10-K 1 dnr-20141231x10k.htm FORM 10-K DNR - 2014.12.31 - 10K


 

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

2014 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, 2014
OR

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

For the transition period from _________ to________

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

Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class:
Name of Each Exchange on Which Registered:
Common Stock $.001 Par Value
New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ   No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o   No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ   No o

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a small reporting company.  See the definitions of "large accelerated filer", "accelerated filer", and "small reporting company" in Rule 12-b2 of the Exchange Act.
Large accelerated filer þ   Accelerated filer o   Non-accelerated filer o  Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes o   No þ

The aggregate market value of the registrant's common stock held by non-affiliates, based on the closing price of the registrant's common stock as of the last business day of the registrant's most recently completed second fiscal quarter was $6,386,671,272.

The number of shares outstanding of the registrant's Common Stock as of January 31, 2015, was 356,635,504.
DOCUMENTS INCORPORATED BY REFERENCE
Document:
 
Incorporated as to:
1. Notice and Proxy Statement for the Annual Meeting of Stockholders to be held May 19, 2015.
 
1.  Part III, Items 10, 11, 12, 13, 14

 




Denbury Resources Inc.

2014 Annual Report on Form 10-K
 Table of Contents 
 
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

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Denbury Resources Inc.

Glossary and Selected Abbreviations
Bbl
One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.
 
 
Bbls/d
Barrels of oil or other liquid hydrocarbons produced per day.
 
 
Bcf
One billion cubic feet of natural gas, CO2 or helium.
 
 
BOE
One barrel of oil equivalent, using the ratio of one barrel of crude oil, condensate or natural gas liquids to 6 Mcf of natural gas.
 
 
BOE/d
BOEs produced per day.
 
 
Btu
British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit (°F).
 
 
CO2
Carbon dioxide.
 
 
EOR
Enhanced oil recovery. In the context of our oil and natural gas production, EOR is also referred to as tertiary recovery.
 
 
Finding and development costs
The average cost per BOE to find and develop proved reserves during a given period. It is calculated by dividing (a) costs, which include the sum of (i) the total acquisition, exploration and development costs incurred during the period plus (ii) future development and abandonment costs related to the specified property or group of properties, by (b) the sum of (i) the change in total proved reserves during the period plus (ii) total production during that period.
 
 
GAAP
Accounting principles generally accepted in the United States of America.
 
 
MBbls
One thousand barrels of crude oil or other liquid hydrocarbons.
 
 
MBOE
One thousand BOEs.
 
 
Mcf
One thousand cubic feet of natural gas, CO2 or helium at a temperature base of 60 degrees Fahrenheit (°F) and at the legal pressure base (14.65 to 15.025 pounds per square inch absolute) of the state or area in which the reserves are located or sales are made.
 
 
Mcf/d
One thousand cubic feet of natural gas, CO2 or helium produced per day.
 
 
MMBbls
One million barrels of crude oil or other liquid hydrocarbons.
 
 
MMBOE
One million BOEs.
 
 
MMBtu
One million Btus.
 
 
MMcf
One million cubic feet of natural gas, CO2 or helium.
 
 
MMcf/d
One million cubic feet of natural gas, CO2 or helium per day.
 
 
Noncash fair value adjustments on commodity derivatives

The net change during the period in the fair market value of commodity derivative positions. Noncash fair value adjustments on commodity derivatives is a non-GAAP measure and makes up only a portion of "Derivatives expense (income)" in the Consolidated Statements of Operations, which also includes the impact of settlements on commodity derivatives during the period. Its use is further discussed in Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Operating Results Table.
 
 
NYMEX
The New York Mercantile Exchange. In the context of our oil and natural gas sales, NYMEX pricing represents the West Texas Intermediate benchmark price for crude oil and Henry Hub benchmark price for natural gas.
 
 
Probable Reserves*
Reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
 
 
Proved Developed Reserves*
Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

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Denbury Resources Inc.

 
 
Proved Reserves*
Reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
 
 
Proved Undeveloped Reserves*
Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells, in each case where a relatively major expenditure is required.
 
 
PV-10 Value
The estimated future gross revenue to be generated from the production of proved reserves, net of estimated future production, development and abandonment costs, and before income taxes, discounted to a present value using an annual discount rate of 10%. PV-10 Values were prepared using average hydrocarbon prices equal to the unweighted arithmetic average of hydrocarbon prices on the first day of each month within the 12-month period preceding the reporting date.  PV-10 Value is a non-GAAP measure and does not purport to represent the fair value of our oil and natural gas reserves; its use is further discussed in footnote 5 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/retrieveECFR?gp=1&SID=6f0cbc2a2934b1576e95496863cfb7ef&ty=HTML&h=L&r=SECTION&n=se17.3.210_14_610.


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Denbury Resources Inc.

PART I

Item 1. Business and Properties

GENERAL

Denbury Resources Inc., a Delaware corporation, is an independent oil and natural gas company with 437.7 MMBOE of estimated proved oil and natural gas reserves as of December 31, 2014, of which 83% is oil.  Our operations are focused in two key operating areas: the Gulf Coast and Rocky Mountain regions.  Our goal is to increase the value of our properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to CO2 enhanced oil recovery operations.

As part of our corporate strategy, we are committed to strong financial discipline, efficient operations and creating long-term value for our shareholders through the following key principles:

target specific regions where we either have, or believe we can create, a competitive advantage as a result of our ownership or use of CO2 reserves, oil fields and CO2 infrastructure;
secure properties where we believe additional value can be created through tertiary recovery operations and a combination of other exploitation, development, exploration and marketing techniques;
acquire properties that give us a majority working interest and operational control or where we believe we can ultimately obtain it;
maximize the value and cash flow generated from our operations by increasing production and reserves while controlling costs;
optimize the timing and allocation of capital among our investment opportunities to maximize the rates of return on our investments;
return a portion of the cash flow generated from our operations to shareholders through regular quarterly dividend payments at a sustainable rate, and strategic repurchases of our common stock made from time to time;
exercise financial discipline by balancing our development capital expenditures and dividends with our cash flow from operations; and
attract and maintain a highly competitive team of experienced and incentivized personnel.

Denbury has been publicly traded on the New York Stock Exchange since 1997. Our corporate headquarters is located at 5320 Legacy Drive, Plano, Texas 75024, and our phone number is 972-673-2000. At December 31, 2014, we had 1,523 employees, 813 of whom were employed in field operations or at our field offices.  We make our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports, filed or furnished pursuant to section 13(a) or 15(d) of the Securities Exchange Act of 1934, available free of charge on or through our website, www.denbury.com, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.  The public may read and copy any materials we file with the SEC at the SEC's Public Reference Room at 100 F Street, NE, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains a website, http://www.sec.gov, which contains reports, proxy and information statements and other information filed by Denbury.  Throughout this Annual Report on Form 10-K ("Form 10-K") we use the terms "Denbury," "Company," "we," "our," and "us" to refer to Denbury Resources Inc. and, as the context may require, its subsidiaries.


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Denbury Resources Inc.

2014 BUSINESS DEVELOPMENTS

In response to the decline in oil prices during the latter part of 2014, in November 2014, we announced a significant reduction in our capital spending plans, reducing projected 2015 capital spending to $550 million, or roughly half of 2014 levels, and decreasing our estimated dividend rate for 2015 to $0.40 per common share on an annualized basis, from the previous projection of a rate ranging between $0.50 per common share to $0.60 per common share on an annualized basis. At the same time, we announced that our share repurchase program was being suspended in order to protect our financial health and preserve liquidity amid a period of declining oil prices and overall oil price uncertainty. As a result of further oil price declines in late 2014 and early 2015, in January 2015, we announced another change in our planned 2015 dividend rate, as the Company's Board of Directors declared a dividend of $0.0625 per common share for the first quarter of 2015, or $0.25 per common share on an annualized basis, a level consistent with our 2014 dividend rate.

2014 business developments also included the following:

Increased our average tertiary oil production to 41,079 Bbls/d in 2014, a 7% increase from average tertiary oil production in 2013, primarily due to continued field development and expansion of facilities in our existing CO2 floods at Hastings, Heidelberg, Oyster Bayou, Tinsley, and Bell Creek fields.

Declared quarterly cash dividends of $0.0625 per common share during each quarter of 2014, with aggregate dividends of $87.0 million, or $0.25 per common share, paid during the year ended December 31, 2014.

Repurchased a total of 12.4 million shares of Denbury common stock for $200.4 million during the first quarter of 2014.

Reduced our interest expense by refinancing a portion of our indebtedness. In April 2014, we issued $1.25 billion of 5½% Senior Subordinated Notes due 2022. The net proceeds of approximately $1.23 billion, after issuance costs, were used to repurchase and redeem our 8¼% Senior Subordinated Notes due 2020 and to pay down approximately $150 million of outstanding borrowings on our bank credit facility.

Amended and restated our bank credit facility, effective as of December 9, 2014, to provide for a borrowing base of $3.0 billion, aggregate lender commitments of $1.6 billion, and an extended termination date of the facility from May 2016 to December 2019.

During the fourth quarter of 2014, we created innovation and improvement teams to evaluate each of our assets during 2015 with a goal of increasing the value of both existing assets and future projects by optimizing field operational and development plans, increasing CO2 flood recovery efficiency and reducing costs.

OIL AND NATURAL GAS OPERATIONS

Summary. Our oil and natural gas properties are concentrated in the Gulf Coast and Rocky Mountain regions of the United States.  Currently our properties with proved and producing reserves in the Gulf Coast region are situated in Mississippi, Texas, Louisiana and Alabama, and in the Rocky Mountain region are situated in Montana, North Dakota and Wyoming. Our primary focus is using CO2 in EOR, and our current portfolio of CO2 EOR projects provides us significant oil production and reserve growth potential in the future.  

We have been conducting and expanding EOR operations on our assets in the Gulf Coast region since 1999, and as a result, we currently have many more CO2 EOR projects in this region than in the Rocky Mountain region. In the Gulf Coast region, we own what is, to our knowledge, the region's only significant naturally occurring source of CO2, and these large volumes of naturally occurring CO2 have allowed us to significantly grow our production in that region. In addition to the sources of CO2 we currently own, we purchase and use CO2 captured from industrial sources which would otherwise be released into the atmosphere (sometimes referred to as anthropogenic, man-made or industrial-source CO2) in our tertiary operations. These industrial sources of CO2 help us recover additional oil from mature oil fields and, we believe, also provide an economical way to reduce atmospheric CO2 emissions through the concurrent underground storage of CO2 which occurs as part of our oil-producing EOR operations. We expect the amount of CO2 we use which is captured from industrial sources to grow in the future.


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Denbury Resources Inc.

Through December 31, 2014, we have invested a total of $4.1 billion in our tertiary fields in the Gulf Coast region (including acquisition costs and goodwill) and, in addition to recovering all of these costs, we have generated $1.9 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 $286.9 million (7%) has been spent on fields that did not have any appreciable proved reserves at December 31, 2014.  The proved oil reserves in our Gulf Coast tertiary oil fields have a year-end 2014 PV-10 Value of $4.8 billion, calculated using average 2014 NYMEX oil prices of $94.99.  Including the Green Pipeline, which currently serves our Hastings and Oyster Bayou fields, we have invested a total of $2.2 billion in CO2 pipelines and CO2 source fields in the Gulf Coast region.

We began operations in the Rocky Mountain region in 2010 in connection with, and following, our merger with Encore Acquisition Company ("Encore").  We completed construction of the first section of the 20-inch Greencore Pipeline (our first CO2 pipeline in the Rocky Mountain region) in late 2012, and received our first CO2 deliveries from the ConocoPhillips-operated Lost Cabin gas plant in central Wyoming during the first quarter of 2013. We started CO2 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 flood in the Rocky Mountain region, we currently have long-term plans to flood Hartzog Draw Field, Grieve Field, and the Cedar Creek Anticline ("CCA") with CO2 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 acquisition (completed in two stages) in 2010 and 2011, the acquisition of an interest in CO2 reserves in LaBarge Field from Exxon Mobil Corporation and its wholly-owned subsidiary XTO Energy Inc. (collectively, "ExxonMobil") in 2012, and the previously mentioned deliveries from the ConocoPhillips-operated Lost Cabin gas plant are expected to provide us the CO2 necessary for our current inventory of CO2 EOR projects in the Rocky Mountain region.

Field Summary Table. The following table provides a summary by field and region of selected proved oil and natural gas reserve information, including total proved reserve quantities and the associated PV-10 Value of those reserves as of December 31, 2014, and average daily production for 2014, all based on Denbury's net revenue interest ("NRI").  The reserve estimates for all years presented were prepared by DeGolyer and MacNaughton ("D&M"), independent petroleum engineers located in Dallas, Texas.  We serve as operator of virtually all of our significant properties, in which we also own most of the interests, although typically less than a 100% working interest, and a lesser NRI due to royalties and other burdens.  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, 2014 (1)
 
2014 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 2014 NRI
Tertiary oil and gas properties
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gulf Coast region
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mature properties:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Brookhaven
8,373

 

 
8,373

 
1.9
%
 
$
254,190

 
1,759

 

 
81.4
%
Eucutta
6,853

 

 
6,853

 
1.6
%
 
161,070

 
2,137

 

 
83.6
%
Mallalieu
5,083

 

 
5,083

 
1.2
%
 
178,238

 
1,799

 

 
78.1
%
Other mature properties (3)
19,813

 

 
19,813

 
4.5
%
 
425,246

 
6,122

 

 
71.7
%
Total mature properties
40,122

 

 
40,122

 
9.2
%
 
1,018,744

 
11,817

 

 
75.9
%
Delhi (4)
27,573

 

 
27,573

 
6.3
%
 
546,648

 
4,340

 

 
74.0
%
Hastings
41,687

 

 
41,687

 
9.5
%
 
1,039,419

 
4,777

 

 
79.9
%
Heidelberg
33,170

 

 
33,170

 
7.5
%
 
904,021

 
5,707

 

 
80.8
%
Oyster Bayou
13,413

 

 
13,413

 
3.1
%
 
508,243

 
4,683

 

 
87.0
%
Tinsley
22,648

 

 
22,648

 
5.2
%
 
829,163

 
8,507

 

 
81.4
%
Total Gulf Coast region
178,613

 

 
178,613

 
40.8
%
 
4,846,238

 
39,831

 

 
79.1
%
Rocky Mountain region
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Bell Creek
36,505

 

 
36,505

 
8.3
%
 
721,717

 
1,248

 

 
83.6
%
Total Rocky Mountain region
36,505

 

 
36,505

 
8.3
%
 
721,717

 
1,248

 

 
83.6
%
Total tertiary properties
215,118

 

 
215,118

 
49.1
%
 
5,567,955

 
41,079

 

 
79.3
%
Non-tertiary oil and gas properties
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gulf Coast region
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mississippi
2,932

 
35,376

 
8,828

 
2.0
%
 
112,754

 
1,093

 
7,350

 
30.9
%
Texas
24,462

 
18,632

 
27,567

 
6.3
%
 
625,952

 
5,384

 
5,436

 
80.7
%
Other
6,033

 
3,301

 
6,583

 
1.6
%
 
99,359

 
976

 
514

 
29.1
%
Total Gulf Coast region
33,427

 
57,309

 
42,978

 
9.9
%
 
838,065

 
7,453

 
13,300

 
53.6
%
Rocky Mountain region
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cedar Creek Anticline (5)
103,886

 
15,839

 
106,526

 
24.3
%
 
2,099,653

 
18,488

 
2,073

 
81.0
%
Riley Ridge

 
367,516

 
61,253

 
14.0
%
 
27,606

 

 
968

 
79.7
%
Other
9,904

 
11,738

 
11,860

 
2.7
%
 
214,790

 
3,586

 
6,614

 
38.8
%
Total Rocky Mountain region
113,790

 
395,093

 
179,639

 
41.0
%
 
2,342,049

 
22,074

 
9,655

 
68.9
%
Total non-tertiary properties
147,217

 
452,402

 
222,617

 
50.9
%
 
3,180,114

 
29,527

 
22,955

 
63.9
%
Company Total
362,335

 
452,402

 
437,735

 
100.0
%
 
$
8,748,069

 
70,606

 
22,955

 
72.1
%

(1)
The above reserve estimates were prepared in accordance with Financial Accounting Standards Board Codification ("FASC") Topic 932, Extractive Industries – Oil and Gas, using the arithmetic average of the first-day-of-the-month NYMEX commodity price for each month during 2014, which were $94.99 per Bbl for crude oil and $4.30 per MMBtu for natural gas, both of which were adjusted for market differentials by field. This prescribed methodology does not reflect significant crude oil price declines in late 2014 and early 2015, when oil prices dropped rapidly, declining to below $45 per Bbl in January 2015. Sustained prices at these recent levels would result in a significant decrease in our PV-10 Value, and to a lesser degree, a reduction in our proved reserve volumes.

(2)
PV-10 Value is a non-GAAP measure and is different from the GAAP measure, the Standardized Measure of Discounted Future Net Cash Flows ("Standardized Measure"), in that PV-10 Value is a pre-tax number and the Standardized Measure is an after-tax number.  The Standardized Measure was $5.9 billion at December 31, 2014.  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

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Denbury Resources Inc.

from data determined in accordance with FASC Topic 932.  See the definition of PV-10 Value in the Glossary and Selected Abbreviations.

(3)
Other mature properties include Cranfield, Little Creek, Martinville, McComb and Soso fields in Mississippi and Lockhart Crossing Field in Louisiana.

(4)
The foregoing Delhi Field reserve quantities, values and average daily production reflect the reversionary assignment of approximately 25% of our interest in that field effective November 1, 2014. The effectiveness, timing, and scope of the reversionary assignment are subject to ongoing litigation, the ultimate outcome of which cannot be predicted.

(5)
The Cedar Creek Anticline consists of a series of 14 different operating areas.

Enhanced Oil Recovery Overview. CO2 used in EOR is one of the most efficient tertiary recovery mechanisms for producing crude oil.  When injected under pressure into underground, oil-bearing rock formations, CO2 acts somewhat like a solvent as it travels through the reservoir rock, mixing with and modifying the characteristics of the oil so it can be produced and sold.  The terms "tertiary flood," "CO2 flood" and "CO2 EOR" are used interchangeably throughout this document.

While enhanced oil recovery projects utilizing CO2 have been successfully performed by numerous oil and gas companies in a wide range of oil-bearing reservoirs in different oil-producing basins, we believe our investments, experience and acquired knowledge give us a strategic and competitive advantage in the areas in which we operate. We apply what we have learned and developed over the years to improve and increase sweep efficiency within the CO2 EOR projects we operate.  

We began our CO2 operations in August 1999, when we acquired Little Creek Field, followed by our acquisition of Jackson Dome CO2 reserves and the NEJD pipeline in 2001.  Based upon our success at Little Creek and the ownership of the CO2 reserves, we began to transition our capital spending and acquisition efforts to focus more heavily on CO2 EOR and, over time, transformed our strategy to focus primarily on owning and operating oil fields that are well suited for CO2 EOR projects. Prior to tertiary flooding, we strive to maximize the currently sizeable primary and secondary production from our prospective tertiary fields and from fields in which tertiary floods have commenced but still contain significant non-tertiary production.  Our asset base today almost entirely consists of, or otherwise relates to, oil fields that we are currently flooding with CO2 or plan to flood with CO2 in the future, or assets that produce CO2.

Our tertiary operations have grown so that (1) 49% of our proved reserves at December 31, 2014 are proved tertiary oil reserves; (2) 55% of our 2014 production was related to tertiary oil operations (on a BOE basis); and (3) 75% of our 2014 capital expenditures (excluding acquisitions) were related to our tertiary oil operations.  At year-end 2014, the proved oil reserves in our tertiary recovery oil fields had an estimated PV-10 Value of approximately $5.6 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 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) an industry-competitive rate of return at relatively low oil prices, depending on the specific field and area, (3) limited competition for this recovery method in our geographic regions, (4) our EOR operations are generally less disruptive to new habitats in comparison to other oil and natural gas development because we further develop existing (as opposed to new) oil fields, and (5) through our oil-producing EOR operations, we concurrently store CO2 captured from industrial sources in the same underground formations that previously trapped and stored oil and natural gas.

2015 Development Plan. In the fourth quarter of 2014, we announced that we were undertaking development plan changes and operational initiatives in light of the late-2014 significant oil price declines and uncertainty around future oil prices. These changes included reducing budgeted 2015 capital spending to a level at which we believe we can maintain production relatively flat with average 2014 levels, while slowing the development pace of certain fields. During this period of reduced capital spending, the recently-created innovation and improvement teams are evaluating each of our assets with a goal of increasing the value of both existing assets and future projects by optimizing field operational and development plans, increasing CO2 flood recovery efficiency and reducing costs. These initiatives aim to increase the profitability of our assets, making them more resilient to lower

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Denbury Resources Inc.

oil prices. We will continue to evaluate the timing of development of our inventory of fields and related pipelines and facilities, which will be largely dependent upon commodity prices and CO2 availability. Therefore, planned development activities presented in the discussions that follow may be delayed or modified depending primarily upon oil prices and our level of cash flow to fund such development, as well as the availability of CO2.

Tertiary Oil Properties

Gulf Coast Region

CO2 Sources and Pipelines

Jackson Dome.  Our primary Gulf Coast CO2 source, Jackson Dome, located near Jackson, Mississippi, was discovered during the 1970s by oil and gas companies that were exploring for hydrocarbons.  This large and relatively pure source of naturally occurring CO2 (98% CO2) is, to our knowledge, the only significant underground deposit of CO2 in the United States east of the Mississippi River. Together with the related CO2 pipeline infrastructure, Jackson Dome provides us a significant strategic advantage in the acquisition of properties in Mississippi, Louisiana and southeastern Texas that are well suited for CO2 EOR.

We acquired Jackson Dome in February 2001 in a purchase that also gave us ownership and control of the NEJD CO2 pipeline and provided us with a reliable supply of CO2 at a reasonable and predictable cost for our Gulf Coast CO2 tertiary recovery operations.  Since February 2001, we have acquired and drilled numerous CO2-producing wells, significantly increasing our estimated proved Gulf Coast CO2 reserves from approximately 800 Bcf at the time of acquisition of Jackson Dome to approximately 5.7 Tcf as of December 31, 2014.  The CO2 reserve estimates are based on a gross working interest of the CO2 reserves, of which our net revenue interest is approximately 4.5 Tcf, and is included in the evaluation of proved CO2 reserves prepared by D&M, an independent petroleum engineering consulting firm.  In discussing our available CO2 reserves, we make reference to the gross amount of proved and probable reserves, as this is the amount that is available both for our own tertiary recovery programs and for industrial users who are customers of Denbury and others, as we are responsible for distributing the entire CO2 production stream.

In addition to our proved reserves, we estimate that we have 2.1 Tcf of probable CO2 reserves at Jackson Dome.  While the majority of these probable reserves are located in structures that have been drilled and tested, such reserves are still considered probable reserves because (1) the original well is plugged; (2) they are located in fault blocks that are immediately adjacent to fault blocks with proved reserves; or (3) they are reserves associated with increasing the ultimate recovery factor from our existing reservoirs with proved reserves. In addition, a significant portion of these probable reserves at Jackson Dome are located in undrilled structures where we have sufficient subsurface and seismic data indicating geophysical attributes that, coupled with our historically high drilling success rate, provide a reasonably high degree of certainty that CO2 is present.

Although our current proved CO2 reserves are sizeable, in order to continue our tertiary development of oil fields in the Gulf Coast region, incremental deliverability of CO2 is required.  In order to obtain additional CO2 deliverability, we have conducted several 3D seismic surveys in the Jackson Dome area over the past several years and anticipate drilling one development well in 2015 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 CO2 expected to be captured from industrial sources, to provide sufficient quantities of CO2 for us to develop our proved and probable EOR reserves in the Gulf Coast region. In the future, we believe that once a CO2 flood in a field reaches its productive economic limit, we could recycle a portion of the CO2 that remains in that field's reservoir and utilize it for oil production in another field's tertiary flood.

In the Gulf Coast region, approximately 91% of our average daily CO2 produced from Jackson Dome or captured from industrial sources in 2014, 2013 and 2012 was used in our tertiary recovery operations, with the balance delivered to third-party industrial users. During 2014, we used an average of 835 MMcf/d of CO2 (including CO2 captured from industrial sources) for our tertiary activities.


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Denbury Resources Inc.

Gulf Coast CO2 Captured from Industrial Sources.  In addition to our natural source of CO2, we are currently party to three long-term contracts to purchase CO2 from industrial plants.  We currently purchase CO2 from an industrial facility in Port Arthur, Texas and from an industrial facility in Geismar, Louisiana, and we anticipate taking deliveries in 2016 from Mississippi Power's Kemper County Energy Facility. We estimate these 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.  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 federal legislation, which could impose economic penalties for atmospheric CO2 emissions.  We believe that we are a likely purchaser of CO2 captured in our areas of operation because of the scale of our tertiary operations and our CO2 pipeline infrastructure.

Gulf Coast CO2 Pipelines. We acquired the 183-mile NEJD CO2 pipeline that runs from Jackson Dome to near Donaldsonville, Louisiana, as part of the 2001 acquisition of our Jackson Dome CO2 source.  Since 2001, we have acquired or constructed nearly 755 miles of CO2 pipelines, and as of December 31, 2014, we have access to over 950 miles of CO2 pipelines, which gives us the ability to deliver CO2 throughout the Gulf Coast region.  In addition to the NEJD CO2 pipeline, the major pipelines in the Gulf Coast region are the Free State Pipeline (90 miles), 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 CO2 from an industrial facility in Port Arthur, Texas in 2012, and are currently transporting a third party's CO2 for a fee to the sales point at Hastings Field.  In addition, we began receiving CO2 from an industrial facility in Geismar, Louisiana in 2013. We expect the volume of CO2 transported through the Green Pipeline to increase in future years as we develop our inventory of CO2 EOR projects in this area.

Tertiary Properties with Tertiary Production and Proved Tertiary Reserves at December 31, 2014

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 29% of our total 2014 CO2 EOR production and approximately 19% 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 2015, we currently plan to invest approximately $20 million to further develop our mature tertiary properties.

From the time we originally acquired these properties through December 31, 2014, we have recovered all of our tertiary investment relating to our mature properties, and the excess net cash flow (revenue less operating expenses and capital expenditures, including the acquisition costs) from these mature properties through that date was $2.1 billion.  As of December 31, 2014, the estimated PV-10 Value of our mature properties was $1.0 billion.

Delhi Field. Delhi Field is located east of Monroe, Louisiana.  In May 2006, we purchased our initial interest in 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 in the applicable agreements between the parties.  We began well and facility development in 2008 and began delivering CO2 to the field in the fourth quarter of 2009 via the Delta Pipeline, which runs from Tinsley Field to Delhi Field.

First tertiary production occurred at Delhi Field in the first quarter of 2010.  Production from Delhi Field in the fourth quarter of 2014 averaged 3,743 Bbls/d, down from 4,793 Bbls/d in the fourth quarter of 2013.  The primary reason for this comparative fourth quarter decline is the November 1, 2014, reversionary assignment to the seller of the field of approximately 25% of our

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Denbury Resources Inc.

interest in Delhi Field. The effectiveness, timing, and scope of the reversionary assignment are subject to ongoing litigation, the ultimate outcome of which cannot be predicted.

Additionally, our development of Delhi Field has been impacted by a release of well fluids within an area of Delhi Field occurring in the second quarter of 2013 and our subsequent remediation of such release. During the years ended December 31, 2014 and 2013, we recorded $16.8 million and $114.0 million, respectively, of lease operating expenses related to this release and its remediation in our Consolidated Statements of Operations, bringing our total cost estimate to date with respect to these expenses to $130.8 million. We received a $25.0 million cost reimbursement ($23.9 million net to Denbury) in October 2014 related to the Delhi Field release and remediation from our insurance carrier providing the first layer of our excess insurance coverage, which was recognized as a reduction to lease operating expenses for the year ended December 31, 2014. See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations Capital Resources and Liquidity Insurance Recoveries to Cover Costs of 2013 Delhi Field Release and Note 11, Commitments and Contingencies to the Consolidated Financial Statements for further discussion of these matters. We currently plan to invest approximately $30 million to $50 million in this field during 2015, primarily related to a natural gas liquids extraction plant, which we anticipate will be placed into service in the second half of 2016. This plant will provide us with the ability to sell natural gas liquids from the produced stream, improve the efficiency of the flood, and utilize extracted methane to power the plant and reduce field operating expenses.

From inception through December 31, 2014, we had not yet recovered our tertiary 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 $12 million. As of December 31, 2014, the estimated PV-10 Value of Delhi Field was $546.6 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.  In 2015, we will begin employing a new series flood approach to certain portions of this field. The series flood includes CO2 flooding one zone at a time and moving up the reservoir, which we believe will enhance the overall efficiency of the flood, and may also be applied in the future to other fields with appropriate reservoir characteristics. During the fourth quarter of 2014, tertiary production from Hastings Field averaged 4,811 Bbls/d, compared to 4,270 Bbls/d in the fourth quarter of 2013. We currently plan to invest approximately $25 million in 2015 to continue to expand our development and implement the series flood at Hastings Field.

From inception through December 31, 2014, we had not yet recovered our tertiary 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 $333 million.  As of December 31, 2014, the estimated PV-10 Value of Hastings Field was $1.0 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 we began flooding the Christmas and Tuscaloosa zones in 2013 and 2014, respectively.  During the fourth quarter of 2014, tertiary production at Heidelberg Field averaged 6,164 Bbls/d, compared to 5,206 Bbls/d in the fourth quarter of 2013.  In 2015, we currently plan to invest approximately $45 million to continue developing the East and West Heidelberg Units, including an expansion of our Tuscaloosa development and Christmas zone and adjustments to our CO2 floods of existing zones to better direct the CO2 through the zones and optimize oil recovery from the field.

From inception through December 31, 2014, we have recovered all of our tertiary investment relating to the CO2 flood at Heidelberg Field, and the excess net cash flow (revenue less operating expenses and capital expenditures, including the acquisition costs) from the field was $14 million.  As of December 31, 2014, the estimated PV-10 Value of Heidelberg Field was $904.0 million.

Oyster Bayou Field.  We acquired a majority interest in Oyster Bayou Field in 2007. The field is located in southeast Texas, east of Galveston Bay, and is somewhat unique when compared to our other CO2 EOR projects because the field covers a relatively small area of 3,912 acres.  We began CO2 injections into Oyster Bayou Field in the second quarter of 2010, commenced tertiary

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Denbury Resources Inc.

production in the fourth quarter of 2011 from the Frio A-1 zone, and booked initial proved tertiary reserves for the field in 2012.  In 2014, we completed development of the Frio A-2 zone and currently expect peak production from the field to occur in 2015. During the fourth quarter of 2014, tertiary production at Oyster Bayou Field averaged 5,638 Bbls/d, compared to 3,869 Bbls/d in the fourth quarter of 2013. In 2015, we currently plan to invest approximately $10 million to complete minor facility and conformance work.

From inception through December 31, 2014, we had not yet recovered our tertiary 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 $29 million.  As of December 31, 2014, the estimated PV-10 Value of Oyster Bayou Field was $508.2 million.

Tinsley Field.  We acquired Tinsley Field in 2006. This Mississippi field was discovered and first developed in the 1930s and is separated by different fault blocks.  As is the case with the majority of fields in Mississippi, Tinsley Field produces from multiple reservoirs.  Our CO2 enhanced oil recovery operations at Tinsley Field have thus far targeted the Woodruff formation, although there is additional potential in the Perry sandstone and other smaller reservoirs.  We commenced tertiary oil production from Tinsley Field in the second quarter of 2008, substantially completed development of the Woodruff formation by the end of 2014, and currently expect production to peak and begin declining in 2015.  During the fourth quarter of 2014, the average tertiary oil production was 8,767 Bbls/d, compared to 7,809 Bbls/d in the fourth quarter of 2013. In 2015, we currently plan to invest approximately $10 million to minimize production declines at the field. 

From inception through December 31, 2014, we have recovered all of our tertiary investment relating to the CO2 flood at 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 $502 million.  As of December 31, 2014, the estimated PV-10 Value of Tinsley Field was $829.2 million.

Future Tertiary Properties with No Tertiary Production or Proved Tertiary Reserves at December 31, 2014

Webster Field. We acquired our interest in Webster Field in the fourth quarter of 2012 as part of the sale and exchange transaction with ExxonMobil under which we sold to ExxonMobil our Bakken area assets in North Dakota and Montana in exchange for (1) $1.3 billion in cash, (2) operating interests in Hartzog Draw and Webster fields in Wyoming and Texas, respectively, and (3) an overriding royalty interest equivalent to an approximate one-third ownership interest in ExxonMobil's CO2 reserves in LaBarge Field in Wyoming (the "Bakken Exchange Transaction"). The field is located in Texas, approximately eight miles northeast of our Hastings Field which we are currently flooding with CO2. At December 31, 2014, Webster Field had estimated proved non-tertiary reserves of approximately 3.0 MMBOE, net to our interest.  During the fourth quarter of 2014, non-tertiary production at Webster Field averaged 1,121 BOE/d, compared to 1,036 BOE/d in the fourth quarter of 2013.  Webster Field is geologically similar to our Hastings Field, producing oil from the Frio zone at similar depths; as a result, we believe it is well suited for CO2 EOR. In 2014, we completed a nine-mile lateral between the Green Pipeline and Webster Field, which will eventually deliver CO2 to the field. In 2015, we currently plan to invest approximately $55 million on well work and field facilities, as well as on initial construction of a CO2 recycle facility for the East Fault Block. We currently expect to commence CO2 injections at Webster Field in 2016, with first tertiary production expected in 2017, the timing of which could be delayed depending on future oil prices.

Conroe Field.  Conroe Field, our largest potential tertiary flood in the Gulf Coast region, is located north of Houston, Texas.  We acquired a majority interest in this field in 2009 for $271 million in cash and 11.6 million shares of Denbury common stock, for a total aggregate value of $439 million.  Conroe Field had estimated proved non-tertiary reserves of approximately 12.3 MMBOE at December 31, 2014, net to our interest, all of which are proved developed.  During the fourth quarter of 2014, production at Conroe Field averaged 3,386 BOE/d, compared to 2,697 BOE/d in the fourth quarter of 2013, with the production increase due primarily to performing recompletions and upgrades in 2014.

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

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Denbury Resources Inc.

currently expect that over the next five years we will begin construction of this pipeline and prepare to commence CO2 injections at Conroe Field, the timing of which may change depending on future oil prices.

Thompson Field. We acquired our interest in Thompson Field in June 2012 for $366 million. The field is located in Texas, approximately 18 miles west of our Hastings Field. Thompson Field had estimated proved non-tertiary reserves of approximately 10.2 MMBOE at December 31, 2014, net to our interest, of which approximately 77% is proved developed.  During the fourth quarter of 2014, non-tertiary production at Thompson Field averaged 1,556 BOE/d net to our interest, compared to 1,331 BOE/d in the fourth quarter of 2013.  Thompson Field is geologically similar to Hastings Field, producing oil from the Frio zone at similar depths, and we therefore believe it has CO2 EOR potential. Under the terms of the Thompson Field acquisition agreement, after the initiation of CO2 injection, the seller will retain approximately a 5% gross revenue interest (less severance taxes) once average monthly oil production exceeds 3,000 Bbls/d. The timing of CO2 injections at Thompson Field is currently scheduled more than five years in the future, the ultimate timing of which is primarily dependent upon future oil prices.

Rocky Mountain Region

CO2 Sources and Pipelines

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

During 2014, we received an average of approximately 40 MMcf/d of CO2 from ExxonMobil's Shute Creek gas processing plant at LaBarge Field. Based on current capacity, and subject to availability of CO2, we currently expect to ultimately receive up to 115 MMcf/d of CO2 by 2021 from such plant. We pay ExxonMobil a fee to process and deliver the CO2, which we use in our Rocky Mountain region CO2 floods. As of December 31, 2014, our interest in LaBarge Field consisted of approximately 1.2 Tcf of proved CO2 reserves.

Riley Ridge. The Riley Ridge Federal Unit is also located in southwestern Wyoming and produces gas from the same LaBarge Field. In a series of two acquisitions in 2010 and 2011, we acquired 100% of the operating interests in Riley Ridge, as well as a gas processing facility that was under construction at the time of purchase, for $347 million. The gas processing facility separates helium and natural gas from the gas stream. During construction of the gas processing facility, we encountered issues related to contractor performance and design failure that resulted in significant delays and incremental costs to complete the facility. We placed the gas processing facility into service during the fourth quarter of 2013 and were successful in running the facility for part of 2014, but encountered additional issues in 2014, which kept the facility from running at optimum levels, as well as additional problems associated with sulfur build-up in the gas supply wells. We are currently working to correct and remedy these issues; however, we currently expect natural gas production at Riley Ridge will remain shut-in due to such issues until 2016.

As of December 31, 2014, our interest in Riley Ridge and minor surrounding acreage contained net proved reserves of 368 Bcf (61 MMBOE) of natural gas and 1.8 Tcf of CO2 reserves.  The gas composition is approximately 65% CO2, approximately 16% to 18% methane, less than one percent helium, and the remainder various other gases. The CO2 reserve estimates are based on the gross working interest of the CO2 reserves, in which our net revenue interest is approximately 1.4 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, 2014, we estimate that Riley Ridge contains proved helium reserves of 13.2 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 CO2 reserve potential in other acreage surrounding Riley Ridge in which we also own an interest.

Initially, the gas processing facility at Riley Ridge was designed to separate for sale the natural gas and helium from the full well stream, with the remaining gases, principally CO2, re-injected into the producing formation or a deeper formation. Ultimately, our primary purpose for acquiring Riley Ridge was to gain a source of CO2 to utilize in flooding our fields in the Rocky Mountain

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Denbury Resources Inc.

region. We intend to construct a CO2 capture facility and will start to use CO2 from Riley Ridge following completion of the capture facility and planned CO2 pipeline connecting Riley Ridge to our existing Greencore Pipeline, the timing of which is largely dependent upon future oil prices and prioritization of development activities.

Other Rocky Mountain CO2 Sources.  We began purchasing and receiving CO2 from the ConocoPhillips-operated Lost Cabin gas plant in central Wyoming in the first quarter of 2013, under a contract that provides us as much as 50 MMcf/d of CO2 for use in our Rocky Mountain region CO2 floods. Our volumes received from the plant averaged approximately 29 MMcf/d in 2014.

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 various Rocky Mountain region CO2 sources (see Rocky Mountain Region CO2 Sources and Pipelines above) to the Cedar Creek Anticline in eastern Montana and western North Dakota. The initial 232-mile section of the Greencore Pipeline begins at the ConocoPhillips-operated Lost Cabin gas plant in Wyoming and terminates at Bell Creek Field in Montana.  We completed construction of this section of the pipeline in the fourth quarter of 2012 and received our first CO2 deliveries from the ConocoPhillips-operated Lost Cabin gas plant during the first quarter of 2013.  During the first quarter of 2014, we completed construction of an interconnect between our Greencore Pipeline and an existing third-party CO2 pipeline in Wyoming, which enables us to transport CO2 from LaBarge Field to our Bell Creek Field.

Tertiary Properties with Tertiary Production and Proved Tertiary Reserves at December 31, 2014

Bell Creek Field.  Bell Creek Field is located in southeast Montana, and we acquired our interest in this field as part of the Encore merger in 2010.  The oil-producing reservoir in Bell Creek Field is a sandstone reservoir with characteristics similar to those we have successfully flooded with CO2 in the Gulf Coast region. We began first CO2 injections into Bell Creek Field 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 2014 averaged 1,659 Bbls/d of oil, compared to 177 Bbls/d in the fourth quarter of 2013, as production has steadily grown from the initial production response in the third quarter of 2013.  We expect production from this field will continue to increase for several years. In 2015, we plan to invest approximately $55 million to expand our CO2 flood at Bell Creek Field.

From inception through December 31, 2014, we had not yet recovered our tertiary 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 $490 million. As of December 31, 2014, the estimated PV-10 Value of Bell Creek Field was $721.7 million.

Future Tertiary Properties with No Tertiary Production or Proved Tertiary Reserves at December 31, 2014

Cedar Creek Anticline.  CCA is the largest potential EOR property that we own and currently our largest producing property, contributing approximately 25% of our 2014 total production. The field is primarily located in Montana but covers such a large area (approximately 126 miles) that it also extends into North Dakota.  CCA is a series of 14 different operating areas, each of which could be considered a field by itself.  We acquired our initial interest in CCA as part of the Encore merger in 2010 and acquired additional interests (the "CCA Acquisition") from a wholly-owned subsidiary of ConocoPhillips in the first quarter of 2013, adding 42.2 MMBOE of incremental proved reserves at that date. See Note 2, Acquisition, to the Consolidated Financial Statements for further discussion of this transaction. Production from CCA, net to our interest, averaged 18,553 BOE/d during the fourth quarter of 2014, compared to production during the fourth quarter of 2013 of 18,601 BOE/d. The non-tertiary proved reserves associated with CCA were 103.9 MMBbls of oil and 15.8 Bcf of gas as of December 31, 2014.

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 2015, we plan to invest approximately $50 million to improve waterfloods, drill infill development wells, and complete an environmental impact study for CO2 development permitting. Our current plan for initiating a CO2 flood at CCA is scheduled more than five years from now, the timing of which may change depending on future oil prices.

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 5.0 MMBOE at December 31, 2014,

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Denbury Resources Inc.

net to our interest, 1.5 MMBOE of which relate to the natural gas producing Big George coal zone.  During the fourth quarter of 2014, non-tertiary production averaged 2,639 BOE/d, compared to 2,204 BOE/d in the fourth quarter of 2013. We successfully completed 5 wells in Hartzog Draw Field in 2014; however, we have temporarily suspended the non-tertiary development of Hartzog Draw Field in light of the recent oil price environment. We will continue to evaluate future development opportunities and plan to continue development of the Shannon formation if prices return to higher levels that provide an acceptable rate of return. We believe the oil reservoir characteristics of Hartzog Draw Field make it well suited for CO2 EOR in the future. 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 more than five years from now, the timing of which is dependent on future oil prices.

Other Non-Tertiary Oil Properties

Despite the majority of our oil and natural gas properties discussed above consisting of either existing or planned future tertiary floods, we do also produce oil and natural gas either from fields in both our Gulf Coast and Rocky Mountain regions that are not amenable to EOR or from specific reservoirs (within an existing tertiary field) that are not amenable to EOR. For example, at Heidelberg Field, we produce natural gas from the Selma Chalk reservoir, which is separate from the Christmas and Eutaw reservoirs currently being flooded with CO2. Production from these other non-tertiary properties totaled 5,747 BOE/d during the fourth quarter of 2014, compared to 6,994 BOE/d during the fourth quarter of 2013.
 
OIL AND GAS ACREAGE, PRODUCTIVE WELLS AND DRILLING ACTIVITY

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

Oil and Gas Acreage

The following table sets forth our acreage position at December 31, 2014:
 
Developed
 
Undeveloped
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Gulf Coast region
232,129

 
200,851

 
298,234

 
20,538

 
530,363

 
221,389

Rocky Mountain region
359,038

 
316,620

 
232,135

 
110,641

 
591,173

 
427,261

Total
591,167

 
517,471

 
530,369

 
131,179

 
1,121,536

 
648,650


The percentage of our net undeveloped acreage that is subject to expiration over the next three years, if not renewed, is approximately 5% in 2015, 7% in 2016 and 10% in 2017.


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Denbury Resources Inc.

Productive Wells

The following table sets forth our gross and net productive oil and natural gas wells as of December 31, 2014:
 
Producing Oil Wells
 
Producing Natural Gas Wells
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Operated wells
 
 
 
 
 
 
 
 
 
 
 
Gulf Coast region
1,322

 
1,226.3

 
212

 
195.2

 
1,534

 
1,421.5

Rocky Mountain region
1,164

 
1,063.9

 
208

 
119.1

 
1,372

 
1,183.0

Total
2,486

 
2,290.2

 
420

 
314.3

 
2,906

 
2,604.5

Non-operated wells
 

 
 

 
 

 
 

 
 

 
 

Gulf Coast region
26

 
1.5

 
4

 
0.1

 
30

 
1.6

Rocky Mountain region
101

 
15.2

 
83

 
28.4

 
184

 
43.6

Total
127

 
16.7

 
87

 
28.5

 
214

 
45.2

Total wells
 

 
 

 
 

 
 

 
 

 
 

Gulf Coast region
1,348

 
1,227.8

 
216

 
195.3

 
1,564

 
1,423.1

Rocky Mountain region
1,265

 
1,079.1

 
291

 
147.5

 
1,556

 
1,226.6

Total
2,613

 
2,306.9

 
507

 
342.8

 
3,120

 
2,649.7


Drilling Activity

The following table sets forth the results of our drilling activities over the last three years.  As of December 31, 2014, we had 13 gross (12.6 net) wells in progress.
 
Year Ended December 31,
 
2014
 
2013
 
2012
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Exploratory wells (1)
 
 
 
 
 
 
 
 
 
 
 
Productive (2)

 

 

 

 
1

 

Non-productive (3)

 

 

 

 

 

Development wells (1)
 

 
 

 
 

 
 

 
 

 
 

Productive (2)
59

 
55.9

 
49

 
44.3

 
201

 
87.4

Non-productive (3)(4)

 

 
1

 
1.0

 
5

 
3.2

Total
59

 
55.9

 
50

 
45.3

 
207

 
90.6


(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 2014, 2013 and 2012, an additional 43, 43 and 56 wells, respectively, were drilled for water or CO2 injection purposes.


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Denbury Resources Inc.

The following table summarizes sales volumes, sales prices and production cost information for our net oil and natural gas production for the years ended December 31, 2014, 2013 and 2012:
 
Year Ended December 31,
 
2014
 
2013
 
2012
Net sales volume
 
 
 
 
 
Gulf Coast region
 
 
 
 
 
Oil (MBbls)
17,259

 
16,858

 
15,621

Natural gas (MMcf)
4,855

 
5,620

 
5,907

Total Gulf Coast region (MBOE)
18,068

 
17,795

 
16,606

Rocky Mountain region
 

 
 

 
 

Oil (MBbls)
8,513

 
7,336

 
8,841

Natural gas (MMcf)
3,524

 
3,046

 
4,747

Total Rocky Mountain region (MBOE)
9,100

 
7,844

 
9,632

Total Company (MBOE)
27,168

 
25,639

 
26,238

 
 
 
 
 
 
Average sales prices – excluding impact of derivative settlements
 

 
 

 
 

Gulf Coast region
 

 
 

 
 

Oil (per Bbl)
$
94.67

 
$
105.34

 
$
105.59

Natural gas (per Mcf)
4.31

 
3.74

 
2.79

 
 
 
 
 
 
Rocky Mountain region
 

 
 

 
 

Oil (per Bbl)
$
82.75

 
$
89.95

 
$
82.33

Natural gas (per Mcf)
3.73

 
3.15

 
3.38

 
 
 
 
 
 
Total Company
 

 
 

 
 

Oil (per Bbl)
$
90.74

 
$
100.67

 
$
97.18

Natural gas (per Mcf)
4.07

 
3.53

 
3.05

 
 
 
 
 
 
Average production cost (per BOE sold) (1)
 

 
 

 
 

Gulf Coast region (2)
$
24.92

 
$
32.34

 
$
24.96

Rocky Mountain region (3)
21.69

 
19.78

 
12.23

Total Company (2)
23.84

 
28.50

 
20.29


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

(2)
Production costs include a net reduction of $7.1 million of lease operating expenses recorded in 2014 related to Delhi Field remediation costs and insurance reimbursements, compared to $114.0 million of lease operating expenses recorded during 2013. Excluding estimated Delhi Field remediation costs and insurance reimbursements, average production costs per BOE for the Gulf Coast region would have totaled $25.31 and $25.93 for the years ended December 31, 2014 and 2013, respectively, and average production costs per BOE for the Company as a whole would have totaled $24.10 and $24.05 for the years ended December 31, 2014 and 2013, respectively.

(3)
Average production cost for the Rocky Mountain region in 2012 included operating costs related to our Bakken area assets, which generally had lower operating costs than our other properties. These assets were sold in connection with the Bakken Exchange Transaction in late 2012.


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Denbury Resources Inc.

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 Operations – Results of Operations – Operating Results Table, included herein.

TITLE TO PROPERTIES

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

SIGNIFICANT OIL AND GAS PURCHASERS AND PRODUCT MARKETING

Oil and natural gas sales are made on a day-to-day basis or under short-term contracts at the current area market price. We would not expect the loss of any single purchaser to have a material adverse effect upon our operations; however, the loss of a large single purchaser could potentially reduce the competition for our oil and natural gas production, which in turn could negatively impact the prices we receive.  For the year ended December 31, 2014, three purchasers accounted for 10% or more of our oil and natural gas revenues: Marathon Petroleum Company (31%), Plains Marketing LP (13%), and ConocoPhillips (12%). For the year ended December 31, 2013, three purchasers accounted for 10% or more of our oil and natural gas revenues: Marathon Petroleum Company (33%), Plains Marketing LP (15%), and Eighty-Eight Oil LLC (10%). For the year ended December 31, 2012, two purchasers accounted for 10% or more of our oil and natural gas revenues: Marathon Petroleum Company (39%) and Plains Marketing LP (17%).

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, 2014, 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

During 2012 and 2013, the oil produced in the Gulf Coast region benefited from strong pricing differentials in relation to NYMEX, and where possible we attached our production to Light Louisiana Sweet ("LLS") pricing. Overall, during 2014, we sold approximately 43% 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. During 2014, LLS pricing and NYMEX pricing have been much closer together, with the fourth quarter of 2014 quarterly average LLS-to-NYMEX differential (on a trade-month basis) narrowing to a positive $3.16 per Bbl, suggesting a potential return to long-term historical spreads compared to the wider-than-normal positive LLS-to-NYMEX spreads we experienced during 2012 and 2013. During 2014, our light sweet crude oil production in the Gulf Coast region, on average, sold for $1.80 per Bbl over NYMEX compared to $7.44 per Bbl over NYMEX in 2013 and more than $11.50 per Bbl over NYMEX in 2012.  The pricing of other Gulf Coast grades of oil deteriorated somewhat during 2014, with our light and medium sour crude production selling at a discount to NYMEX of $2.43 per Bbl.  The market dynamics of the region suggest that differentials to NYMEX are not expected to return to the more favorable levels seen over the last few years due to current global supply and demand indicators, as well as the influx of light sweet crude and condensate from producing regions outside of the Gulf Coast region by rail and recently completed 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 of future demand. We are, therefore, monitoring the marketplace for opportunities to strategically enter into long-term marketing arrangements.

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Denbury Resources Inc.


The marketing of our Rocky Mountain region oil production is dependent on transportation through local pipelines to market centers in Guernsey, Wyoming; Clearbrook, Minnesota; Wood River, Illinois; and most recently Cushing, Oklahoma.  Shipments on some of the pipelines are oversubscribed and subject to apportionment.  We currently have access to, or have contracted for, sufficient pipeline capacity to move our oil production; however, there can be no assurance that we will be allocated sufficient pipeline capacity to move all of our oil production in the future.  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 markets outside of the region. Therefore, prices in the Rocky Mountain region are further influenced by fluctuations in prices (primarily Brent and LLS) in coastal markets and by available pipeline capacity in the Midwest and Cushing markets.  For the year ended December 31, 2014, the discount for our oil production in the Rocky Mountain region averaged $10.19 per Bbl, compared to $8.10 per Bbl during 2013 and $11.86 per Bbl during 2012. 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.

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, 2014, the amount received for our Mississippi natural gas production averaged $0.25 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, 2014, averaged $0.21 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, 2014, we averaged $0.53 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.

COMPETITION AND MARKETS

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

The demand for qualified and experienced field personnel to drill wells and conduct field operations and for geologists, geophysicists, engineers and other professionals in the oil and gas industry can fluctuate significantly, often in correlation with commodity prices, causing periodic shortages in such personnel.  In recent years, the competition for qualified technical personnel has been extensive, and our personnel costs have been escalating. There have also been periods with shortages of drilling rigs and other equipment, as demand for rigs and equipment has increased along with the number of wells being drilled.  These factors also cause significant increases in costs for equipment, services and personnel.  We cannot be certain when we will experience these issues, and these types of shortages or price increases could significantly decrease our profit margin, cash flow and operating results, and cause significant delays in our development operations.


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Denbury Resources Inc.

FEDERAL AND STATE REGULATIONS

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

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

Regulation of Natural Gas and Oil Exploration and Production

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

Federal Regulation of Sales Prices and Transportation

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

Federal Energy and Climate Change Legislation and Regulation

In early 2012, the President signed the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011. This act, among other things, updates federal pipeline safety standards, increases penalties for violations of such standards, gives the Department of Transportation's Pipeline and Hazardous Materials Safety Administration (the "PHMSA") authority for new damage prevention and incident notification, and directs the PHMSA to prescribe new minimum safety standards for CO2 pipelines, which safety standards could affect our operations and the costs thereof. While the PHMSA has adopted or proposed to adopt a number of new regulations to implement this act, no new minimum safety standards have been proposed or adopted for CO2 pipelines.  In the future, Congress may create new incentives for alternative energy sources and may also consider legislation to reduce emissions of CO2 or other greenhouse gases. This legislation, if enacted, could (1) impose a tax or other economic penalty on the production of fossil fuels that, when used, ultimately release CO2, (2) reduce the demand for, and uses of, oil, gas and other minerals, and/or (3) increase the costs incurred by us in our exploration and production activities.  The Environmental Protection Agency ("EPA")

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Denbury Resources Inc.

has promulgated regulations requiring permitting for certain sources of greenhouse gas emissions, and has announced its intention to assess methane and other greenhouse gas emissions from the oil and gas sector and to adopt amended regulations if further reductions are warranted.  At the same time, legislation or regulation to reduce the emissions of CO2 or other greenhouse gases could also create economic incentives for technologies and practices that reduce or avoid such emissions, including processes that recognize the associated storage of CO2 in oil and gas reservoirs through CO2 EOR operations.

Natural Gas Gathering Regulations

State 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 greenhouse gas emissions and those that could discourage the production of fossil fuels that, when used, ultimately release CO2; (4) the Oil Pollution Act of 1990, which contains numerous requirements relating to the prevention of, and response to, oil spills into waters of the United States; (5) the Resource Conservation and Recovery Act, which is the principal federal statute governing the treatment, storage and disposal of hazardous wastes; (6) the Endangered Species Act and counterpart state legislation, which protects certain species (and their related habitats), including certain species that could be present on our leases, as threatened or endangered; and (7) state regulations and statutes governing the handling, treatment, storage and disposal of NORM.

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.


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Denbury Resources Inc.

Hydraulic Fracturing

During 2014, we fracture stimulated five operated wells at Hartzog Draw Field utilizing water-based fluids with no diesel fuel component. We currently have no plans to hydraulically fracture additional wells at Hartzog Draw Field during 2015. However, we are familiar with the laws and regulations applicable to hydraulic fracturing operations and take steps to ensure compliance with these requirements.

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

Internal Controls Over Reserve Estimates

Reserve information in this report is based on estimates prepared by D&M, an independent petroleum engineering consulting firm located in Dallas, Texas, utilizing data provided by our internal reservoir engineering team and is the responsibility of management. We rely on D&M's expertise to ensure that our reserve estimates are prepared in compliance with SEC rules and regulations and that appropriate geologic, petroleum engineering, and evaluation principles and techniques are applied in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007)".  The person responsible for the preparation of the reserve report is a Senior Vice President at D&M; he is a Registered Professional Engineer in the State of Texas. He received a Bachelor of Science degree in Petroleum Engineering at Texas A&M University in 1974, and he has in excess of 40 years of experience in oil and gas reservoir studies and evaluations.  Our Senior Vice President – Development, Technical and Innovation is primarily responsible for overseeing the independent petroleum engineering firm during the process.  Our Senior Vice President – Development, Technical and Innovation has a Master of Science and Bachelor of Science degree in Chemical Engineering from Columbia University, a Bachelor of Science in Chemistry from Davidson College and over 31 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 – Development, Technical and Innovation.  In addition, our Board of Directors' Reserves and Health, Safety and Environmental ("HSE") Committee, on behalf of the Board of Directors, oversees the qualifications, independence, performance and hiring of our independent petroleum engineering firm and reviews the final report and subsequent reporting of our oil and natural gas reserve estimates.  The Chairman of the Reserves and HSE Committee holds a Ph.D. in Chemical Engineering from the Massachusetts Institute of Technology and bachelor's degrees in Chemistry and Mathematics from Capital University in Ohio. He has 35 years of industry experience, with responsibilities including reserves preparation and approval.

Oil and Natural Gas Reserve Estimates

D&M prepared estimates of our net proved oil and natural gas reserves as of December 31, 2014, 2013 and 2012.  See the summary of D&M's report as of December 31, 2014, included as an exhibit to this Form 10-K. These estimates of reserves were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices on the first day of each month within the 12-month period in accordance with rules and regulations of the SEC.  These oil and natural gas reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage.  The reserve estimates represent our net revenue interest in our properties.  During 2014, we provided oil and gas reserve estimates for 2013 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, 2013.

Our proved non-producing 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 may have both proved producing and proved non-producing reserves.


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Denbury Resources Inc.

As of December 31, 2014, our estimated proved undeveloped reserves totaled approximately 99.0 MMBOE, or approximately 23% of our estimated total proved reserves, a decline of 81.0 MMBOE from December 31, 2013 levels for these reserves.  Our proved undeveloped oil reserves primarily relate to our CO2 tertiary operations (80.5 MMBOE), and our proved undeveloped natural gas reserves are primarily located in our Riley Ridge Field (5.9 MMBOE).  We generally consider the CO2 tertiary proved undeveloped reserves to be lower risk than other proved undeveloped reserves that require drilling at locations offsetting existing production, because all of these proved undeveloped reserves are associated with tertiary recovery operations in fields and reservoirs that historically produced substantial volumes of oil under primary production.

During 2014, we spent approximately $130 million to convert 79.9 MMBOE of proved undeveloped reserves to proved developed reserves, primarily related to behind-pipe reserves at Riley Ridge, as well as continued tertiary development activities at Heidelberg, Tinsley, Bell Creek, and Oyster Bayou fields. During 2014, we added 4.3 MMBOE of proved undeveloped reserves primarily related to our non-tertiary operations at CCA, and recognized other net downward proved undeveloped reserve revisions of 5.4 MMBOE.

As of December 31, 2014, 42.0 MMBOE of our total proved undeveloped reserves are not scheduled to be developed within five years of initial booking, nearly all of which are part of CO2 EOR projects. We believe these reserves satisfy the conditions to be included as proved reserves because (1) we have established and continue to follow the previously adopted development plan for each of these projects; (2) we have significant ongoing development activities in each of these CO2 EOR projects and (3) we have a historical record of completing the development of comparable long-term projects.


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Denbury Resources Inc.

The following table provides certain estimated proved reserve information in total and by category, as well as related pricing information as of December 31, 2014, 2013 and 2012. 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 for further discussion of reserve inputs and changes between periods.
 
December 31,
 
2014
 
2013
 
2012
Estimated proved reserves (1)
 
 
 
 
 
Oil (MBbls)
362,335

 
386,659

 
329,124

Natural gas (MMcf)
452,402

 
489,954

 
481,641

Oil equivalent (MBOE)
437,735

 
468,318

 
409,398

Reserve volumes categories
 
 
 
 
 
Proved developed producing
 
 
 
 
 
Oil (MBbls)
240,004

 
245,722

 
208,745

Natural gas (MMcf)
72,799

 
68,976

 
60,832

Oil equivalent (MBOE)
252,137

 
257,218

 
218,884

Proved developed non-producing
 
 
 
 
 
Oil (MBbls)
29,373

 
30,670

 
27,264

Natural gas (MMcf) (2)
343,622

 
3,119

 
3,359

Oil equivalent (MBOE)
86,643

 
31,190

 
27,824

Proved undeveloped
 
 
 
 
 
Oil (MBbls)
92,958

 
110,267

 
93,115

Natural gas (MMcf) (2)
35,981

 
417,859

 
417,450

Oil equivalent (MBOE)
98,955

 
179,910

 
162,690

Percentage of total MBOE
 
 
 
 
 
Proved developed producing
57
%
 
55
%
 
53
%
Proved developed non-producing
20
%
 
7
%
 
7
%
Proved undeveloped
23
%
 
38
%
 
40
%
Representative oil and natural gas prices (3)
 
 
 
 
 
Oil – NYMEX
$
94.99

 
$
96.94

 
$
94.71

Natural gas – Henry Hub
4.30

 
3.67

 
2.85

Present values (in thousands) (4)
 
 
 
 
 
Discounted estimated future net cash flows before income taxes (PV-10 Value) (5)
$
8,748,069

 
$
10,633,783

 
$
9,909,592

Standardized measure of discounted estimated future net cash flows after income taxes ("Standardized Measure")
$
5,908,128

 
$
7,128,744

 
$
6,414,380


(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), but do not include reserves of 42.2 MMBOE related to the CCA Acquisition, acquired during the first quarter of 2013.

(2)
In 2014, we converted approximately 364 Bcf of proved undeveloped natural gas reserves at Riley Ridge to proved developed non-producing reserves, as these reserves are behind pipe during the period in which the Riley Ridge gas processing facility is shut-in, which we currently expect will continue until 2016.


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Denbury Resources Inc.

(3)
The reference prices were based on the arithmetic average of the first-day-of-the-month NYMEX commodity prices for each month during the respective year. These prices do not reflect adjustments for market differentials by field that are utilized in the preparation of our reserve report to arrive at the appropriate net price we receive, and also do not reflect significant crude oil price declines in late 2014 and early 2015, when oil prices dropped rapidly, declining to below $45 per Bbl in January 2015. In response to these price decreases, we have deferred our development spending for certain projects in 2015, which has been reflected in our December 31, 2014, reserve report. Sustained prices at these recent levels would result in a significant decrease in our proved reserve value, and to a lesser degree, a reduction in our proved reserve volumes.  See Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Operating Results Table for details of oil and natural gas prices received, both including and excluding the impact of derivative settlements.

(4)
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. The decrease in the PV-10 Value and the Standardized Measure in 2014 was significantly impacted by the decline in oil prices we received relative to NYMEX oil prices (our NYMEX oil price differential) between 2013 and 2014. The weighted-average oil price differentials utilized were $3.10 per Bbl below representative NYMEX oil prices as of December 31, 2014, compared to $3.41 per Bbl and $7.57 per Bbl above representative NYMEX oil prices as of December 31, 2013 and 2012, respectively.

(5)
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 $2.84 billion at December 31, 2014; $3.51 billion at December 31, 2013; and $3.50 billion at December 31, 2012.  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.
 
Item 1A.  Risk Factors

A lengthy period of low oil prices or their further deterioration could adversely affect our future financial condition, results of operations, cash flows, the carrying value of our oil and gas properties, our dividend payments and our growth prospects.

As discussed in greater detail in the risk factors below, NYMEX oil prices have declined from $107 per Bbl in June 2014 to below $45 per Bbl in January 2015. If oil prices remain at late 2014 or early 2015 levels or decline further for an extended period of time, we could be harmed in a number of ways:

lower cash flows from operations may require continued or further reduced levels of capital expenditures;
reduced levels of capital expenditures in turn could lower our present and future production levels, and lower the quantities and value of our oil and gas reserves, which constitute our major asset;
our lenders could reduce our borrowing base, and we may not be able to raise capital at attractive rates in the public markets;
cause us to change our policy of paying regular cash dividends, or reduce the amount of dividends below the current rate;
we could be required to impair various assets, including a write-down of our oil and gas assets, our goodwill or the value of other tangible or intangible assets;
construction of plants that produce CO2 as a byproduct that we can purchase could be delayed or cancelled, thus limiting the amount of industrial-source CO2 available for use in our tertiary operations; and/or
our potential cash flows from our 2015 and 2016 commodity derivative contracts that include sold puts could be limited to the extent that oil prices are below the prices of those sold puts.

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If oil prices fall to lower levels, some or all of our tertiary projects could become uneconomical. 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 and reduce our production. Since operating costs do not decrease as quickly as commodity prices, it is difficult to determine a current precise break-even point for our tertiary projects; however, based on prior history, we currently estimate an industry-competitive rate of return at relatively low oil prices, depending on the specific field and area.

Oil and natural gas prices are volatile.

Oil and natural gas prices historically have been volatile and may continue to be volatile in the future. Therefore, even if oil prices recover for a period of time, volatility will remain, and prices could move downward or upward on a rapid or repeated basis, which can make transactions, valuations and business strategies difficult. Our cash flow from operations is highly dependent on the prices that we receive for oil.  Oil prices currently affect us more than natural gas prices because oil comprised approximately 95% of our 2014 production and 83% of our proved reserves at December 31, 2014. The prices for oil and natural gas are subject to a variety of factors that are beyond our control.  These factors include the supply of, and demand for, these commodities, which fluctuate with changes in market and economic conditions and other factors, including:

the level of worldwide consumer demand for oil and natural gas and the domestic and foreign supply of oil and natural gas and levels of domestic oil and gas storage;
the degree to which members of the Organization of Petroleum Exporting Countries maintain oil price and production controls;
the degree to which domestic oil and natural gas production decreases U.S. imports of crude oil;
domestic governmental regulations and taxes;
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 Mountains that can delay or impede operations;
commodity and financial market uncertainty;
worldwide political events and conditions, including actions taken by foreign oil and natural gas producing nations; and
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.  For the past several years, we have employed a strategy of hedging a substantial portion of our forecasted production approximately 18 months to two years into the future (from the then-current quarter), to mitigate the risks associated with price fluctuations (see Note 9, Commodity Derivative Contracts, to the Consolidated Financial Statements for details regarding our commodity derivative contracts).  As of February 19, 2015, we have oil derivative contracts in place covering 58,000 Bbls/d for the first three quarters of 2015, 38,000 Bbls/d for the fourth quarter of 2015, 36,000 Bbls/d for the first quarter of 2016, and 12,000 Bbls/d for the second quarter of 2016. With the decline in commodity futures prices in late 2014 and early 2015, as of late February 2015, we have deferred entering into new oil derivative contracts since the third quarter of 2014. Therefore, as of late February 2015, the percentage of our forecasted oil production that is currently hedged for the fourth quarter of 2015 and calendar 2016 is less than the percentage hedged in recent years. During periods of lower oil prices, we may defer entering into new contracts until futures prices return to levels that we consider economically conducive to our doing so.

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 $23 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. In recent years we have benefited from the favorable differential for sales based upon the LLS index relative to NYMEX prices, but market dynamics of the region over the past year suggest that these differentials to NYMEX are unlikely to return to the more favorable levels seen previously due to the influx of light sweet crude and condensate from producing regions outside of the Gulf Coast region. See Significant Oil and Gas Purchasers and Product Marketing and

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Management's Discussion and Analysis of Financial Condition and Results of OperationsResults of Operations Oil and Natural Gas Revenues for further discussion.

A financial downturn in one or more of the world's major markets could negatively affect our liquidity, business and financial condition.

Liquidity is essential to our business.  Our liquidity could be substantially negatively affected by an inability to obtain capital in the long-term or short-term debt capital markets or equity capital markets or an inability to access bank financing.  A prolonged credit crisis, including a severe economic contraction in Europe or turmoil in the global financial system, could materially affect our liquidity, business and financial condition.  In the past, such conditions have adversely impacted financial markets and have created substantial volatility and uncertainty with the related negative impact on global economic activity. Negative credit market conditions could inhibit our lenders from fully funding our bank credit facility or cause them to make the terms of our bank credit facility more costly and more restrictive.  Negative economic conditions could also adversely affect the collectability of our trade receivables or performance by our suppliers or cause our commodity hedging arrangements to be ineffective if our counterparties are unable to perform their obligations or otherwise seek bankruptcy protection.

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

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

The development of our principal CO2 source at Jackson Dome involves the drilling of wells to increase and extend the CO2 reserves available for use in our tertiary fields. These drilling activities are subject to many of the same drilling and geological risks of drilling and producing oil and gas wells (see Oil and natural gas development and producing operations involve various risks below). Recent market conditions may well cause the delay or cancellation of construction of plants that produce CO2 as a byproduct that we can purchase, thus limiting the amount of industrial-source CO2 available for our use in our tertiary operations.

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

As of December 31, 2014, our outstanding senior indebtedness consisted of $2.9 billion principal amount of subordinated notes, virtually all of which have maturity dates between 2021 and 2023 at interest rates ranging from 4.625% to 6.375% per annum at a weighted average interest rate of 5.26% per annum, and $395.0 million principal amount outstanding under our bank credit facility.  We currently have a borrowing base of $3.0 billion and total lender commitments of $1.6 billion under our bank credit facility and, at December 31, 2014, availability with respect to such commitments of $1.2 billion.  Our bank borrowing base is adjusted annually and upon requested unscheduled special redeterminations, in each case at the banks' discretion, and the amount is established and based, in part, upon certain external factors, such as commodity prices.  We do not know, nor can we control, the results of such redeterminations or the effect of then-current oil and natural gas prices on any such redetermination. A future redetermination lowering our borrowing base could limit availability under our bank credit facility. If the outstanding debt under our bank credit facility exceeds the then-effective and redetermined borrowing base, we will be required to repay the excess amount over a period not to exceed six months.

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

impairing our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or general corporate and other purposes;
potentially restricting us from making acquisitions or exploiting business opportunities;
lowering our available cash flow if market interest rates increase or if the level of our indebtedness significantly increases;

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requiring dedication of a substantial portion of our cash flows from operations to servicing our indebtedness (so that such cash flows would not be available for capital expenditures or other purposes); and
limiting our ability to borrow additional funds, dispose of assets, pay dividends, fund share repurchases and make certain investments.

The debt covenants contained in the agreements governing our outstanding indebtedness may also affect our flexibility in reacting to changes in the economy and in our industry. For example, as our cash flow from operations is highly dependent on the prices that we receive for oil and natural gas, if oil and natural gas prices remain at depressed levels for an extended period of time, our degree of leverage could increase significantly or our leverage metrics could deteriorate, potentially causing us to not be in compliance with our bank credit facility's maximum permitted ratio of consolidated total net debt to consolidated EBITDAX (as defined in the bank credit facility) of not more than 4.25 to 1.0 (see Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – Bank Credit Facility). If we are unable to generate sufficient cash flows or otherwise obtain funds necessary to make required payments on our indebtedness, or if we otherwise fail to comply with the various covenants related to such indebtedness, including covenants in our bank credit facility, we would be in default under our debt instruments. Any such default, if not cured or waived, could permit the holders of such indebtedness to accelerate the maturity of such indebtedness and could cause defaults under other indebtedness, which could have a material adverse effect on us. 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.

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 have considered or may again consider the adoption of laws or regulations that could limit or eliminate the ability of a state, state's legislature or its administrative agencies to exercise eminent domain over private property, in addition to possible judicially imposed constraints on, and additional requirements for, the exercise of eminent domain.  We also conduct operations on federal and other oil and natural gas leases inhabited by species, such as the sage grouse, that could be listed as threatened or endangered under the Endangered Species Act, which listing could lead to tighter restrictions as to federal land use.  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.

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

Our operations are subject to all the risks normally incident and inherent to the operation and development of oil and natural gas properties and the drilling of oil and natural gas wells, including, without limitation, well blowouts; cratering and explosions; pipe failure; fires; formations with abnormal pressures; uncontrollable flows of oil, natural gas, brine or well fluids; release of contaminants into the environment and other environmental hazards and risks. In addition, our operations are sometimes near populated commercial or residential areas, which add additional risks. The nature of these risks is such that some liabilities could exceed our insurance policy limits or otherwise be excluded from, or limited by, our insurance coverage, as in the case of environmental fines and penalties, for example, which are excluded from coverage as they cannot be insured.

We could incur significant costs related to these risks that could have a material adverse effect on our results of operations, financial condition and cash flows. Our CO2 tertiary recovery projects require a significant amount of electricity to operate the related facilities, which is our largest single cost related to the projects.  If these costs or others 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 $45 million for this effort for 2015. We may incur significant costs in connection with remedial plugging operations to

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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 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.

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

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

The reserves data included in documents incorporated by reference represent estimates only.  Quantities of proved reserves are estimated based on economic conditions, including first-day-of-the-month average oil and natural gas prices for the 12-month period preceding the date of the assessment.  The representative oil and natural gas prices used in estimating our December 31, 2014 reserves were $94.99 per Bbl for crude oil and $4.30 per MMBtu for natural gas, both of which were adjusted for market differentials by field. This prescribed methodology does not reflect significant crude oil price declines in late 2014 and early 2015, when oil prices dropped rapidly, declining to below $45 per Bbl in January 2015. In response to these price decreases, we have deferred our development spending for certain projects in 2015, which has been reflected in our December 31, 2014 reserve report. Sustained prices at late 2014 or early 2015 levels would result in a significant decrease in our proved reserve value, and to a lesser degree, a reduction in our proved reserve volumes, which may cause us to begin recording write-downs due to the full cost ceiling test in the first or second quarter of 2015, and also in subsequent quarterly periods if prices remain low. 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, 2014, approximately 23% 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

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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.

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

During 2014, we declared a regular quarterly dividend of $0.0625 per outstanding common share, and have declared a similar dividend for the first quarter of 2015. While we currently intend to continue to pay regular quarterly cash dividends, our ability to pay dividends may be adversely affected if certain of the other 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 oil prices and their impact on our cash flows, 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.

Our future performance and growth rate depend 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.  For internal organic growth activities, the magnitude of proved reserves that we can book in any given year depends on our progress with new floods and the timing of the production response; there were no significant additions to our oil and natural gas reserves in 2014, as we initiated no new floods in 2014. 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 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 may have the opportunity to acquire other oil fields that we believe are tertiary flood candidates, requiring significant amounts of capital.  If we are unable to successfully develop and produce the potential oil in any acquired fields, it would negatively affect our return on investment relative to these acquisitions and could significantly reduce our ability to obtain additional capital for the future or fund future acquisitions, and also negatively affect our financial results to a significant degree.

Commodity derivative contracts may expose us to potential financial loss.

To reduce our exposure to fluctuations in the prices of oil and natural gas, we enter into commodity derivative contracts in order to economically hedge a substantial portion of our forecasted 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, when the cash benefit from hedges including a sold put is limited to the extent oil prices fall below the price of our sold puts, or when the counterparty to the derivative contract is financially constrained and defaults on its contractual obligations. In addition, these derivative contracts may limit the benefit we would otherwise receive from increases in the prices for oil and natural gas. 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 – Oil and Natural Gas Derivative Contracts, and in Note 9, Commodity Derivative Contracts, to the Consolidated Financial Statements.

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

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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, although it is anticipated that recent oil price declines may slacken this personnel shortage to some degree. In the past, during periods of high oil and natural gas prices, we have experienced shortages of oil field and other necessary equipment, including drilling rigs, along with increased prices for such equipment, services and associated personnel.  These types of shortages or price increases could significantly decrease our profit margin, cash flow and operating results and/or restrict or delay our ability to drill wells and conduct our operations, possibly causing us to miss our forecasts and projections.

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

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

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, including the protection of endangered species. These laws and regulations and related public policy considerations affect the costs, manner, and feasibility of our operations and require us to make significant expenditures in order to comply. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial obligations, and the issuance of injunctions that could limit or prohibit our operations. In addition, some of these laws and regulations may impose joint and several, strict liability for contamination resulting from spills, discharges, and releases of substances, including petroleum hydrocarbons and other wastes, without regard to fault, or the legality of the original conduct. Under such laws and regulations, we could be required to remove or remediate previously disposed substances and property contamination, including wastes disposed or released by prior owners or operators. Changes in, or additions to, environmental laws and regulations occur frequently, and any changes or additions that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or other environmental protection requirements could have a material adverse effect on our operations and financial position.

Enactment of 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, state legislatures and various federal and state agencies.  Among these proposals are: (1) climate change/carbon tax legislation introduced in Congress, and EPA regulations to reduce greenhouse gas emissions; (2) 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, proposed or anticipated Department of Interior and EPA regulations to impose new and more stringent regulatory requirements on hydraulic fracturing activities, particularly those performed on federal lands, and to require disclosure of the chemicals used in the fracturing process; and (4) the Pipeline Safety, Regulatory Certainty, and Job Creation Act enacted in 2011, which increases penalties, grants new authority to impose damage prevention and incident notification requirements, and directs the PHMSA to prescribe minimum safety standards for CO2 pipelines. 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.


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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 the after-tax returns generated on our oil and gas investments and 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 to our counterparties of their hedging and swap positions that they can provide or lower their availability. In addition, for uncleared swaps, the CFTC or federal banking regulators may require end-users to enter into credit support documentation or post margin collateral. Any changes in the regulations of swaps may result in certain market participants deciding to curtail or cease their derivative activities.

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

The loss of one or more of our large oil and natural gas purchasers could have an adverse effect on our operations.

For the year ended December 31, 2014, three purchasers individually accounted for 10% or more of our oil and natural gas revenues and, in the aggregate, for 56% of such revenues.  The loss of a large single purchaser could adversely impact the prices we receive or the transportation costs we incur.

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

Certain of our operations in North Dakota, Montana and Wyoming, including the construction of CO2 pipelines, the drilling of new wells and production from existing wells, are conducted in areas subject to extreme weather conditions, including severe cold, snow and rain, which conditions may cause such operations to be hindered or delayed, or otherwise require that they be conducted only during non-winter months, and depending on the severity of the weather, could have a negative effect on our results of operations in these areas. Further, certain of our operations in these areas are confined to certain time periods due to environmental regulations, federal restrictions on when drilling can take place on federal lands, and lease stipulations designed to protect certain wildlife, which regulations, restrictions and limitations could slow down our operations, cause delays, increase costs and have a negative effect on our results of operations.

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Denbury Resources Inc.


Our results of operations could be negatively affected as a result of goodwill or long-lived asset impairments.

At December 31, 2014, our goodwill balance totaled $1.3 billion and our net property and equipment balance totaled $10.4 billion, representing approximately 10% and 81%, respectively, 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 our goodwill may be impaired, requiring an estimate of the fair values of the reporting unit's assets and liabilities. Our oil and natural gas properties balance is subject to our quarterly full cost pool ceiling test, and other long-lived assets are required to be tested for impairment when events or circumstances indicate the carrying value may not be recoverable. An impairment of goodwill or long-lived assets could significantly reduce earnings during the period in which the impairment occurs and would result in a corresponding reduction to goodwill or long-lived assets and equity. See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations Critical Accounting Policies and Estimates Impairment Assessment of Goodwill.

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. For example, we are currently conducting a search to fill two vacant executive-level operations positions, but there is no guarantee we can quickly fill them with personnel of our desired skill set. The continued vacancy in these positions or an additional 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, which could cause financial loss.

Although we utilize various procedures and controls to monitor and protect against these threats and to mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing and causing us to suffer such losses in the future.  As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our procedures and controls or to investigate and remediate any cyber vulnerabilities.

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.

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Denbury Resources Inc.


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 of probable losses 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 well as dividends declared within those periods.  Prior to 2014, we had not historically declared or paid dividends on our common stock. As of January 31, 2015, 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 1,772.  On February 26, 2015, the last reported sale price of Denbury's common stock, as reported on the NYSE, was $8.38 per share.
 
2014
 
2013
 
High
 
Low
 
Dividends Declared Per Share
 
High
 
Low
 
Dividends Declared Per Share
First Quarter
$
16.44

 
$
15.33

 
$
0.0625

 
$
19.11

 
$
16.50

 
$

Second Quarter
18.31

 
16.14

 
0.0625

 
19.48

 
16.68

 

Third Quarter
18.12

 
14.93

 
0.0625

 
18.55

 
16.90

 

Fourth Quarter
14.41

 
6.34

 
0.0625

 
19.44

 
15.98

 


On January 27, 2015, the Board of Directors declared a dividend of $0.0625 per share on our common stock, payable on March 31, 2015, to stockholders of record at the close of business on February 24, 2015. While we currently expect to continue to pay a regular quarterly dividend on our common stock, the declaration and payment of future dividends are at the discretion of our Board of Directors, and the amount thereof will depend on our results of operations, financial condition, capital requirements, level of indebtedness, market conditions, 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.  No unregistered securities were sold by the Company during 2014.

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 2014
 
3,737

 
$
12.89

 

 
$
221.9

November 2014
 
5,359

 
10.79

 

 
221.9

December 2014
 
66,602

 
8.25

 

 
221.9

Total
 
75,698

 
 
 

 



(1)
Stock repurchases during the fourth quarter of 2014 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 share repurchase program for up to $500 million of Denbury's common stock. During 2012 and 2013, the Board of Directors increased the dollar amount of Denbury common shares that could be purchased under the program to an aggregate of up to $1.162 billion. The program has no pre-established ending date and may be suspended or discontinued at any time.  In November 2014, the Company's Board of Directors suspended the common share repurchase program in light of commodity price uncertainty in order to protect our financial

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Denbury Resources Inc.

strength and preserve liquidity. We are not obligated to repurchase any dollar amount or specific number of shares of our common stock under the program.

Between early October 2011, when we announced the commencement of a common share repurchase program, and December 31, 2014, we repurchased 60.0 million shares of Denbury common stock (approximately 14.9% of our outstanding shares of common stock at September 30, 2011) for $940.0 million, or $15.68 per share.


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Denbury Resources Inc.

Share Performance Graph

The following Performance Graph and related information shall not be deemed "soliciting material" or to be "filed" with the SEC, nor shall such information be incorporated by reference into any future filings under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filings.

The following graph illustrates changes over the five-year period ended December 31, 2014, 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, 2009, to December 31, 2014.

COMPARISON OF 5-YEAR CUMULATIVE TOTAL RETURN
 
December 31,
 
2009
 
2010
 
2011
 
2012
 
2013
 
2014
Denbury Resources Inc.
$
100

 
$
129

 
$
102

 
$
109

 
$
111

 
$
56

S&P 500 (1)
100

 
115

 
117

 
136

 
180

 
205

Dow Jones U.S. Exploration & Production (2)
100

 
117

 
112

 
118

 
156

 
139


(1) Copyright© 2015 S&P, a division of The McGraw-Hill Companies Inc. All rights reserved.
(2) Copyright© 2015 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
 
2014
 
2013
 
2012
 
2011
 
2010 (1)
Consolidated Statements of Operations data
 
 
 
 
 
 
 
 
 
 
Revenues and other income
 
 
 
 
 
 
 
 
 
 
Oil, natural gas, and related product sales
 
$
2,372,473

 
$
2,466,234

 
$
2,409,867

 
$
2,269,151

 
$
1,793,292

Other
 
62,732

 
50,893

 
46,605

 
40,173

 
128,499

Total revenues and other income
 
$
2,435,205

 
$
2,517,127

 
$
2,456,472

 
$
2,309,324

 
$
1,921,791

Net income attributable to Denbury stockholders
 
635,491

 
409,597

 
525,360

 
573,333

 
271,723

Net income per common share
 
 
 
 
 
 
 
 
 
 
Basic
 
1.82

 
1.12

 
1.36

 
1.45

 
0.73

Diluted
 
1.81

 
1.11

 
1.35

 
1.43

 
0.72

Dividends declared per common share
 
0.25

 

 

 

 

Weighted average number of common shares outstanding
 
 
 
 
 
 
 
 
 
 
Basic
 
348,962

 
366,659

 
385,205

 
396,023

 
370,876

Diluted
 
351,167

 
369,877

 
388,938

 
400,958

 
376,255

Consolidated Statements of Cash Flows data
 
 
 
 
 
 
 
 
 
 
Cash provided by (used in)
 
 
 
 
 
 
 
 
 
 
Operating activities
 
$
1,222,825

 
$
1,361,195

 
$
1,410,891

 
$
1,204,814

 
$
855,811

Investing activities
 
(1,076,755
)
 
(1,275,309
)
 
(1,376,841
)
 
(1,605,958
)
 
(354,780
)
Financing activities
 
(135,104
)
 
(172,210
)
 
45,768

 
37,968

 
(139,753
)
Production (average daily)
 
 
 
 
 
 
 
 
 
 
Oil (Bbls)
 
70,606

 
66,286

 
66,837

 
60,736

 
59,918

Natural gas (Mcf)
 
22,955

 
23,742

 
29,109

 
29,542

 
78,057

BOE (6:1)
 
74,432

 
70,243

 
71,689

 
65,660

 
72,927

Unit sales prices – excluding impact of derivative settlements
 
 
 
 
 
 
 
 
 
 
Oil (per Bbl)
 
$
90.74

 
$
100.67

 
$
97.18

 
$
100.03

 
$
75.97

Natural gas (per Mcf)
 
4.07

 
3.53

 
3.05

 
4.79

 
4.63

Unit sales prices – including impact of derivative settlements
 
 
 
 
 
 
 
 
 
 
Oil (per Bbl)
 
$
90.82

 
$
100.64

 
$
96.77

 
$
98.90

 
$
71.69

Natural gas (per Mcf)
 
3.99

 
3.53

 
5.67

 
7.34

 
6.45

Costs per BOE
 
 
 
 
 
 
 
 
 
 
Lease operating expenses (2)
 
$
23.84

 
$
28.50

 
$
20.29

 
$
21.17

 
$
17.67

Taxes other than income
 
6.25

 
6.87

 
6.10

 
6.16

 
4.53

General and administrative expenses
 
5.83

 
5.66

 
5.49

 
5.24

 
5.04

Depletion, depreciation, and amortization
 
21.83

 
19.89

 
19.34

 
17.07

 
16.32

Proved oil and natural gas reserves (3)
 
 
 
 
 
 
 
 
 
 
Oil (MBbls)
 
362,335

 
386,659

 
329,124

 
357,733

 
338,276

Natural gas (MMcf)
 
452,402

 
489,954

 
481,641

 
625,208

 
357,893

MBOE (6:1)
 
437,735

 
468,318

 
409,398

 
461,934

 
397,925


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Denbury Resources Inc.

 
 
Year Ended December 31,
In thousands, except per-share data or otherwise noted
 
2014
 
2013
 
2012
 
2011
 
2010 (1)
Proved carbon dioxide reserves
 
 
 
 
 
 
 
 
 
 
Gulf Coast region (MMcf) (4)
 
5,697,642

 
6,070,619

 
6,073,175

 
6,685,412

 
7,085,131

Rocky Mountain region (MMcf) (5)
 
3,035,286

 
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)
 
13,231

 
13,251

 
12,712

 
12,004

 
7,159

Consolidated Balance Sheets data
 
 
 
 
 
 
 
 
 
 
Total assets
 
$
12,727,802

 
$
11,788,737

 
$
11,139,342

 
$
10,184,424

 
$
9,065,063

Total long-term liabilities
 
6,383,821

 
5,812,132

 
5,408,032

 
4,716,659

 
4,105,011

Stockholders' equity
 
5,703,856

 
5,301,406

 
5,114,889

 
4,806,498

 
4,380,707


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

(2)
If lease operating expenses and related insurance recoveries recorded in 2013 and 2014 to remediate an area of Delhi Field were excluded, lease operating expenses would have totaled $654.7 million and $616.6 million for the years ended December 31, 2014 and 2013, respectively, and lease operating expenses per BOE would have averaged $24.10 and $24.05 for the years ended December 31, 2014 and 2013, respectively (see Management's Discussion and Analysis of Financial Condition and Results of Operations Capital Resources and Liquidity Insurance Recoveries to Cover Costs of 2013 Delhi Field Release).

(3)