009
 
2010
 
2011
 
2012
 
2013
Denbury Resources Inc.
$
100.00

 
$
135.53

 
$
174.82

 
$
138.28

 
$
148.35

 
$
150.46

S&P 500 (1)
100.00

 
126.46

 
145.51

 
148.59

 
172.37

 
228.19

Dow Jones US Exploration & Production (2)
100.00

 
140.56

 
164.09

 
157.22

 
166.37

 
219.35


(1) Copyright© 2014 S&P, a division of The McGraw-Hill Companies Inc. All rights reserved.
(2) Copyright© 2014 Dow Jones & Co. All rights reserved. 

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Denbury Resources Inc.

Item 6. Selected Financial Data
 
 
Year Ended December 31,
In thousands, except per-share data or otherwise noted
 
2013
 
2012
 
2011
 
2010 (1)
 
2009
Consolidated Statements of Operations data:
 
 
 
 
 
 
 
 
 
 
Revenues and other income:
 
 
 
 
 
 
 
 
 
 
Oil, natural gas, and related product sales
 
$
2,466,234

 
$
2,409,867

 
$
2,269,151

 
$
1,793,292

 
$
866,709

Other
 
50,893

 
46,605

 
40,173

 
128,499

 
22,441

Total revenues and other income
 
$
2,517,127

 
$
2,456,472

 
$
2,309,324

 
$
1,921,791

 
$
889,150

Net income (loss) attributable to Denbury stockholders
 
409,597

 
525,360

 
573,333

 
271,723

 
(75,156
)
Net income (loss) per common share:
 
 
 
 
 
 
 
 
 
 
Basic
 
1.12

 
1.36

 
1.45

 
0.73

 
(0.30
)
Diluted
 
1.11

 
1.35

 
1.43

 
0.72

 
(0.30
)
Weighted average number of common shares outstanding:
 
 
 
 
 
 
 
 
 
 
Basic
 
366,659

 
385,205

 
396,023

 
370,876

 
246,917

Diluted
 
369,877

 
388,938

 
400,958

 
376,255

 
246,917

Consolidated Statements of Cash Flows data:
 
 
 
 
 
 
 
 
 
 
Cash provided by (used by):
 
 
 
 
 
 
 
 
 
 
Operating activities
 
$
1,361,195

 
$
1,410,891

 
$
1,204,814

 
$
855,811

 
$
530,599

Investing activities
 
(1,275,309
)
 
(1,376,841
)
 
(1,605,958
)
 
(354,780
)
 
(969,714
)
Financing activities
 
(172,210
)
 
45,768

 
37,968

 
(139,753
)
 
442,637

Production (average daily):
 
 
 
 
 
 
 
 
 
 
Oil (Bbls)
 
66,286

 
66,837

 
60,736

 
59,918

 
36,951

Natural gas (Mcf)
 
23,742

 
29,109

 
29,542

 
78,057

 
68,086

BOE (6:1)
 
70,243

 
71,689

 
65,660

 
72,927

 
48,299

Unit sales prices – excluding impact of derivative settlements:
 
 
 
 
 
 
 
 
 
 
Oil (per Bbl)
 
$
100.67

 
$
97.18

 
$
100.03

 
$
75.97

 
$
57.75

Natural gas (per Mcf)
 
3.53

 
3.05

 
4.79

 
4.63

 
3.54

Unit sales prices – including impact of derivative settlements:
 
 
 
 
 
 
 
 
 
 
Oil (per Bbl)
 
$
100.64

 
$
96.77

 
$
98.90

 
$
71.69

 
$
68.63

Natural gas (per Mcf)
 
3.53

 
5.67

 
7.34

 
6.45

 
3.54

Costs per BOE:
 
 
 
 
 
 
 
 
 
 
Lease operating expenses (2)
 
$
28.50

 
$
20.29

 
$
21.17

 
$
17.67

 
$
17.85

Taxes other than income
 
6.87

 
6.10

 
6.16

 
4.53

 
2.45

General and administrative expenses
 
5.66

 
5.49

 
5.24

 
5.04

 
5.77

Depletion, depreciation and amortization
 
19.89

 
19.34

 
17.07

 
16.32

 
13.52

Proved oil and natural gas reserves: (3)
 
 
 
 
 
 
 
 
 
 
Oil (MBbls)
 
386,659

 
329,124

 
357,733

 
338,276

 
192,879

Natural gas (MMcf)
 
489,954

 
481,641

 
625,208

 
357,893

 
87,975

MBOE (6:1)
 
468,318

 
409,398

 
461,934

 
397,925

 
207,542

Proved carbon dioxide reserves:
 
 
 
 
 
 
 
 
 
 
Gulf Coast region (MMcf) (4)
 
6,070,619

 
6,073,175

 
6,685,412

 
7,085,131

 
6,302,836

Rocky Mountain region (MMcf) (5)
 
3,272,428

 
3,495,534

 
2,195,534

 
2,189,756

 

Proved helium reserves associated with Denbury's production rights: (6)
 
 
 
 
 
 
 
 
 
 
Rocky Mountain region (MMcf)
 
13,251

 
12,712

 
12,004

 
7,159

 

Consolidated Balance Sheets data:
 
 
 
 
 
 
 
 
 
 
Total assets
 
$
11,788,737

 
$
11,139,342

 
$
10,184,424

 
$
9,065,063

 
$
4,269,978

Total long-term liabilities
 
5,812,132

 
5,408,032

 
4,716,659

 
4,105,011

 
1,903,951

Stockholders’ equity
 
5,301,406

 
5,114,889

 
4,806,498

 
4,380,707

 
1,972,237

 

- 37 -


Denbury Resources Inc.


(1)
On March 9, 2010, we acquired Encore Acquisition Company ("Encore").  We consolidated Encore's results of operations beginning March 9, 2010.

(2)
Lease operating expenses for the year ending December 31, 2013 include estimated costs to remediate an area of Delhi Field. Excluding these costs, lease operating expenses totaled $616.6 million and lease operating expense per BOE averaged $24.05 for the year ended December 31, 2013.

(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). Year-end 2012 reserves reflect CCA reserves acquired in 2010 as part of the Encore merger, but do not include then-estimated reserves of approximately 42.2 MMBOE related to the CCA Acquisition, which closed during the first quarter of 2013. See Note 2, Acquisitions and Divestitures, to the Consolidated Financial Statements for further discussion of these transactions.

(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 4.8 Tcf, 4.8 Tcf, 5.3 Tcf, 5.6 Tcf and 5.0 Tcf at December 31, 2013, 2012, 2011, 2010 and 2009, respectively, and include reserves dedicated to volumetric production payments of 28.9 Bcf, 57.1 Bcf, 84.7 Bcf, 100.2 Bcf and 127.1 Bcf at December 31, 2013, 2012, 2011, 2010 and 2009, 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 working interest basis) and our overriding royalty interest in LaBarge Field, of which our net revenue interest was approximately 2.9 Tcf, 2.9 Tcf, 1.6 Tcf and 0.9 Tcf at December 31, 2013, 2012, 2011 and 2010, respectively.

(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, who 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.

- 38 -


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 a growing, dividend-paying, domestic oil and natural gas company. Our primary focus is on enhanced oil recovery utilizing CO2, and our operations are focused in two key operating areas: the Gulf Coast and Rocky Mountain regions. Our goal is to increase the value of acquired properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to tertiary recovery operations.

Adoption of Growth and Income Strategy. In the fourth quarter of 2013, following a comprehensive review of our long-term plans, we announced our intention to expand our shareholder value proposition to include both growth and income. Our focused strategy, significant inventory of development projects and proven track record of value creation give us confidence that we can deliver a long-term cash flow profile to stockholders that is unique among independent oil companies. To enable our shift to a growth and income company in 2014, we modified our previous development timeline for future capital projects principally in the Rocky Mountain region, making our anticipated capital spending levels more consistent over the next five to ten years. This smoothing effect on our anticipated capital expenditures allows us to accelerate our expected free cash flow. These changes reduce our capital spending on major infrastructure projects over the next few years, accelerating our plan of providing a return to our shareholders through a dividend, while still growing our oil and natural gas reserves and production at nearly the previously anticipated growth rate.

With the declaration of the first cash dividend in our history on January 28, 2014, we have begun this program of distributing free cash flow to stockholders. Our first quarterly dividend of $0.0625 per common share (a rate of $0.25 per share on an annualized basis) will be paid on March 25, 2014 to shareholders of record as of the close of business on February 25, 2014. Based on our current financial projections and commodity price outlook, we expect to grow our regular annual dividend rate to between $0.50 per share and $0.60 per share in 2015 and at a sustainable rate thereafter. All dividends are subject to declaration by Denbury’s Board of Directors.

2013 Operating Highlights. Our net income was $409.6 million, or $1.11 per diluted common share, during 2013, compared to net income of $525.4 million, or $1.35 per diluted common share, during 2012.  Although we had a $56.4 million increase in oil and natural gas revenues in 2013 compared to 2012 levels, driven by higher realized prices, this increase in revenues was more than offset by increases in expenses, including (1) a $198.2 million increase in lease operating expense in the current year, $114.0 million of which constitutes remediation costs incurred or estimated for an area of Delhi Field, (2) an increase of $45.9 million in commodity derivatives expense, $27.3 million of which relates to a change in the noncash fair value adjustments on our commodity derivatives, a non-GAAP measure, between the two periods and (3) a $44.7 million loss on early extinguishment of debt. These matters are further described throughout this Management's Discussion and Analysis. Our cash flow from operations was $1.4 billion in both 2013 and 2012.

During 2013, our oil and natural gas production, which was 94% oil, averaged 70,243 BOE/d, compared to 71,689 BOE/d produced during 2012.  This slight decline in production was primarily due to the inclusion of 11 months of production in 2012 from the Bakken area assets sold in the Bakken Exchange Transaction (defined below), versus only nine months of production in 2013 from the purchase of additional interests in the Cedar Creek Anticline ("CCA"). This decline was offset in part by a 9% increase in our tertiary oil production. See Results of OperationsProduction for more information.

Our average realized oil price per barrel, excluding the impact of commodity derivative contracts, was $100.67 per Bbl during 2013, or about 4% higher than our average realized oil price of $97.18 per Bbl during 2012.  Our realized oil price during 2013 was $2.62 per Bbl above NYMEX oil prices compared to $2.99 per Bbl above NYMEX oil prices in 2012. The lower premium to NYMEX in 2013 is primarily due to a decline in Louisiana Light Sweet ("LLS") oil pricing relative to NYMEX prices, which

- 39 -


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


LLS-to-NYMEX differential averaged a positive $11.10 in 2013 compared to positive $16.46 in 2012, partially offset by improved differentials in the Rocky Mountain region, which were positively impacted by the sale of the Bakken area assets late in 2012, which assets generally sold at a more significant discount to NYMEX than the CCA assets we acquired in early 2013.  See Results of Operations – Oil and Natural Gas Revenues below for more information.

Cedar Creek Anticline Acquisition. On March 27, 2013, we closed our acquisition of producing assets in the CCA of Montana and North Dakota in a purchase from a wholly-owned subsidiary of ConocoPhillips Company ("ConocoPhillips") for $1.0 billion in cash, after final closing adjustments (the "CCA Acquisition"). We funded the acquisition with a portion of the cash proceeds from the late-2012 Bakken Exchange Transaction. The assets purchased include both additional interests in certain of our then-existing operated fields in CCA, as well as operating interests in other CCA fields. In conjunction with this acquisition, we added 42.2 MMBOE of estimated proved reserves.

Rocky Mountain Tertiary Operations Startup. In late 2012, we completed construction of the first section of the 20-inch Greencore Pipeline in Wyoming, our first CO2 pipeline in the Rocky Mountain region, and received our first CO2 deliveries from the Lost Cabin gas plant in central Wyoming during the first quarter of 2013. In December 2012, we completed the three-mile CO2 pipeline required to deliver CO2 from our source at LaBarge Field to Grieve Field in Wyoming, and began injecting CO2 into Grieve Field during the first quarter of 2013. We currently expect tertiary production from Grieve Field to commence in 2015. We started injections at our Bell Creek Field in Montana during the second quarter of 2013, with the first tertiary oil production from this field during the third quarter of 2013. During the first quarter of 2014, we completed the pipeline interconnect between a third party's existing CO2 pipeline and our Greencore pipeline, which will allow us to transport additional volumes of CO2 to Bell Creek Field.

Riley Ridge Plant. During the fourth quarter of 2013, we placed our Riley Ridge gas processing facility in Wyoming into service.

Proved Oil and Natural Gas Reserves. Our estimated proved oil and gas reserves were 468.3 MMBOE as of December 31, 2013, compared to 409.4 MMBOE at December 31, 2012. We added total proved reserves of 84.6 MMBOE during 2013, including estimated proved tertiary reserves of 34.0 MMBbls at Bell Creek Field during the fourth quarter, 42.2 MMBOE from the acquisition of additional interests in CCA during the first quarter and 8.4 MMBOE of other additions or revisions.

Addition of Proved CO2 Reserves. During the year ended December 31, 2013, we added approximately 350 Bcf of estimated proved CO2 reserves as a result of successful drilling in the Jackson Dome area, our primary source of CO2 for the Gulf Coast region, replacing our 2013 CO2 production.

Debt Refinancing. In February 2013, we issued $1.2 billion of 4 5/8% Senior Subordinated Notes due 2023 (the "2023 Notes"). The net proceeds of approximately $1.18 billion were used to repurchase or redeem our 9½% Senior Subordinated Notes due 2016 (the "9½% Notes") and our 9¾% Senior Subordinated Notes due 2016 (the "9¾% Notes"), and to pay down a portion of outstanding borrowings on our bank credit facility. We recognized a loss associated with the redemption of our 9½% Notes and 9¾% Notes of $44.7 million during the year ended December 31, 2013, which is included in our Consolidated Statement of Operations under the caption "Loss on early extinguishment of debt". See Note 5, Long-Term Debt, to the Consolidated Financial Statements for additional details surrounding the repurchase and redemption of our 9½% Notes and 9¾% Notes.

Delhi Field Release. In June 2013, a release of well fluids, consisting of a mixture of carbon dioxide, saltwater, natural gas and oil, was discovered and reported within an area of the Denbury-operated Delhi Field located in northern Louisiana. Denbury immediately took remedial action to stop the release and contain and recover well fluids in the affected area. We have determined that the release originated from one or more wells in the affected area of the field that we believed had been previously and properly plugged and abandoned by a prior operator of the field. We completed our remediation efforts during the fourth quarter of 2013; however, we will continue to monitor the area to ensure the remediation efforts were successful.

During the year ended December 31, 2013, we recorded $114.0 million of lease operating expenses related to this release in our Consolidated Statement of Operations. These expenses represent our current estimate of the costs related to the release, including remediation costs, based on actual costs incurred through December 31, 2013 of approximately $92.0 million, plus the Company’s estimate of future costs related to the satisfaction of known claims and liabilities. Due to the possibility of new claims

- 40 -


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


being asserted in the future in connection with the release, as well as variability in the estimated cost to continue to monitor the area to ensure the remediation efforts were successful, we cannot reliably determine at this time the full extent of the costs that may ultimately be incurred by the Company related to this release. Although the Company maintains insurance policies that we believe cover certain of the costs, damages and claims related to the release, and we currently and preliminarily estimate that one-third to two-thirds of our current cost estimate may be recoverable under such insurance policies, we have not reached any agreement with our insurance carriers as to recoverable amounts, and accordingly have not recognized any insurance recoveries in our financial statements as of December 31, 2013. See Note 11, Commitments and Contingencies, to the Consolidated Financial Statements for further discussion.

Costs incurred as a result of the release, together with lower production levels during the second half of 2013, are currently expected to delay into 2014 the effective date of the approximate 25% reversionary interest to the third party that sold the Delhi Field interest to us, the specific timing of which is dependent upon, among other things, the amount and timing of any potential insurance proceeds received and their application to the calculation of "total net cash flow" which determines the reversionary date, as well as oil prices, production, and production costs. We currently estimate that the reversionary date could occur as late as the fourth quarter of 2014.

Bakken Exchange Transaction. In late 2012, we closed a sale and exchange transaction with Exxon Mobil Corporation and its wholly-owned subsidiary XTO Energy Inc. (collectively, "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 magnitude of the Bakken Exchange Transaction and the CCA Acquisition discussed above impact the comparability of our 2012 and 2013 financial results in many ways, including oil and natural gas production, revenues, and operating expenses. Our financial results for the year ended December 31, 2013 include the results from the CCA Acquisition beginning late in the first quarter of 2013.

CAPITAL RESOURCES AND LIQUIDITY

Overview. Our primary sources of capital and liquidity are our cash flows from operations and borrowings under our bank credit facility. Our business is capital intensive, and it is common for oil and natural gas companies our size to reinvest most or all of their cash flow into developing new assets. We generally attempt to balance our capital spending with cash flow from operations, and we have repurchased 59.4 million shares of our common stock (approximately 14.8% of our outstanding shares at September 30, 2011) since commencement of our share repurchase program in October 2011 through February 20, 2014. During 2013, we purchased $277.8 million of our common stock, which was funded with a combination of cash flow from operations and incremental borrowings. In early 2013, we refinanced two of our high-rate subordinated notes with ten-year notes carrying an interest rate of 4 5/8%, lowering our interest expense and reducing our outstanding bank borrowings with a portion of the proceeds. We project that we will have more than adequate capital resources and liquidity for the foreseeable future because (1) we have refinanced our bank debt with low-cost subordinated debt, leaving significant borrowing capacity on our bank line; (2) we have oil hedges in place for a substantial portion of our forecasted proven oil production for the next two years, including fixed price swap derivative contracts for 2014 (see Note 9, Commodity Derivative Contracts, to the Consolidated Financial Statements for further details regarding the prices and volumes of our commodity derivative contracts); (3) we expect to fund our projected capital expenditures for the next few years with cash flow from operations, which means that our expected growth in production and cash flow will gradually reduce our leverage (assuming oil prices are relatively consistent with current levels); (4) we expect to fund our planned dividends with cash flow from operations, (5) depending on the amount of shares of our common stock we repurchase in 2014, we might defer a portion of our planned 2014 capital expenditures, and (6) we can significantly reduce our capital expenditures for extended periods of time if necessary and still maintain current production levels as a result of our unique EOR operations.

2014 Capital Spending. We anticipate that our 2014 capital budget, excluding acquisitions, will be $1.0 billion, plus approximately $125 million in capitalized internal acquisition, exploration and development costs; capitalized interest; and pre-production costs associated with new tertiary floods.  This combined 2014 capital budget amount of $1.125 billion, excluding acquisitions, is comprised of the following:

$680 million allocated for tertiary oil field expenditures;

- 41 -


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


$220 million allocated for other areas, primarily non-tertiary oil field expenditures;