2013 Annual Report
GROWTH
INCOME
3
Table of Contents
2 Denbury’s CO2 Cycle
4 Letter to Shareholders
6 Tertiary Operations Map
11 Board of Directors
12 Officers
Form 10-K
Corporate Information (Inside Back Cover)
Forward-Looking Statements
The data contained in this annual report that are not historical facts are forward-looking statements that involve a number of risks and uncertainties. Such statements
may relate to, among other things: long-term strategy; anticipated levels of future dividends and rate of dividend growth; forecasts of capital expenditures, drilling
activity and development activities; timing of carbon dioxide (CO2 ) injections and initial production response to such tertiary flooding projects; estimated timing of
pipeline construction or completion or the cost thereof; dates of completion of to-be-constructed industrial plants and their first date of capture of anthropogenic CO2 ;
estimates of costs, forecasted production rates or peak production rates and the growth thereof; estimates of hydrocarbon reserve quantities and values, CO2
reserves, helium reserves, future hydrocarbon prices or assumptions; future cash flows or uses of cash, availability of capital or borrowing capacity; rates of return and
overall economics; estimates of potential or recoverable reserves and anticipated production growth rates in our CO2 models; estimated production and capital
expenditures for full-year 2014 and periods beyond; and availability and cost of equipment and services. These forward-looking statements are generally accompanied
by words such as “estimated”, “preliminary”, “projected”, “potential”, “anticipated”, “forecasted”, “expected”, “assume” or other words that convey the uncertainty of
future events or outcomes. These statements are based on management’s current plans and assumptions and are subject to a number of risks and uncertainties as
further outlined in our most recent Form 10-K and Form 10-Q filed with the SEC. Therefore, actual results may differ materially from the expectations, estimates or
assumptions expressed in or implied by any forward-looking statement herein made by or on behalf of the Company.
Cautionary Note to U.S. Investors — Current SEC rules regarding oil and gas reserve information allow oil and gas companies to disclose in filings with the SEC not only
proved reserves, but also probable and possible reserves that meet the SEC’s definitions of such terms. We disclose only proved reserves in our filings with the SEC.
Denbury’s proved reserves as of December 31, 2013 were estimated by DeGolyer & MacNaughton, an independent petroleum engineering firm. In this annual report, we
make reference to probable and possible reserves, some of which have been estimated by our independent engineers and some of which have been estimated by
Denbury’s internal staff of engineers. In this annual report, we also refer to estimates of original oil in place, resource or reserves “potential”, barrels recoverable, or
other descriptions of volumes potentially recoverable, which in addition to reserves generally classifiable as probable and possible (2P and 3P reserves), include
estimates of reserves that do not rise to the standards for possible reserves, and which SEC guidelines strictly prohibit us from including in filings with the SEC. These
estimates, as well as the estimates of probable and possible reserves, are by their nature more speculative than estimates of proved reserves and are subject to greater
uncertainties, and accordingly the likelihood of recovering those reserves is subject to substantially greater risk.
OPERATIONS OVERVIEWDENBURY RESOURCES INC. 1
DISCIPLINED GROWTH
Denbury is a growing, dividend-paying,
domestic oil and natural gas company.
Our primary focus is on enhanced
oil recovery utilizing carbon dioxide
(CO2 EOR). Our goal is to increase the
value of acquired properties through a
combination of exploitation, drilling and
proven engineering extraction practices,
with the most significant emphasis
relating to tertiary recovery operations.
2013 ANNUAL REPORTOPERATIONS OVERVIEW Denbury’s CO2 Cycle
STEP
1
CO2 SOURCES & CAPTURE
The first step in implementing a CO2 EOR project is to secure
access to substantial volumes of CO2. We source our CO2
from both naturally occurring underground reservoirs and
anthropogenic (man-made) sources. The proven CO2 reserves
associated with our naturally occurring sources are located
in Jackson Dome in Mississippi and LaBarge Field in Wyoming.
We source our anthropogenic CO2 from industrial facilities
which capture, purify, dry and then compress the CO2 for
delivery into our pipeline network.
~9.3
TRILLION
CUBIC FEET
GROSS PROVED
CO2 RESERVES
AS OF 12/31/2013
~70
MILLION
CUBIC FEET PER DAY
ANTHROPOGENIC CO2
STEP
2
CO2 TRAnSPORTATiOn
The second step in implementing a CO2 EOR project is transporting the CO2
from the source to the oil field. We operate or control over 1,100 miles of CO2
pipelines and are continually expanding this network to transport natural and
anthropogenic CO2 to our tertiary fields. We currently utilize ~ 70 million cubic
feet of anthropogenic CO2 per day and anticipate an additional ~115 million
cubic feet of anthropogenic CO2 per day from currently planned or future
construction of facilities in our Gulf Coast region.
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CARBON DIOxIDE PIPELINEM
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38,477
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TERTIARY
PRODUCTION
IN 2013
STEP
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CO2 inJECTiOn
The third step in implementing a CO2 EOR project
is to inject the carbon dioxide into the oil-bearing
reservoir through a wellbore. The injected CO2
moves through the reservoir, mixing with the
crude oil trapped there. The CO2 acts to separate
the oil from the reservoir rock and increase the
oil’s mobility within the reservoir. The mixture is
driven through the formation into a producing
wellbore, where it then comes to the surface,
increasing the field’s oil production. To date,
our CO2 EOR operations have resulted in the
gross production of over 100 million barrels of
otherwise stranded oil.
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STEP
4
CO2 EOR BEnEfiTS & STORAGE
CO2 EOR operations provide considerable economic, environmental and political
benefits. The economic benefits of CO2 EOR include the creation of jobs due
to large cash investments required to implement and operate a CO2 EOR project
along with tax payments to local governments. Our CO2 EOR operations also
provide an environmentally responsible method of utilizing and ultimately
storing CO2 in underground oil reservoirs while also making our nation more
energy secure.
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Dear Fellow Shareholders:
During 2013, we started the transition of our
company from one focused purely on growth to one
that supplements both Growth & Income (dividends),
Since CO2 EOR is limited to areas with large CO2
quantities, our ownership of significant CO2 resources
and pipeline infrastructure needed to transport CO2
the theme of this year’s annual report. We are able
gives us a significant competitive advantage in the areas
to do this because of the unique production and cash
in which we operate. We have chosen to utilize and
flow profile of our assets, which are all either current
maximize our strategic advantage, and therefore have
carbon dioxide enhanced oil recovery (“CO2 EOR”)
projects, future CO2 EOR projects or assets that
produce much of the CO2 that we use in our projects.
We anticipate that our unique capability among
oil and gas independents will enhance shareholder
value and returns in the coming years.
made CO2 EOR our core strategy and business.
To enable the expansion of our strategy from
growth to Growth & Income, we modified our future
development plans and flattened out our anticipated
annual capital spending levels for the remainder of
the decade. This adjustment, combined with our view
In preparation for this transition to Growth & Income,
that these changes would not significantly reduce our
over the last few years we made a series of tax efficient
anticipated oil and gas production and reserve growth
acquisitions and dispositions that sharpened our
rates, allowed us to bring forward our free cash flow
operational focus and made us a pure CO2 EOR play.
by a few years. This, in turn, allowed us to accelerate
our objective of providing returns to our shareholders
through cash dividend payments.
Proved Tertiary Reserves (1)
Bell Creek
oyster Bayou
tinsley
Delhi
heiDelBerg
hastings
Mature FielDs
255
225
195
165
135
105
75
45
15
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(1) Proved tertiary reserves based on SEC pricing for the respective years.
December 31,
With the declaration of our first-ever cash
dividend on January 28, 2014, we began the process
of distributing free cash flow generated from our
operations to shareholders. Our first quarterly
dividend of $0.0625 per common share, or a rate of
$0.25 per share on an annualized basis, was paid to
stockholders on March 25, 2014. Based on our current
financial projections and commodity price outlook,
we expect to grow our regular annual dividend rate to
FIRST
CASH DIVIDEND
PAID IN 2014
between $0.50 per share and $0.60 per share in 2015 and
The first cash dividend in Denbury’s history was
at a sustainable rate thereafter.
Of course, the expansion of our shareholder
return strategy to include both Growth & Income
is made possible by the many accomplishments of
our operations team over the last few years. Let me
touch on a few of these achievements over the past
twelve months:
» We delivered average production of 70,243 barrels
of oil equivalent per day in 2013, which was just
slightly above the mid-point of the estimated
range we presented in the prior year. Our tertiary
oil production increased by 9% between 2012 and
2013. Our non-tertiary production, after the closing
of our Cedar Creek Anticline acquisition in March
of 2013, was down only modestly from levels prior
to our Bakken area asset sale and exchange in late
2012. Our tertiary production growth in 2013 was
driven by our newest CO2 floods at Oyster Bayou
and Hastings fields in the Houston area, and we
anticipate additional growth at both of these
fields in 2014. Going forward, we expect to deliver
4% to 8% annual production growth through the
end of this decade without needing to acquire any
additional properties.
paid to stockholders on March 25, 2014, making
the expansion of the Company’s shareholder
value proposition to include quarterly cash
dividends. We remain focused on developing our
significant inventory of enhanced oil recovery
projects in order to increase shareholder value.
» We delivered our first tertiary oil production and
proved reserves in the Rocky Mountain region.
Since establishing our position in the Rocky
Mountain region in 2010, our team has worked
diligently to initiate our first CO2 flood in the
region. The milestones we have attained since late
2012 include: completion of the 20-inch Greencore
Pipeline in Wyoming, our first CO2 pipeline in the
Rocky Mountain region; the first receipt, delivery,
and injection of CO2 into Bell Creek and Grieve
fields; the first tertiary oil production at Bell Creek
Field; and the completion of an interconnect
between a third party’s CO2 pipeline and our
Greencore Pipeline, which allows us to transport
our CO2 volumes from ExxonMobil’s Shute Creek gas
processing plant to Bell Creek Field. With tertiary
production now established and growing in the
Rocky Mountain region, we look forward to the
continued expansion of our tertiary operations in
the region, at both Bell Creek Field and Grieve Field.
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Tertiary Operations Map
Our oil and natural gas properties are concentrated
Rocky Mountain region in Montana, North Dakota and
in the Gulf Coast and Rocky Mountain regions of the
Wyoming. Our primary focus is using CO2 in EOR and we
United States. Currently our properties with proved and
expect the development plan for our current portfolio of
producing reserves in the Gulf Coast region are situated
CO2 EOR projects will allow us to grow our oil production
in Mississippi, Texas, Louisiana and Alabama, and in the
for the remainder of the decade.
Gulf Coast Region: Potential Tertiary Reserves(1)
Tinsley
46 MMBbls
MS
AL
Headquarters
TX
Conroe
130 MMBbls
Jackson
Dome
Mississippi
Power
Free State
Pipeline
Heidelberg
44 MMBbls
Delhi
45 MMBoes
Delta Pipeline
LA
Sonat MS
Pipeline
Mature Area
170 MMBbls
NEJD Pipeline
Oyster Bayou
20–30 MMBbls
Green Pipeline
Lake Charles
Cogeneration
PCS Nitrogen
Other Plants
Air Products
Houston Area
150–215 MMBbls
Hastings
60–80 MMBbls
Webster
60–75 MMBbls
Thompson
30–60 MMBbls
Tertiary & Total Company Potential (MMBOEs)
Tertiary
Proved(1)
Potential(2)
Produced-to-Date(3)
Total Tertiary(2)
230
680
85
995
Total Company Potential(4)
1,250
OPERATIONS OVERVIEWDENBURY RESOURCES INC.
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Rocky Mountain Region: Potential Tertiary Reserves(1)
MT
Cedar Creek
Anticline
260–290
MMBbls
ND
Bell Creek
40–50
MMBbls
Greencore
Pipeline
WY
Lost Cabin
LaBarge Area
Riley Ridge
Shute Creek
Hartzog
Draw
20–30
MMBbls
Grieve
6 MMBbls
Headquarters
Existing Denbury CO2 Pipelines
Denbury Proposed CO2 Pipelines
CO2 Pipelines Not Owned or
Operated by Denbury
Denbury CO2 EOR Fields
Denbury Future CO2 EOR Fields
CO2 Resources Owned or Contracted
Anthropogenic CO2 Sources: Producing or Pending Startup
Anthropogenic CO2 Sources: Contracted with Future Construction
(1) Potential, proved and produced-to-date tertiary reserves estimated as of 12/31/13 based on a range of recovery factors. Proved
reserves based on year-end 12/31/13 SEC reporting.
(2) Using mid-points of ranges.
(3) Produced-to-date is cumulative tertiary production through 12/31/13.
(4) Proved and potential conventional and tertiary reserves including other conventional reserves estimated as of 12/31/13 based on a
range of recovery factors. Excludes tertiary production to date.
2013 ANNUAL REPORTOPERATIONS OVERVIEW
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» We increased our proved oil and natural gas
reserves to 468 million barrels of oil equivalent
» We purchased and used man-made CO2 in our
operations. Starting in late 2012, we began
(“MMBOE”) as of December 31, 2013, compared to
purchasing and utilizing anthropogenic (man-
409 MMBOE at December 31, 2012. We added 85
MMBOE of estimated proved reserves during 2013,
including tertiary reserves of 34 MMBOE at Bell
made) CO2 in our tertiary operations. In the Gulf
Coast region, we are currently receiving CO2 from
two plants and anticipate, adding a third source in
Creek Field during the fourth quarter, non-tertiary
2014. We expect the new facility to be our largest
reserves of 42 MMBOE from the acquisition of
man-made source in the region, with other sources
additional interests in CCA during the first quarter,
expected throughout the remainder of this decade.
and 9 MMBOE of other additions or revisions. We
estimate our total proved and potential reserves
These projects illustrate our unique ability to use
and store captured CO2 that would otherwise be
at December 31, 2013, were 1,250 MMBOE, including
released into the atmosphere.
an estimated 910 MMBOE associated with the
planned future CO2 EOR development of fields
we currently operate. We plan to convert these
potential reserves to proved reserves as we develop
these oil fields.
While we had many accomplishments in 2013, we
did face several challenges, particularly at Delhi Field
in northern Louisiana. In June, a release of well fluids,
consisting of a mixture of carbon dioxide, saltwater,
natural gas and oil, was discovered and reported within
» We placed our Riley Ridge gas processing facility
Delhi Field. We immediately took remedial action to
into service. We acquired our initial interest in
the Riley Ridge gas processing facility and the
stop the release and contain and recover well fluids in
the affected area. We have determined that the release
LaBarge Field in southwestern Wyoming in 2010
originated from one or more wells in the affected
with the goal of making it our “Jackson Dome” of
area of the field that we believe had previously been
the Rockies. LaBarge Field is estimated to hold
improperly plugged and abandoned by a prior operator
significantly more CO2 than Jackson Dome, but it
of the field. While we completed our remediation
is mixed with other gases, including methane and
efforts during the fourth quarter of 2013, the halting of
helium. With the startup of the plant and our sales
CO2 injections into the directly impacted area reduced
of both methane and helium, we will generate cash
the field’s oil production and required significant
flow on our investment, although the bigger prize
corporate resources. We have taken numerous steps to
will be realized later this decade when we add CO2
mitigate the risk of something similar occurring in the
separation equipment, connect this plant to our
future, including a more thorough review of plugged
existing CO2 pipelines, and make Riley Ridge our
and abandoned wells, more stringent criteria for what
anchor source of CO2 in the Rocky Mountain region.
is an acceptable plugged and abandoned well, and
assignment of additional, dedicated staff and capital
resources to administer this program. I am confident
which our Board first authorized in 2011. We believe
that the lessons learned and applied from the incident
our stock has been undervalued, even today, trading
will make Denbury a better company in the future.
below the net asset value of our proved oil and natural
On the financial front, we generated $1.36 billion
of cash flow from operations, more than enough to
fund the $1.14 billion we spent on oil and natural
gas development, CO2 supply, pipelines, and plant
capital expenditures. The excess cash flow was used to
partially fund our common stock repurchase program,
gas reserves and at levels that completely ignore the
significant incremental value of our potential CO2 EOR
reserves. We have spent over $940 million through the
first quarter of 2014 to repurchase approximately
15% of the shares we had outstanding when we
initiated the program in 2011. We’ve repurchased
A Premier Growth & Income Company
PROVEN & REPEATABLE PROCESS
CO2 EOR is one of the most efficient
tertiary oil recovery methods, delivering
almost as much production as each of
primary and secondary recovery. To date,
Denbury has produced over 100 million
barrels (gross) of oil from CO2 EOR.
STRATEGIC & COMPETITIVE ADVANTAGE
The acquisition and construction of strategic
assets has yielded a competitive advantage:
large amounts of naturally occurring and
man-made CO2 supply, over 1,100 miles of CO2
pipelines and a large inventory of oil fields.
LARGE PORTFOLIO OF LOWER RISK
GROWTH PROJECTS
Our long-term growth strategy is focused on
our CO2 tertiary recovery operations, made
possible by strategic acquisitions & infrastructure
developments. We have a substantial asset
base with excellent visibility on long-term
production growth.
UNIQUE PRODUCTION & CASH FLOW PROFILE
CO2 EOR is a proven method to extract significant
additional amounts of oil from mature oil fields.
The unique production profile of CO2 EOR projects
allows for the generation of substantial amounts
of free cash flow after the up-front investments
are made in CO2 supply, pipelines, and facilities to
initiate them.
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production growth in our two core regions, our solid
balance sheet provides us tremendous financial
flexibility, and our workforce of highly technical,
dedicated, and motivated employees is focused on
executing our unique strategy.
We strongly believe in our strategy and its long-term
economic benefits and are committed to creating
value for our shareholders through a combination of
production and proved reserve growth, dividends and
share repurchases. We look forward to executing our
value-driven strategy in 2014 and beyond.
Sincerely,
Phil Rykhoek
President and Chief Executive Officer
March 28, 2014
“
WE
are committed to creating value for our
shareholders through a combination of
production and proved reserve growth,
dividends and share repurchases.
”
between 3.5% and 4.2% of shares outstanding every
year starting in 2011 and have repurchased over
3% thus far in 2014, all while maintaining a solid
capital structure. The repurchases have improved
our per-share metrics and have been completed
at attractive prices that we believe make them very
accretive for our shareholders. Our repurchase
program remains in place with approximately
$220 million still authorized as of the date of this letter.
We intend to be opportunistic with this program.
In summary, it has been another eventful and
productive year at Denbury. We remain focused
on increasing shareholder value by optimizing the
development of our attractive asset base. We are aware
that we have had unfavorable operating and capital
cost trends in 2013 and recent years, and as a result are
implementing several internal initiatives that we expect
will result in meaningful cost reductions in the future.
We believe that we can make significant improvements
in our cost structure and reverse the recent negative
trends. We have excellent visibility on long-term oil
Board of Directors
Wieland F. Wettstein
Chairman of the Board
President
Finex Financial
Corporation, Ltd.
Calgary, Alberta
Michael L. Beatty
Chairman and Chief
Executive Officer
Beatty & Wozniak, P.C.
Denver, Colorado
Michael B. Decker
Partner
Wingate Partners
Dallas, Texas
John P. Dielwart
Vice-Chairman
ARC Financial Corp.
Calgary, Alberta
Ronald G. Greene
Principal
Tortuga Investment Corp.
Calgary, Alberta
Gregory L. McMichael
Independent
Consultant
Denver, Colorado
Kevin O. Meyers
Independent
Consultant
Anchorage, Alaska
Phil Rykhoek
Director, President and
Chief Executive Officer
Denbury Resources Inc.
Plano, Texas
Randy Stein
Independent
Consultant
Denver, Colorado
Laura A. Sugg
Independent
Consultant
Houston, Texas
Our corporate governance guidelines, as well as the charters for our nominating/corporate governance committee; compensation
committee; audit committee; and reserves and health, safety and environmental committee can be found on the Company website
at www.denbury.com. The website also contains other corporate governance information such as our code of ethics for our directors,
officers and employees; our hotline number to report any abnormalities; and other data.
You may contact our board members by addressing a letter to Denbury Resources Inc., Attn: Corporate Secretary, or by email
to secretary@denbury.com.
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Officers
Phil Rykhoek
Director, President
and Chief Executive
Officer
Mark C. Allen
Senior Vice President,
Chief Financial Officer,
Treasurer and Assistant
Secretary
K. Craig McPherson
Senior Vice President
and Chief Operating
Officer
Charlie Gibson
Senior Vice President —
Planning, Technology
and CO2 Supply
James S. Matthews
Vice President, General
Counsel and Secretary
Dan E. Cole
Vice President —
Marketing, Business
Development and
Government Relations
Matt Elmer
Vice President —
West Region
John Filiatrault
Vice President —
CO2 Supply and
Pipeline
Jeff Marcel
Vice President —
Drilling
Steve McLaurin
Vice President and
Chief Information
Officer
Alan Rhoades
Vice President and
Chief Accounting
Officer
Barry Schneider
Vice President —
North Region
Whitney Shelley
Vice President and
Chief Human Resources
Officer
Phil Webb
Vice President —
East Region
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
2013 FORM 10-K
(Mark One)
3 Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2013
OR
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
(State or other jurisdiction of incorporation or organization)
20-0467835
(I.R.S. Employer Identification No.)
5320 Legacy Drive, Plano, TX
(Address of principal executive offices)
75024
(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 3 No
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 No 3
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 3 No
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 3 No
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. 3
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a
small reporting company. See definition of “large accelerated filer”, “accelerated filer”, and “small reporting company” in
Rule 12-b2 of the Exchange Act.
Large accelerated filer 3 Accelerated filer Non-accelerated filer Smaller reporting company
Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2).
Yes No 3
The aggregate market value of the registrant’s common stock held by non-affiliates, based on the closing price of the
registrant’s common stock as of the last business day of the registrant’s most recently completed second fiscal quarter
was $5,625,842,252.
The number of shares outstanding of the registrant’s Common Stock as of January 31, 2014, was 355,982,927.
DOCUMENTS INCORPORATED BY REFERENCE
Document:
1. Notice and Proxy Statement for the Annual Meeting
of Shareholders to be held May 20, 2014.
Incorporated as to:
1. Part III, Items 10, 11, 12, 13, 14
Table of Contents
Glossary and Selected Abbreviations ...............................................................................................
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PA RT I
Item 1.
Business and Properties ....................................................................................................................
Item 1A. Risk Factors .......................................................................................................................................
Item 1B.
Unresolved Staff Comments .............................................................................................................
Item 2.
Properties ..........................................................................................................................................
Item 3.
Legal Proceedings .............................................................................................................................
Item 4.
Mine Safety Disclosures ....................................................................................................................
PA RT I I
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities ...............................................................................................
Item 6.
Selected Financial Data .....................................................................................................................
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations ..............
Item 7A. Quantitative and Qualitative Disclosures About Market Risk .............................................................
Item 8.
Financial Statements and Supplementary Information .....................................................................
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure .............
Item 9A. Controls and Procedures ...................................................................................................................
Item 9B. Other Information ..............................................................................................................................
PA RT I I I
Item 10.
Directors, Executive Officers and Corporate Governance .................................................................
Item 11.
Executive Compensation ...................................................................................................................
Item 12.
Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters .............................................................................................................
Item 13.
Certain Relationships and Related Transactions, and Director Independence ...................................
Item 14.
Principal Accountant Fees and Services ............................................................................................
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PA RT I V
Item 15.
Exhibits and Financial Statement Schedules .....................................................................................
98
Signatures .........................................................................................................................................
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Glossary and Selected Abbreviations
Bbl
Bbls/d
Bcf
BOE
BOE/d
Btu
CO2
EOR
One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil or
other liquid hydrocarbons.
Barrels of oil or other liquid hydrocarbons produced per day.
One billion cubic feet of natural gas, CO2 or helium.
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.
BOEs produced per day.
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).
Carbon dioxide.
Enhanced oil recovery.
Finding and development costs The average cost per BOE to find and develop proved reserves during a given period. It is
calculated by dividing (a) costs, which include the sum of (i) the total acquisition, exploration and
development costs incurred during the period plus (ii) future development and abandonment
costs related to the specified property or group of properties, by (b) the sum of (i) the change in
total proved reserves during the period plus (ii) total production during that period.
Accounting principles generally accepted in the United States of America.
One thousand barrels of crude oil or other liquid hydrocarbons.
One thousand BOEs.
One thousand Btus.
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.
One thousand cubic feet of natural gas, CO2 or helium produced per day.
One million barrels of crude oil or other liquid hydrocarbons.
One million BOEs.
One million Btus.
One million cubic feet of natural gas, CO2 or helium.
One million cubic feet of natural gas, CO2 or helium per day.
GAAP
MBbls
MBOE
Mbtu
Mcf
Mcf/d
MMBbls
MMBOE
MMBtu
MMcf
MMcf/d
Noncash fair value
adjustments on
commodity derivatives
NYMEX
The net change during the period in the fair market value of commodity derivative positions.
up only a portion of “Derivatives expense (income)” in the Consolidated Statements of
Operations, which also includes the impact of cash settlements on commodity derivatives during
the period. Its use is further discussed in Management’s Discussion and Analysis of Financial
Condition – Results of Operations – Operating Results Table.
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.
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
Tcf
Tertiary Recovery
The estimated future gross revenue to be generated from the production of proved reserves, net
of estimated future production, development and abandonment costs, and before income taxes,
discounted to a present value using an annual discount rate of 10%. PV-10 Values were prepared
using average hydrocarbon prices equal to the unweighted arithmetic average of hydrocarbon
prices on the first day of each month within the 12-month period preceding the reporting date.
PV-10 Value is a non-GAAP measure and its use is further discussed in footnote 4 to the table
included in Item 1, Estimated Net Quantities of Proved Oil and Natural Gas Reserves and Present
Value of Estimated Future Net Revenues – Oil and Natural Gas Reserve Estimates.
One trillion cubic feet of natural gas, CO2 or helium.
A term used to represent techniques for extracting incremental oil out of existing oil fields
(as opposed to primary and secondary recovery or “non-tertiary” recovery). In the context of our
oil and natural gas production, tertiary recovery is also referred to as EOR.
* This definition is an abbreviated version of the complete definition set forth in Rule 4-10(a) of Regulation S-X. For the complete definition see:
http://www.ecfr.gov/cgi-bin/text-idx?c=ecfr&rgn=div5&view=text&node=17:2.0.1.1.8&idno=17.
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Item 1. Business and Properties
GENERAL
Denbury Resources Inc., a Delaware corporation, is a growing, dividend-paying, domestic oil and natural gas
company with 468.3 MMBOE of estimated proved oil and natural gas reserves as of December 31, 2013, of which 83%
is oil. Our primary focus is on enhanced oil recovery utilizing CO2, and our operations are focused in two key
operating areas: the Gulf Coast and Rocky Mountain regions. Our goal is to increase the value of acquired properties
through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant
emphasis relating to tertiary recovery operations.
As part of our corporate strategy, we believe in the following fundamental principles:
•
focus in specific regions where we either have, or believe we can create, a competitive advantage as a result of
our ownership or use of CO2 reserves, oil fields and CO2 infrastructure;
• acquire properties where we believe additional value can be created through tertiary recovery operations and a
combination of other exploitation, development, exploration and marketing techniques;
• acquire properties that give us a majority working interest and operational control or where we believe we can
ultimately obtain it;
• maximize the value and cash flow generated from our operations by increasing production and reserves while
controlling costs;
• optimize the timing and allocation of capital among our investment opportunities to maximize the rates of return
on our investments;
•
return a portion of the cash flow generated from our operations to shareholders through regular quarterly
dividend payments, and repurchases of our common stock made from time to time; and
• maintain a highly competitive team of experienced and incentivized personnel.
Denbury has been publicly traded on the New York Stock Exchange since 1997. Our corporate headquarters is
located at 5320 Legacy Drive, Plano, Texas 75024, and our phone number is 972-673-2000. At December 31, 2013, we
had 1,501 employees, 807 of whom were employed in field operations or at our field offices. We make our annual
report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports,
filed or furnished pursuant to section 13(a) or 15(d) of the Securities Exchange Act of 1934, available free of charge
on or through our Internet website, www.denbury.com, as soon as reasonably practicable after we electronically file
such material with, or furnish it to, the SEC. The SEC also maintains a website, www.sec.gov, which contains
reports, proxy and information statements and other information filed by Denbury. Throughout this Annual Report on
Form 10-K (“Form 10-K”) we use the terms “Denbury,” “Company,” “we,” “our,” and “us” to refer to Denbury
Resources Inc. and, as the context may require, its subsidiaries.
2012 AND 2013 MAJOR PROPERTY EXCHANGES AND ACQUISITIONS
We set the stage for our 2013 business developments with two major transactions. In December 2012, we closed a
sale and exchange transaction with Exxon Mobil Corporation and its wholly-owned subsidiary XTO Energy Inc,
(collectively, “ExxonMobil”) under which we sold to ExxonMobil our Bakken area assets in North Dakota and Montana
in exchange for (1) $1.3 billion in cash, (2) operating interests in Hartzog Draw and Webster fields in Wyoming and
Texas, respectively, and (3) an overriding royalty interest equivalent to an approximate one-third ownership interest in
ExxonMobil’s CO2 reserves in LaBarge Field in Wyoming (the “Bakken Exchange Transaction”). We utilized cash
received in this exchange to fund our March 2013 acquisition of producing assets in the Cedar Creek Anticline (“CCA”)
in Montana and North Dakota from ConocoPhillips Company (“ConocoPhillips”) for $1.05 billion in cash, before
closing adjustments.
Taken together, these two asset transactions nearly replaced the production of the sold assets with production
from the acquired assets, exchanged proved reserves with a high proved undeveloped component in the Bakken
for reserves that were nearly all proved developed in CCA, increased our Rocky Mountain CO2 reserves by 1.3 Tcf
and our CO2 deliverability by up to 115 MMcf/d, and positioned us to provide dividends to our stockholders as
discussed below.
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2013 BUSINESS DEVELOPMENTS
In the fourth quarter of 2013, following a comprehensive review of our long-term plans, we announced our
intention to expand our shareholder value proposition to include both growth and income. The expansion includes
the initiation of regular quarterly cash dividend payments to our shareholders starting with $0.0625 per share
(a rate of $0.25 per share on an annualized basis). The first quarterly cash dividend of $0.0625 was declared on
January 28, 2014, payable March 25, 2014, to shareholders of record as of the close of business on February 25, 2014.
Based on our current financial projections and commodity price outlook, we expect to grow our annual dividend
rate to between $0.50 per share and $0.60 per share in 2015 and at a sustainable rate thereafter. All dividends are
discretionary and subject to declaration by Denbury’s Board of Directors.
To expand our free cash flow, we adjusted certain of our development plans and timelines for various capital
projects, principally in the Rocky Mountain region, in order to reduce our spending on certain major infrastructure
projects over the next few years. These adjustments allowed us to accelerate our plan of providing a return to our
shareholders through a growing cash dividend, while still growing our reserves and production. Our focused strategy,
significant inventory of development projects and proven track record of value creation give us confidence that we
can deliver a long-term cash flow profile that is unique among independent oil companies and successfully execute
on our value-driven growth and income strategy in 2014 and beyond.
2013 business developments also include the following:
•
Increased our average tertiary oil production to 38,477 Bbls/d in 2013, a 9% increase from average tertiary
production in 2012, primarily due to continued field development and expansion of facilities in our existing CO2
floods at Delhi, Hastings, Heidelberg and Oyster Bayou fields.
• Added total proved reserves of 84.6 MMBOE including estimated proved tertiary reserves of 34.0 MMBbls at
Bell Creek Field, proved non-tertiary reserves of 42.2 MMBOE (added through our 2013 acquisition of interests at
CCA) and 8.4 MMBOE of other additions or revisions.
• Added estimated proved CO2 reserves of 350 Bcf as a result of successful drilling in the Jackson Dome area, our
primary source of CO2 for the Gulf Coast region.
• Continued our share repurchase program, under which we repurchased a total of 16.5 million shares of Denbury
common stock for $277.8 million during 2013. We have purchased a total of 59.4 million shares of Denbury
common stock (approximately 14.8% of our outstanding shares of common stock at September 30, 2011) for
$931.2 million, or an average of $15.68 per share, since commencement of the share repurchase program
in October 2011 and continuing through February 20, 2014. As of February 20, 2014, we had $230.7 million
remaining for future purchases under our authorized share repurchase program.
• Commenced injection of CO2 into our first two tertiary floods in the Rocky Mountain region, Bell Creek Field in
Montana and Grieve Field in Wyoming during the first half of 2013, and commenced our first tertiary oil
production in that region from Bell Creek Field during the third quarter of 2013.
• Placed our Riley Ridge gas processing facility into service in the fourth quarter of 2013.
• Commenced a horizontal oil drilling program at Hartzog Draw Field in the Powder River Basin of Wyoming
targeting the Shannon formation. We expect the horizontal wells to increase the field’s non-tertiary oil
production and reserves and to eventually be utilized in our planned future CO2 flood of the field.
•
Issued $1.2 billion of 4 5/8% Senior Subordinated Notes due 2023 in February 2013. The net proceeds of
approximately $1.18 billion were used to repurchase or redeem our 9½% Senior Subordinated Notes due 2016
and our 9¾% Senior Subordinated Notes due 2016, and to pay down a portion of outstanding borrowings on
our bank credit facility.
• Closed our acquisition of producing assets in the CCA in Montana and North Dakota in March 2013 from a
wholly-owned subsidiary of ConocoPhillips for $1.05 billion in cash, before closing adjustments. The assets
purchased include both additional interests in certain of our existing operated fields in CCA, as well as operating
interests in other CCA fields.
2013 ANNUAL REPORTFORM 10-K PART I 6
OIL AND NATUR AL GAS OPER ATIONS
Summary. Our oil and natural gas properties are concentrated in the Gulf Coast and Rocky Mountain regions of
the United States. Currently our properties with proved and producing reserves in the Gulf Coast region are situated
in Mississippi, Texas, Louisiana and Alabama, and in the Rocky Mountain region in Montana, North Dakota and
Wyoming. Our primary focus is using CO2 in EOR, and we expect the development plan for our current portfolio of
CO2 EOR projects will allow us to grow our oil production for the remainder of the decade.
We have been conducting and expanding EOR operations on our assets in the Gulf Coast region since 1999, and as
a result, we currently have many more CO2 EOR projects in this region than in the Rocky Mountain region. In the
Gulf Coast region, we own what is, to our knowledge, its only significant naturally occurring source of CO2. These
large volumes of naturally occurring CO2 have allowed us to significantly grow our production in that region. In
addition to the sources of CO2 we currently own, in 2013 we began to purchase and use anthropogenic (man-made)
CO2 in our tertiary operations. We believe these man-made sources of CO2 will help us recover additional oil
from mature oil fields while also providing an economical way to reduce atmospheric CO2 emissions through the
concurrent underground storage of CO2 from our oil-producing EOR operations, and expect the amount of
anthropogenic CO2 we use in such operations to grow in the future.
Through December 31, 2013, we have invested a total of $3.5 billion in our tertiary fields in the Gulf Coast region
(including allocated acquisition costs and amounts assigned to goodwill), have recovered all of these costs, and have
generated $1.5 billion of excess net cash flow (revenue less operating expenses and capital expenditures, excluding
capital expenditures related to pipelines and CO2 source fields). Of this total invested amount, approximately
$206.7 million (6%) has been spent on fields that did not yet have any appreciable proved reserves at December 31, 2013.
The proved oil reserves in our Gulf Coast tertiary oil fields have a year-end 2013 PV-10 Value of $6.1 billion.
Including the Green Pipeline, which currently serves our Hastings and Oyster Bayou fields, we have invested a total
of $2.1 billion in CO2-producing assets and pipelines in the Gulf Coast region.
We began operations in the Rocky Mountain region in 2010 as part of our merger with Encore Acquisition Company
(“Encore”). In late 2012, we completed construction of the first section of the 20-inch Greencore Pipeline, our first
CO2 pipeline in the Rocky Mountain region, and received our first CO2 deliveries from the Lost Cabin gas plant in
central Wyoming during the first quarter of 2013. We also began injecting CO2 into Grieve Field in Wyoming early
in 2013 and currently expect initial tertiary oil production from Grieve Field in 2015. We started injections at our Bell
Creek Field in Montana during the second quarter of 2013, with tertiary oil production from this field commencing
in the third quarter of 2013. In addition to our current tertiary floods in the Rocky Mountain region, we currently have
long-term plans to flood Hartzog Draw Field and CCA after we perform additional non-tertiary development of
these fields. CCA is a geological structure over 126 miles in length consisting of 14 different operating areas. Our
Riley Ridge Field acquisitions in 2010 and 2011 and acquisition of an interest in CO2 reserves from ExxonMobil
in 2012 are expected to provide us the CO2 necessary for our current inventory of CO2 EOR projects in the Rocky
Mountain region.
FORM 10-K PART IDENBURY RESOURCES INC. 7
Field Summary Table. The following table provides a summary by field and region of selected proved oil and
natural gas reserve information, including total proved reserve quantities and the associated PV-10 Value of those
reserves as of December 31, 2013, and average daily production and net revenue interest (“NRI”) for 2013. The
reserve estimates for all years presented were prepared by DeGolyer and MacNaughton, independent petroleum
engineers located in Dallas, Texas. We serve as operator of virtually all of our significant properties, in which we
also own most of the interests, although typically less than a 100% working interest, and a lesser NRI due to royalties
and other burdens. For additional oil and natural gas reserves information, see Estimated Net Quantities of
Proved Oil and Natural Gas Reserves and Present Value of Estimated Future Net Revenues below.
Proved Reserves as of December 31, 2013(1)
2013 Average
Daily Production
Oil
(MBbls)
Natural Gas
(MMcf)
% of Company
Total
MBOEs MBOEs
PV-10
Value(2)
(000’s)
Oil
(Bbls/d)
Natural Gas Average
2013 NRI
(Mcf/d)
Tertiary oil properties
Gulf Coast region
Mature properties:
Brookhaven
Eucutta
Mallalieu
Other mature properties (3)
Total mature properties
Delhi
Hastings
Heidelberg
Oyster Bayou
Tinsley
Total Gulf Coast region
Rocky Mountain region
Bell Creek
10,069
8,074
5,700
24,756
48,599
26,449
43,424
34,496
15,132
25,344
193,444
34,015
34,015
227,459
Total Rocky Mountain region
Total tertiary properties
Non-tertiary oil and gas properties
Gulf Coast region
Mississippi
Texas
Other
Total Gulf Coast region
4,514
30,988
6,609
42,111
Rocky Mountain region
Cedar Creek Anticline (4)
Riley Ridge
Other
105,396
—
11,693
Total Rocky Mountain region 117,089
Total non-tertiary properties 159,200
386,659
Company Total
—
—
—
—
—
17,856
—
—
—
—
17,856
10,069
8,074
5,700
24,756
48,599
29,425
43,424
34,496
15,132
25,344
196,420
2.2%
1.7%
1.2%
5.3%
10.4%
6.3%
9.3%
7.3%
3.2%
5.4%
41.9%
$ 363,644
267,583
220,759
747,767
1,599,753
747,334
1,106,246
1,097,130
550,025
1,018,938
6,119,426
2,223
2,514
2,050
7,016
13,803
5,149
3,984
4,466
2,968
8,051
38,421
—
—
17,856
34,015
34,015
230,435
7.3%
7.3%
49.2%
739,019
739,019
6,858,445
56
56
38,477
—
—
—
—
—
—
—
—
—
—
—
—
—
—
81.2%
83.6%
78.0%
73.8%
77.2%
76.3%
81.7%
81.4%
87.0%
81.1%
79.5%
84.8%
84.8%
79.5%
33,290
18,105
1,386
52,781
10,062
34,006
6,840
50,908
2.1%
7.3%
1.5%
10.9%
195,138
814,609
147,406
1,157,153
1,234
5,549
983
7,766
8,766
5,946
686
15,398
26.1%
79.1%
26.4%
48.7%
6,043
399,373
13,901
419,317
472,098
489,954
106,403
66,562
14,010
186,975
237,883
468,318
22.7%
14.2%
3.0%
39.9%
50.8%
100%
2,335,966
27,810
254,409
2,618,185
3,775,338
$ 10,633,783
16,406
—
3,637
20,043
27,809
66,286
997
64
7,283
8,344
23,742
23,742
79.6%
61.4%
29.4%
60.5%
56.2%
68.2%
(1) The reserves were prepared in accordance with Financial Accounting Standards Board Codification (“FASC”) Topic 932, Extractive Industries –
Oil and Gas, using the arithmetic average of the first-day-of-the-month NYMEX commodity price for each month during 2013. These prices were
$96.94 per Bbl for crude oil and $3.67 per MMBtu for natural gas, both of which were adjusted for market differentials by field.
(2) PV-10 Value is a non-GAAP measure and is different from the Standardized Measure of Discounted Future Net Cash Flows (“Standardized
Measure”) in that PV-10 Value is a pre-tax number and the Standardized Measure is an after-tax number. The Standardized Measure was $7.1 billion
at December 31, 2013. A comparison of PV-10 Value to the Standardized Measure is included in the reserves table in Estimated Net Quantities
of Proved Oil and Natural Gas Reserves and Present Value of Estimated Future Net Revenues below. The information used to calculate PV-10
Value is derived directly from data determined in accordance with FASC Topic 932. See the definition of PV-10 Value in the Glossary and
Selected Abbreviations.
(3) Other mature properties include Cranfield, Little Creek, Lockhart Crossing, Martinville, McComb and Soso fields in Mississippi and Lockhart
Crossing in Louisiana.
(4) The Cedar Creek Anticline consists of a series of 14 different operating areas.
2013 ANNUAL REPORTFORM 10-K PART I
8
Enhanced Oil Recovery Overview. CO2 used in EOR is one of the most efficient tertiary recovery mechanisms for
producing crude oil. When injected at pressure into underground, oil-bearing rock formations, CO2 acts somewhat like
a solvent as it travels through the reservoir rock, mixing with and modifying the characteristics of the oil so it can
be produced and sold. CO2 tertiary floods are unique in that they require large volumes of CO2. The terms “tertiary
flood,” “CO2 flood” and “CO2 EOR” are used interchangeably throughout this document.
While enhanced oil recovery projects utilizing CO2 have been successfully performed by numerous oil and gas
companies in a wide range of oil-bearing reservoirs in different oil-producing basins, we apply what we have learned
and developed over the years to fields to improve and increase sweep efficiency within the CO2 EOR projects we
operate, which include (1) well evaluation and monitoring methods, (2) monitoring the flood and striving to direct the
CO2 to all economically recoverable portions of the oil-bearing reservoirs, (3) new completion techniques, (4) varied
operating equipment and operating methods, and (5) application of intense reservoir management and production
techniques. We began our CO2 operations in August 1999, when we acquired Little Creek Field, followed by our
acquisition of Jackson Dome CO2 reserves and the NEJD pipeline in 2001. Based upon our success at Little Creek and
the ownership of the CO2 reserves, we began to transition our capital spending and acquisition efforts to focus a
greater percentage on CO2 EOR and, over time, transformed our strategy to focus primarily, and now almost
exclusively, on owning and operating oil fields that are well suited for CO2 EOR projects, although prior to tertiary
flooding, we strive to maximize the currently sizeable primary and secondary production from our prospective tertiary
fields and from fields in which tertiary floods have commenced but still contain significant non-tertiary production.
With the sale of our Bakken area assets in 2012, our asset base today almost entirely consists of, or otherwise relates
to, oil fields that we are currently flooding with CO2 or plan to flood with CO2 in the future, or assets that produce
CO2. We believe our investments, experience and acquired knowledge give us a strategic and competitive advantage
in the areas in which we operate.
Our tertiary operations have grown so that (1) 49% of our proved reserves at December 31, 2013 are proved tertiary
oil reserves; (2) 55% of our 2013 production was related to tertiary oil operations (on a BOE basis); and (3) 77% of
our 2013 capital expenditures (excluding acquisitions) were related to our tertiary oil operations. At year-end 2013, the
proved oil reserves in our tertiary recovery oil fields had an estimated PV-10 Value of approximately $6.9 billion, or
64% of our total PV-10 Value. In addition, there are significant probable and possible reserves at several other fields
for which tertiary operations are underway or planned. Although the up-front cost of tertiary production infrastructure
and time to construct these pipelines and production facilities is greater than in primary oil recovery, we believe
tertiary recovery has several favorable, offsetting and unique attributes, including (1) a lower exploration risk, as we
are operating oil fields that have significant historical production and reservoir and geological data, (2) a reasonable
rate of return at relatively low oil prices (we currently estimate our economic break-even point before corporate-
related overhead, based on currently estimated expenses, occurs at oil prices in the low-to-mid $40-per-barrel range,
depending on the specific field and area), (3) limited competition for this recovery method in our geographic
regions, (4) our EOR operations are generally less disruptive to new habitats in comparison to other oil and natural
gas development because we further develop existing (as opposed to new) oil fields, and (5) through our oil-
producing EOR operations, we concurrently store anthropogenic CO2 in the same underground formations that had
previously trapped and stored oil and natural gas.
Tertiary Oil Properties
Gulf Coast Region
CO2 Sources and Pipelines
Jackson Dome. Our primary Gulf Coast CO2 source, Jackson Dome, located near Jackson, Mississippi, was
discovered during the 1970s by oil and gas companies that were exploring for hydrocarbons. This large and relatively
pure source of naturally occurring CO2 (98% CO2) is, to our knowledge, the only significant underground deposit
of CO2 in the United States east of the Mississippi River, and we believe that it, together with the related CO2 pipeline
infrastructure, provides us a significant strategic advantage in the acquisition of other properties in Mississippi,
Louisiana and southeastern Texas that are well suited for CO2 EOR.
We acquired Jackson Dome in February 2001 in a purchase that also gave us ownership and control of the NEJD
CO2 pipeline and provided us with a reliable supply of CO2 at a reasonable and predictable cost for our Gulf Coast
CO2 tertiary recovery operations. Since February 2001, we have acquired and drilled numerous CO2-producing wells,
significantly increasing our estimated proved Gulf Coast CO2 reserves from approximately 800 Bcf at the time of
acquisition to approximately 6.1 Tcf as of December 31, 2013. The CO2 reserve estimates are based on a gross
working interest of the CO2 reserves, of which our net revenue interest is approximately 4.8 Tcf, and is included in the
FORM 10-K PART IDENBURY RESOURCES INC. 9
evaluation of proved CO2 reserves prepared by our outside reserves engineer, DeGolyer and MacNaughton. In
discussing our available CO2 reserves, we make reference to the gross amount of proved and probable reserves,
as this is the amount that is available both for our own tertiary recovery programs and for industrial users who
are customers of Denbury and others, as we are responsible for distributing the entire CO2 production stream.
In addition to the proved reserves, we estimate that we have 2.5 Tcf of probable CO2 reserves at Jackson Dome.
The majority of our probable reserves at Jackson Dome are located in structures that have been drilled and tested in
the area but are not currently capable of producing or are not considered proved reserves because (1) the original
well is plugged; (2) they are located in fault blocks that are immediately adjacent to fault blocks with proved reserves;
(3) they are in undrilled structures where we have sufficient subsurface data, and seismic and geophysical attributes
that provide a high degree of certainty that CO2 is present; or (4) they are reserves associated with increasing the
ultimate recovery factor from our existing reservoirs with proved reserves. Our historically high drilling success rate,
coupled with our seismic data across the undrilled structures, provide us with a reasonably high degree of
certainty that additional proved CO2 reserves will be discovered and developed.
Although our current proved CO2 reserves are quite large, in order to continue our tertiary development of oil
fields in the Gulf Coast region, incremental deliverability of CO2 is required. In order to obtain additional CO2
deliverability, we have conducted several 3D seismic surveys in the Jackson Dome area over the past several years,
and anticipate drilling one development well in 2014 that is intended to increase the area’s productive capacity.
In addition to our drilling at Jackson Dome, we continue to expand our processing and dehydration capacities, and
we continue to install pipelines and/or pumping stations necessary to transport the CO2 through our controlled
pipeline network. We expect our current proved reserves of CO2, coupled with a risked drilling program at Jackson
Dome and expected anthropogenic sources, to provide sufficient quantities of CO2 for us to develop our proved
and probable EOR reserves in the Gulf Coast region. Additionally, in the future, we believe that once a CO2 flood in a
field reaches its productive economic limit, we could recycle a portion of any CO2 that remains in that reservoir and
utilize it for oil production in another tertiary flood.
In the Gulf Coast region, we also currently sell CO2 to third-party industrial users under contracts of various terms
and currently have three CO2 volumetric production payment contracts. Approximately 91% of our average daily
CO2 produced or acquired from anthropogenic sources in 2013, 2012 and 2011 was used in our tertiary recovery
operations, with the balance delivered to third-party industrial users. During 2013, we used an average of
913 MMcf/d of CO2 (including CO2 from anthropogenic sources) for our tertiary activities.
Gulf Coast Anthropogenic CO2 Sources. In addition to our natural source of CO2, we are currently party to four
long-term contracts to purchase man-made CO2 from four plants. We currently purchase anthropogenic CO2 from an
industrial facility in Port Arthur, Texas and from a plant in Geismar, Louisiana, and we anticipate taking deliveries
in late 2014 from Mississippi Power’s Kemper County Energy Facility. We estimate these three sources will supply, in
the aggregate, approximately 185 MMcf/d of CO2 to our EOR operations, although under certain circumstances they
could provide higher or lower volumes. If the fourth plant for which we have a long-term CO2 purchase contract were
also to be built (targeted for the 2018 time frame), we currently estimate this source in Lake Charles, Louisiana
could potentially add another 200 MMcf/d of CO2 volumes to our anthropogenic sources. Construction of this remaining
plant is considered probable, although such construction is contingent on the satisfactory resolution of various
matters, including financing. Additionally, we are in ongoing discussions with other parties who have plans to construct
plants near the Green Pipeline.
In addition to the potential CO2 sources discussed above, we continue to have ongoing discussions with owners of
existing plants of various types that emit CO2 that we may be able to purchase and/or transport. In order to capture
such volumes, we (or the plant owner) would need to install additional equipment, which includes, at a minimum,
compression and dehydration facilities. Most of these existing plants emit relatively small volumes of CO2,
generally less than our contracted sources, but such volumes may still be attractive if the source is located near CO2
pipelines. The capture of CO2 could also be influenced by potential federal legislation, which could impose
economic penalties for atmospheric CO2 emissions. We believe that we are a likely purchaser of CO2 captured in our
areas of operation because of the scale of our tertiary operations and our CO2 pipeline infrastructure.
Gulf Coast CO2 Pipelines. We acquired the 183-mile NEJD CO2 pipeline that runs from Jackson Dome to near
Donaldsonville, Louisiana, as part of the 2001 acquisition of our Jackson Dome source. Since 2001 we have acquired
or constructed nearly 750 miles of CO2 pipelines, which give us the ability to deliver CO2 throughout the Gulf Coast
region. As of December 31, 2013, we have access to over 940 miles of CO2 pipelines in the Gulf Coast region.
In addition to the NEJD CO2 pipeline, the major pipelines are the Free State Pipeline (90 miles), the Delta Pipeline
(110 miles), the Green Pipeline Texas (120 miles), and the Green Pipeline Louisiana (200 miles).
2013 ANNUAL REPORTFORM 10-K PART I 10
Completion of the Green Pipeline allowed for the first CO2 injection into Hastings Field, located near Houston,
Texas, in 2010, and gives us the ability to deliver CO2 to oil fields all along the Gulf Coast from Baton Rouge,
Louisiana, to Alvin, Texas. At the present time, most of the CO2 flowing in the Green Pipeline is delivered from the
Jackson Dome area, but we began receiving anthropogenic CO2 from an industrial facility in Port Arthur, Texas
in 2012, and are currently transporting a third party’s CO2 for a fee to the sales point at Hastings Field. We expect the
volume of CO2 transported through the Green Pipeline to increase in future years as we develop our inventory of
CO2 EOR projects in the Houston area.
Tertiary Properties with Tertiary Production and Proved Tertiary Reserves at December 31, 2013
Mature properties. Mature properties include our longest-producing properties which are generally located along
our NEJD CO2 pipeline in southwest Mississippi and Louisiana and our Free State pipeline in east Mississippi. This
group of properties includes our initial CO2 field, Little Creek, as well as several other fields (Brookhaven, Cranfield,
Eucutta, Lockhart Crossing, Mallalieu, Martinville, McComb and Soso fields). These fields accounted for 36% of
our total 2013 CO2 EOR production and approximately 21% of our year-end proved tertiary reserves. These fields have
been producing for some time, and their production is generally declining. Many of these fields contain multiple
reservoirs that are amenable to CO2 EOR. In 2014, we plan to invest approximately $115 million to further develop our
mature tertiary properties.
In order to improve the oil recovery of our more mature CO2 EOR projects, we have experimented with various
techniques such as cement squeezes (injection and producing wells), chemical squeezes, perforation design,
mechanical isolation assemblies and operating pressure controls. We have also utilized water-alternating-gas
injections, where water is substituted for the CO2 for a given volume and then CO2 is injected behind the water.
Each one of these processes has had some success, and we plan to continue to utilize them in the future
where appropriate.
From the time we originally acquired these properties through December 31, 2013, we have recovered all our costs
relating to our mature properties, and the excess net cash flow (revenue less operating expenses and capital
expenditures, including the acquisition costs) from the mature properties through that date was $1.9 billion. As of
December 31, 2013, the estimated PV-10 Value of our mature properties was $1.6 billion.
Delhi Field. Delhi Field is located east of Monroe, Louisiana. During May 2006, we purchased Delhi for $50 million,
plus an approximate 25% reversionary interest to the seller after we receive $200 million in “total net cash flow,”
as defined. We began well and facility development in 2008 and began delivering CO2 to the field in the fourth
quarter of 2009 via the Delta Pipeline, which runs from Tinsley Field to Delhi Field. First tertiary production
occurred at Delhi Field in the first quarter of 2010. Production from Delhi in the fourth quarter of 2013 averaged
4,793 Bbls/d, down from 5,237 Bbls/d in the fourth quarter of 2012. This decline in production is primarily related to
our efforts to remediate a release of well fluids within an area of Delhi Field in the second quarter of 2013,
consisting of a mixture of carbon dioxide, saltwater, natural gas and oil. During 2013, we recorded $114.0 million of
lease operating expenses in our Consolidated Statement of Operations related to this incident. Costs incurred
as a result of the release, together with lower production levels, are currently expected to delay the effective date
of the reversionary interest into 2014, the specific timing of which is dependent upon, among other things, the
amount and timing of any potential insurance proceeds received and their application to the calculation of “total
net cash flow,” as well as oil prices, production, and production costs. We currently estimate that the reversionary
date could occur as late as the fourth quarter of 2014. See Item 7, Management’s Discussion and Analysis of
Financial Condition and Results of Operations – Overview – Delhi Field Release and Note 11, Commitments and
Contingencies to the Consolidated Financial Statements for further discussion of this matter. In 2014, we plan
to invest approximately $40 million in this field, primarily to install a natural gas liquids extraction plant, which we
anticipate will be operational in 2015.
From inception through December 31, 2013, we had not yet recovered our investment in this field, and the
remaining investment to be recovered (revenue less operating expenses and capital expenditures, including
acquisition costs) from Delhi Field was $111 million. As of December 31, 2013, the estimated PV-10 Value of Delhi Field
was $747.3 million.
FORM 10-K PART IDENBURY RESOURCES INC. 11
Hastings Field. Hastings Field is located south of Houston, Texas. We acquired a majority interest in this field in
February 2009 for $247 million. We initiated CO2 injection in the West Hastings Unit during the fourth quarter of 2010
upon completion of the construction of the Green Pipeline. Due to the large vertical oil column that exists in
the field, we are developing the Frio reservoir using dedicated CO2 injection and producing wells for each of the
major sand intervals. We began producing oil from our EOR operations at Hastings Field in the first quarter of 2012,
and we booked initial proved tertiary reserves for the West Hastings Unit in 2012. During the fourth quarter of 2013,
tertiary production from Hastings Field averaged 4,270 Bbls/d, compared to 3,409 Bbls/d in the fourth quarter of 2012.
In 2014, we plan to invest approximately $75 million to continue developing the West Hastings Unit, including the
development of additional patterns and expansion of the processing facilities.
From inception through December 31, 2013, we had not yet recovered our investment in this field, and the
remaining investment to be recovered (revenue less operating expenses and capital expenditures, including the
acquisition cost) from Hastings Field was $336 million. As of December 31, 2013, the estimated PV-10 Value of
Hastings Field was $1.1 billion.
Heidelberg Field. Heidelberg Field is located in Mississippi and consists of an East Unit and a West Unit.
Construction of the CO2 facility, connecting pipeline and well work commenced on the West Heidelberg Unit during
2008, with our first CO2 injections into the Eutaw zone in the fourth quarter of 2008. Our first tertiary oil
production occurred in the second quarter of 2009, and during 2010, we added injection patterns and expanded the
central processing facility. In 2013, we began flooding the Christmas zone. During the fourth quarter of 2013,
tertiary production at Heidelberg Field averaged 5,206 Bbls/d, compared to 3,930 Bbls/d in the fourth quarter of 2012.
In 2014, we plan to invest approximately $120 million to continue developing the East and West Heidelberg Units,
including an expansion of our development of the Eutaw and Christmas zones and adjustments to our CO2 floods of
existing zones to better direct the CO2 through the zones and optimize oil recovery from the field.
From inception through December 31, 2013, we had not yet recovered our costs relating to the CO2 flood at
Heidelberg Field, and the remaining investment to be recovered (revenue less operating expenses and capital
expenditures, including the acquisition costs) from the field was $10 million. As of December 31, 2013, the estimated
PV-10 Value of Heidelberg Field was $1.1 billion.
Oyster Bayou Field. We acquired a majority interest in Oyster Bayou Field in 2007. The field is located in southeast
Texas, east of Galveston Bay. We began CO2 injections into Oyster Bayou in the second quarter of 2010. Oyster
Bayou Field is somewhat unique when compared to our other CO2 EOR projects because the field covers a relatively
small area of 3,912 acres. We commenced tertiary production from Oyster Bayou Field in the fourth quarter of 2011
from the Frio A-1 zone and booked initial proved tertiary reserves for the field in 2012. During the fourth quarter
of 2013, tertiary production at Oyster Bayou Field averaged 3,869 Bbls/d, compared to 1,826 Bbls/d in the fourth
quarter of 2012. In 2014, we plan to invest approximately $50 million to develop the Frio A-2 zone and optimize
our Frio A-1 zone development.
From inception through December 31, 2013, we had not yet recovered our investment in this field, and the
remaining investment to be recovered (revenue less operating expenses and capital expenditures, including
the acquisition costs) from Oyster Bayou Field was $98 million. As of December 31, 2013, the estimated PV-10 Value
of Oyster Bayou Field was $550.0 million.
Tinsley Field. We acquired Tinsley Field in 2006. The field is located in Mississippi, was discovered and first
developed in the 1930s and is separated into different fault blocks. As is the case with the majority of fields in
Mississippi, Tinsley produces from multiple reservoirs. Our CO2 enhanced oil recovery operations at Tinsley have
thus far targeted the Woodruff formation, although there is additional potential in the Perry sandstone and other
smaller reservoirs. We commenced tertiary oil production from Tinsley Field in the second quarter of 2008. In 2014,
we expect to invest approximately $50 million to continue our development of the North Fault Block and to
develop dedicated injection wells in the East Fault Block. We currently expect our development of the Woodruff to be
substantially complete by the end of 2014. During the fourth quarter of 2013, the average tertiary oil production
was 7,809 Bbls/d, compared to 8,166 Bbls/d in the fourth quarter of 2012.
From inception through December 31, 2013, we have recovered all our costs in this field, and our tertiary operations
at Tinsley Field have generated excess net cash flow (revenue less operating expenses and capital expenditures,
including the acquisition costs) of $340 million. As of December 31, 2013, the estimated PV-10 Value of Tinsley Field
was $1.0 billion.
2013 ANNUAL REPORTFORM 10-K PART I 12
Future Tertiary Properties with No Tertiary Production or Proved Tertiary Reserves at December 31, 2013
Webster Field. We acquired our interest in Webster Field in the fourth quarter of 2012 as part of the Bakken
Exchange Transaction. The field is located in Texas, approximately eight miles northeast of our Hastings Field, which
we are currently flooding with CO2. At December 31, 2013, Webster Field had estimated proved non-tertiary
reserves of approximately 3.2 MMBOE, net to our acquired interest. During the fourth quarter of 2013, non-tertiary
production at Webster Field averaged 1,036 BOE/d. Webster Field is geologically similar to our Hastings Field,
producing oil from the Frio zone at similar depths; as a result, we believe it is well suited for CO2 EOR. In 2014, we
plan to invest approximately $105 million to drill or recomplete injection and production wells and begin water
injections to re-pressurize the reservoir. We currently expect to commence CO2 injections at Webster Field in 2015,
with first tertiary production expected late that same year.
Conroe Field. Conroe Field, our largest potential tertiary flood in the Gulf Coast region, is located north of
Houston, Texas. We acquired a majority interest in this field in 2009 for $271 million in cash and 11.6 million shares
of Denbury common stock, for a total aggregate value of $439 million. Conroe Field had estimated proved non-
tertiary reserves of approximately 12.3 MMBOE at December 31, 2013, net to our interest, nearly all of which are
proved developed. During the fourth quarter of 2013, production at Conroe Field averaged 2,697 BOE/d, compared
to 2,745 BOE/d in the fourth quarter of 2012. Given the size of the Conroe Field (approximately 20,000 acres), the
volume of CO2 that could be injected is quite sizable, and much larger than any field we have developed to date.
Therefore, the pace of development will be dictated in part by the amount of available CO2.
A pipeline must be constructed so that CO2 can be delivered to Conroe Field. This pipeline, which is planned
as an extension of our Green Pipeline, is preliminarily estimated to cover approximately 90 miles at a cost of
approximately $220 million. We currently expect to begin construction of this pipeline in 2016 and to commence CO2
injections at Conroe Field in 2017, with first tertiary production currently expected in 2018. In 2014, we plan to
continue work on pipeline route selection, right-of-way acquisition, engineering, and regulatory permits while building
our CO2 EOR development plan for Conroe Field. In 2014, we also plan to invest approximately $30 million on
non-tertiary well recompletions and to begin water injections into the area of the field in which we plan to commence
CO2 injections to begin building reservoir pressure.
Thompson Field. We acquired our interest in Thompson Field in June 2012 for $366 million. The field is located in
Texas, approximately 18 miles west of our Hastings Field. Thompson Field had estimated proved non-tertiary
reserves of approximately 15.4 MMBOE at December 31, 2013, net to our interest, of which approximately 54% are
proved developed. During the fourth quarter of 2013, non-tertiary production at Thompson Field averaged
1,331 BOE/d net to our interest, compared to 1,517 BOE/d in the fourth quarter of 2012. Thompson Field is geologically
similar to Hastings Field, producing oil from the Frio zone at similar depths and we therefore believe it is well
suited for CO2 EOR. Under the terms of the Thompson Field acquisition agreement, after the initiation of CO2
injection, the seller will retain approximately a 5% gross revenue interest (less severance taxes) once average monthly
oil production exceeds 3,000 Bbls/d. In 2014, we plan to invest approximately $15 million on non-tertiary drilling
opportunities and facility upgrades. We currently plan to commence CO2 injections at Thompson Field in 2018, with
first tertiary production expected in 2020.
Rocky Mountain Region
CO2 Sources and Pipelines
LaBarge Field. We acquired an overriding royalty interest equivalent to an approximate one-third ownership
interest in ExxonMobil’s CO2 reserves in LaBarge Field in the fourth quarter of 2012 as part of the Bakken Exchange
Transaction. LaBarge Field is located in southwestern Wyoming. The gas composition from LaBarge Field is
expected to be approximately 65% CO2, approximately 18% to 20% methane, less than one percent helium, and the
remainder various other gases.
During December 2013, we received approximately 41 MMcf/d from ExxonMobil’s Shute Creek gas processing plant
at LaBarge Field. Based on current capacity, and subject to availability of CO2, we currently expect to ultimately
receive up to 65 MMcf/d of CO2 in 2014, rising to approximately 115 MMcf/d of CO2 by 2021 from such plant. We pay
ExxonMobil a fee to process and deliver the CO2, which we plan to use in our Rocky Mountain region CO2 floods.
As of December 31, 2013, our interest in LaBarge Field consisted of approximately 1.3 Tcf of proved CO2 reserves.
The Riley Ridge Federal Unit is also located in southwestern Wyoming and produces gas from the same LaBarge
Field. In a series of two acquisitions in 2010 and 2011, we acquired 100% of the operating interests in Riley Ridge
for $347 million. These purchases included a gas processing facility that was under construction at the purchase dates
to separate the helium and natural gas from the gas stream. We placed our gas processing facility at Riley Ridge
into service in the fourth quarter of 2013.
FORM 10-K PART IDENBURY RESOURCES INC. 13
As of December 31, 2013, our interest in Riley Ridge and minor surrounding acreage contained net proved reserves
of 399 Bcf (67 MMBOE) of natural gas and 2.0 Tcf of CO2 reserves. The CO2 reserve estimates are based on the
gross working interest of the CO2 reserves, in which our net revenue interest is approximately 1.6 Tcf. The helium
reserves at Riley Ridge are owned primarily by the U.S. government; however, we have the right to produce and sell
the helium reserves to a third party on behalf of the government. In exchange for this right, we pay the U.S.
government a fee that fluctuates based upon realized sales proceeds. Our helium extraction agreement with the U.S.
government has a minimum term extending 20 years from first production and continuing thereafter until either
party terminates the contract. Reserve volumes presented herein assume that the term of this helium extraction
agreement continues beyond 20 years, given the benefit to both parties to the agreement. As of December 31, 2013,
we estimate that Riley Ridge contains proved helium reserves of 13.3 Bcf, which volume estimate is reduced
to reflect the related fee we will remit to the U.S. government. In addition, we believe there is significant reserve
potential in other acreage surrounding Riley Ridge in which we also own an interest.
The gas processing facility at Riley Ridge will separate for sale the natural gas and helium from the full well
stream, and the remaining gases, including CO2, will be re-injected into the producing formation or a deeper
formation until we complete construction of a planned CO2 capture facility and pipeline later this decade. We currently
project that we will start to use CO2 from Riley Ridge around 2020, following completion of the capture facility
and planned CO2 pipeline connecting Riley Ridge to our existing Greencore Pipeline.
Other Rocky Mountain CO2 Sources. We began purchasing and receiving CO2 from the Lost Cabin plant in central
Wyoming in the first quarter of 2013, under a contract that provides us as much as 50 MMcf/d of CO2 for use in our
Rocky Mountain region CO2 floods. Our volumes received from the plant averaged approximately 22 MMcf/d in 2013.
We plan to continue to pursue additional sources for CO2 supply in the Rocky Mountain region.
Greencore Pipeline. The 20-inch Greencore Pipeline in Wyoming is the first CO2 pipeline we have constructed
in the Rocky Mountain region. We plan to use the pipeline as our trunk line in the Rocky Mountain region, eventually
connecting our Lost Cabin, LaBarge and Riley Ridge CO2 sources (see Rocky Mountain Region CO2 Sources and
Pipelines above) to the Cedar Creek Anticline in eastern Montana. The initial 232-mile section of the Greencore Pipeline
begins at the Lost Cabin gas plant in Wyoming and terminates at Bell Creek Field in Montana. We completed
construction of this section of the pipeline in the fourth quarter of 2012 and received our first CO2 deliveries from the
Lost Cabin gas plant during the first quarter of 2013. In the first quarter of 2014, we completed construction of an
interconnect between our Greencore Pipeline and an existing third-party CO2 pipeline in Wyoming, which will enable
us to transport CO2 from LaBarge Field to our Bell Creek Field.
Tertiary Properties with Tertiary Production and Proved Tertiary Reserves at December 31, 2013
Bell Creek Field. Bell Creek Field is located in southeast Montana. The oil-producing reservoir in Bell Creek Field is
a sandstone reservoir with characteristics similar to those we have successfully flooded with CO2 in the Gulf Coast
region; as a result, we believe it is well suited for CO2 EOR. We acquired our interest in Bell Creek Field through the
Encore merger in 2010 and have worked since that time to commence a CO2 EOR project in the field. We began
first CO2 injections during the second quarter of 2013, recorded our first tertiary oil production in the third quarter of
2013, and booked initial proved tertiary reserves in the fourth quarter of 2013. Tertiary production, net to our
interest, during the fourth quarter of 2013 averaged 177 Bbls/d. In 2014, we plan to invest approximately $55 million
to expand our CO2 flood of Bell Creek Field.
From inception through December 31, 2013, we had not yet recovered our investment in this field, and the remaining
investment to be recovered (revenue less operating expenses and capital expenditures, including the acquisition
costs) from Bell Creek Field was $432 million. As of December 31, 2013, the estimated PV-10 Value of Bell Creek Field
was $739.0 million.
Future Tertiary Properties with No Tertiary Production or Proved Tertiary Reserves at December 31, 2013
Cedar Creek Anticline. CCA is the largest potential EOR property that we own and currently our largest producing
property. The field is primarily located in Montana but covers such a large area (approximately 126 miles) that it
also extends into North Dakota. CCA is a series of 14 producing areas, each of which could be considered a field by
itself. We acquired our initial interest in CCA as part of the Encore merger in 2010 and acquired additional interests
(the “CCA Acquisition”) from a wholly-owned subsidiary of ConocoPhillips in the first quarter of 2013. See 2013
Business Developments above and Note 2, Acquisitions and Divestitures, to the Consolidated Financial Statements for
further discussion of this transaction and information as to other recent acquisitions and divestitures by Denbury.
2013 ANNUAL REPORTFORM 10-K PART I 14
The 2013 CCA Acquisition added 42.2 MMBOE of incremental proved reserves. Production from CCA, net to our
interest, averaged 18,601 BOE/d during the fourth quarter of 2013, compared to pro forma production during the
fourth quarter of 2012 of 19,493 BOE/d (including production associated with our newly acquired CCA assets of
approximately 11,000 BOE/d and production from our previously owned CCA assets of 8,493 BOE/d). The non-tertiary
proved reserves associated with CCA were 105.4 MMBbls of oil and 6.0 Bcf of gas as of December 31, 2013.
CCA is located approximately 110 miles north of Bell Creek Field, and we currently expect to ultimately connect
this field to our Greencore Pipeline. In 2014, we plan to invest approximately $110 million to improve waterfloods, drill
new wells, and recomplete existing wells. We currently plan to commence CO2 injections at CCA after 2020.
Grieve Field. In the second quarter of 2011, we entered into a farm-in agreement, under which we will obtain a
65% working interest in Grieve Field, located in Natrona County, Wyoming, in exchange for developing the Grieve Field
CO2 flood. We completed a three-mile CO2 pipeline to deliver CO2 from an existing CO2 pipeline to the
Grieve Field in the fourth quarter of 2012, and are preparing for construction of the field’s CO2 recycle facility. We
began injecting CO2 into Grieve Field during the first quarter of 2013 and currently expect tertiary production to
commence in 2015.
Hartzog Draw Field. We acquired our interest in Hartzog Draw Field in the fourth quarter of 2012 as part of the
Bakken Exchange Transaction. The field is located in the Powder River Basin of northeastern Wyoming, approximately
12 miles from our Greencore Pipeline. Hartzog Draw Field had estimated proved reserves of approximately
5.2 MMBOE at December 31, 2013, net to our acquired interest, 1.9 MMBOE of which relate to the natural gas producing
Big George coal zone. During the fourth quarter of 2013, non-tertiary production averaged 2,204 BOE/d. We
believe the oil reservoir characteristics of Hartzog Draw Field make it well suited for CO2 EOR. In 2014, we plan to
invest approximately $40 million to drill and complete six horizontal wells in the Shannon formation and re-frac
eight existing wells. We anticipate drilling additional horizontal wells in the Shannon formation over the next several
years. The drilling of these wells is expected to generate near-term cash flow, as well as complement our planned
future CO2 EOR project in the field. We must obtain regulatory approval and construct a CO2 pipeline from our
existing Greencore Pipeline to Hartzog Draw Field before we can commence our planned CO2 EOR project. We currently
plan to commence CO2 injections at Hartzog Draw Field after 2020.
Other Non-Tertiary Oil Properties
Although almost all of our oil and natural gas properties are either existing or planned future tertiary floods
(discussed above), we also produce oil and natural gas either from fields that are not amenable to EOR or out of
specific reservoirs (within an existing tertiary field) that are not amenable to EOR. For example, at Heidelberg Field,
we produce natural gas from the Selma Chalk reservoir, which is separate from the Christmas and Eutaw reservoirs
currently being flooded with CO2. Production from these other non-tertiary properties totaled 6,994 BOE/d during
the fourth quarter of 2013, compared to 18,615 BOE/d during the fourth quarter of 2012. Production during the fourth
quarter of 2012 includes 10,064 BOE/d of production from our Bakken area assets that were sold during that period.
FORM 10-K PART IDENBURY RESOURCES INC. 15
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, 2013:
Gulf Coast region
Rocky Mountain region
Total
Developed
Gross
Net
250,732
362,163
612,895
211,058
311,687
522,745
Undeveloped
Total
Gross
390,678
188,055
578,733
Net
Gross
Net
40,383
83,647
124,030
641,410
550,218
1,191,628
251,441
395,334
646,775
The percentage of our net undeveloped acreage that is subject to expiration over the next three years, if not
renewed, is approximately 3% in 2014, 12% in 2015 and 12% in 2016.
Productive Wells
The following table sets forth our gross and net productive oil and natural gas wells as of December 31, 2013:
Producing
Oil Wells
Gross
Net
Producing
Natural Gas Wells
Gross
Net
Total
Gross
Net
1,233
1,160
2,393
33
72
105
1,266
1,232
2,498
1,140.1
1,039.0
2,179.1
0.9
8.7
9.6
1,141.0
1,047.7
2,188.7
212
201
413
—
101
101
212
302
514
192.6
111.2
303.8
—
37.5
37.5
192.6
148.7
341.3
1,445
1,361
2,806
33
173
206
1,478
1,534
3,012
1,332.7
1,150.2
2,482.9
0.9
46.2
47.1
1,333.6
1,196.4
2,530.0
Operated wells:
Gulf Coast region
Rocky Mountain region
Total
Non-operated wells:
Gulf Coast region
Rocky Mountain region
Total
Total wells:
Gulf Coast region
Rocky Mountain region
Total
Drilling Activity
The following table sets forth the results of our drilling activities over the last three years. As of December 31, 2013,
we had 5 gross (4.8 net) wells in progress.
Exploratory wells: (1)
Productive (2)
Non-productive (3)
Development wells: (1)
Productive (2)
Non-productive (3)(4)
Total
2013
Year Ended December 31,
2012
2011
Gross
Net
Gross
Net
Gross
Net
—
—
49
1
50
—
—
44.3
1.0
45.3
1
—
201
5
207
—
—
87.4
3.2
90.6
—
1
221
—
222
—
0.7
116.6
—
117.3
(1) An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in
another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test
well. A development well is a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be
productive.
(2) A productive well is an exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify
completion as an oil or natural gas well.
(3) A non-productive well is an exploratory or development well that is not a productive well.
(4) During 2013, 2012 and 2011, an additional 43, 56 and 46 wells, respectively, were drilled for water or CO2 injection purposes.
2013 ANNUAL REPORTFORM 10-K PART I
16
The following table summarizes sales volumes, sales prices and production cost information for our net oil and
natural gas production for the years ended December 31, 2013, 2012 and 2011:
Year Ended December 31,
2013
2012
2011
Net sales volume:
Gulf Coast region
Oil (MBbls)
Natural gas (MMcf)
Total Gulf Coast region (MBOE)
Rocky Mountain region
Oil (MBbls)
Natural gas (MMcf)
Total Rocky Mountain region (MBOE)
Total Company (MBOE)
Average sales price:
Gulf Coast region
Oil (per Bbl)
Natural gas (per Mcf)
Rocky Mountain region
Oil (per Bbl)
Natural gas (per Mcf)
Total Company
Oil (per Bbl)
Natural gas (per Mcf)
Average production cost (per BOE sold): (1)
Gulf Coast region (2)
Rocky Mountain region
Total Company (2)
(1) Excludes oil and natural gas ad valorem and production taxes.
16,858
5,620
17,795
7,336
3,046
7,844
25,639
$ 105.34
3.74
$ 89.95
3.15
$ 100.67
3.53
$ 32.34
19.78
28.50
15,621
5,907
16,606
8,841
4,747
9,632
26,238
$ 105.59
2.79
$ 82.33
3.38
$ 97.18
3.05
$ 24.96
12.23
20.29
14,635
7,934
15,957
7,534
2,849
8,009
23,966
$ 105.23
4.31
$ 89.93
6.12
$ 100.03
4.79
$ 24.51
14.52
21.17
(2) Production costs include $114 million of lease operating expenses recorded during 2013 to remediate an area of Delhi Field. Excluding estimated
Delhi Field remediation costs, average production costs in 2013 totaled $25.93 per BOE for the Gulf Coast Region and $24.05 per BOE for the
Company as a whole.
PRODUCTION AND UNIT PRICES
Further information regarding average production rates, unit sale prices and unit costs per BOE are set forth under
Item 7, Management’s Discussion and Analysis of Financial Condition and Results of 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 gas sales are made on a day-to-day basis under short-term contracts at the current area market price. The
loss of any single purchaser would not be expected to have a material adverse effect upon our operations; however,
the loss of a large single purchaser could potentially reduce the competition for our oil and natural gas production,
which in turn could negatively impact the prices we receive. For the year ended December 31, 2013, three purchasers
accounted for 10% or more of our oil and natural gas revenues: Marathon Petroleum Company (33%), Plains
Marketing LP (15%), and Eighty-Eight Oil LLC (10%). For the years ended December 31, 2012 and 2011, two purchasers
accounted for 10% or more of our oil and natural gas revenues: Marathon Petroleum Company (39% and 43% in
2012 and 2011, respectively) and Plains Marketing LP (17% and 16% in 2012 and 2011, respectively).
FORM 10-K PART IDENBURY RESOURCES INC.
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, 2013, we have not experienced significant difficulty in
finding a market for all of our production as it becomes available or in transporting our production to those markets;
however, there is no assurance that we will always be able to market all of our production or obtain favorable prices.
Oil Marketing
Over the past couple of years, the oil produced in the Gulf Coast region has benefited from strong pricing
differentials in relation to NYMEX and, where possible, we have attached our production to Louisiana Light Sweet
(“LLS”) pricing. During 2013, LLS pricing and NYMEX pricing have been much closer together, with the fourth
quarter of 2013 quarterly average LLS-to-NYMEX differential (on a trade-month basis) narrowing to a positive
$2.58 per Bbl, suggesting a return to historical spreads compared to the wider-than-normal positive LLS-to-NYMEX
spreads we experienced during 2012 and 2011. During 2013, our light sweet oil production in this area, on average,
sold for $7.44 per Bbl over NYMEX compared to more than $11.50 per Bbl over NYMEX in 2012 and 2011. The pricing
of other Gulf Coast grades was relatively consistent with NYMEX pricing in 2013, with our light and medium sour
crude production selling at a premium to NYMEX of $0.08 per Bbl. The market dynamics of the region suggest the
possibility that differentials to NYMEX will narrow due to the influx of light sweet crude and condensate from
producing regions outside of the Gulf Coast region by rail and publicly announced major pipeline projects. Our
current markets, at various sales points along the Gulf Coast, have sufficient demand to accommodate our
production, but there can be no assurance of future demand. We are, therefore, monitoring the marketplace for
opportunities to strategically enter into long-term marketing arrangements.
The marketing of our Rocky Mountain region oil production is dependent on transportation through local pipelines
to market centers in Guernsey, Wyoming; Clearbrook, Minnesota; and Wood River, Illinois. Shipments on some of
the pipelines are oversubscribed and subject to apportionment. We currently have access to sufficient pipeline
capacity to move our oil production; however, there can be no assurance that we will be allocated sufficient pipeline
capacity to move all of our oil production in the future. Expansion of pipeline and newly built rail infrastructure
in the Rocky Mountain region is ongoing and, we believe, has improved the overall stability of oil differentials in the
area. However, because local demand for production is small in comparison to current production levels, much of
the production in the Rocky Mountain region is transported to coastal markets. Therefore, prices in the Rocky Mountain
region are further influenced by fluctuations in prices (primarily Brent and LLS) in those coastal markets. For the
year ended December 31, 2013, the discount for our oil production in the Rocky Mountain region averaged $8.10 per
Bbl, compared to $11.86 per Bbl during 2012 and $5.15 per Bbl during 2011. Excluding the Bakken area assets
that we sold during the fourth quarter of 2012, our oil production in the Rocky Mountain region sold at a discount to
NYMEX of $8.43 per Bbl during the year ended December 31, 2012.
Overall, during 2013, we sold approximately 46% of our crude oil at prices based on the LLS index price,
approximately 23% at prices partially tied to the LLS index price, and the balance at prices based on various other
indexes tied to NYMEX prices, primarily in the Rocky Mountain region.
Natural Gas Marketing
Virtually all of our natural gas production in the Gulf Coast region is close to existing pipelines; consequently, we
generally have a variety of options to market our natural gas. However, our natural gas production in the Rocky
Mountain region, like our oil production, is dependent on, among other factors, limited transportation options that
can affect our ability to find markets for it. We sell the majority of our natural gas on one-year contracts, with prices
fluctuating month to month based on published pipeline indices and with slight premiums or discounts to the index.
We currently receive near NYMEX or Henry Hub prices for most of our natural gas sales in Mississippi. For the
year ended December 31, 2013, the amount received for our Mississippi natural gas production averaged $0.12 per
Mcf over NYMEX prices. In the Texas Gulf Coast region, due primarily to its location, the price we received for
the year ended December 31, 2013 averaged $0.12 per Mcf below NYMEX prices. The CCA natural gas production in
the Rocky Mountain region is sold at the wellhead on a percent-of-proceeds basis. We receive a percentage
of proceeds on both the residue natural gas volumes and the natural gas liquids volumes. The natural gas has a
significant component of propane, butanes and other higher-density hydrocarbons, resulting in a measurable natural
gas liquids stream. In addition, we have coal bed methane production in the Hartzog Draw that is sold at the
2013 ANNUAL REPORTFORM 10-K PART I 18
Cheyenne Hub. For the year ended December 31, 2013, we averaged $0.57 per Mcf below NYMEX prices for our
Rocky Mountain region natural gas production due primarily to its location, the natural gas liquids extracted from the
CCA gas stream (resulting in a decreased net price), and the quality of the coal bed methane gas in Wyoming.
Helium Marketing
We placed the Riley Ridge gas processing facility in service in the fourth quarter of 2013. During 2014, we expect
to begin to supply helium to a third party purchaser under a 20-year helium supply arrangement. Helium will be sold
under the contract at a price that will fluctuate based on helium deliveries, CPI and other factors over the 20-year
term.
COMPETITION AND MARKETS
We face competition from other oil and natural gas companies in all aspects of our business, including acquisition
of producing properties, oil and gas leases, drilling rights, and CO2 properties; marketing of oil and natural gas;
and obtaining and maintaining goods, services and labor. Many of our competitors have substantially larger financial
and other resources. Factors that affect our ability to acquire producing properties include available liquidity,
available information about prospective properties and our expectations for earning a minimum projected return on
our investments. Because of the primary nature of our core assets (our tertiary operations) and our ownership of
relatively uncommon significant natural sources of CO2 in the Gulf Coast and Rocky Mountain regions, we believe
that we are effective in competing in the market and have less competition than our peers in certain aspects
of our business.
The demand for qualified and experienced field personnel to drill wells and conduct field operations and for
geologists, geophysicists, engineers and other professionals in the oil and gas industry can fluctuate significantly,
often in correlation with commodity prices, causing periodic shortages in such personnel. In recent years, the
competition for qualified technical personnel has been extensive, and our personnel costs have been escalating.
There have also been periods with shortages of drilling rigs and other equipment, as demand for rigs and equipment
has increased along with the number of wells being drilled. These factors also cause significant increases in costs
for equipment, services and personnel. We cannot be certain when we will experience these issues, and these types
of shortages or price increases could significantly decrease our profit margin, cash flow and operating results, and
cause significant delays in our development operations.
FEDERAL AND STATE REGULATIONS
Numerous federal, state and local laws and regulations govern the oil and gas industry. Additions or changes to
these laws and regulations are often made in response to the current political or economic environment. Compliance
with this evolving regulatory burden is often difficult, and substantial penalties may be incurred for noncompliance.
Additionally, the future annual cost of complying with all laws and regulations applicable to our operations is
uncertain and will be ultimately determined by several factors, including future changes to legal and regulatory
requirements. Management believes that continued compliance with existing laws and regulations applicable to our
operations and future compliance therewith will not have a materially adverse effect on our consolidated financial
position, results of operations or cash flows, although such laws and regulations, and compliance therewith, could
cause significant delays or otherwise impede operations, which may, among other things, cause our expected
production rates and cash flows to be less than anticipated.
The following sections describe some specific laws and regulations that may affect us. We cannot predict the cost
or impact of these or other future legislative or regulatory initiatives.
Regulation of Natural Gas and Oil Exploration and Production
Our operations are subject to various types of regulation at the federal, state and local levels. Such regulation
includes requiring permits for drilling wells; maintaining bonding requirements in order to drill or operate wells and
regulating the location of wells; the method of drilling and casing wells; the surface use and restoration of properties
upon which wells are drilled; the plugging and abandoning of wells; and the composition or disposal of chemicals
and fluids used in connection with operations. Our operations are also subject to various conservation laws and
regulations. These include regulation of the size of drilling, spacing or proration units and the density of wells that
may be drilled in those units, and the unitization or pooling of oil and gas properties. In addition, state conservation
laws, which establish maximum rates of production from oil and gas wells, generally prohibit or restrict the venting
or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of
FORM 10-K PART IDENBURY RESOURCES INC. 19
these laws and regulations may limit the amount of oil and natural gas we can produce from our wells and may limit
the number of wells or the locations at which we can drill. The regulatory burden on the oil and gas industry increases
our costs of doing business and, consequently, affects our profitability.
Federal Regulation of Sales Prices and Transportation
The transportation of, and certain sales with respect to, natural gas in interstate commerce are heavily regulated
by agencies of the U.S. federal government and are affected by, among other things, the availability, terms and cost
of transportation. Notably, the price and terms of access to pipeline transportation are subject to extensive U.S.
federal and state regulation. The Federal Energy Regulatory Commission (“FERC”) is continually proposing and
implementing new and/or modified rules and regulations affecting the natural gas industry, some of which may
adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. While our
sales of crude oil, condensate and natural gas liquids are not currently subject to FERC regulation, our ability to
transport and sell such products is dependent on certain pipelines whose rates, terms and conditions of service are
subject to FERC regulation. Additional proposals and proceedings that might affect the natural gas industry are
considered from time to time by Congress, FERC, state regulatory bodies and the courts, and we cannot predict when
or if any such proposals or proceedings might become effective and their effect or impact, if any, on our operations.
Federal Energy and Climate Change Legislation and Regulation
In early 2012, the President signed the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011. This act,
among other things, updates federal pipeline safety standards, increases penalties for violations of such standards,
gives the Department of Transportation (the “DOT”) authority for new damage prevention and incident notification,
and directs the DOT to prescribe new minimum safety standards for CO2 pipelines, which safety standards could
affect our operations and the costs thereof. While the DOT has adopted or proposed to adopt a number of new
regulations to implement this act, no such new minimum safety standards have been proposed or adopted for CO2
pipelines. In the future, Congress may create new incentives for alternative energy sources and may also consider
legislation to reduce emissions of CO2 or other greenhouse gases which legislation, if enacted, could (1) impose a tax
or other economic penalty on the production of fossil fuels that, when used, ultimately release CO2, (2) reduce the
demand for, and uses of, oil, gas and other minerals, and/or (3) increase the costs incurred by us in our exploration
and production activities. The Environmental Protection Agency (“EPA”) has promulgated regulations requiring
permitting for certain sources of greenhouse gas emissions, along with requirements for wells used for geologic
sequestration. At the same time, legislation to reduce the emissions of CO2 or other greenhouse gases could also
create economic incentives for technologies and practices that reduce or avoid such emissions, including processes
that sequester CO2 in geologic formations such as depleted oil and gas reservoirs.
Natural Gas Gathering Regulations
State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some
circumstances, nondiscriminatory-take requirements. With the increase in construction and operation of natural gas
gathering lines in various states, natural gas gathering is receiving greater regulatory scrutiny from state regulatory
agencies, which is likely to continue in the future.
Federal, State or Indian Leases
Our operations on federal, state or Indian oil and gas leases, especially those in the Rocky Mountain region, are
subject to numerous restrictions, including nondiscrimination statutes. Such operations must be conducted
pursuant to certain on-site security regulations and other permits and authorizations issued by the Bureau of Land
Management, the Bureau of Ocean Energy Management, the Bureau of Safety and Environmental Enforcement,
the Bureau of Indian Affairs, and other federal and state stakeholder agencies.
Environmental Regulations
Our oil and natural gas production, saltwater disposal operations, injection of CO2, and the processing, handling
and disposal of materials such as hydrocarbons and naturally occurring radioactive materials (“NORM”) are subject to
stringent regulation. We could incur significant costs, including cleanup costs resulting from a release of product,
third-party claims for property damage and personal injuries, or penalties and other sanctions as a result of any
violations or liabilities under environmental or other laws applicable to our operations. Changes in, or more stringent
enforcement of, environmental laws and other laws applicable to our operations could also result in delays or
additional operating costs and capital expenditures.
2013 ANNUAL REPORTFORM 10-K PART I 20
Various federal, state and local laws and regulations controlling the discharge of materials into the environment, or
otherwise relating to the protection of the environment, directly impact our oil and gas exploration, development and
production operations. These include, among others, (1) regulations adopted by the EPA and various state agencies
regarding approved methods of disposal for certain hazardous and nonhazardous wastes; (2) the Comprehensive
Environmental Response, Compensation, and Liability Act and analogous state laws that regulate the removal or
remediation of previously disposed wastes (including wastes disposed of or released by prior owners or operators),
property contamination (including groundwater contamination), and remedial plugging operations to prevent future
contamination; (3) the Clean Air Act and comparable state and local requirements already applicable to our operations
and new restrictions on air emissions from our operations, including those that could discourage the production of
fossil fuels that, when used, ultimately release CO2; (4) the Oil Pollution Act of 1990, which contains numerous
requirements relating to the prevention of, and response to, oil spills into waters of the United States; (5) the
Resource Conservation and Recovery Act, which is the principal federal statute governing the treatment, storage and
disposal of hazardous wastes; (6) the Endangered Species Act and counterpart state legislation, which protects
certain species (and their related habitats), including certain species that could be present on our leases, as
threatened or endangered; and (7) state regulations and statutes governing the handling, treatment, storage and
disposal of NORM.
Management believes that we are currently in substantial compliance with existing applicable environmental laws
and regulations, and does not currently anticipate that future compliance will have a materially adverse effect on our
consolidated financial position, results of operations or cash flows, although such laws and regulations, and
compliance therewith, could cause significant delays or otherwise impede operations, which may, among other
things, cause our expected production rates and cash flows to be less than anticipated.
Hydraulic Fracturing
During 2013, we fracture stimulated one operated well at Hartzog Draw and two CO2 source wells at Jackson Dome,
in each case utilizing water-based fluids with no diesel fuel component. In 2014, we currently plan to hydraulically
fracture approximately seven additional wells at Hartzog Draw using similar techniques. We are familiar with the
laws and regulations applicable to hydraulic fracturing operations and take steps to ensure compliance with
these requirements.
ESTIMATED NET QUANTITIES OF PROVED OIL AND NATURAL GAS RESERVES
AND PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES
Internal Controls Over Reserve Estimates
Reserve information in this report is based on estimates prepared by DeGolyer and MacNaughton (“D&M”), an
independent petroleum engineering consulting firm located in Dallas, Texas, utilizing data provided by our internal
reservoir engineering team and is the responsibility of management. We rely on D&M’s expertise to ensure that
our reserve estimates are prepared in compliance with SEC rules and regulations and that appropriate geologic,
petroleum engineering, and evaluation principles and techniques are applied in accordance with practices generally
recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers
entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of
February 19, 2007)”. The person responsible for the preparation of the reserve report is a Senior Vice President
at D&M; he is a Registered Professional Engineer in the State of Texas. He received a Bachelor of Science degree in
Petroleum Engineering at Texas A&M University in 1974, and he has in excess of 39 years of experience in oil and
gas reservoir studies and evaluations. Our Senior Vice President – Planning, Technology and CO2 Supply is primarily
responsible for overseeing the independent petroleum engineering firm during the process. Our Senior Vice
President – Planning, Technology and CO2 Supply has a Bachelor of Science degree in Petroleum Engineering from
Louisiana State University and over 32 years of industry experience working with petroleum reserve estimates.
D&M relies on various data provided by our internal reservoir engineering team in preparing its reserve estimates,
including such items as oil and natural gas prices, ownership interests, production information, operating costs,
planned capital expenditures and other technical data. Our internal reservoir engineering team consists of qualified
petroleum engineers who maintain the Company’s internal evaluation of reserves and compare the Company’s
information to the reserves prepared by D&M. Management is responsible for designing the internal control
procedures used in the preparation of our oil and gas reserves, which include verification of data input into reserve
forecasting and economics evaluation software, as well as multi-discipline management reviews. The internal
FORM 10-K PART IDENBURY RESOURCES INC. 21
reservoir engineering team reports directly to our Senior Vice President – Planning, Technology and CO2 Supply.
In addition, our Board of Directors’ Reserves and Health, Safety and Environment (“HSE”) Committee, on behalf of
the Board of Directors, oversees the qualifications, independence, performance and hiring of our independent
petroleum engineering firm and reviews the final report and subsequent reporting of our oil and natural gas reserve
estimates. The Chairman of the Reserves and HSE Committee holds a Ph.D. in Chemical Engineering from the
Massachusetts Institute of Technology and bachelor’s degrees in Chemistry and Mathematics from Capital University
in Ohio. He has 34 years of industry experience, with responsibilities including reserves preparation and approval.
Oil and Natural Gas Reserve Estimates
D&M prepared estimates of our net proved oil and natural gas reserves as of December 31, 2013, 2012 and 2011.
See the summary of D&M’s report as of December 31, 2013, included as an exhibit to this Form 10-K. These estimates
of reserves were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices
on the first day of each month within the 12-month period in accordance with rules and regulations of the SEC. These
oil and natural gas reserve estimates do not include any value for probable or possible reserves that may exist,
nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in
our properties. During 2013, we provided oil and gas reserve estimates for 2012 to the United States Energy
Information Agency that were substantially the same as the reserve estimates included in our Form 10-K for the year
ended December 31, 2012.
Our proved nonproducing reserves primarily relate to reserves that are to be recovered from productive zones that
are currently behind pipe. Since a majority of our properties are in areas with multiple pay zones, these properties
typically have both proved producing and proved nonproducing reserves.
As of December 31, 2013, our estimated proved undeveloped reserves totaled approximately 179.9 MMBOE, or
approximately 38% of our estimated total proved reserves, an increase of 17.2 MMBOE from December 31, 2012
levels. Our proved undeveloped oil reserves primarily relate to our CO2 tertiary operations (92.8 MMBOE), and our
proved undeveloped natural gas reserves are primarily located in our Riley Ridge Field (66.6 MMBOE). We consider
the CO2 tertiary proved undeveloped reserves to be lower risk than other proved undeveloped reserves that require
drilling at locations offsetting existing production, because all of these proved undeveloped reserves are associated
with tertiary recovery operations in fields and reservoirs that historically produced substantial volumes of oil under
primary production.
During 2013, we spent approximately $260 million to convert 16.7 MMBOE of proved undeveloped reserves to
proved developed reserves, primarily as a result of tertiary development activities at Heidelberg, Hastings, and
Tinsley fields. During 2013, we added 30.0 MMBOE of proved undeveloped reserves, including 27.3 MMBOE related
to our tertiary operations at Bell Creek Field, and recognized net positive proved undeveloped reserve revisions of
3.9 MMBOE.
As of December 31, 2013, 26.7 MMBOE of our total proved undeveloped reserves are not scheduled to be
developed within five years of initial booking, 26.1 MMBOE of which are part of CO2 EOR projects. We believe
these reserves satisfy the conditions to be included as proved reserves because (1) we have established and continue
to follow the previously adopted development plan for each of these projects; (2) we have significant ongoing
development activities in each of these CO2 EOR projects and (3) we have a historical record of completing the
development of comparable long-term projects.
2013 ANNUAL REPORTFORM 10-K PART I 22
Estimated proved reserves (1)
Oil (MBbls)
Natural gas (MMcf)
Oil equivalent (MBOE)
Reserve volumes categories
Proved developed producing:
Oil (MBbls)
Natural gas (MMcf)
Oil equivalent (MBOE)
Proved developed non-producing:
Oil (MBbls)
Natural gas (MMcf)
Oil equivalent (MBOE)
Proved undeveloped:
Oil (MBbls)
Natural gas (MMcf)
Oil equivalent (MBOE)
Percentage of total MBOE:
Proved developed producing
Proved developed non-producing
Proved undeveloped
Representative oil and natural gas prices: (2)
Oil – NYMEX
Natural gas – Henry Hub
Present values (in thousands): (3)
Discounted estimated future net cash flow
before income taxes (PV-10 Value) (4)
December 31,
2013
2012
2011
386,659
489,954
468,318
245,722
68,976
257,218
30,670
3,119
31,190
110,267
417,859
179,910
329,124
481,641
409,398
208,745
60,832
218,884
27,264
3,359
27,824
93,115
417,450
162,690
357,733
625,208
461,934
189,904
116,562
209,331
49,837
9,408
51,405
117,992
499,238
201,198
55%
7%
38%
53%
7%
40%
45%
11%
44%
$
96.94
3.67
$
94.71
2.85
$
96.19
4.16
$ 10,633,783
$ 9,909,592
$ 10,559,139
Standardized measure of discounted estimated future
net cash flow after income taxes (“Standardized Measure”)
$ 7,128,744
$ 6,414,380
$ 7,007,605
(1) Estimated proved reserves as of December 31, 2012 reflect the sale of reserves associated with our Bakken area assets sold in 2012
(approximately 109 MMBOE). Year-end 2012 reserves reflect CCA reserves acquired in 2010 as part of the Encore merger, but do not include
reserves of 42.2 MMBOE related to the CCA Acquisition, which closed during the first quarter of 2013.
(2) The reference prices were based on the arithmetic average of the first-day-of-the-month NYMEX commodity prices for each month during the
respective year. These prices do not reflect adjustments for market differentials by field that are utilized in the preparation of our reserve report to
arrive at the appropriate net price we receive. See Management’s Discussion and Analysis of Financial Condition and Results of Operations –
Results of Operations – Operating Results Table for details of oil and natural gas prices received, both including and excluding the impact of
derivative settlements.
(3) Determined based on the average first-day-of-the-month prices for each month, adjusted to prices received by field in accordance with standards
set forth in the FASC.
(4) PV-10 Value is a non-GAAP measure and is different from the Standardized Measure in that PV-10 Value is a pre-tax number and the Standardized
Measure is an after-tax number. The information used to calculate PV-10 Value is derived directly from data determined in accordance with
FASC Topic 932. The difference between these two amounts, the discounted estimated future income tax was $3.505 billion at December 31, 2013;
$3.495 billion at December 31, 2012; and $3.552 billion at December 31, 2011. We believe that PV-10 Value is a useful supplemental disclosure
to the Standardized Measure because the Standardized Measure can be impacted by a company’s unique tax situation, and it is not practical to
calculate the Standardized Measure on a property-by-property basis. Because of this, PV-10 Value is a widely used measure within the industry
and is commonly used by securities analysts, banks and credit rating agencies to evaluate the estimated future net cash flows from proved
reserves on a comparative basis across companies or specific properties. PV-10 Value is commonly used by us and others in our industry to
evaluate properties that are bought and sold and to assess the potential return on investment in our oil and gas properties. PV-10 Value is not a
measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for the Standardized
Measure. Our PV-10 Value and the Standardized Measure do not purport to represent the fair value of our oil and natural gas reserves. See
Glossary and Selected Abbreviations for the definition of “PV-10 Value” and see Supplemental Oil and Natural Gas Disclosures (Unaudited), to the
Consolidated Financial Statements for additional disclosures about the Standardized Measure.
There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and
their values, including many factors beyond our control. See Item 1A, Risk Factors – Estimating our reserves,
production and future net cash flows is difficult to do with any certainty. See also Supplemental Oil and Natural Gas
Disclosures (Unaudited), to the Consolidated Financial Statements.
FORM 10-K PART IDENBURY RESOURCES INC.
23
Item 1A. Risk Factors
Oil and natural gas prices are volatile. A substantial decrease in oil and natural gas prices could adversely affect
our financial results.
Our future financial condition, results of operations, cash flows and the carrying value of our oil and natural
gas properties depend primarily upon the prices we receive for our oil and natural gas production. Oil and natural
gas prices historically have been volatile and may continue to be volatile in the future. Substantial decreases in
commodity prices in the future could require us to record full cost ceiling test write-downs. The amount of any future
write-down is difficult to predict and will depend upon oil and natural gas prices, the incremental proved reserves
that might be added during each period and additional capital spent.
Our cash flow from operations is highly dependent on the prices that we receive for oil. This price volatility also
affects the amount of our cash flow available for capital expenditures and our ability to borrow money or raise
additional capital. Oil prices currently affect us more than natural gas prices because oil comprised approximately
94% of our 2013 production and 83% of our proved reserves at December 31, 2013.
The prices for oil and natural gas are subject to a variety of additional factors that are beyond our control. These
factors include the supply of, and demand for, these commodities, which fluctuate with changes in market and
economic conditions and other factors, including:
•
•
•
•
the level of worldwide consumer demand for oil and natural gas;
the domestic and foreign supply of oil and natural gas;
the degree to which domestic oil and natural gas production decreases U.S. imports of crude oil;
the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil
price and production controls;
• domestic governmental regulations and taxes;
•
the price and availability of alternative fuel sources;
• storage levels of oil and natural gas;
• weather conditions, including hurricanes and tropical storms in and around the Gulf of Mexico that can
damage oil and natural gas facilities and delivery systems and disrupt operations, and winter conditions and
forest fires in the Rocky Mountains that can delay or impede operations;
• market uncertainty;
• worldwide political events and conditions, including actions taken by foreign oil and natural gas producing
nations; and
• worldwide economic conditions.
These factors and the volatility of the energy markets generally make it extremely difficult to predict future oil and
natural gas price movements. Also, prices for oil and prices for natural gas do not necessarily move in tandem.
Declines in oil or natural gas prices would not only reduce revenue but could reduce the amount of oil and natural
gas that we can produce economically. If the oil and natural gas industry experiences significant price declines,
we may, among other things, be unable to meet all of our financial obligations or make planned expenditures.
Over the past six years oil prices have fluctuated significantly, reaching record highs of approximately $145 per
Bbl in July 2008, declining precipitously during the last half of 2008, and ending that year at a NYMEX price of
$44.60 per Bbl. Since 2008, oil prices have continued to fluctuate, ending 2013 at a NYMEX price of $98.42 per Bbl.
If substantial volatility of oil prices continues, oil prices could decline to a level that makes some or all of our tertiary
projects uneconomical. If that were to happen, we may decide to suspend future expansion projects, and if prices
were to drop below our cash break-even point for an extended period of time, we may further decide to shut-in
existing production, both of which could have a material adverse effect on our operations. We may also be required
to reduce our capital expenditures in the event of declining commodity prices in order to compensate for diminished
cash flow, which could reduce or eliminate our growth. Since operating costs do not decrease as quickly as
commodity prices, it is difficult to determine a precise break-even point for our tertiary projects; however, based on
prior history, we currently estimate our economic break-even point (before corporate-related overhead and based
on currently estimated expenses relative to these tertiary projects) occurs at oil prices in the low-to-mid $40-per-barrel
range, depending on the specific field and area.
2013 ANNUAL REPORTFORM 10-K PART I 24
We have a current practice of hedging approximately 18 months to two years (from the current quarter) of forecasted
production to mitigate the risks associated with price fluctuations (see Management’s Discussion and Analysis
of Financial Condition and Results of Operations – Market Risk Management and Note 9, Commodity Derivative
Contracts, to the Consolidated Financial Statements for details regarding our commodity derivative contracts). As of
February 20, 2014, we have oil derivative contracts in place covering 58,000 Bbls/d during 2014 and 58,000 Bbls/d
during the first three quarters of 2015.
The prices we receive for our crude oil often do not correlate with NYMEX prices and can vary from such prices
depending on, among other factors, the quality of the crude oil we sell, the location of our crude oil production and
the related markets to which we sell, variations in prices paid based upon different indices used, and the pricing
contracts and indices at which we sell production. Our NYMEX differentials on a field-by-field basis over the last few
years have ranged from approximately $25 per Bbl above NYMEX to approximately $25 per Bbl below NYMEX.
On a corporate-wide basis, our NYMEX differentials over the last few years have ranged from approximately
$11 per Bbl above NYMEX oil prices to approximately $5 per Bbl below NYMEX oil prices. These variances have been
due to various factors and are difficult to forecast or anticipate, but they have a direct impact on the net oil price
we receive.
Natural gas price volatility has been severe over the last few years as a result of, among other things, weak
demand, increased production of natural gas, and significant natural gas storage in place, leading to excess gas
supply. NYMEX natural gas prices averaged $4.03 per MMBtu during 2011, $2.82 per MMBtu during 2012, and
$3.72 per MMBtu during 2013, and ended 2013 at $4.23 per MMBtu. As of February 20, 2014, we have natural gas
derivative contracts in place covering 14,000 MMBtu/d during 2014 and 6,000 MMBtu/d during 2015 (see
Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Risk Management
and Note 9, Commodity Derivative Contracts, to the Consolidated Financial Statements for details regarding our
commodity derivative contracts).
Our production will decline if our access to sufficient amounts of carbon dioxide is limited.
Our long-term strategy is focused on our CO2 tertiary recovery operations. The crude oil production from our
tertiary recovery projects depends, in large part, on having access to sufficient amounts of CO2. Our ability to
produce oil from these projects would be hindered if our supply of CO2 was limited due to, among other things,
problems with our current CO2 producing wells and facilities, including compression equipment, or catastrophic
pipeline failure. This could have a material adverse effect on our financial condition, results of operations and cash
flows. Our anticipated future crude oil production from tertiary operations is also dependent on the timing,
volumes and location of CO2 injections and, in particular, on our ability to increase our combined purchased and
produced volumes of CO2 and inject adequate amounts of CO2 into the proper formation and area within each of
our tertiary oil fields.
Our planned tertiary operations and the related construction of necessary CO2 pipelines could be delayed by
difficulties in obtaining pipeline rights-of-way and/or permits, and/or by the listing of certain species as threatened
or endangered.
The production of crude oil from our planned tertiary operations is dependent upon having access to pipelines
to transport available CO2 to our oil fields at a cost that is economically viable. Our current and future construction of
CO2 pipelines will require us to obtain rights-of-way from private landowners and from the federal government in
certain areas. Certain states where we operate are considering the adoption of laws and regulations that would limit
or eliminate a state’s (and, accordingly, its legislative delegates’) ability to exercise eminent domain over private
property, in addition to possible judicially imposed constraints on, and additional requirements for, the exercise of
eminent domain. We also conduct operations on federal and other oil and natural gas leases inhabited by
species, such as the sage grouse, that could be listed as threatened or endangered under the Endangered Species
Act, which listing could lead to material restrictions as to federal land use. These laws and regulations, together
with any other changes in law related to the use of eminent domain or the listing of certain species as threatened or
endangered, could inhibit or eliminate our ability to secure rights-of-way or otherwise access land for current
or future pipeline construction projects. As a result, obtaining rights-of-way or other means of access may require
additional regulatory and environmental compliance, and increased costs in connection therewith, which could
delay our CO2 pipeline construction schedule and initiation of our pipeline operations, and/or increase the costs of
constructing our pipelines.
FORM 10-K PART IDENBURY RESOURCES INC. 25
Our level of indebtedness may adversely affect operations and limit our growth.
As of December 31, 2013, our outstanding senior indebtedness consisted of $2.6 billion principal amount of
subordinated notes, virtually all of which have maturity dates between 2020 and 2023 at interest rates ranging from
4.625% to 8.25% per annum at a weighted average interest rate of 6.29% per annum, and $340.0 million principal
amount outstanding under our bank credit facility. We currently have a borrowing base of $1.6 billion under our bank
credit facility and, at December 31, 2013, availability with respect to such borrowing base of $1.2 billion. Our bank
borrowing base is adjusted semi-annually and upon requested special redeterminations, in each case at the banks’
discretion, and the amount is established and based, in part, upon certain external factors, such as commodity
prices, over which we have no control. If the outstanding credit under our bank credit facility exceeds the then
effective and redetermined borrowing base, we will be required to repay the excess amount over a period not to
exceed four months.
We may incur additional indebtedness in the future under our bank credit facility in connection with, among
other things, our acquisition and development of oil and natural gas properties. Further, as our cash flow from
operations is highly dependent on the prices that we receive for oil and natural gas, if oil and natural gas prices
decrease substantially and remain at depressed levels for an extended period of time, our degree of leverage could
increase significantly. The level of our indebtedness could have important consequences, including but not limited
to the following:
• our level of indebtedness may impair our ability to obtain additional financing in the future for working capital,
capital expenditures, acquisitions or general corporate and other purposes;
• our vulnerability to general adverse economic and industry conditions may be greater as a result of our level of
indebtedness, and increases in interest rates thereon, potentially restricting us from making acquisitions,
introducing new technologies or exploiting business opportunities;
• our interest expense may increase in the event of increases in market interest rates;
• a substantial portion of our cash flows from operations may be dedicated to servicing our indebtedness and
would not be available for capital expenditures or other purposes;
• our ability to, among other things, borrow additional funds, dispose of assets, pay dividends and make certain
investments may be limited by the covenants contained in the agreements governing our outstanding
indebtedness; and
• our debt covenants contained in the agreements governing our outstanding indebtedness may also affect our
flexibility in planning for, and reacting to, changes in the economy and in our industry, and our failure to comply
with such covenants could result in an event of default under such debt instruments which, if not cured or
waived, could have a material adverse effect on us.
If we are unable to generate sufficient cash flow or otherwise obtain funds necessary to make required payments
on our indebtedness, or if we otherwise fail to comply with the various covenants related to such indebtedness,
including covenants in our bank credit facility, we would be in default under our debt instruments. This default could
permit the holders of such indebtedness to accelerate the maturity of such indebtedness and could cause
defaults under other indebtedness, which could have a material adverse effect on us. Our ability to meet our
obligations under our debt instruments will depend, in part, upon our future performance, which will be subject
to prevailing economic conditions, commodity prices, and financial, business and other factors, including factors
beyond our control.
Commodity derivative contracts may expose us to potential financial loss.
To reduce our exposure to fluctuations in the prices of oil and natural gas, we enter into commodity derivative
contracts in order to economically hedge a substantial portion of our oil and natural gas production. Derivative
contracts expose us to risk of financial loss in some circumstances, including when there is a change in the expected
differential between the underlying price in the hedging agreement and actual prices received, or when the
counterparty to the derivative contract defaults on its contractual obligations. In addition, these derivative contracts
may limit the benefit we would otherwise receive from increases in the prices for oil and natural gas. Information
as to these activities is set forth under Item 7, Management’s Discussion and Analysis of Financial Condition and
Results of Operations – Market Risk Management, and in Note 9, Commodity Derivative Contracts, to the Consolidated
Financial Statements.
2013 ANNUAL REPORTFORM 10-K PART I 26
There are no assurances of our ability to pay dividends in the future and at what level.
On January 28, 2014, we declared our first quarterly cash common stock dividend of $0.0625 per share, payable
March 25, 2014, to shareholders of record on February 25, 2014. We currently intend to pay regular quarterly cash
dividends in the future; however, our ability to pay dividends may be adversely affected if certain of the risks
described herein were to occur. Our payment of dividends is subject to, and conditioned upon, among other things,
compliance with the covenants and restrictions contained in our bank credit facility and the indentures governing
our subordinated notes. All dividends will be paid at the discretion of our Board of Directors and will depend upon
many factors, including our earnings, financial condition and such other factors as our Board of Directors may
deem relevant from time to time. There are no assurances as to our ability to pay dividends in the future or the
level thereof.
A worldwide financial downturn or negative credit market conditions may have lasting effects on our liquidity,
business and financial condition that we cannot control or predict.
Liquidity is essential to our business. Our liquidity could be substantially negatively affected by an inability to
obtain capital in the long-term or short-term debt capital markets or equity capital markets or an inability to access
bank financing. A prolonged credit crisis, including a sovereign debt crisis in Europe or turmoil in the global
financial system, could materially affect our liquidity, business and financial condition. These conditions have
adversely impacted financial markets and have created substantial volatility and uncertainty, and may continue to do
so, with the related negative impact on global economic activity and the financial markets. Negative credit market
conditions could materially affect our liquidity and may inhibit our lenders from fully funding our bank credit facility
or cause them to make the terms of our bank credit facility more costly and more restrictive. We are subject to
semiannual, as well as unscheduled, reviews and redeterminations of our borrowing base under our bank credit
facility, and we do not know, nor can we control, the results of such redeterminations or the effect of then-current
oil and natural gas prices on any such redetermination. A negative economic situation could also adversely affect the
collectability of our trade receivables or performance by our suppliers and cause our commodity hedging
arrangements to be ineffective if our counterparties are unable to perform their obligations or otherwise seek
bankruptcy protection. Additionally, negative economic conditions could lead to reduced demand for oil and natural
gas, or lower prices for oil and natural gas, which could have a negative impact on our revenues.
Our future performance depends upon our ability to find or acquire additional oil and natural gas reserves that are
economically recoverable.
Unless we can successfully replace the reserves that we produce, our reserves will decline, resulting eventually in
a decrease in oil and natural gas production and lower revenues and cash flows from operations. We have historically
replaced reserves through both acquisitions and internal organic growth activities. In the future, we may not be
able to continue to replace reserves at acceptable costs. The business of exploring for, developing or acquiring reserves
is capital intensive. We may not be able to make the necessary capital investment to maintain or expand our oil
and natural gas reserves if our cash flows from operations are reduced, whether due to lower oil or natural gas prices
or otherwise, or if external sources of capital become limited or unavailable. Further, the process of using CO2 for
tertiary recovery, and the related infrastructure, requires significant capital investment up to five years prior to any
resulting and associated production and cash flows from these projects, heightening potential capital constraints.
If we do not continue to make significant capital expenditures, or if outside capital resources become limited, we may
not be able to maintain our growth rate or otherwise meet expectations.
During the last few years, we have acquired several fields at a substantial cost because we believe that they have
significant additional production potential through tertiary flooding, and we plan to continue acquiring other oil
fields that we believe are tertiary flood candidates. We are investing significant amounts of capital as part of this
strategy. If we are unable to successfully develop and produce the potential oil in these acquired fields, it would
negatively affect our return on investment relative to these acquisitions and could significantly reduce our ability to
obtain additional capital for the future or fund future acquisitions, and also negatively affect our financial results to
a significant degree.
Oil and natural gas development and producing operations involve various risks.
Our operations are subject to all the risks normally incident and inherent to the operation and development of oil
and natural gas properties and the drilling of oil and natural gas wells, including, without limitation, well blowouts;
cratering and explosions; pipe failure; fires; formations with abnormal pressures; uncontrollable flows of oil, natural
gas, brine or well fluids; release of contaminants into the environment and other environmental hazards and risks.
FORM 10-K PART IDENBURY RESOURCES INC. 27
The nature of these risks is such that some liabilities could exceed our insurance policy limits or otherwise be
excluded from, or limited by, our insurance coverage, as in the case of environmental fines and penalties, for example,
which are excluded from coverage as they cannot be insured. We could incur significant costs related to these risks
that could have a material adverse effect on our results of operations, financial condition and cash flows.
Our CO2 tertiary recovery projects require a significant amount of electricity to operate the related facilities. If these
costs were to increase significantly, it could have an adverse effect upon the profitability of these operations.
Additionally, a portion of our production activities involves CO2 injections into fields with wells plugged and abandoned
by prior operators. Although it is often difficult (or impracticable) to determine whether a well has been properly
plugged prior to commencing injections and pressuring the oil reservoirs, we have budgeted $50 million for this
effort for 2014. We may incur significant costs in connection with remedial plugging operations to prevent
environmental contamination and to otherwise comply with federal, state and local regulation relative to the plugging
and abandoning of our oil, natural gas and CO2 wells. In addition to the increased costs, if wells have not been
properly plugged, modification to those wells may delay our operations and reduce our production.
While mitigated somewhat by our significant emphasis on tertiary recovery operations in fields and reservoirs that
have historically produced substantial volumes of oil under primary production, development activities are subject
to many risks, including the risk that new wells drilled by us will not result in the discovery of commercially
productive reservoirs or the risk that we will not recover all or any portion of our investment in such wells. Drilling
for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are
productive but do not produce sufficient net reserves to return a profit after deducting drilling, operating and other
costs. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely
affect the economics of a project. Further, our drilling operations may be curtailed, delayed or canceled as a result of
numerous factors, including:
• unexpected drilling conditions;
•
title problems;
• pressure or irregularities in formations;
• equipment failures or accidents;
• adverse weather conditions, including hurricanes and tropical storms in and around the Gulf of Mexico that can
damage oil and natural gas facilities and delivery systems and disrupt operations, and winter conditions and
forest fires in the Rocky Mountain region that can delay or impede operations;
• compliance with environmental and governmental requirements; and
•
the cost of, or shortages or delays in the availability of, drilling rigs, equipment, pipelines and services.
Certain of our operations may be limited during certain periods due to severe weather conditions and other regulations.
Certain of our operations in North Dakota, Montana and Wyoming, including the construction of CO2 pipelines, the
drilling of new wells and production from existing wells, are conducted in areas subject to extreme weather
conditions, including severe cold, snow and rain, which conditions may cause such operations to be hindered or
delayed, or otherwise require that they be conducted only during non-winter months, and depending on the severity of
the weather, could have a negative effect on our results of operations in these areas. Further, certain of our operations
in these areas are confined to certain time periods due to environmental regulations, federal restrictions on when
drilling can take place on federal lands, and lease stipulations designed to protect certain wildlife, which regulations,
restrictions and limitations could slow down our operations, cause delays, increase costs and have a negative effect
on our results of operations.
Shortages of oil field equipment, services and qualified personnel could reduce our cash flow and adversely affect
results of operations.
The demand for qualified and experienced field personnel, geologists, geophysicists, engineers and other
professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural
gas prices, causing periodic shortages in such personnel. In recent years, the competition for qualified technical
personnel has been fierce, and our personnel costs have been escalating at a rate higher than general inflation.
During periods of high oil and natural gas prices, we have experienced shortages of oil field and other necessary
equipment, as well as drilling rigs, as demand for equipment and rigs has increased in tandem with higher
commodity prices. Additionally, higher oil and natural gas prices generally stimulate increased demand, which results
in increased prices for drilling rigs, crews and associated supplies, oilfield equipment and services, and personnel
2013 ANNUAL REPORTFORM 10-K PART I 28
in our exploration and production operations. These types of shortages or price increases could significantly
decrease our profit margin, cash flow and operating results and/or restrict or delay our ability to drill wells and
conduct those operations that we currently have planned and budgeted, causing us to miss our forecasts
and projections.
The marketability of our production is dependent upon transportation lines and other facilities, certain of
which we do not control. When these facilities are unavailable, our operations can be interrupted and our
revenues reduced.
The marketability of our oil and natural gas production depends, in part upon the availability, proximity and
capacity of transportation lines owned by third parties. In general, we do not control these transportation facilities,
and our access to them may be limited or denied. A significant disruption in the availability of, and access to,
these transportation lines or other production facilities could adversely impact our ability to deliver to market or
produce our oil and thereby cause a significant interruption in our operations.
Governmental laws and regulations relating to environmental protection are costly and stringent.
Our exploration, production, and marketing operations are subject to complex and stringent federal, state, and local
laws and regulations governing, among other things, the discharge of substances into the environment or otherwise
relating to environmental protection. These laws and regulations and related public policy considerations affect the
costs, manner, and feasibility of our operations and require us to make significant expenditures in order to comply.
Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal
penalties, the imposition of investigatory and remedial obligations, and the issuance of injunctions that could limit
or prohibit our operations. In addition, some of these laws and regulations may impose joint and several, strict liability
for contamination resulting from spills, discharges, and releases of substances, including petroleum hydrocarbons
and other wastes, without regard to fault or the legality of the original conduct. Under such laws and regulations, we
could be required to remove or remediate previously disposed substances and property contamination, including
wastes disposed or released by prior owners or operators. Changes in, or additions to, environmental laws and
regulations occur frequently, and any changes or additions that result in more stringent and costly waste handling,
storage, transport, disposal, cleanup or other environmental protection requirements could have a material adverse
effect on our operations and financial position.
Enactment of legislative or regulatory proposals under consideration could negatively affect our business.
Numerous legislative and regulatory proposals affecting the oil and gas industry have been introduced, are
anticipated to be introduced, or are otherwise under consideration, by Congress and various federal agencies.
Among these proposals are: (1) climate change/carbon tax legislation introduced in Congress, and EPA regulations
to reduce greenhouse gas emissions; (2) proposals contained in the President’s budget, along with legislation
introduced in Congress (none of which have passed), to impose new taxes on, or repeal various tax deductions
available to, oil and gas producers, such as the current tax deductions for intangible drilling and development costs
and qualified tertiary injectant expenses which deductions, if eliminated, could raise the cost of energy production,
reduce energy investment and affect the economics of oil and gas exploration and production activities;
(3) legislation previously considered by Congress (but not adopted) that would subject the process of hydraulic
fracturing to federal regulation under the Safe Drinking Water Act, and new or anticipated Department of Interior and
EPA regulations to impose new and more stringent regulatory requirements on hydraulic fracturing activities,
particularly those performed on federal lands, and to require disclosure of the chemicals used in the fracturing process;
and (4) the Pipeline Safety, Regulatory Certainty, and Job Creation Act enacted in 2011, which increases penalties,
grants new authority to impose damage prevention and incident notification requirements, and directs the
Department of Transportation to prescribe minimum safety standards for CO2 pipelines. Any of the foregoing
described proposals could affect our operations and the costs thereof. The trend toward stricter standards, increased
oversight and regulation and more extensive permit requirements, along with any future laws and regulations,
could result in increased costs or additional operating restrictions that could have an effect on demand for oil and
natural gas or prices at which it can be sold. However, until such legislation or regulations are enacted or
adopted into law and thereafter implemented, it is not possible to gauge their impact on our future operations or
our results of operations and financial condition.
FORM 10-K PART IDENBURY RESOURCES INC. 29
Certain federal income tax deductions currently available with respect to natural gas and oil exploration and
development may be eliminated, and additional state taxes on natural gas extraction may be imposed, as a result of
future legislation.
In recent years, legislation has been proposed that would, if enacted into law, make significant changes to U.S.
federal income tax laws, including the elimination of certain U.S. federal income tax benefits and deductions currently
available to oil and gas companies. Such changes include, but are not limited to, (1) the repeal of the percentage
depletion allowance for oil and gas properties, (2) the increase of the amortization period of geological and geophysical
expenses, (3) the elimination of current deductions for intangible drilling and development costs and qualified
tertiary injectant expenses, and (4) the elimination of the deduction for certain U.S. production activities. It is
currently unclear whether any such proposals will be enacted into law and, if so, what form such laws might possibly
take or impact they may have; however, the passage of such legislation or any other similar change in U.S. federal
income tax law could eliminate, reduce or postpone certain tax deductions that are currently available to us, and any
such legislation or change could negatively affect our financial condition and results of operations.
The derivatives market regulations promulgated under the Dodd-Frank Act could have an adverse effect on our
ability to hedge risks associated with our business.
The Dodd-Frank Act requires the Commodities Futures Trading Commission (“CFTC”) and the SEC to promulgate
rules and regulations establishing federal oversight and regulation of the over-the-counter derivatives market and
entities that participate in that market, including swap clearing and trade execution requirements. Our derivative
transactions are not currently subject to such swap clearing and trade execution requirements; however, in the event
our derivative transactions potentially become subject to such requirements, we believe that our derivative transactions
would qualify for the “end-user” exception. New or modified rules, regulations or requirements may increase the
cost and availability to our counterparties of their hedging and swap positions that they can make available to us, and
may further require the counterparties to our derivative instruments to spin off some of their derivative activities to
separate entities that may not be as creditworthy as the current counterparties. In addition, for uncleared swaps, the
CFTC or federal banking regulators may require end-users to enter into credit support documentation or post margin
collateral. Any changes in the regulations of swaps may result in certain market participants deciding to curtail or cease
their derivative activities.
While many rules and regulations have been promulgated and are already in effect, other rules and regulations,
including the proposed margin rules, remain to be finalized or effectuated; therefore, the impact of those rules and
regulations on us is uncertain at this time. The Dodd-Frank Act, and the rules promulgated thereunder, could
(1) significantly increase the cost, or decrease the liquidity, of energy-related derivatives we use to hedge against
commodity price fluctuations (including through requirements to post collateral), (2) materially alter the terms of
derivative contracts, (3) reduce the availability of derivatives to protect against risks we encounter, and (4) increase
our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the
Dodd-Frank Act and applicable rules and regulations, our cash flow may become more volatile and less predictable,
which could adversely affect our ability to plan for and fund capital expenditures.
The loss of one or more of our large oil and natural gas purchasers could have an adverse effect on our operations.
For the year ended December 31, 2013, three purchasers individually accounted for 10% or more of our oil
and natural gas revenues and, in the aggregate, for 58% of such revenues. The loss of a large single purchaser could
adversely impact the prices we receive or the transportation costs we incur.
Estimating our reserves, production and future net cash flows is difficult to do with any certainty.
Estimating quantities of proved oil and natural gas reserves is a complex process. It requires interpretations of
available technical data and various assumptions, including assumptions relating to economic factors such as future
commodity prices, production costs, severance and excise taxes, capital expenditures and workover and remedial
costs, and the assumed effect of governmental rules and regulations. There are numerous uncertainties about when
a property may have proved reserves as compared to potential or probable reserves, particularly relating to our
tertiary recovery operations. Forecasting the amount of oil reserves recoverable from tertiary operations, and the
production rates anticipated therefrom, requires estimates, one of the most significant being the oil recovery
factor. Actual results most likely will vary from our estimates. Also, the use of a 10% discount factor for reporting
purposes, as prescribed by the SEC, may not necessarily represent the most appropriate discount factor, given
actual interest rates and risks to which our business, and the oil and natural gas industry in general, are subject. Any
significant inaccuracies in these interpretations or assumptions, or changes of conditions, could result in a
reduction of the quantities and net present value of our reserves.
2013 ANNUAL REPORTFORM 10-K PART I 30
The reserves data included in documents incorporated by reference represent estimates only. Quantities of proved
reserves are estimated based on economic conditions, including first-day-of-the-month average oil and natural
gas prices for the 12-month period preceding the date of the assessment. Our reserves and future cash flows may be
subject to revisions based upon changes in economic conditions, including oil and natural gas prices, as well
as due to production results, results of future development, operating and development costs, and other factors.
Downward revisions of our reserves could have an adverse effect on our financial condition and operating results.
Actual future prices and costs may be materially higher or lower than the prices and costs used in our estimates.
As of December 31, 2013, approximately 38% of our estimated proved reserves were undeveloped. Recovery of
undeveloped reserves requires significant capital expenditures and may require successful drilling operations. The
reserves data assumes that we can and will make these expenditures and conduct these operations successfully, but
these assumptions may not be accurate, and these expenditures and operations may not occur.
Significant acquisitions or other transactions could require substantial external capital and could change our risk
and property profile.
To finance acquisitions, we may need to substantially alter or increase our capitalization through the use of our
bank credit facility, the issuance of debt or equity securities, the sale of production payments, or by other means.
Such changes in capitalization could significantly affect our risk profile. Additionally, significant acquisitions or
other transactions can change the character of our operations and business. The character of the new properties may
be substantially different in operating or geological characteristics or geographic location from that of our
existing properties.
Our results of operations could be negatively affected as a result of goodwill impairments.
At December 31, 2013, the Company’s goodwill balance totaled $1.3 billion and represented approximately 10.9%
of our total assets. Goodwill is not amortized; rather it is tested for impairment annually during the fourth quarter
and when facts or circumstances indicate that the carrying value of the Company’s goodwill may be impaired,
requiring an estimate of the fair values of the reporting unit’s assets and liabilities. An impairment of goodwill could
significantly reduce earnings during the period in which the impairment occurs and would result in a
corresponding reduction to goodwill and equity. See Item 7, Management’s Discussion and Analysis of Financial
Condition and Results of Operations – Critical Accounting Policies and Estimates – Impairment Assessment of Goodwill.
We may lose executive officers or other key management personnel, which could endanger the future success of
our operations.
Our success depends to a significant degree upon the continued contributions of our executive officers and other
key management personnel. Our employees, including our executive officers, are employed at will and do not
have employment agreements. If one or more members of our management team dies, becomes disabled or
voluntarily terminates employment with us, there is no assurance that we will find a suitable or comparable
substitute. We believe that our future success depends, in large part, upon our ability to hire and retain highly skilled
managerial personnel. Competition for persons with these skills is intense, and we cannot assure that we will be
successful in attracting and retaining such skilled personnel. The loss of any of our management personnel could
adversely affect our operations.
A cyber incident could occur and result in information theft, data corruption, operational disruption, and/or
financial loss.
Our business has become increasingly dependent on digital technologies to conduct day-to-day operations,
including certain of our exploration, development and production activities. We depend on digital technology to
estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and
drilling information and in many other activities related to our business. Our technologies, systems and networks may
become the target of cyber attacks or information security breaches that could result in the disruption of our
business operations. For example, unauthorized access to our seismic data, reserves information or other proprietary
information could lead to data corruption, communication interruption, or other operational disruptions in our
drilling or production operations.
To date we have not experienced any material losses relating to cyber attacks, but there can be no assurance that
we will not suffer such losses in the future. As cyber threats continue to evolve, we may be required to expend
significant additional resources to continue to modify or enhance our protective measures or to investigate and
remediate any cyber vulnerabilities.
FORM 10-K PART IDENBURY RESOURCES INC. 31
Item 1B. Unresolved Staff Comments
There are no unresolved written SEC staff comments regarding our periodic or current reports under the
Securities Exchange Act of 1934 received 180 days or more before the end of the fiscal year to which this annual
report on Form 10-K relates.
Item 2. Properties
Information regarding the Company’s properties called for by this item is included in Item 1, Business and Properties –
Oil and Natural Gas Operations. We also have various operating leases for rental of office space, office and field
equipment, and vehicles. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of
Operations – Capital Resources and Liquidity – Off-Balance Sheet Agreements, and Note 11, Commitments and
Contingencies, to the Consolidated Financial Statements for the future minimum rental payments. Such information
is incorporated herein by reference.
Item 3. Legal Proceedings
We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses. While we
currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a
material adverse effect on our consolidated financial position or overall trends in results of operations or cash
flows, litigation is subject to inherent uncertainties. If an unfavorable ruling in one of these lawsuits or proceedings
were to occur, there exists the possibility of a material adverse impact on our net income in the period in which
the ruling occurs. We provide accruals for litigation and claims if we determine that we may have a range of legal
exposure that would require accrual.
Item 4. Mine Safety Disclosures
Not applicable.
2013 ANNUAL REPORTFORM 10-K PART I Item 5. Market for Registrant’s Common Equity,
Related Stockholder Matters and Issuer Purchases
of Equity Securities
Common Stock Trading Summary
The following table summarizes the high and low reported sales prices on days in which there were trades of
Denbury’s common stock on the New York Stock Exchange (“NYSE”) for each quarterly period for the last two fiscal
years. As of January 31, 2014, based on information from the Company’s transfer agent, American Stock Transfer
and Trust Company, the number of holders of record of Denbury’s common stock was 1,687. On February 27, 2014,
the last reported sale price of Denbury’s common stock, as reported on the NYSE, was $16.22 per share.
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
High
$ 19.11
19.48
18.55
19.44
2013
2012
Low
High
$ 16.50
16.68
16.90
15.98
$ 20.91
19.50
17.65
16.76
Low
$ 16.29
13.46
13.74
14.32
On January 28, 2014, the Board of Directors declared a dividend of $0.0625 per share on our common stock, to
stockholders of record at the close of business on February 25, 2014. While we currently expect to continue to pay a
regular quarterly dividend on our common stock, the declaration and payment of dividends are at the discretion of
our Board of Directors and will depend on our results of operations, financial condition, capital requirements, level of
indebtedness, and other factors deemed relevant by the Board of Directors. Our Bank Credit Agreement and senior
subordinated note indentures require us to meet certain financial covenants at the time dividend payments are made.
For further discussion, see Note 5, Long-Term Debt, to the Consolidated Financial Statements. Prior to 2014, we
had not historically paid dividends on our common stock. No unregistered securities were sold by the Company
during 2013.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
Month
October 2013
November 2013
December 2013
Total
Total Number
of Shares
Purchased (1)
7,567
18,636
4,801,979
4,828,182
Average
Price Paid
per Share
$ 18.83
19.11
16.22
Total Number of
Shares Purchased
as Part of Publicly
Announced Plans
or Programs
—
—
4,793,461
4,793,461
Approximate
Dollar Value of
Shares that May
Yet Be Purchased
Under the Plans
or Programs
(in millions)(2)
$ 109.3
250.0
422.3 (3)
(1) Stock repurchases during the fourth quarter of 2013 other than those under our common stock repurchase program were made in connection
with delivery by our employees of shares to us to satisfy their tax withholding requirements related to the vesting of restricted shares and the
exercise of stock appreciation rights.
(2) In October 2011, the Company’s Board of Directors approved a common stock repurchase program for up to $500 million of Denbury’s
common stock, which was increased by an additional $271.2 million in November 2012, $140.7 million in November 2013, and $250.0 million in
December 2013, for a total authorization under the program of $1.162 billion. The program has no pre-established ending date and may be
suspended or discontinued at any time. We are not obligated to repurchase any dollar amount or specific number of shares of our common
stock under the program.
(3) Amounts shown do not give effect to the repurchase of an additional 11.8 million shares of Denbury common stock from January 1, 2014 through
February 20, 2014 under the share repurchase program for $191.6 million, or $16.17 per share.
Between early October 2011, when we announced the commencement of a common share repurchase program,
and December 31, 2013, we repurchased 47,559,266 shares of Denbury common stock (approximately 11.8% of our
outstanding shares of common stock at September 30, 2011) for $739.7 million, or $15.55 per share.
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Share Performance Graph
The following Performance Graph and related information shall not be deemed “soliciting material” or to be
“filed” with the SEC, nor shall such information be incorporated by reference into any future filings under the
Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company
specifically incorporates it by reference into such filings.
The following graph illustrates changes over the five-year period ended December 31, 2013, in cumulative total
stockholder return on our common stock as measured against the cumulative total return of the S&P 500 Index
and the Dow Jones U.S. Exploration and Production Index. The graph tracks the performance of a $100 investment
in our common stock and in each index (with the reinvestment of all dividends for the index securities) from
December 31, 2008 to December 31, 2013.
Comparison of 5-Year Cumulative Total Return
$240
$220
$200
$180
$160
$140
$120
$100
$80
12/08
12/09
12/10
12/11
12/12
12/13
Denbury Resources Inc.
S&P 500
Dow Jones U.S. Exploration and Production
$ 100.00
100.00
100.00
$ 135.53
126.46
140.56
$ 174.82
145.51
164.09
$ 138.28
148.59
157.22
$ 148.35
172.37
166.37
$ 150.46
228.19
219.35
2008
2009
2010
2011
2012
2013
December 31,
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Item 6. Selected Financial Data
In thousands, except per-share data or otherwise noted
2013
2012
2011
2010 (1)
2009
Year Ended December 31,
$ 2,466,234
50,893
$ 2,517,127
Consolidated Statements of Operations data:
Revenues and other income:
Oil, natural gas, and related product sales
Other
Total revenues and other income
Net income (loss) attributable to Denbury
stockholders
Net income (loss) per common share:
Basic
Diluted
Weighted average number of common shares outstanding:
Basic
Diluted
366,659
369,877
1.12
1.11
409,597
$ 2,409,867
46,605
$ 2,456,472
$ 2,269,151
40,173
$ 2,309,324
$ 1,793,292
128,499
$ 1,921,791
$ 866,709
22,441
$ 889,150
525,360
573,333
271,723
(75,156)
1.36
1.35
1.45
1.43
0.73
0.72
(0.30)
(0.30)
385,205
388,938
396,023
400,958
370,876
376,255
246,917
246,917
Consolidated Statements of Cash Flows data:
Cash provided by (used by):
Operating activities
Investing activities
Financing activities
Production (average daily):
Oil (Bbls)
Natural gas (Mcf)
BOE (6:1)
Unit sales prices –
excluding impact of derivative settlements:
Oil (per Bbl)
Natural gas (per Mcf)
Unit sales prices –
including impact of derivative settlements:
Oil (per Bbl)
Natural gas (per Mcf)
Costs per BOE:
Lease operating expenses (2)
Taxes other than income
General and administrative expenses
Depletion, depreciation and amortization
Proved oil and natural gas reserves: (3)
Oil (MBbls)
Natural gas (MMcf)
MBOE (6:1)
Proved carbon dioxide reserves:
Gulf Coast region (MMcf) (4)
Rocky Mountain region (MMcf) (5)
Proved helium reserves associated with
Denbury’s production rights: (6)
Rocky Mountain region (MMcf)
Consolidated Balance Sheets data:
Total assets
Total long-term liabilities
Stockholders’ equity
$ 1,361,195
(1,275,309)
(172,210)
$ 1,410,891
(1,376,841)
45,768
$ 1,204,814
(1,605,958)
37,968
$ 855,811
(354,780)
(139,753)
$ 530,599
(969,714)
442,637
66,286
23,742
70,243
100.67
3.53
100.64
3.53
28.50
6.87
5.66
19.89
$
$
$
66,837
29,109
71,689
97.18
3.05
96.77
5.67
20.29
6.10
5.49
19.34
60,736
29,542
65,660
100.03
4.79
98.90
7.34
21.17
6.16
5.24
17.07
$
$
$
$
$
$
59,918
78,057
72,927
36,951
68,086
48,299
$
$
$
75.97
4.63
71.69
6.45
17.67
4.53
5.04
16.32
$
$
$
57.75
3.54
68.63
3.54
17.85
2.45
5.77
13.52
386,659
489,954
468,318
329,124
481,641
409,398
357,733
625,208
461,934
338,276
357,893
397,925
192,879
87,975
207,542
6,070,619
3,272,428
6,073,175
3,495,534
6,685,412
2,195,534
7,085,131
2,189,756
6,302,836
—
13,251
12,712
12,004
7,159
—
$ 11,788,737
5,812,132
5,301,406
$ 11,139,342
5,408,032
5,114,889
$ 10,184,424
4,716,659
4,806,498
$ 9,065,063
4,105,011
4,380,707
$ 4,269,978
1,903,951
1,972,237
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(1) On March 9, 2010, we acquired Encore Acquisition Company (“Encore”). We consolidated Encore’s results of operations beginning March 9, 2010.
(2) Lease operating expenses for the year ending December 31, 2013 include estimated costs to remediate an area of Delhi Field. Excluding these costs,
lease operating expenses totaled $616.6 million and lease operating expense per BOE averaged $24.05 for the year ended December 31, 2013.
(3) Estimated proved reserves as of December 31, 2012 reflect the disposition of reserves associated with our Bakken area assets sold in late 2012
(approximately 109 MMBOE). Year-end 2012 reserves reflect CCA reserves acquired in 2010 as part of the Encore merger, but do not include
then-estimated reserves of approximately 42.2 MMBOE related to the CCA Acquisition, which closed during the first quarter of 2013. See Note 2,
Acquisitions and Divestitures, to the Consolidated Financial Statements for further discussion of these transactions.
(4) Proved CO2 reserves in the Gulf Coast region consist of reserves from our reservoirs at Jackson Dome and are presented on a gross or 8/8ths
working interest basis, of which our net revenue interest was approximately 4.8 Tcf, 4.8 Tcf, 5.3 Tcf, 5.6 Tcf and 5.0 Tcf at December 31, 2013, 2012,
2011, 2010 and 2009, respectively, and include reserves dedicated to volumetric production payments of 28.9 Bcf, 57.1 Bcf, 84.7 Bcf, 100.2 Bcf
and 127.1 Bcf at December 31, 2013, 2012, 2011, 2010 and 2009, respectively. (See Supplemental CO2 and Helium Disclosures (Unaudited), to the
Consolidated Financial Statements.)
(5) Proved CO2 reserves in the Rocky Mountain region consist of our reserves at Riley Ridge (presented on a gross working interest basis) and our
overriding royalty interest in LaBarge Field, of which our net revenue interest was approximately 2.9 Tcf, 2.9 Tcf, 1.6 Tcf and 0.9 Tcf at December 31,
2013, 2012, 2011 and 2010, respectively.
(6) Reserves associated with helium production rights include helium reserves located in the acreage in the Rocky Mountain region for which we have
the contractual right to extract the helium on behalf of the U.S. government, who owns the helium. Our extraction agreement with the U.S.
government gives us the ability to produce the helium on behalf of the U.S. government in exchange for a fee, which amount fluctuates based upon
the realized sales proceeds we receive for the helium. The estimate of helium reserves is reduced to reflect the estimated fee we will remit to the
U.S. government. Our extraction agreement with the U.S. government has a minimum term extending 20 years from first production and continuing
thereafter until either party terminates the contract. Reserve volumes presented herein assume that the term of this helium extraction agreement
continues beyond 20 years, given the benefit to both parties to the agreement.
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Item 7. Management’s Discussion and Analysis
of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements
and Notes thereto included in Item 8, Financial Statements and Supplementary Information. Our discussion and
analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction
with Risk Factors under Item 1A of this Form 10-K, along with Forward-Looking Information at the end of this section
for information on the risks and uncertainties that could cause our actual results to be materially different from our
forward-looking statements.
OVERVIEW
Denbury is a growing, dividend-paying, domestic oil and natural gas company. Our primary focus is on enhanced
oil recovery utilizing CO2, and our operations are focused in two key operating areas: the Gulf Coast and Rocky
Mountain regions. Our goal is to increase the value of acquired properties through a combination of exploitation,
drilling and proven engineering extraction practices, with the most significant emphasis relating to tertiary
recovery operations.
Adoption of Growth and Income Strategy. In the fourth quarter of 2013, following a comprehensive review of our
long-term plans, we announced our intention to expand our shareholder value proposition to include both growth
and income. Our focused strategy, significant inventory of development projects and proven track record of value
creation give us confidence that we can deliver a long-term cash flow profile to stockholders that is unique among
independent oil companies. To enable our shift to a growth and income company in 2014, we modified our previous
development timeline for future capital projects principally in the Rocky Mountain region, making our anticipated
capital spending levels more consistent over the next five to ten years. This smoothing effect on our anticipated
capital expenditures allows us to accelerate our expected free cash flow. These changes reduce our capital spending
on major infrastructure projects over the next few years, accelerating our plan of providing a return to our
shareholders through a dividend, while still growing our oil and natural gas reserves and production at nearly the
previously anticipated growth rate.
With the declaration of the first cash dividend in our history on January 28, 2014, we have begun this program of
distributing free cash flow to stockholders. Our first quarterly dividend of $0.0625 per common share (a rate of
$0.25 per share on an annualized basis) will be paid on March 25, 2014 to shareholders of record as of the close of
business on February 25, 2014. Based on our current financial projections and commodity price outlook, we expect
to grow our regular annual dividend rate to between $0.50 per share and $0.60 per share in 2015 and at a sustainable
rate thereafter. All dividends are subject to declaration by Denbury’s Board of Directors.
2013 Operating Highlights. Our net income was $409.6 million, or $1.11 per diluted common share, during 2013,
compared to net income of $525.4 million, or $1.35 per diluted common share, during 2012. Although we had a
$56.4 million increase in oil and natural gas revenues in 2013 compared to 2012 levels, driven by higher realized
prices, this increase in revenues was more than offset by increases in expenses, including (1) a $198.2 million
increase in lease operating expense in the current year, $114.0 million of which constitutes remediation costs incurred
or estimated for an area of Delhi Field, (2) an increase of $45.9 million in commodity derivatives expense, $27.3
million of which relates to a change in the noncash fair value adjustments on our commodity derivatives, a non-GAAP
measure, between the two periods and (3) a $44.7 million loss on early extinguishment of debt. These matters
are further described throughout this Management’s Discussion and Analysis. Our cash flow from operations was
$1.4 billion in both 2013 and 2012.
During 2013, our oil and natural gas production, which was 94% oil, averaged 70,243 BOE/d, compared to
71,689 BOE/d produced during 2012. This slight decline in production was primarily due to the inclusion of 11 months
of production in 2012 from the Bakken area assets sold in the Bakken Exchange Transaction (defined below), versus
only nine months of production in 2013 from the purchase of additional interests in the Cedar Creek Anticline (“CCA”).
This decline was offset in part by a 9% increase in our tertiary oil production. See Results of Operations –
Production for more information.
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Our average realized oil price per barrel, excluding the impact of commodity derivative contracts, was $100.67 per
Bbl during 2013, or about 4% higher than our average realized oil price of $97.18 per Bbl during 2012. Our realized
oil price during 2013 was $2.62 per Bbl above NYMEX oil prices compared to $2.99 per Bbl above NYMEX oil prices
in 2012. The lower premium to NYMEX in 2013 is primarily due to a decline in Louisiana Light Sweet (“LLS”) oil
pricing relative to NYMEX prices, which LLS-to-NYMEX differential averaged a positive $11.10 in 2013 compared
to positive $16.46 in 2012, partially offset by improved differentials in the Rocky Mountain region, which
were positively impacted by the sale of the Bakken area assets late in 2012, which assets generally sold at a more
significant discount to NYMEX than the CCA assets we acquired in early 2013. See Results of Operations – Oil and
Natural Gas Revenues below for more information.
Cedar Creek Anticline Acquisition. On March 27, 2013, we closed our acquisition of producing assets in the CCA
of Montana and North Dakota in a purchase from a wholly-owned subsidiary of ConocoPhillips Company
(“ConocoPhillips”) for $1.0 billion in cash, after final closing adjustments (the “CCA Acquisition”). We funded the
acquisition with a portion of the cash proceeds from the late-2012 Bakken Exchange Transaction. The assets
purchased include both additional interests in certain of our then-existing operated fields in CCA, as well as
operating interests in other CCA fields. In conjunction with this acquisition, we added 42.2 MMBOE of estimated
proved reserves.
Rocky Mountain Tertiary Operations Startup. In late 2012, we completed construction of the first section of the
20-inch Greencore Pipeline in Wyoming, our first CO2 pipeline in the Rocky Mountain region, and received our first
CO2 deliveries from the Lost Cabin gas plant in central Wyoming during the first quarter of 2013. In December 2012,
we completed the three-mile CO2 pipeline required to deliver CO2 from our source at LaBarge Field to Grieve Field
in Wyoming, and began injecting CO2 into Grieve Field during the first quarter of 2013. We currently expect tertiary
production from Grieve Field to commence in 2015. We started injections at our Bell Creek Field in Montana during
the second quarter of 2013, with the first tertiary oil production from this field during the third quarter of 2013.
During the first quarter of 2014, we completed the pipeline interconnect between a third party’s existing CO2 pipeline
and our Greencore pipeline, which will allow us to transport additional volumes of CO2 to Bell Creek Field.
Riley Ridge Plant. During the fourth quarter of 2013, we placed our Riley Ridge gas processing facility in Wyoming
into service.
Proved Oil and Natural Gas Reserves. Our estimated proved oil and gas reserves were 468.3 MMBOE as of
December 31, 2013, compared to 409.4 MMBOE at December 31, 2012. We added total proved reserves of 84.6 MMBOE
during 2013, including estimated proved tertiary reserves of 34.0 MMBbls at Bell Creek Field during the fourth
quarter, 42.2 MMBOE from the acquisition of additional interests in CCA during the first quarter and 8.4 MMBOE of
other additions or revisions.
Addition of Proved CO2 Reserves. During the year ended December 31, 2013, we added approximately 350 Bcf
of estimated proved CO2 reserves as a result of successful drilling in the Jackson Dome area, our primary source of
CO2 for the Gulf Coast region, replacing our 2013 CO2 production.
Debt Refinancing. In February 2013, we issued $1.2 billion of 4 5/8% Senior Subordinated Notes due 2023 (the
“2023 Notes”). The net proceeds of approximately $1.18 billion were used to repurchase or redeem our 9½% Senior
Subordinated Notes due 2016 (the “9½% Notes”) and our 9¾% Senior Subordinated Notes due 2016 (the
“9¾% Notes”), and to pay down a portion of outstanding borrowings on our bank credit facility. We recognized a
loss associated with the redemption of our 9½% Notes and 9¾% Notes of $44.7 million during the year ended
December 31, 2013, which is included in our Consolidated Statement of Operations under the caption “Loss on early
extinguishment of debt”. See Note 5, Long-Term Debt, to the Consolidated Financial Statements for additional details
surrounding the repurchase and redemption of our 9½% Notes and 9¾% Notes.
Delhi Field Release. In June 2013, a release of well fluids, consisting of a mixture of carbon dioxide, saltwater,
natural gas and oil, was discovered and reported within an area of the Denbury-operated Delhi Field located in
northern Louisiana. Denbury immediately took remedial action to stop the release and contain and recover well fluids
in the affected area. We have determined that the release originated from one or more wells in the affected area
of the field that we believed had been previously and properly plugged and abandoned by a prior operator of the field.
We completed our remediation efforts during the fourth quarter of 2013; however, we will continue to monitor the
area to ensure the remediation efforts were successful.
During the year ended December 31, 2013, we recorded $114.0 million of lease operating expenses related to this
release in our Consolidated Statement of Operations. These expenses represent our current estimate of the costs
related to the release, including remediation costs, based on actual costs incurred through December 31, 2013 of
approximately $92.0 million, plus the Company’s estimate of future costs related to the satisfaction of known claims
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and liabilities. Due to the possibility of new claims being asserted in the future in connection with the release,
as well as variability in the estimated cost to continue to monitor the area to ensure the remediation efforts were
successful, we cannot reliably determine at this time the full extent of the costs that may ultimately be incurred
by the Company related to this release. Although the Company maintains insurance policies that we believe cover
certain of the costs, damages and claims related to the release, and we currently and preliminarily estimate that
one-third to two-thirds of our current cost estimate may be recoverable under such insurance policies, we have not
reached any agreement with our insurance carriers as to recoverable amounts, and accordingly have not recognized
any insurance recoveries in our financial statements as of December 31, 2013. See Note 11, Commitments and
Contingencies, to the Consolidated Financial Statements for further discussion.
Costs incurred as a result of the release, together with lower production levels during the second half of 2013, are
currently expected to delay into 2014 the effective date of the approximate 25% reversionary interest to the third
party that sold the Delhi Field interest to us, the specific timing of which is dependent upon, among other things, the
amount and timing of any potential insurance proceeds received and their application to the calculation of “total
net cash flow” which determines the reversionary date, as well as oil prices, production, and production costs. We
currently estimate that the reversionary date could occur as late as the fourth quarter of 2014.
Bakken Exchange Transaction. In late 2012, we closed a sale and exchange transaction with Exxon Mobil
Corporation and its wholly-owned subsidiary XTO Energy Inc. (collectively, “ExxonMobil”) under which we sold to
ExxonMobil our Bakken area assets in North Dakota and Montana in exchange for (1) $1.3 billion in cash, (2) operating
interests in Hartzog Draw and Webster fields in Wyoming and Texas, respectively, and (3) an overriding royalty
interest equivalent to an approximate one-third ownership interest in ExxonMobil’s CO2 reserves in LaBarge Field in
Wyoming (the “Bakken Exchange Transaction”). The magnitude of the Bakken Exchange Transaction and the CCA
Acquisition discussed above impact the comparability of our 2012 and 2013 financial results in many ways,
including oil and natural gas production, revenues, and operating expenses. Our financial results for the year ended
December 31, 2013 include the results from the CCA Acquisition beginning late in the first quarter of 2013.
CAPITAL RESOURCES AND LIQUIDITY
Overview. Our primary sources of capital and liquidity are our cash flows from operations and borrowings under
our bank credit facility. Our business is capital intensive, and it is common for oil and natural gas companies our size
to reinvest most or all of their cash flow into developing new assets. We generally attempt to balance our capital
spending with cash flow from operations, and we have repurchased 59.4 million shares of our common stock
(approximately 14.8% of our outstanding shares at September 30, 2011) since commencement of our share repurchase
program in October 2011 through February 20, 2014. During 2013, we purchased $277.8 million of our common stock,
which was funded with a combination of cash flow from operations and incremental borrowings. In early 2013, we
refinanced two of our high-rate subordinated notes with ten-year notes carrying an interest rate of 4 5/8%, lowering
our interest expense and reducing our outstanding bank borrowings with a portion of the proceeds. We project that
we will have more than adequate capital resources and liquidity for the foreseeable future because (1) we have
refinanced our bank debt with low-cost subordinated debt, leaving significant borrowing capacity on our bank line;
(2) we have oil hedges in place for a substantial portion of our forecasted proven oil production for the next two
years, including fixed price swap derivative contracts for 2014 (see Note 9, Commodity Derivative Contracts, to the
Consolidated Financial Statements for further details regarding the prices and volumes of our commodity derivative
contracts); (3) we expect to fund our projected capital expenditures for the next few years with cash flow from
operations, which means that our expected growth in production and cash flow will gradually reduce our leverage
(assuming oil prices are relatively consistent with current levels); (4) we expect to fund our planned dividends
with cash flow from operations, (5) depending on the amount of shares of our common stock we repurchase in
2014, we might defer a portion of our planned 2014 capital expenditures, and (6) we can significantly reduce
our capital expenditures for extended periods of time if necessary and still maintain current production levels as a
result of our unique EOR operations.
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2014 Capital Spending. We anticipate that our 2014 capital budget, excluding acquisitions, will be $1.0 billion,
plus approximately $125 million in capitalized internal acquisition, exploration and development costs; capitalized
interest; and pre-production costs associated with new tertiary floods. This combined 2014 capital budget amount of
$1.125 billion, excluding acquisitions, is comprised of the following:
• $680 million allocated for tertiary oil field expenditures;
• $220 million allocated for other areas, primarily non-tertiary oil field expenditures;
• $60 million for pipeline construction;
• $40 million to be spent on CO2 sources; and
• $125 million for other capital items such as capitalized internal acquisition, exploration and development costs;
capitalized interest; and pre-production start-up costs associated with new tertiary floods.
Based on oil and natural gas commodity futures prices in early February 2014, our current production forecast, and
our fixed-price swaps covering a substantial portion of our anticipated 2014 production, we believe our anticipated
2014 cash flow from operations should be adequate to cover our combined 2014 capital budget and planned dividend
payments. If prices were to decrease or changes in operating results were to cause us to have a significant
reduction in anticipated 2014 cash flows, we have ample availability on our bank credit facility to cover any potential
shortfall, and we also have the ability to reduce our capital expenditures.
If we reduce our capital spending due to lower cash flows or to fund share repurchases, any sizeable reduction
could lower our anticipated production levels in future years. For 2014 and some future years, we have contracted for
certain capital expenditures; therefore, we cannot eliminate all of our capital commitments without penalties (see
Commitments and Obligations for further information regarding these commitments).
Stock Repurchase Program. Our Board of Directors has approved a common share repurchase program for
up to $1.162 billion of Denbury common stock. As of February 20, 2014, we had spent $931.2 million to repurchase
59.4 million shares of our common stock under this program. Our share repurchases are based on various
parameters and, therefore, may be less than the remaining approved balance under the program, for which there
is no set expiration date. We anticipate that repurchases during 2014 will be primarily funded with excess cash flow
from operations or with borrowings under our bank credit facility or a reduction in capital spend. See Note 7,
Stockholders’ Equity, to the Consolidated Financial Statements for further discussion.
Bank Credit Facility. We have a $1.6 billion bank credit facility that is secured by substantially all of our oil and
natural gas properties. As part of our semiannual bank review in late October 2013, the borrowing base for our bank
credit facility was reaffirmed at $1.6 billion. Our next borrowing base redetermination is scheduled on or around
May 1, 2014. We currently do not anticipate any reduction in our borrowing base as part of that redetermination, and
we believe, based on current commodity prices and our proved reserves, that we could obtain lender approval to
significantly increase the borrowing base under our bank credit facility above the current $1.6 billion level if we
desired to do so. As of February 21, 2014, we had $645.0 million outstanding under our $1.6 billion bank credit facility
and estimated cash of approximately $85.4 million, leaving us significant liquidity to fund capital expenditures and
future dividends.
2014 Commencement of Payment of Dividends. On January 28, 2014, our Board of Directors declared a dividend
of $0.0625 per share on our common stock, to stockholders of record at the close of business on February 25, 2014.
We expect this dividend payment to be approximately $22 million and to be paid on March 25, 2014. The declaration
and payment of future dividends is 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, and other factors deemed
relevant by the Board of Directors.
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Capital Expenditure Summary. The following table summarizes our 2013 capital expenditures by project area.
Amounts include accrued capital expenditures:
In thousands
Capital expenditures by project
Tertiary oil fields
Non-tertiary fields
Capitalized interest and internal costs (1)
Oil and natural gas capital expenditures
CO2 pipelines
CO2 sources (2)
CO2 capitalized interest and other
Capital expenditures before acquisitions
Less: recoveries from sale/leaseback transactions
Net capital expenditures excluding acquisitions
Property acquisitions (3)
Capital expenditures, net of sale/leaseback transactions
Year Ended December 31,
2013
2012
2011
$ 534,878
224,556
114,197
873,631
57,136
163,710
49,021
1,143,498
—
1,143,498
1,032,218
$ 2,175,716
$ 449,226
543,162
93,663
1,086,051
181,873
238,613
47,628
1,554,165
(35,102)
1,519,063
942,359
$ 2,461,422
$ 487,383
558,545
105,849
1,151,777
163,464
158,303
27,181
1,500,725
(70,332)
1,430,393
250,084
$ 1,680,477
(1) Includes capitalized internal acquisition, exploration and development costs; capitalized interest; and pre-production start-up costs associated
with new tertiary floods.
(2) Includes capital expenditures related to the Riley Ridge gas processing facility.
(3) Property acquisitions during the years ended December 31, 2013 and 2012 include capital expenditures of approximately $1.0 billion and
$0.2 billion, respectively, related to acquisitions during the period that are not reflected as an Investing Activity on our Consolidated Statements
of Cash Flows due to the movement of proceeds through a qualified intermediary to facilitate like-kind-exchange treatment under federal income
tax rules. In addition, property acquisitions in 2012 shown above include capital expenditures of approximately $0.6 billion representing the
aggregate fair value of net assets acquired, excluding cash, in the Bakken Exchange Transaction. See Note 2, Acquisitions and Divestitures, to the
Consolidated Financial Statements.
Our 2013 capital expenditures, other than those for property acquisitions, were funded with $1.4 billion of cash flow
from operations, and those for property acquisitions were funded with proceeds from the Bakken Exchange
Transaction. Our 2012 capital expenditures were funded primarily with $1.4 billion of cash flow from operations, and
our property acquisitions were funded with proceeds from the sale of non-core assets and the Bakken Exchange
Transaction. Our 2011 capital expenditures, excluding the Riley Ridge acquisition, were funded with $1.2 billion of
cash flow from operations and cash on hand at the beginning of the period. The Riley Ridge acquisition was
funded with incremental bank debt.
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Commitments and Obligations. A summary of our obligations at December 31, 2013 is presented in the
following table:
In thousands
2014
2015 and 2016
2017 and 2018
Thereafter
Total
Payments Due by Period
Contractual obligations:
Bank Credit Agreement
Estimated interest payments on bank credit
facility and subordinated debt
Subordinated debt
Operating lease obligations
Pipeline and capital lease obligations
Other obligations (1)
Commodity derivative liabilities (2)
Asset retirement obligations (3)
Total contractual obligations
$
—
$ 340,000
$
—
$
—
$ 340,000
174,491
1,072
11,695
62,929
168,938
53,822
5,307
$ 478,254
341,514
485
25,052
123,073
220,139
3,413
2,933
$ 1,056,609
326,535
2,250
25,504
106,159
193,609
—
107
$ 654,164
411,467
2,596,273
67,832
280,272
750,835
—
493,880
$ 4,600,559
1,254,007
2,600,080
130,083
572,433
1,333,521
57,235
502,227
$ 6,789,586
(1) Represents future cash commitments under contracts in place as of December 31, 2013, primarily for pipe, anthropogenic CO2 purchase contracts,
drilling rig services and well-related costs. As is common in our industry, we commit to make certain expenditures on a regular basis as part
of our ongoing development and exploration program. These commitments generally relate to projects that occur during the subsequent several
months and are usually part of our normal operating expenses or part of our capital budget (see 2014 Capital Spending above). In certain cases we
have the ability to terminate contracts for equipment or supplies, in which case we would be liable only for the cost incurred by the vendor up to
that point; however, as we currently do not anticipate canceling those contracts, these amounts include our estimated payments under those
contracts. We also have recurring expenditures for such things as accounting, engineering and legal fees; software maintenance; subscriptions; and
other overhead-type items. Normally these expenditures do not change materially on an aggregate basis from year to year and are part of our
general and administrative expenses. We have not attempted to estimate the amounts of these types of recurring expenditures in this table, as
most could be quickly canceled with regard to any specific vendor, even though the expense itself may be required for our ongoing normal
operations. Other obligations exclude approximately $980 million of potential costs for periods after 2017 to buy anthropogenic CO2 in accordance
with purchase contracts under which we may not become obligated, as construction of the plants which may emit CO2 has not yet begun.
(2) Commodity derivative liabilities represent the fair value of our commodity derivatives presented as liabilities in our Consolidated Balance Sheet as
of December 31, 2013. The ultimate settlement amounts of our derivative obligations are unknown because they are subject to continuing market
fluctuations. See further discussion of our commodity derivative contracts and their market price sensitivities in Market Risk Management below in
this Management’s Discussion and Analysis of Financial Condition and Results of Operations, and in Note 9, Commodity Derivative Contracts, to the
Consolidated Financial Statements.
(3) Represents the estimated future asset retirement obligations on an undiscounted basis. The present value of the discounted asset retirement
obligation is $126.3 million, as determined under the Asset Retirement and Environmental Obligations topic of the FASC, and is further discussed in
Note 3, Asset Retirement Obligations, to the Consolidated Financial Statements.
Off-Balance Sheet Arrangements. We have several operating leases relating to office space and other minor
equipment leases. At December 31, 2013, we had a total of $11.7 million of letters of credit outstanding under our
bank credit facility. Additionally, we have obligations that are not currently recorded on our balance sheet relating
to various obligations for development and exploratory expenditures that arise from our normal capital expenditure
program or from other transactions common to our industry. These obligations are further described in
Commitments and Obligations above. In addition, in order to recover our undeveloped proved reserves, we must also
fund the associated future development costs estimated in our proved reserve reports. For a further discussion
of our future development costs, see Supplemental Oil and Natural Gas Disclosures (Unaudited), to the Consolidated
Financial Statements.
FINANCIAL OVERVIEW OF TERTIARY OPERATIONS
As discussed in Item 1, Business and Properties – Oil and Natural Gas Operations – Enhanced Oil Recovery
Overview above, our tertiary operations represent a significant portion of our overall operations and have become our
primary strategic focus. The economics of a tertiary field and the related impact on our financial statements differ
from a conventional oil and gas play and are explained further below.
While it is difficult to accurately forecast future production, we believe our tertiary recovery operations provide
significant long-term production growth potential at reasonable rates of return, with relatively low risk. Our rate of
return from our tertiary operations has generally been higher than our rate of return on traditional oil and gas
operations. Generally, finding and development costs are lower and operating costs are higher than traditional oil
and gas operations. We have been developing tertiary oil properties for over 14 years, and the financial impact
of such operations is reflected in our historical financial statements. The summary below highlights our observations
regarding how tertiary operations have impacted our financial statements.
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Finding and Development Costs. We currently expect finding and development costs (including future
development and abandonment costs but excluding CO2 pipeline infrastructure capital expenditures) over the life of
each field to be lower than the industry average costs for other oil properties. See the definition of finding and
development costs in the Glossary and Selected Abbreviations.
Timing of Capital Costs. There is a significant delay between the initial capital expenditures on tertiary oil fields
and the resulting production increases. We must build facilities, and often a CO2 pipeline to the field, before CO2
flooding can commence, and it usually takes six to twelve months before the field responds to the injection of CO2
(i.e., oil production commences). Further, we may spend significant amounts of capital before we can recognize any
proved reserves from fields we flood and, even after a field has proved reserves, significant amounts of additional
capital will usually be required to fully develop the field.
Recognition of Proved Reserves. In order to recognize proved tertiary oil reserves, we must either demonstrate
production resulting from the tertiary process or the field must be analogous to an existing tertiary flood. The
magnitude of proved reserves that we can book in any given year will depend on our progress with new floods, the
timing of the production response from new floods and the performance of our existing floods. Typically, a
high percentage of the potential reserves for a tertiary field are recognized when a production response is initially
observed, and generally only modest increases are made thereafter.
Production Rates. The production growth rate at a tertiary flood can vary from quarter to quarter, as a tertiary
field’s production may increase rapidly when wells respond to the CO2, plateau temporarily, and then resume growth
as additional areas of the field are developed. During a tertiary flood life cycle, facility capacity is increased from time
to time, which occasionally requires temporary shutdowns during installation, thereby causing temporary declines
in production. We also find it difficult to precisely predict when any given well will respond to the injected CO2, as the
CO2 seldom travels through the rock consistently due to heterogeneity in the oil-bearing formations. We find all of
these fluctuations to be normal, and generally expect oil production at a tertiary field to increase over time until the
entire field is developed, albeit sometimes in inconsistent patterns.
Operating Costs. Tertiary projects may be more expensive to operate than traditional industry operations because
of the cost of injecting and recycling the CO2 (primarily due to the cost of the CO2 and the significant energy
requirements to re-compress the CO2 back into a near-liquid state for re-injection purposes). The costs of our CO2
and the electricity required to recycle and inject this CO2 comprise almost half of our typical tertiary operating
expenses. Since these costs vary along with commodity and commercial electricity prices, they are highly variable
and will increase in a high-commodity-price environment and decrease in a low-price environment. Most of our CO2
operating costs are allocated to our tertiary oil fields and recorded as lease operating expenses (following the
commencement of tertiary oil production) at the time the CO2 is injected. These costs have historically represented
approximately 20% to 25% of the total operating costs for our tertiary operations. Since we expense all of the
operating costs to produce and inject our CO2 (following the commencement of tertiary oil production), operating
costs per barrel for a new flood will be higher at the inception of CO2 injection projects because of minimal related oil
production at that time.
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RESULTS OF OPERATIONS
Operating Results Table
Certain of our operating results and statistics for each of the last three years are included in the following table.
In thousands, except per share and unit data
Operating results
Net income
Net income per common share – basic
Net income per common share – diluted
Net cash provided by operating activities
Average daily production volumes
Bbls/d
Mcf/d
BOE/d
Operating revenues
Oil sales
Natural gas sales
Total oil and natural gas sales
Commodity derivative contracts (1)
Cash receipt (payment) on settlements of commodity derivatives
Noncash fair value adjustments on commodity derivatives (2)
Commodity derivatives income (expense)
Unit prices – excluding impact of derivative settlements
Oil price per Bbl
Natural gas price per Mcf
Unit prices – including impact of derivative settlements (1)
Oil price per Bbl
Natural gas price per Mcf
Oil and natural gas operating expenses
Lease operating expenses (3)
Marketing expenses, net of third-party purchases
Production and ad valorem taxes
Oil and natural gas operating revenues and expenses per BOE
Oil and natural gas revenues
Lease operating expenses (3)
Marketing expenses, net of third-party purchases
Production and ad valorem taxes
CO2 sources – revenues and expenses
CO2 sales and transportation fees
CO2 discovery and operating expenses (4)
CO2 revenue and expenses, net
Year Ended December 31,
2013
2012
2011
$ 409,597
1.12
1.11
1,361,195
$ 525,360
1.36
1.35
1,410,891
$ 573,333
1.45
1.43
1,204,814
66,286
23,742
70,243
66,837
29,109
71,689
60,736
29,542
65,660
$ 2,435,625
30,609
$ 2,466,234
$ 2,377,337
32,530
$ 2,409,867
$ 2,217,529
51,622
$ 2,269,151
$
$
$
$
(662)
(40,362)
(41,024)
100.67
3.53
100.64
3.53
$
$
$
$
17,880
(13,046)
4,834
$
2,377
50,120
$ 52,497
97.18
3.05
$ 100.03
4.79
96.77
5.67
$
98.90
7.34
$ 730,574
37,754
162,791
$ 532,359
41,936
149,919
$ 507,397
26,047
139,170
$
96.19
28.50
1.47
6.35
$
91.85
20.29
1.60
5.71
$
94.68
21.17
1.09
5.81
$
$
27,950
(16,916)
11,034
$
$
26,453
(14,694)
11,759
$
$
22,711
(14,258)
8,453
(1) See also Market Risk Management below for information concerning our commodity derivative transactions.
(2) Noncash fair value adjustments on commodity derivatives is a non-GAAP measure and is different from “Commodity derivatives expense
(income)” in the Consolidated Statements of Operations in that the noncash fair value adjustments on commodity derivatives represents only the
net change between periods of the fair market values of commodity derivative positions, and excludes the impact of cash settlements on
commodity derivatives during the period, which were cash receipts (payments) on settlements of $(0.7) million, $17.9 million and $2.4 million for the
years ended December 31, 2013, 2012 and 2011, respectively. We believe that noncash fair value adjustments on commodity derivatives is a useful
supplemental disclosure to “Commodity derivatives expense (income)” in order to differentiate noncash fair market value adjustments from cash
settlements on commodity derivatives during the period. This supplemental disclosure is widely used within the industry and by securities
analysts, banks and credit rating agencies in calculating EBITDA and in adjusting net income to present those measures on a comparative basis
across companies, as well as to assess compliance with certain debt covenants. Noncash fair value adjustments on commodity derivatives is not a
measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for “Commodity
derivatives expense (income)” in the Consolidated Statements of Operations. See also the Glossary and Selected Abbreviations for the definition of
noncash fair value adjustments on commodity derivatives.
(3) Excluding estimated lease operating expenses recorded during 2013 to remediate an area of Delhi Field, lease operating expenses totaled
$616.6 million and lease operating expense per BOE averaged $24.05 for the year ended December 31, 2013.
(4) Includes $0.8 million, $9.5 million, and $7.5 million of exploratory costs incurred in 2013, 2012 and 2011, respectively.
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Production
Average daily production by area for 2013, 2012 and 2011, and for each of the quarters of 2013, is shown below:
Operating Area
Tertiary oil production
Gulf Coast region
Mature properties:
Brookhaven
Eucutta
Mallalieu
Other mature properties (1)
Total mature properties
Delhi
Hastings
Heidelberg
Oyster Bayou
Tinsley
Total Gulf Coast region
Rocky Mountain region
Bell Creek
Total Rocky Mountain region
Total tertiary oil production
Non-tertiary oil and gas production
Gulf Coast region
Mississippi
Texas
Other
Total Gulf Coast region
Rocky Mountain region
Cedar Creek Anticline (2)
Other
Total Rocky Mountain region
Total non-tertiary production
Total continuing production
Properties disposed:
Bakken area assets (3)
Non-core asset divestitures (4)
Total production
Average Daily Production (BOE/d)
2013 Quarters
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
Year Ended December 31,
2013
2012
2011
2,305
2,636
2,116
7,800
14,857
5,827
3,956
3,943
2,252
8,222
39,057
—
—
39,057
3,013
6,692
1,153
10,858
8,745
5,163
13,908
24,766
63,823
—
—
63,823
2,339
2,642
2,157
7,233
14,371
5,479
4,010
4,149
2,518
8,225
38,752
—
—
38,752
2,367
6,932
1,108
10,407
19,935
4,958
24,893
35,300
74,052
2,224
2,504
2,042
6,761
13,531
4,517
3,699
4,553
3,213
7,951
37,464
49
49
37,513
2,692
6,548
1,087
10,327
18,872
4,819
23,691
34,018
71,531
2,026
2,280
1,886
6,287
12,479
4,793
4,270
5,206
3,869
7,809
38,426
177
177
38,603
2,711
5,994
1,041
9,746
18,601
4,516
23,117
32,863
71,466
2,223
2,514
2,050
7,016
13,803
5,149
3,984
4,466
2,968
8,051
38,421
56
56
38,477
2,695
6,540
1,097
10,332
16,572
4,862
21,434
31,766
70,243
2,692
2,868
2,338
7,707
15,605
4,315
2,188
3,763
1,388
7,947
35,206
—
—
35,206
3,930
4,737
1,235
9,902
8,503
3,231
11,734
21,636
56,842
3,255
3,121
2,693
8,955
18,024
2,739
—
3,448
5
6,743
30,959
—
—
30,959
5,486
4,133
1,336
10,955
8,968
2,968
11,936
22,891
53,850
—
—
74,052
—
—
71,531
—
—
71,466
—
—
70,243
14,395
452
71,689
9,340
2,470
65,660
(1) Other mature properties include Cranfield, Little Creek, Lockhart Crossing, Martinville, McComb and Soso fields.
(2) Beginning March 27, 2013, amounts include production from our purchase of additional interests in the CCA on that date.
(3) Includes production from certain Bakken area assets sold in the fourth quarter of 2012.
(4) Includes production from certain non-core Gulf Coast assets sold in late February 2012 and certain non-operated assets in the Greater Aneth
Field in the Paradox Basin of Utah sold in April 2012.
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Total Production
We closed on our Bakken Exchange Transaction late in 2012 and utilized the proceeds from that transaction to
purchase additional interests in CCA in late March 2013. Accordingly, total production decreased 1,446 BOE/d (2%)
between 2012 and 2013, primarily due to the inclusion in 2012 of 11 months of production from our Bakken area
assets, compared to the inclusion of only nine months of additional CCA production in our 2013 results. This
decline in production due to timing of transactions was partially offset by a 9% increase in tertiary production.
Total production increased 6,029 BOE/d (9%) between 2011 and 2012. The increases were primarily due to
production increases from our tertiary oil fields and increases from our Bakken area assets (which were sold late in
the fourth quarter of 2012), offset by normal declines in most of our other non-tertiary properties.
Our production during 2013 was 94% oil compared to 93% for 2012 and 2011. The slight increase in oil production
percentage in 2013 is due to increases in our tertiary production, which is primarily oil, as well as the sale of
our Bakken area assets, which had a higher percentage of natural gas production than the CCA assets acquired.
Tertiary Production
Oil production from our tertiary operations increased to record levels during 2013, averaging 38,477 Bbls/d, a
9% increase over our 2012 tertiary production level of 35,206 Bbls/d, primarily due to production growth in response
to continued field development and expansion of facilities in our tertiary floods at Delhi, Hastings, Heidelberg
and Oyster Bayou fields. Offsetting these 2013 production gains were production declines in our more mature
tertiary fields. Tertiary production during the fourth quarter of 2013 increased 3% over third-quarter levels,
largely due to continued production growth at Heidelberg and Oyster Bayou fields, the completion of planned
maintenance activities at Hastings Field, and increased CO2 injections into areas surrounding the impacted area of
Delhi Field (see Overview – Delhi Field Release and Note 11, Commitments and Contingencies, to the Consolidated
Financial Statements for further discussion of this matter). We started injections at our Bell Creek Field in
Montana during the second quarter of 2013, with the first tertiary oil production from this field during the third
quarter of 2013. The ramp up of production at Bell Creek Field has been slower than anticipated due to the
delayed completion of a CO2 pipeline interconnect originally scheduled for the fourth quarter of 2013 and the
interruptions in CO2 delivery from the Lost Cabin gas plant. With the completion of the pipeline interconnect
during the first quarter of 2014, we have increased CO2 injections at Bell Creek Field and expect production at the
field to increase at a faster pace during 2014.
Oil production from our tertiary operations averaged 35,206 Bbls/d during 2012, a 14% increase over our 2011
tertiary production level of 30,959 Bbls/d, primarily due to production growth in response to continued expansion of
the tertiary floods at Tinsley and Delhi fields and production at our Oyster Bayou and Hastings fields, which
experienced their initial tertiary production response in late December 2011 and early January 2012, respectively.
Offsetting 2012 tertiary production gains were declines in our more mature tertiary fields.
Non-Tertiary Production
Continuing production from our non-tertiary operations, which excludes production from our Bakken and other
non-core assets divested during 2012, increased to an average of 31,766 BOE/d during 2013, an increase of 10,130
BOE/d (47%) compared to 2012 continuing production levels. The non-tertiary continuing production increases were
primarily due to production from newly acquired fields, specifically the additional interests in CCA acquired in
March 2013, Webster and Hartzog Draw fields acquired in the Bakken Exchange Transaction in late 2012, and
Thompson Field acquired in June 2012. With the exception of the impact of the production added from fields acquired
during 2012 and 2013, production from our other non-tertiary properties is generally on decline, and in some
instances the decline is pronounced due to the expansion of our tertiary floods, which causes non-tertiary production
to be shut in for a period while the field is being pressured up. Continuing production from our non-tertiary
operations during the fourth quarter of 2013 decreased 3% from third-quarter levels, partially due to severe weather-
related issues during the fourth quarter. Continuing production from our non-tertiary operations decreased 5%
from 2011 to 2012, due primarily to non-tertiary oil production declines as a result of the expansion of our tertiary
floods in those areas. These declines were partially offset by production from acquisitions during 2012, which
increased our production in Texas.
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Oil and Natural Gas Revenues
Oil and natural gas revenues increased in each of the past two years. The increase in oil and natural gas revenues
in 2013 was the result of increases in commodity prices, slightly offset by a small decline in production, whereas
the increase in oil and natural gas revenues in 2012 was attributable to higher production volumes, slightly offset by
a decline in commodity prices. The changes in revenues due to these factors, excluding any impact of our
commodity derivative contracts, are reflected in the following table:
In thousands
Change in revenues due to:
Year Ended December 31,
2013 vs. 2012
Year Ended December 31,
2012 vs. 2011
Increase
(Decrease) in
Revenues
Percentage
Increase
(Decrease) in
Revenues
Increase
(Decrease) in
Revenues
Percentage
Increase
(Decrease) in
Revenues
Increase (decrease) in production
Increase (decrease) in commodity prices
Total increase in oil and natural gas revenues
$ (55,065)
111,432
$ 56,367
(2)%
4%
2%
$ 215,150
(74,434)
$ 140,716
9%
(3)%
6%
Excluding any impact of our commodity derivative contracts, our net realized commodity prices and NYMEX
differentials were as follows during 2013, 2012 and 2011:
Net realized prices:
Oil price per Bbl
Natural gas price per Mcf
Price per BOE
NYMEX differentials:
Oil per Bbl
Natural gas per Mcf
Year Ended December 31,
2013
2012
2011
$ 100.67
3.53
96.19
$ 97.18
3.05
91.85
$ 100.03
4.79
94.68
$ 2.62
(0.19)
$ 2.99
0.23
$ 4.95
0.76
As reflected in the table above, our average net realized oil price increased 4% during 2013 compared to the
average price received during 2012. Company-wide average oil price differentials were $2.62 per Bbl above NYMEX
in 2013, compared to an average differential of $2.99 per Bbl above NYMEX in 2012 and $4.95 per Bbl above
NYMEX in 2011. During 2013, we sold approximately 46% of our crude oil at prices based on the LLS index price,
approximately 23% at prices partially tied to the LLS index price, and the balance at prices based on various other
indexes tied to NYMEX prices, primarily in the Rocky Mountain region. The net differential we received was primarily
impacted by positive differentials in the Gulf Coast region, offset by unfavorable differentials in the Rocky Mountain
region, each of which is discussed in further detail below.
We received favorable NYMEX differentials in the Gulf Coast region during 2013, 2012 and 2011, primarily due to
the favorable differential for crude oil sold under LLS index prices. During 2013, the quarterly average LLS-to-NYMEX
differential (on a trade-month basis) decreased in each quarter of 2013, from the first quarter average of $20.15
per Bbl to $2.58 per Bbl in the fourth quarter. In 2012 and 2011, the quarterly average LLS-to-NYMEX differential (on a
trade-month basis) ranged from a positive $9.28 per Bbl to $23.36 per Bbl.
NYMEX oil differentials in the Rocky Mountain region during 2013 were $8.10 per Bbl below NYMEX compared to
an average differential of $11.86 per Bbl below NYMEX in 2012. The change in the differential between 2012 and 2013
was largely impacted by the sale of our Bakken area assets in the fourth quarter of 2012, since oil from the Bakken
area assets generally sold at a higher discount to NYMEX than the CCA production acquired in early 2013.
Prices received in a regional market fluctuate frequently and can differ from NYMEX pricing due to a variety of
reasons, including supply and/or demand factors and location differentials. During the fourth quarter of 2013,
we observed a decline in the favorable LLS-to-NYMEX differential and a widening of the Rocky Mountain differential,
causing our overall NYMEX oil differential to be a negative $4.57 per Bbl in the fourth quarter of 2013. This
quarterly negative differential is the widest we have experienced in several years. Although we have seen the LLS
and Rocky Mountain differentials improve somewhat in early 2014, we do not expect the LLS-to-NYMEX differential
to return to more favorable levels we have experienced during the last few years due to the oil transportation
capacity that has been added, which allows more oil production access to the LLS market.
Our natural gas NYMEX differentials are generally caused by movement in the NYMEX natural gas prices during
the month, as most of our natural gas is sold on an index price that is set near the first of each month. While the
percentage change in NYMEX natural gas differentials can be quite large, these differentials are very seldom more
than a dollar above or below NYMEX prices.
Commodity Derivative Contracts
From time to time, we enter into oil and natural gas derivative contracts to provide an economic hedge of our
exposure to commodity price risk associated with anticipated future oil and natural gas production. These contracts
have consisted of price floors, collars and fixed price swaps. The following table summarizes the impact our oil and
natural gas derivative contracts had on our operating results for 2013, 2012 and 2011:
In thousands
2013
2012
2011
2013
2012
2011
Non-Cash Fair Value Gain/(Loss) (1)
Cash Settlements Receipt/(Payment)
Crude oil derivative contracts:
First quarter
Second quarter
Third quarter
Fourth quarter
Full Year
Natural gas derivative contracts:
First quarter
Second quarter
Third quarter
Fourth quarter
Full Year
$ (11,929)
45,501
(79,784)
5,854
$ (40,358)
$
$
—
—
—
(4)
(4)
Total commodity derivative contracts:
First quarter
Second quarter
Third quarter
Fourth quarter
Full Year
$ (11,929)
45,501
(79,784)
5,850
$ (40,362)
$ (42,445)
140,923
(60,726)
(26,848)
$ 10,904
$ (1,640)
(9,096)
(7,174)
(6,040)
$ (23,950)
$ (44,085)
131,827
(67,900)
(32,888)
$ (13,046)
$ (167,064)
187,194
205,355
(166,505)
$ 58,980
$
$
(5,274)
(3,348)
229
(467)
(8,860)
$ (172,338)
183,846
205,584
(166,972)
$ 50,120
$ —
—
(662)
—
$ (662)
$ —
—
—
—
$ —
$ —
—
(662)
—
$ (662)
$ (8,230)
(709)
(641)
(411)
$ (9,991)
$ 7,040
7,991
6,910
5,930
$ 27,871
$ (1,190)
7,282
6,269
5,519
$ 17,880
$ (5,028)
(16,972)
(1,857)
(1,271)
$ (25,128)
$ 6,616
6,030
6,427
8,432
$ 27,505
$ 1,588
(10,942)
4,570
7,161
$ 2,377
(1) Noncash fair value adjustments on commodity derivatives is a non-GAAP measure. A reconciliation of noncash fair value adjustments on
commodity derivatives to “Commodity derivatives expense (income)” is included in the Operating Results Table above. See also the Glossary and
Selected Abbreviations for the definition of noncash fair value adjustments on commodity derivatives.
Changes in commodity prices and the expiration of contracts cause fluctuations in the estimated fair value of our
oil and natural gas derivative contracts. Because we do not utilize hedge accounting for our commodity derivative
contracts, the period-to-period changes in the fair value of these contracts, as outlined above, are recognized in our
statements of operations. The detail of our outstanding commodity derivative contracts at December 31, 2013 is
included in Note 9, Commodity Derivative Contracts, to the Consolidated Financial Statements.
Production Expenses
Lease operating expense
In thousands, except per BOE data
Lease operating expense
Tertiary – excluding Delhi Field remediation
Tertiary – Delhi Field remediation
Non-tertiary
Total lease operating expense
Lease operating expense per BOE
Tertiary – excluding Delhi Field remediation
Tertiary – Delhi Field remediation
Non-tertiary
Total lease operating expense per BOE (1)
Year Ended December 31,
2013
2012
2011
$ 358,281
114,000
258,293
$ 730,574
$ 25.51
8.12
22.28
28.50
$ 307,686
—
224,673
$ 532,359
$ 23.88
—
16.83
20.29
$ 272,066
—
235,331
$ 507,397
$ 24.08
—
18.58
21.17
(1) Excluding estimated lease operating expenses recorded during the year ended December 31, 2013 to remediate an area of Delhi Field, total lease
operating expense per BOE averaged $24.05. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations –
Overview – Delhi Field Release, and Note 11, Commitments and Contingencies, to the Consolidated Financial Statements for further discussion
of this matter.
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Total lease operating expense during 2013 increased on an absolute-dollar and per-BOE basis from 2012 primarily
due to $114.0 million in incurred and estimated lease operating expenses recorded for the costs to remediate an area
of Delhi Field impacted by a release of well fluids discovered during the second quarter (see Item 7, Management’s
Discussion and Analysis of Financial Condition and Results of Operations – Overview – Delhi Field Release, and Note 11,
Commitments and Contingencies, to the Consolidated Financial Statements). Excluding these incurred and estimated
remediation expenses, lease operating expense increased $84.2 million (16%) or $3.76 per BOE during 2013 compared
to 2012 levels due primarily to increased expenses resulting from the expansion of our tertiary floods, including our
new tertiary flood at Bell Creek Field; increases in the cost and utilization of CO2 between the comparative periods;
and higher lease operating expenses at the fields we acquired in the Bakken Exchange Transaction relative to the
Bakken assets we sold. Lease operating expense increased 5% between 2011 and 2012 on an absolute-dollar basis
due to the expansion of our tertiary floods and decreased 4% on a per-BOE basis primarily due to the higher
production volumes in our tertiary floods and growth in our Bakken production, which had a relatively low operating
cost per barrel.
Excluding the incurred and estimated Delhi Field remediation expense, tertiary lease operating expense increased
$50.6 million (16%) or $1.63 per Bbl during 2013 compared to 2012. The increase was primarily a result of the
expansion of our tertiary floods, including our new tertiary flood at Bell Creek Field, and increased CO2 expenses due
to increases in the cost of CO2 and an increase in CO2 volumes injected into tertiary floods between years. During
2012, tertiary lease operating expense increased 13% on an absolute-dollar basis compared to 2011 levels, but
decreased slightly on a per-BOE basis. The decrease in tertiary operating costs per barrel was due to the 14% increase
in tertiary production, which more than offset the higher total tertiary operating expenses resulting from the increase
in the number of our active tertiary floods due to the tertiary floods at Hastings and Oyster Bayou fields. For any
specific field, we expect our tertiary lease operating expense per barrel to be high initially, as we experienced in 2013
with our Bell Creek flood, and then decrease as production increases, ultimately leveling off until production begins
to decline in the later life of the field, when operating expense per barrel will again increase. One of our most
substantial costs in our tertiary operations is our cost for fuel and utilities, averaging $6.64 per Bbl in 2013, $6.51 per
Bbl in 2012 and $6.31 per Bbl in 2011, which has increased on a per-barrel basis due to the higher cost of these items
and the continued expansion of our tertiary floods.
Currently, our CO2 expense comprises approximately one-fourth of our typical Gulf Coast tertiary operating
expenses, and for the CO2 reserves we already own, consists of our CO2 production expenses, and for the CO2
reserves we do not own, consists of our purchase of CO2 from royalty and working interest owners and
anthropogenic (man-made) sources. During the year ended December 31, 2013, approximately 69% of the CO2 utilized
in our Gulf Coast region CO2 floods consisted of CO2 owned and produced by us, and we purchased the
remaining portion from third-party owners (primarily royalty owners). The price we pay others for CO2 varies by
source and is generally indexed to oil prices. When combining the production cost of the CO2 we own with what
we pay third parties for CO2, our average cost of CO2 for the Gulf Coast region during 2013 was approximately
$0.33 per Mcf, including taxes paid on CO2 production but excluding depletion and depreciation of capital expended
at our Jackson Dome source and CO2 pipelines. This rate during 2013 was higher than the $0.26 per Mcf spent during
2012 and 2011 primarily due to higher oil prices (to which the cost of CO2 is partially tied) and increased volumes
purchased from anthropogenic sources during 2013, which volumes have a higher purchase price but require a
smaller capital outlay than CO2 we obtain from the Jackson Dome area. Including depletion expense related to the
Jackson Dome CO2 production, but excluding depreciation of our CO2 pipelines, our cost of CO2 was $0.42 per Mcf
in 2013, $0.33 per Mcf in 2012 and $0.31 per Mcf in 2011.
Non-tertiary lease operating expense increased 15% on an absolute-dollar basis during 2013, compared to the prior
year period, as declines resulting from the sale of our Bakken area assets were more than offset by increases in
newly acquired fields, including Thompson field acquired in the second quarter of 2012, Webster and Hartzog Draw
fields acquired in the Bakken Exchange Transaction in late 2012, and additional interests in CCA acquired in the
first quarter of 2013. On a per-BOE basis, non-tertiary lease operating expense increased 32% from 2012 to 2013 due
to increases in newly acquired fields, which have a higher per-BOE operating cost than the properties disposed in
the Bakken Exchange Transaction. Non-tertiary lease operating expense decreased 5% on an absolute-dollar basis
and decreased 9% on a per-BOE basis during 2012 compared to 2011. The lower operating expense per BOE was
largely driven by increased production related to our Bakken area assets (which had lower operating costs than our
other properties), and the sale of certain non-core assets during the first half of 2012, which had a higher operating
cost per BOE compared to the average of our other properties.
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Taxes other than income
Taxes other than income includes ad valorem, production and franchise taxes. Taxes other than income increased
$16.2 million between 2012 and 2013 and increased $12.5 million between 2011 and 2012. The change in each period
is generally aligned with fluctuations in oil and natural gas revenues. The increase during 2013 is further impacted by
the change in the mix of properties subject to production and ad valorem taxes as a result of the Bakken Exchange
Transaction and CCA acquisition.
General and Administrative Expenses (“G&A”)
In thousands, except per BOE data and employees
Gross cash compensation and administrative costs
Gross stock-based compensation
Operator labor and overhead recovery charges
Capitalized exploration and development costs
Net G&A expense
G&A per BOE:
Net administrative costs
Net stock-based compensation
Net G&A expense
Employees as of December 31
Year Ended December 31,
2013
2012
2011
$ 324,580
42,091
(166,012)
(55,448)
$ 145,211
$
$
4.47
1.19
5.66
1,501
$ 296,696
37,897
(141,358)
(49,216)
$ 144,019
$ 246,112
39,875
(125,466)
(34,996)
$ 125,525
$
$
4.48
1.01
5.49
$
$
3.98
1.26
5.24
1,432
1,308
On an absolute-dollar basis, net G&A expense increased slightly between 2012 and 2013 and increased 15%
between 2011 and 2012 and on a per-BOE basis increased 3% between 2012 and 2013 and 5% between 2011 and 2012.
Gross cash compensation and administrative costs increased $27.9 million (9%) between 2012 and 2013 and $50.6
million (21%) between 2011 and 2012. The increase in both comparative periods is due to higher compensation-
related costs from increases in headcount, annual merit increases and other employee-related costs such as health
insurance. Employee bonus expense was relatively unchanged from 2012 to 2013 despite the 5% increase in
headcount, as bonuses were paid at a lower rate in 2013 than in 2012, but contributed to the increase in gross
administrative cost between 2011 and 2012.
Gross stock-based compensation costs increased in 2013 compared to 2012 due to the increased number of
employees during 2013 compared to 2012. The increase to gross stock-based compensation as a result of additional
headcount during 2012 compared to 2011 was more than offset by a shift in the mix of compensation to more
cash-based compensation. Stock-based compensation, net of amounts capitalized or reclassified to field operations,
was approximately $30.4 million in 2013, $26.5 million in 2012 and $30.3 million in 2011.
Our well operating agreements allow us, when we are the operator, to charge a well with a specified overhead rate
during the drilling phase and also to charge a monthly fixed overhead rate for each producing well. In addition,
salaries associated with field personnel are initially recorded as gross cash compensation and administrative costs
and are subsequently reclassified to lease operating expenses or capitalized to field development costs to the
extent those individuals are dedicated to oil and natural gas production, exploration, and development activities. As a
result of additional operated wells, increased compensation expense and an increase in the COPAS overhead rate,
the amount we recovered as operator labor and overhead recovery charges increased by 17% between 2012 and
2013, and 13% between 2011 and 2012. Capitalized exploration and development costs also increased between the
periods, primarily due to increased compensation costs subject to capitalization.
Interest and Financing Expenses
In thousands, except per BOE data and interest rates
Cash interest expense
Noncash interest expense
Less: Capitalized interest
Interest expense, net
Interest expense, net per BOE
Average debt outstanding
Average interest rate (1)
Year Ended December 31,
2013
2012
2011
$ 205,938
14,024
(79,253)
$ 140,709
$ 216,205
14,808
(77,432)
$ 153,581
$ 207,727
18,219
(61,586)
$ 164,360
$
5.49
$ 3,257,686
$
5.85
$ 2,935,485
$
6.86
$ 2,470,682
6.3%
7.4%
8.4%
(1) Includes commitment fees but excludes debt issue costs and amortization of discount or premium.
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Interest expense, net decreased 8% between 2012 and 2013. The decrease in interest expense is due to a lower
average interest rate, partially offset by higher average debt outstanding and higher capitalized interest. The decrease
in the average interest rate between 2012 and 2013 is a result of refinancing our 9½% Notes and 9¾% Notes with our
2023 Notes, which carry a rate of 4 5/8% (see Overview – Debt Refinancing above). During 2014, we expect capitalized
interest to decline due to the completion of various development projects during the fourth quarter of 2013.
Interest expense, net decreased 7% between 2011 and 2012, largely due to higher capitalized interest, offset in part
by higher cash interest expense resulting from an increase in average debt outstanding during the period.
Capitalized interest increased 26% during 2012, compared to 2011 primarily due to incremental capitalized interest on
the Riley Ridge gas processing facility and Greencore Pipeline construction projects.
Depletion, Depreciation and Amortization (“DD&A”)
In thousands, except per BOE data
Depletion and depreciation of oil and natural gas properties
Depletion and depreciation of CO2 properties
Asset retirement obligations
Depreciation of pipelines, plants and other property and equipment
Total DD&A
DD&A per BOE:
Oil and natural gas properties
CO2 and other fixed assets
Total DD&A cost per BOE
Year Ended December 31,
2013
2012
2011
$ 392,603
27,783
8,450
81,107
$ 509,943
$ 420,094
23,843
7,228
56,373
$ 507,538
$ 362,788
18,220
6,287
21,901
$ 409,196
$ 15.64
4.25
$ 19.89
$ 16.28
3.06
$ 19.34
$ 15.40
1.67
17.07
$
We adjust our DD&A rate each quarter for significant changes in our estimates of oil and natural gas reserves and
costs. In addition, under full cost accounting rules, the divestiture of oil and natural gas properties generally does
not result in gain or loss recognition; instead, the proceeds of the disposition reduce the full cost pool. As such, our
DD&A rate has changed significantly over time, and it may continue to change in the future. Depletion and
depreciation of oil and natural gas properties decreased 7% on an absolute-dollar basis and 4% on a per-BOE basis
between 2012 and 2013. These decreases were primarily due to the Bakken Exchange Transaction in late 2012,
which resulted in a decrease in capitalized costs relating to the sales proceeds credited to the full cost pool and a
significant reduction in future development costs relating to the sold proved reserves, partially offset by the
reduction in total proved reserves. This decrease in DD&A was partially offset by the impact of the CCA Acquisition
in the first quarter of 2013 and the movement of Bell Creek reserves from unevaluated to proved reserves during
the fourth quarter of 2013.
Depletion and depreciation of oil and natural gas properties increased 16% on an absolute-dollar basis and 6% on a
per-BOE basis between 2011 and 2012. During the first nine months of 2012, our DD&A rate for our oil and natural
gas properties was $16.90 per BOE, which was higher than 2011 levels due to higher finding and development costs
related to our Bakken capital program. However, in the fourth quarter of 2012, our DD&A rate for our oil and natural
gas properties decreased to $14.39 per BOE due to the Bakken Exchange Transaction.
During 2013, we added 84.6 MMBOE of estimated proved reserves, including tertiary reserves of 34.0 MMBbls at
Bell Creek Field based on the field’s response to CO2 injections, 42.2 MMBOE from the acquisition of additional
interests in CCA Fields and 8.4 MMBOE of other additions and revisions. We reclassified approximately $417.6 million
from unevaluated properties to the full cost pool relating to Bell Creek Field, representing the acquisition costs and
development expenditures incurred on the field prior to recognizing proved reserves. Our depletion and depreciation
rate of oil and natural gas properties increased to $16.90 per BOE during the fourth quarter of 2013, primarily as a
result of the reclassification of Bell Creek costs to the full cost pool, increased finding and development costs, and the
related recognition of additional proved reserves.
Depletion and depreciation of our CO2 properties, pipelines, plants, and other property and equipment increased on
an absolute-dollar and per-BOE basis during 2013 from 2012 levels, primarily due to an increase in CO2 properties,
pipelines and plants subject to depreciation as a result of continued development. The increase in 2013 was further
impacted by a change in classification of our equipment leases from operating to capital during the second quarter
of 2012, and the amount on a per-BOE basis was also impacted by lower oil and natural gas production during 2013.
Depletion and depreciation of our CO2 properties increased on an absolute-dollar and per-BOE basis in 2012
compared to 2011 due to increased drilling activity at Jackson Dome, and depreciation of other fixed assets increased
during the same period due to incremental pipeline depreciation and the change in classification of our
equipment leases.
Under full cost accounting rules, we are required each quarter to perform a ceiling test calculation. Under these
rules, the full cost ceiling value is calculated using a 12-month average price based on the first-day price of every
month during the period. We did not have a ceiling test write-down during 2013, 2012 or 2011. However, if oil prices
were to decrease significantly in subsequent periods, we may be required to record write-downs under the full cost
pool ceiling test in the future. The possibility and amount of any future write-down is difficult to predict, and
will depend, in part, upon oil and natural gas prices, the incremental proved reserves that may be added each period,
revisions to previous reserve estimates and future capital expenditures, as well as additional capital spent.
Income Taxes
In thousands, except per BOE amounts and tax rates
2013
2012
2011
Year Ended December 31,
Current income tax expense
Deferred income tax expense
Total income tax expense
Average income tax expense per BOE
Effective tax rate
Total net deferred tax liability
$
10,257
222,526
$ 232,783
$
75,754
255,743
$ 331,497
$
8,249
342,463
$ 350,712
$
9.08
36.2%
$
12.63
$
14.63
38.7%
38.0%
$ 2,346,540
$ 2,124,296
$ 1,868,420
Our income tax provisions for 2013 and 2011 were based on an estimated statutory rate of approximately 38%,
while the 2012 tax provision was based on an estimated statutory rate of approximately 38.5%. The fluctuation in our
statutory rate is significantly driven by a shift in the amount of revenues we earn in each state due to acquisitions
and divestitures and other production changes. Our 2013 effective tax rate was lower than our statutory rate due to
the revaluation of our deferred taxes as a result of the lower overall statutory rate compared to 2012, as well as
the change in treatment of certain items between our 2012 tax provision and our 2012 tax returns. Our effective tax
rate was consistent with our estimated statutory rates in 2012 and 2011.
During 2012, for federal income tax purposes, we structured the divestitures of our Bakken area assets and certain
non-core assets as like-kind-exchange transactions for interests acquired in Thompson, Webster, Hartzog Draw and
LaBarge fields as well as the CCA Acquisition in 2013 (see Note 2, Acquisitions and Divestitures, to the Consolidated
Financial Statements), thereby deferring the majority of the taxable gain on those divestitures. The increase in current
income tax expense during 2012 included $42 million of current taxes resulting from the taxable gain recognized in
the Bakken Exchange Transaction that we were unable to defer through a like-kind exchange transaction. Current
income tax expense during 2013 is primarily related to state income taxes while current income tax during 2012 and
2011 also includes our alternative minimum cash taxes that we cannot offset with enhanced oil recovery credits, as
well as state income taxes. We currently expect our cash taxes in the future to increase over 2013 cash taxes. Our
current income tax expense during 2011 was offset by a net benefit due to the change in treatment for certain items
between our 2010 tax provision and our 2010 filed tax return. This change in treatment resulted in a reclassification
of approximately $16.9 million from current to deferred taxes.
As of December 31, 2013, we had an estimated $15.0 million of enhanced oil recovery credits to carry forward
related to our tertiary operations, and $34.8 million of alternative minimum tax credits that can be utilized to reduce
our current income taxes during 2014 or future years. These enhanced oil recovery credits do not begin to expire
until 2025. Since the ability to earn additional enhanced oil recovery credits is based upon the level of oil prices,
we would not currently expect to earn additional enhanced oil recovery credits unless oil prices were to
significantly deteriorate.
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Per-BOE Data
The following table summarizes our cash flow, DD&A and results of operations on a per-BOE basis for the
comparative periods. Each of the individual components is discussed above.
Per-BOE data
Oil and natural gas revenues
Cash receipt (payment) on settlements of commodity derivatives
Lease operating expenses – excluding Delhi Field remediation
Lease operating expenses – Delhi Field remediation
Production and ad valorem taxes
Marketing expenses, net of third party purchases
Production netback
CO2 sales, net of operating and exploration expenses
General and administrative expenses
Interest expense, net
Other
Changes in assets and liabilities relating to operations
Cash flow from operations
DD&A
Deferred income taxes
Loss on early extinguishment of debt
Noncash fair value adjustments on commodity derivatives
Impairment of assets
Other noncash items
Net income
Market Risk Management
Restricted Cash
Year Ended December 31,
2013
2012
2011
$ 96.19
(0.03)
(24.05)
(4.45)
(6.35)
(1.47)
59.84
0.43
(5.66)
(5.49)
0.48
3.49
53.09
(19.89)
(8.68)
(1.74)
(1.57)
—
(5.23)
$ 15.98
$ 91.85
0.68
(20.29)
—
(5.71)
(1.60)
64.93
0.45
(5.49)
(5.85)
(1.44)
1.17
53.77
(19.34)
(9.75)
—
(0.50)
(0.67)
(3.49)
$ 20.02
$ 94.68
0.10
(21.17)
—
(5.81)
(1.09)
66.71
0.36
(5.24)
(6.86)
1.77
(6.47)
50.27
(17.07)
(14.29)
(0.67)
2.09
(0.96)
4.55
$ 23.92
Restricted cash on our Consolidated Balance Sheet as of December 31, 2012 consisted of proceeds from the Bakken
Exchange Transaction (see Note 2, Acquisitions and Divestitures, to the Consolidated Financial Statements)
previously held by a qualified intermediary and which were restricted for application towards future potential
acquisitions to enable a like-kind-exchange transaction for federal income tax purposes. We managed and
controlled counterparty credit risk related to this restricted cash using a trust agreement, whereby the assets held in
trust must be segregated from the financial institution’s assets, and in the event of its bankruptcy, the funds would
not be subject to payments to the creditors of the financial institution.
Debt
We finance some of our acquisitions and other expenditures with fixed and variable rate debt. These debt
agreements expose us to market risk related to changes in interest rates. At December 31, 2013, we had $340.0 million
in outstanding borrowings on our bank credit facility. None of our existing debt has any triggers or covenants
regarding our debt ratings with rating agencies, although under the NEJD financing lease, in the event of significant
downgrades of our corporate credit rating by the rating agencies, certain credit enhancements can be required
from us, and possibly other remedies made available under the lease. The fair value of our senior subordinated debt
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is based on quoted market prices. The following table presents the principal cash flows and fair values of our
outstanding debt at December 31, 2013:
In thousands
2014
2015
2016
2017
2020
2021
2023
Total
Fair
Value
Variable rate debt:
Bank credit facility
(weighted average interest
rate of 1.9% at
December 31, 2013)
$ — $ — $ 340,000 $ — $
— $
— $
— $ 340,000 $ 340,000
Fixed rate debt:
8¼% Senior Subordinated
Notes due 2020
6 3/8% Senior Subordinated
Notes due 2021
4 5/8% Senior Subordinated
Notes due 2023
—
—
—
—
996,273
—
—
996,273
1,097,096
—
—
—
—
—
400,000
—
400,000
425,000
Other Subordinated Notes
1,072
485
—
—
—
—
—
2,250
—
—
—
—
1,200,000
1,200,000
1,092,000
—
3,807
2,735
See Note 5, Long-Term Debt, to the Consolidated Financial Statements for details regarding our long-term debt.
Oil and Natural Gas Derivative Contracts
From time to time, we enter into oil and natural gas derivative contracts to provide an economic hedge of our
exposure to commodity price risk associated with anticipated future oil and natural gas production. These contracts
have consisted of price floors, collars and fixed price swaps. We do not hold or issue derivative financial instruments
for trading purposes. The production that we hedge has varied from year to year, depending on our levels of debt
and financial strength and expectation of future commodity prices. We currently employ a strategy to hedge a portion
of our forecasted production for approximately 18 months to two years in the future from the current quarter, as
we believe it is important to protect our future cash flow for that time in order to give us time to adjust to commodity
price fluctuations, particularly since many of our expenditures have long lead times (see Capital Resources and
Liquidity above). Now that we are paying a dividend, we may look to extend the periods covered by our hedges
further into the future, possibly for periods up to three years, in order to provide greater certainty around oil and
natural gas prices and projected cash flows. Also, in December 2013, we converted our 2014 oil collars to fixed-price
swaps and in early 2014, we converted a portion of our 2015 oil collars to fixed-price swaps. See Note 9, Commodity
Derivative Contracts, to the Consolidated Financial Statements for additional information regarding our commodity
derivative contracts.
All of the mark-to-market valuations used for our oil and natural gas derivatives are provided by external sources.
We manage and control market and counterparty credit risk through established internal control procedures that are
reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit
policies, monitoring procedures and diversification. All of our commodity derivative contracts are with parties that are
lenders under our bank credit facility. We have included an estimate of nonperformance risk in the fair value
measurement of our oil and natural gas derivative contracts, which we have measured for nonperformance risk based
upon credit default swaps or credit spreads.
For accounting purposes, we do not apply hedge accounting to our oil and natural gas derivative contracts.
This means that any changes in the fair value of these commodity derivative contracts will be charged to earnings
on a quarterly basis instead of charging the effective portion to other comprehensive income and the ineffective
portion to earnings.
At December 31, 2013, our commodity derivative contracts were recorded at their fair value, which was a net
liability of approximately $47.3 million, a $40.4 million increase from the $6.9 million net liability recorded at
December 31, 2012. This change is primarily related to the expiration of oil derivative contracts during 2013, new
commodity derivative contracts we entered into during 2013 for future periods, and to the oil and natural gas
futures prices as of December 31, 2013.
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Commodity Derivative Sensitivity Analysis
Based on NYMEX and LLS crude oil futures prices and natural gas futures prices as of December 31, 2013, and
assuming both a 10% increase and decrease thereon, we would expect to make or receive payments on our crude oil
and natural gas derivative contracts as shown in the following table:
In thousands
Based on:
NYMEX futures prices as of December 31, 2013
10% increase in prices
10% decrease in prices
Crude Oil
Derivative
Contracts
Receipt/
(Payment)
Natural Gas
Derivative
Contracts
Receipt/
(Payment)
$ (58,377)
(286,016)
167,853
$ —
(930)
1,348
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements in accordance with generally accepted accounting principles requires that
we select certain accounting policies and make certain estimates and judgments regarding the application of those
policies. Our significant accounting policies are included in Note 1, Significant Accounting Policies, to the Consolidated
Financial Statements. These policies, along with the underlying assumptions and judgments by our management
in their application, have a significant impact on our consolidated financial statements. Following is a discussion of
our most critical accounting estimates, judgments and uncertainties that are inherent in the preparation of our
financial statements.
Full Cost Method of Accounting, Depletion and Depreciation and Oil and Natural Gas Properties
Businesses involved in the production of oil and natural gas are required to follow accounting rules that are
unique to the oil and gas industry. We apply the full cost method of accounting for our oil and natural gas properties.
Another acceptable method of accounting for oil and natural gas production activities is the successful efforts
method of accounting. In general, the primary differences between the two methods are related to the capitalization
of costs and the evaluation for asset impairment. Under the full cost method, all geological and geophysical costs,
exploratory dry holes and delay rentals are capitalized to the full cost pool, whereas under the successful efforts
method such costs are expensed as incurred. In the assessment of impairment of oil and natural gas properties, the
successful efforts method follows the FASB guidance under the Accounting for the Impairment or Disposal of Long-
Lived Assets topic of the FASC, under which the net book value of assets is measured for impairment against the
undiscounted future cash flows using commodity prices consistent with management expectations. Under the full
cost method, the full cost pool (net book value of oil and natural gas properties) is measured against future cash
flows discounted at 10% using the average first-day-of-the-month oil and natural gas price for each month during the
12-month period ended as of each quarterly reporting period. The financial results for a given period could be
substantially different depending on the method of accounting that an oil and gas entity applies. Further, we do not
designate our oil and natural gas derivative contracts as hedge instruments for accounting purposes under the
Derivatives and Hedging topic of the FASC (see below), and as a result, these contracts are not considered in the full
cost ceiling test.
We make significant estimates at the end of each period related to accruals for oil and natural gas revenues,
production, capitalized costs and operating expenses. We calculate these estimates with our best available data,
which includes, among other things, production reports, price posting, information compiled from daily drilling
reports and other internal tracking devices, and analysis of historical results and trends. While management is not
aware of any required revisions to its estimates, there will likely be future adjustments resulting from such things as
changes in ownership interests, payouts, joint venture audits, re-allocations by the purchaser/pipeline, or other
corrections and adjustments common in the oil and gas industry, many of which will require retroactive application.
These types of adjustments cannot be currently estimated or determined and will be recorded in the period during
which the adjustment occurs.
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Under full cost accounting, the estimated quantities of proved oil and natural gas reserves used to compute
depletion and the related present value of estimated future net cash flows therefrom used to perform the full cost
ceiling test have a significant impact on the underlying financial statements. The process of estimating oil and
natural gas reserves is very complex, requiring significant decisions in the evaluation of all available geological,
geophysical, engineering and economic data. The data for a given field may also change substantially over time as a
result of numerous factors, including additional development activity, evolving production history and continued
reassessment of the viability of production under varying economic conditions. As a result, material revisions to
existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that the
reported reserve estimates represent the most accurate assessments possible, including the hiring of independent
engineers to prepare reported estimates, the subjective decisions and variances in available data for various fields
make these estimates generally less precise than other estimates included in our financial statement disclosures.
Over the last four years, annual revisions to our reserve estimates have averaged approximately 2.0% of the previous
year’s estimates and have been both positive and negative.
Changes in commodity prices also affect our reserve quantities. Between 2011 and 2012, oil and natural gas prices
used to calculate reserve quantities in our year-end proved reserve report decreased, resulting in a decrease in our
proved reserves of 6.7 MMBOE. Between 2012 and 2013, oil and natural gas prices used to calculate year-end proved
reserves increased, resulting in an increase in our proved reserves of 3.0 MMBOE. These changes in quantities
affect our DD&A rate, and the combined effect of changes in quantities and commodity prices impacts our full cost
ceiling test calculation. For example, we estimate that a 5% increase in our estimate of proved reserves quantities
would have lowered our fourth quarter 2013 DD&A rate from $16.90 per BOE to approximately $16.12 per BOE, and a
5% decrease in our proved reserve quantities would have increased our DD&A rate to approximately $17.76 per BOE.
Also, reserve quantities and their ultimate values, determined solely by our lenders, are the primary factors in
determining the maximum borrowing base under our bank credit facility.
Under full cost accounting rules, we are required each quarter to perform a ceiling test calculation. The net
capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling.
The cost center ceiling is defined as (1) the present value of our future net revenues from proved reserves before
future abandonment costs calculated using the average first-day-of-the-month oil and natural gas price for each
month during the 12-month period then ended, discounted at 10%; plus (2) the cost of properties not being amortized;
plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if
any; less (4) related income tax effects. Our future net revenues from proved reserves are not reduced for development
costs related to the cost of drilling for and developing CO2 reserves nor for those related to the cost of constructing
CO2 pipelines, as those costs have already been incurred by the Company. Therefore, we include in the ceiling test,
as a reduction of future net revenues, that portion of our capitalized CO2 costs related to CO2 reserves and CO2
pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves. The
fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate
these contracts as hedge instruments for accounting purposes.
We did not have a full cost pool ceiling test write-down in 2013, 2012 or 2011. Crude oil prices decreased between
2011 and 2012, and increased during 2013, with first-day-of-the-month NYMEX oil prices during 2013 averaging
$96.94 per Bbl during the year. First-day-of-the-month unweighted average NYMEX natural gas prices during 2013
of $3.67 per Mcf were higher than unweighted average natural gas prices for 2012. Commodity prices have
historically been volatile and are expected to continue to be so in the future. If oil and natural gas prices should
decrease, we may be required to record write-downs due to the full cost ceiling test. The amount of any future
write-down is difficult to predict and will depend upon the oil and natural gas prices utilized in the ceiling test, the
incremental proved reserves that might be added during each period and additional capital spent.
Tertiary Injection Costs
Our tertiary operations are conducted in reservoirs that have already produced significant amounts of oil over
many years; however, in accordance with the rules for recording proved reserves, we cannot recognize proved
reserves associated with enhanced recovery techniques such as CO2 injection until we can demonstrate production
resulting from the tertiary process or unless the field is analogous to an existing flood. Our costs associated with
the CO2 we produce (or acquire) and inject are principally our cash out-of-pocket costs of production, transportation
and acquisition, and to pay royalties.
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We capitalize, as a development cost, injection costs in fields that are in their development stage, which means we
have not yet seen incremental oil production due to the CO2 injections (i.e., a production response). These
capitalized development costs will be included in our unevaluated property costs if there are not already proved tertiary
reserves in that field. After we see a production response to the CO2 injections (i.e., the production stage), injection
costs will be expensed as incurred, and any previously deferred unevaluated development costs will become subject
to depletion upon recognition of proved tertiary reserves. During 2013, 2012 and 2011, we capitalized $38.7 million,
$36.8 million and $65.3 million, respectively, of tertiary injection costs associated with our tertiary projects.
Income Taxes
We make certain estimates and judgments in determining our income tax expense for financial reporting
purposes. These estimates and judgments occur in the calculation of certain tax assets and liabilities that arise from
differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Our
federal and state income tax returns are generally not prepared or filed before the consolidated financial statements
are prepared; therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as
the effects of tax rate changes, tax credits and net operating loss carryforwards. Adjustments related to these
estimates are recorded in our tax provision in the period in which we finalize our income tax returns. Further, we
must assess the likelihood that we will be able to recover or utilize our deferred tax assets (primarily our enhanced
oil recovery credits and state loss carryforwards). If recovery is not likely, we must record a valuation allowance
against such deferred tax assets for the amount we would not expect to recover, which would result in an increase
to our income tax expense. As of December 31, 2013, we believe that all of our deferred tax assets recorded on our
Consolidated Balance Sheet will ultimately be recovered. If our estimates and judgments change regarding our
ability to utilize our deferred tax assets, our tax provision would increase in the period it is determined that recovery
is not likely. A 1% increase in our effective tax rate would have increased our calculated income tax expense
by approximately $6.4 million, $8.6 million and $9.2 million for the years ended December 31, 2013, 2012 and 2011,
respectively. See Note 6, Income Taxes, to the Consolidated Financial Statements and see Income Taxes above for
further information concerning our income taxes.
Fair Value Estimates
The FASC defines fair value, establishes a framework for measuring fair value and expands disclosures about fair
value measurements. It does not require us to make any new fair value measurements, but rather establishes a fair
value hierarchy that prioritizes the inputs to the valuation techniques used to measure fair value. Level 1 inputs
are given the highest priority in the fair value hierarchy, as they represent observable inputs that reflect unadjusted
quoted prices for identical assets or liabilities in active markets as of the reporting date, while Level 3 inputs are
given the lowest priority, as they represent unobservable inputs that are not corroborated by market data. Valuation
techniques that maximize the use of observable inputs are favored. See Note 10, Fair Value Measurements, to the
Consolidated Financial Statements for disclosures regarding our recurring fair value measurements.
Significant uses of fair value measurements include:
• allocation of the purchase price paid to acquire businesses to the assets acquired and liabilities assumed in
those acquisitions;
• assessment of impairment of long-lived assets;
• assessment of impairment of goodwill; and
•
recorded value of commodity derivative instruments.
Acquisitions
Under the acquisition method of accounting for business combinations, the purchase price paid to acquire a
business is allocated to its assets and liabilities based on the estimated fair values of the assets acquired and
liabilities assumed as of the date of acquisition. The FASC Fair Value Measurements and Disclosures topic defines fair
value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction
between market participants at the measurement date (often referred to as the “exit price”). A fair value
measurement is based on the assumptions of market participants and not those of the reporting entity. Therefore,
entity-specific intentions do not impact the measurement of fair value unless those assumptions are consistent
with market participant views.
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The excess of the purchase price over the fair value (as defined by the FASC Fair Value Measurements and
Disclosures topic) of the net tangible and identifiable intangible assets acquired is recorded as goodwill. A significant
amount of judgment is involved in estimating the individual fair values involving long-term tangible assets,
identifiable intangible assets and long-term asset retirement obligations. We use all available information to estimate
the fair values of assets acquired and liabilities assumed in an acquisition and engage a third-party consultant to
review certain assumptions utilized in our valuations.
Specifically, the FASC Fair Value Measurements and Disclosures topic requires us to value oil properties recoverable
through enhanced oil recovery by estimating the cost a third party market participant would pay for CO2. A third
party’s economics and access to CO2 is substantially different in our operating regions than our own, as CO2
is limited and there may be no known CO2 available in a given area except through our own sources. These factors
generally result in our estimation of the cost of CO2 to a market participant being higher than our cost. Because
of our strategic advantage relating to CO2 supply and associated infrastructure, a third party’s economics (the required
basis for allocating values) for a potential EOR flood will be less than ours. Therefore, we cannot attribute much, if
any, of our purchase price relating to the future EOR flood to unevaluated properties, even though we may have
attributed value to the future flood when we made the purchase decision. As such, we must attribute the unallocated
purchase price to goodwill, which has resulted in our recognition of more goodwill than most of our industry peers.
The fair values used to allocate the purchase price of an acquisition are often estimated using the expected present
value of future cash flows method, which requires us to project related future cash inflows and outflows and apply
an appropriate discount rate. The estimates used in determining fair values are based on assumptions believed to be
reasonable but that are inherently uncertain. Accordingly, actual results may differ from the projected results used
to determine fair value.
Impairment Assessment of Goodwill
We test goodwill for impairment annually during the fourth quarter, or between annual tests if an event occurs
or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying
amount. The need to test for impairment can be based on several indicators, including a significant reduction in
prices of oil or natural gas, a full-cost ceiling write-down of oil and natural gas properties, unfavorable adjustments to
reserves, significant changes in the expected timing of production, other changes to contracts or changes in the
regulatory environment.
Goodwill is tested for impairment at the reporting unit level. Denbury applies SEC full cost accounting rules,
under which the acquisition cost of oil and gas properties is recognized on a cost center basis (country), of which
Denbury has only one cost center (United States). Goodwill is assigned to this single reporting unit.
In each period that a goodwill impairment test is performed, we have the option to assess qualitative factors to
determine if it is more likely than not that our reporting unit’s fair value is less than its carrying amount. The
following events and circumstances are certain of the qualitative factors we consider in evaluating whether it is more
likely than not the fair value of our reporting unit is less than its carrying amount:
• Macroeconomic conditions, such as deterioration in general economic conditions, limitations on accessing
capital, or other developments in equity and credit markets;
•
Industry and market conditions, such as deterioration in the environment in which we operate, including
significant declines in oil prices, inability to access oil field equipment and/or qualified personnel and regulations
impacting the oil and natural gas industry, among others;
• Cost factors, such as increases in power and labor costs;
• Overall financial performance, such as negative or declining cash flows or a decline in actual or forecasted
revenues or earnings;
• Other relevant Company-specific events, such as material changes in management or key personnel, a change
in strategy or litigation;
• Material events, such as a change in the composition or carrying amount of our reporting unit’s net assets,
including acquisitions and dispositions; and
• Consideration of the relationship of our market capitalization to our book value, as well as a sustained decrease
in our share price.
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If we determine that it is more likely than not that our reporting unit’s fair value is less than its carrying amount,
we will proceed to step 1 of the 2-step quantitative goodwill assessment, in which we perform a calculation to
compare the fair value of our reporting unit to its carrying cost. In any given period, we have the option to bypass the
qualitative assessment and proceed directly to step 1 of the 2-step quantitative goodwill impairment test.
Fair value calculated for the purpose of testing for impairment of our goodwill is estimated using the expected
present value of future cash flows method, and comparative market prices and net asset value when appropriate.
The Company also takes into consideration the Company’s market capitalization, including a control premium.
A significant amount of judgment is involved in performing these fair value estimates for goodwill, since the results
are based on forecasted assumptions. Significant assumptions include projections of future oil and natural gas
prices, projections of estimated quantities of oil and natural gas reserves, projections of future rates of production,
timing and amount of future development and operating costs, projected availability and cost of CO2, projected
recovery factors of tertiary reserves and risk-adjusted discount rates. We base our fair value estimates on projected
financial information that we believe to be reasonable. However, actual results may differ from those projections.
We completed our goodwill impairment assessment during the fourth quarter of 2013 and did not record any
goodwill impairment during 2013, nor have we recorded a goodwill impairment historically.
Oil and Natural Gas Derivative Contracts
We enter into oil and natural gas derivative contracts to mitigate our exposure to commodity price risk associated
with future oil and natural gas production. These contracts have historically consisted of options, in the form of
price floors or collars, and fixed price swaps. We do not designate these commodity derivative contracts as hedge
instruments for accounting purposes under the FASC Derivatives and Hedging topic. This means that any changes
in the fair value of these commodity derivative contracts will be charged to earnings on a quarterly basis instead of
charging the effective portion to other comprehensive income and the balance to earnings. While we may experience
more volatility in our net income than if we were to apply hedge accounting treatment as permitted by the FASC
Derivatives and Hedging topic, we believe that for us the benefits associated with applying hedge accounting do not
outweigh the cost, time and effort to comply with hedge accounting.
Environmental and Litigation Contingencies
The Company makes judgments and estimates in recording liabilities for contingencies such as environmental
remediation or ongoing litigation. Liabilities are recorded when it is both probable that a loss has been incurred and
such loss is reasonably estimable. Assessments of liabilities are based on information obtained from independent
and in-house experts, loss experience in similar situations, actual costs incurred, and other case-by-case factors.
Actual costs can vary from such estimates for a variety of reasons. The costs of environmental remediation or
litigation can vary from estimates due to new developments regarding the facts and circumstances of each event,
including in the case of environmental remediation, the timing of remediation, our understanding of the
environmental impact, remediation methods available, and regulatory requirements, and in the case of litigation,
differing interpretations of laws and facts and assessments of damages asserted and/or incurred.
Use of Estimates
See Note 1, Significant Accounting Policies, to the Consolidated Financial Statements for a discussion of our use
of estimates.
Recent Accounting Pronouncements
See Note 1, Significant Accounting Policies, to the Consolidated Financial Statements for a discussion of the effects
of recently issued and recently adopted accounting pronouncements.
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FORWARD-LOOKING INFORMATION
The statements contained in this Annual Report on Form 10-K that are not historical facts, including, but not limited
to, statements found in the sections entitled “Business” and “Management’s Discussion and Analysis of Financial
Condition and Results of Operations,” are forward-looking statements, as that term is defined in Section 21E of the
Securities and Exchange Act of 1934, as amended, that involve a number of risks and uncertainties. Such forward-
looking statements may be or may concern, among other things, forecasted capital expenditures, drilling activity or
methods including the timing and location thereof, estimated timing of pipeline construction or completion
or the cost thereof, dates of completion of to-be-constructed industrial plants and the initial date of capture of
anthropogenic CO2 from such plants, timing of CO2 injections and initial production responses in tertiary flooding
projects, acquisition plans and proposals and dispositions, development activities, finding costs, cost savings, capital
budgets, production rates and volumes or forecasts thereof, assumptions regarding payment of future cash
dividends to shareholders, the rate thereof, or the sustainability or growth of future payments, hydrocarbon reserve
quantities and values, CO2 reserves, helium reserves, potential reserves, percentages of recoverable original oil in
place, hydrocarbon prices, pricing or cost assumptions based on current and projected oil and gas prices, liquidity,
cash flows, availability of capital, borrowing capacity, regulatory matters, prospective legislation affecting the oil and
gas industry, mark-to-market values, competition, long-term forecasts of production, finding costs, rates of return,
estimated costs, or changes in costs, future capital expenditures and overall economics and other variables
surrounding our operations and future plans. Such forward-looking statements generally are accompanied by words
such as “plan,” “estimate,” “expect,” “predict,” “anticipate,” “projected,” “should,” “assume,” “believe,” “target”
or other words that convey the uncertainty of future events or outcomes. Such forward-looking information is based
upon management’s current plans, expectations, estimates and assumptions and is subject to a number of risks
and uncertainties that could significantly affect current plans, anticipated actions, the timing of such actions and our
financial condition and results of operations. As a consequence, actual results may differ materially from
expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by us or
on our behalf. Among the factors that could cause actual results to differ materially are fluctuations of the prices
received or demand for our oil and natural gas; effects of our indebtedness; success of our risk management
techniques; inaccurate cost estimates; availability of and fluctuations in the prices of goods and services; the uncertainty
of drilling results and reserve estimates; operating hazards; disruption of operations and damages from hurricanes
or tropical storms; acquisition risks; requirements for capital or its availability; conditions in the financial and credit
markets; general economic conditions; competition and government regulations; and unexpected delays, as well
as the risks and uncertainties inherent in oil and gas drilling and production activities or that are otherwise discussed
in this annual report, including, without limitation, the portions referenced above, and the uncertainties set forth
from time to time in our other public reports, filings and public statements.
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Item 7A. Quantitative and Qualitative Disclosures
About Market Risk
The information required by Item 7A is set forth under Market Risk Management in Item 7, Management’s
Discussion and Analysis of Financial Condition and Results of Operations.
Item 8. Financial Statements and
Supplementary Information
Report of Independent Registered Public Accounting Firm ..........................................................................................
Consolidated Balance Sheets .............................................................................................................................................
Consolidated Statements of Operations ...........................................................................................................................
Consolidated Statements of Comprehensive Operations .............................................................................................
Consolidated Statements of Cash Flows ..........................................................................................................................
Consolidated Statements of Changes in Stockholders’ Equity ....................................................................................
Notes to Consolidated Financial Statements
1.
2.
3.
4.
5.
6.
7.
8.
9.
Significant Accounting Policies ........................................................................................................................
Acquisitions and Divestitures ...........................................................................................................................
Asset Retirement Obligations ...........................................................................................................................
Property and Equipment ....................................................................................................................................
Long-Term Debt ...................................................................................................................................................
Income Taxes .......................................................................................................................................................
Stockholders’ Equity ...........................................................................................................................................
Stock Compensation Plans ................................................................................................................................
Commodity Derivative Contracts .....................................................................................................................
10.
Fair Value Measurements ..................................................................................................................................
11.
Commitments and Contingencies ....................................................................................................................
12.
Additional Balance Sheet Details .....................................................................................................................
13.
Supplemental Cash Flow Information .............................................................................................................
14.
Subsequent Events .............................................................................................................................................
Supplemental Oil and Natural Gas Disclosures (Unaudited) ........................................................................................
Supplemental CO2 and Helium Disclosures (Unaudited) ...............................................................................................
Unaudited Quarterly Information .......................................................................................................................................
Page
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62
63
64
65
66
67
73
75
76
77
80
81
82
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89
91
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95
95
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Denbury Resources Inc.:
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material
respects, the financial position of Denbury Resources Inc. and its subsidiaries at December 31, 2013 and 2012, and
the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013
in conformity with accounting principles generally accepted in the United States of America. Also in our opinion,
the Company maintained, in all material respects, effective internal control over financial reporting as of December 31,
2013, based on criteria established in Internal Control – Integrated Framework (1992) issued by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these
financial statements, for maintaining effective internal control over financial reporting and for its assessment of
the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over
Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements
and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our
audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial
statements are free of material misstatement and whether effective internal control over financial reporting
was maintained in all material respects. Our audits of the financial statements included examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall financial statement presentation.
Our audit of internal control over financial reporting included obtaining an understanding of internal control over
financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and
operating effectiveness of internal control based on the assessed risk. Our audits also included performing such
other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable
basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles. A company’s internal control over financial reporting
includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable
assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles, and that receipts and expenditures of the company are being
made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the
company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect
misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.
PricewaterhouseCoopers LLP
Dallas, Texas
February 28, 2014
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CONSOLIDATED BALANCE SHEETS
In thousands, except par value and share data
Current assets
Cash and cash equivalents
Restricted cash
Accrued production receivable
Trade and other receivables, net
Derivative assets
Deferred tax assets
Other current assets
Total current assets
Assets
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved properties
Unevaluated properties
CO2 properties
Pipelines and plants
Other property and equipment
Less accumulated depletion, depreciation, amortization and impairment
Net property and equipment
Derivative assets
Goodwill
Other assets
Total assets
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable and accrued liabilities
Oil and gas production payable
Derivative liabilities
Current maturities of long-term debt
Total current liabilities
Long-term liabilities
Long-term debt, net of current portion
Asset retirement obligations
Derivative liabilities
Deferred tax liabilities
Other liabilities
Total long-term liabilities
Commitments and contingencies (Note 11)
Stockholders’ equity
Preferred stock, $.001 par value, 25,000,000 shares authorized,
none issued and outstanding
Common stock, $.001 par value, 600,000,000 shares authorized; 409,215,573
and 406,163,194 shares issued, respectively
Paid-in capital in excess of par
Retained earnings
Accumulated other comprehensive loss
Treasury stock, at cost, 46,710,896 and 30,601,262 shares, respectively
Total stockholders’ equity
Total liabilities and stockholders’ equity
See accompanying Notes to Consolidated Financial Statements.
December 31,
2013
2012
$
12,187
—
262,047
78,295
5
52,754
9,271
414,559
98,511
$
1,050,015
253,131
81,971
19,477
29,156
10,493
1,542,754
8,945,326
780,481
1,117,167
2,209,560
466,969
(3,668,225)
9,851,278
9,942
1,283,590
229,368
$ 11,788,737
6,963,211
809,154
1,032,653
2,035,126
417,207
(3,180,241)
8,077,110
36
1,283,590
235,852
$ 11,139,342
$
410,543
174,677
53,822
36,157
675,199
3,260,625
119,888
3,413
2,399,294
28,912
5,812,132
$ 414,668
161,945
2,842
36,966
616,421
3,104,462
102,730
23,781
2,153,452
23,607
5,408,032
—
—
409
3,186,714
2,844,432
(276)
(729,873)
5,301,406
$ 11,788,737
406
3,136,461
2,434,835
(348)
(456,465)
5,114,889
$ 11,139,342
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CONSOLIDATED STATEMENTS OF OPER ATIONS
In thousands, except per share data
Revenues and other income
Oil, natural gas, and related product sales
CO2 sales and transportation fees
Interest income and other income
Total revenues and other income
Expenses
Lease operating expenses
Marketing expenses
CO2 discovery and operating expenses
Taxes other than income
General and administrative expenses
Interest, net of amounts capitalized of $79,253, $77,432 and
$61,586, respectively
Depletion, depreciation and amortization
Commodity derivatives expense (income)
Loss on early extinguishment of debt
Impairment of assets
Other expenses
Total expenses
Income before income taxes
Income tax provision
Net Income
Net income per common share
Basic
Diluted
Weighted average common shares outstanding
Basic
Diluted
See accompanying Notes to Consolidated Financial Statements.
Year Ended December 31,
2013
2012
2011
$ 2,466,234
27,950
22,943
2,517,127
$ 2,409,867
26,453
20,152
2,456,472
$ 2,269,151
22,711
17,462
2,309,324
730,574
49,246
16,916
176,231
145,211
140,709
509,943
41,024
44,651
—
20,242
1,874,747
642,380
232,783
532,359
52,836
14,694
160,016
144,019
507,397
26,047
14,258
147,534
125,525
153,581
507,538
(4,834)
—
17,515
21,891
1,599,615
856,857
331,497
164,360
409,196
(52,497)
16,131
22,951
4,377
1,385,279
924,045
350,712
$ 409,597
$ 525,360
$ 573,333
$
$
1.12
1.11
$
$
1.36
1.35
$
$
1.45
1.43
366,659
369,877
385,205
388,938
396,023
400,958
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CONSOLIDATED STATEMENTS OF COMPREHENSIVE OPER ATIONS
In thousands
Net income
Other comprehensive income, net of income tax:
Interest rate lock derivative contracts reclassified to income,
net of tax of $40, $43 and $43, respectively
Total other comprehensive income
Comprehensive income
See accompanying Notes to Consolidated Financial Statements.
Year Ended December 31,
2013
2012
2011
$ 409,597
$ 525,360
$ 573,333
72
72
$ 409,669
70
70
$ 525,430
70
70
$ 573,403
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CONSOLIDATED STATEMENTS OF C ASH FLOWS
In thousands
Cash flow from operating activities
Net income
Adjustments to reconcile net income to cash flow
from operating activities
Depletion, depreciation and amortization
Deferred income taxes
Stock-based compensation
Commodity derivatives expense (income)
Cash receipt (payment) on settlements of commodity derivatives
Loss on early extinguishment of debt
Amortization of debt issuance costs and discounts
Impairment of assets
Other, net
Changes in assets and liabilities, net of effects from acquisitions
Accrued production receivable
Trade and other receivables
Other current and long-term assets
Accounts payable and accrued liabilities
Oil and natural gas production payable
Other liabilities
Net cash provided by operating activities
Cash flow used for investing activities
Oil and natural gas capital expenditures
Acquisitions of oil and natural gas properties
Cash paid in Riley Ridge acquisition
Bakken exchange transaction
CO2 capital expenditures
Pipelines and plants capital expenditures
Purchases of other assets
Net proceeds from sales of oil and natural gas properties
and equipment
Net proceeds from sale of short-term investments
Other
Net cash used for investing activities
Cash flow provided by (used for) financing activities
Bank repayments
Bank borrowings
Repayment of senior subordinated notes
Premium paid on repayment of senior subordinated notes
Net proceeds from issuance of senior subordinated notes
Costs of debt financing
Common stock repurchase program
Other
Net cash provided by (used for) financing activities
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year
See accompanying Notes to Consolidated Financial Statements.
Year Ended December 31,
2013
2012
2011
$ 409,597
$ 525,360
$ 573,333
509,943
222,526
33,003
41,024
(662)
44,651
14,023
—
(2,318)
(15,085)
4,981
10,462
91,816
12,731
(15,497)
1,361,195
(900,221)
(9,243)
—
(10,385)
(93,744)
(184,286)
(65,987)
507,538
255,743
29,310
(4,834)
17,880
—
14,695
17,515
16,917
36,234
45,836
7,688
5,828
(23,460)
(41,359)
1,410,891
(1,122,615)
(156,082)
—
281,669
(131,043)
(330,417)
(25,765)
409,196
342,463
33,190
(52,497)
2,377
16,131
16,954
22,951
(4,190)
(74,781)
(55,470)
(15,817)
(35,462)
54,391
(27,955)
1,204,814
(1,082,853)
(35,305)
(199,263)
—
(84,789)
(236,133)
(28,838)
8,037
—
(19,480)
(1,275,309)
34,750
83,545
(10,883)
(1,376,841)
69,370
—
(8,147)
(1,605,958)
(1,550,000)
1,190,000
(651,270)
(36,475)
1,200,000
(20,161)
(281,958)
(22,346)
(172,210)
(86,324)
98,511
12,187
$
(1,555,000)
1,870,000
—
—
—
(34)
(251,480)
(17,718)
45,768
79,818
18,693
98,511
$
(330,000)
715,000
(525,000)
(13,137)
400,000
(13,123)
(195,227)
(545)
37,968
(363,176)
381,869
18,693
$
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CONSOLIDATED STATEMENTS OF STOCKHOLDERS ’ EQUITY
Dollar amounts in thousands
Balance – December 31, 2010
Stock Repurchase Program
Issued or purchased pursuant to employee stock
compensation plans
Issued pursuant to employee stock purchase plan
Issued pursuant to directors’ compensation plan
Stock-based compensation
Income tax benefit from equity awards
Tax withholding – stock compensation
Derivative contracts, net
Net income
Balance – December 31, 2011
Stock Repurchase Program
Issued or purchased pursuant to employee stock
compensation plans
Issued pursuant to employee stock purchase plan
Issued pursuant to directors’ compensation plan
Stock-based compensation
Income tax benefit from equity awards
Tax withholding – stock compensation
Derivative contracts, net
Net income
Balance – December 31, 2012
Stock Repurchase Program
Issued or purchased pursuant to employee stock
compensation plans
Issued pursuant to employee stock purchase plan
Issued pursuant to directors’ compensation plan
Stock-based compensation
Income tax benefit from equity awards
Tax withholding – stock compensation
Derivative contracts, net
Net income
Common Stock
($.001 Par Value)
Shares
Amount
Paid-In
Capital in
Excess of
Par
Accumulated
Other
Treasury Stock
(at cost)
Retained Comprehensive
Earnings
Income (Loss) Shares
Amount
Total
Equity
400,291,033
—
$ 400
—
$ 3,045,937
—
$ 1,336,142
—
$ (488)
—
78,524
14,112,610
$ (1,284) $ 4,380,707
(195,227)
(195,227)
2,623,962
11,330
19,745
—
—
—
—
—
402,946,070
—
3,197,476
—
19,648
—
—
—
—
—
406,163,194
—
3,038,767
—
13,612
—
—
—
—
—
3
—
—
—
—
—
—
—
403
—
3
—
—
—
—
—
—
—
406
—
3
—
—
—
—
—
—
—
4,685
(1,623)
309
40,187
879
—
—
—
3,090,374
—
6,021
1,607
321
37,897
241
—
—
—
3,136,461
—
5,486
1,844
344
42,091
488
—
—
—
—
—
—
—
—
—
—
573,333
1,909,475
—
—
—
—
—
—
—
—
525,360
2,434,835
—
—
—
—
—
—
—
—
409,597
—
—
—
—
—
—
70
—
(418)
—
—
—
—
—
—
—
70
—
(348)
—
—
—
—
—
—
—
72
—
—
(666,867)
—
—
—
441,406
—
—
13,965,673
16,978,008
—
(815,385)
—
—
—
472,966
—
—
30,601,262
16,468,648
—
(860,901)
—
—
—
501,887
—
—
—
12,858
—
—
—
(9,683)
—
—
(193,336)
(266,657)
—
11,653
—
—
—
(8,125)
—
—
(456,465)
(277,768)
—
13,260
—
—
—
(8,900)
—
—
4,688
11,235
309
40,187
879
(9,683)
70
573,333
4,806,498
(266,657)
6,024
13,260
321
37,897
241
(8,125)
70
525,360
5,114,889
(277,768)
5,489
15,104
344
42,091
488
(8,900)
72
409,597
Balance – December 31, 2013
409,215,573
$ 409
$ 3,186,714
$ 2,844,432
$ (276)
46,710,896
$ (729,873) $ 5,301,406
See accompanying Notes to Consolidated Financial Statements.
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Note 1. Significant Accounting Policies
Organization and Nature of Operations
Denbury Resources Inc., a Delaware corporation, is a growing, dividend-paying, domestic oil and natural gas
company. Our primary focus is on enhanced oil recovery utilizing CO2, and our operations are focused in two key
operating areas: the Gulf Coast and Rocky Mountain regions. Our goal is to increase the value of our acquired
properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most
significant emphasis relating to tertiary recovery operations.
Principles of Reporting and Consolidation
The consolidated financial statements herein have been prepared in accordance with accounting principles
generally accepted in the United States (“GAAP”) and include the accounts of Denbury and entities in which we hold
a controlling financial interest. Undivided interests in oil and gas joint ventures are consolidated on a proportionate
basis. All intercompany balances and transactions have been eliminated.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and
assumptions that affect the reported amount of certain assets and liabilities, disclosure of contingent assets and
liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during each
reporting period. Management believes its estimates and assumptions are reasonable; however, such estimates
and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially
from such estimates. Significant estimates underlying these financial statements include (1) the fair value of
financial derivative instruments; (2) the estimated quantities of proved oil and natural gas reserves used to compute
depletion of oil and natural gas properties, the related present value of estimated future net cash flows therefrom
and the ceiling test; (3) the estimated quantities of proved and probable CO2 reserves used to compute depletion of
CO2 properties; (4) accruals related to oil and natural gas sales volumes and revenues, capital expenditures and
lease operating expenses; (5) the estimated costs and timing of future asset retirement obligations; (6) estimates
made in the calculation of income taxes; and (7) estimates made in determining the fair values for purchase price
allocations, including goodwill. While management is not aware of any significant revisions to any of its estimates,
there will likely be future revisions to its estimates resulting from matters such as revisions in estimated oil and
natural gas volumes, changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or
pipelines, or other corrections and adjustments common in the oil and natural gas industry, many of which require
retroactive application. These types of adjustments cannot be currently estimated and will be recorded in the period
in which the adjustment occurs.
Reclassifications
Certain prior period amounts have been reclassified to conform to the current year presentation. Such
reclassifications had no impact on our reported net income, current assets, total assets, current liabilities, total
liabilities or stockholders’ equity.
Cash Equivalents
We consider all highly liquid investments to be cash equivalents if they have maturities of three months or less at
the date of purchase.
Restricted Cash
Restricted cash at December 31, 2012 consisted of proceeds from the exchange of oil and gas properties with
Exxon Mobil Corporation and its wholly-owned subsidiary, XTO Energy Inc., (see Note 2, Acquisitions and Divestitures)
previously held by a qualified intermediary and which were restricted for application towards future acquisitions
to enable like-kind-exchange transactions for federal income tax purposes, which exchange transactions took place
in 2013.
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Oil and Natural Gas Properties
Capitalized Costs. We follow the full cost method of accounting for oil and natural gas properties. Under this
method, all costs related to acquisitions, exploration and development of oil and natural gas reserves are capitalized
and accumulated in a single cost center representing our activities, which are undertaken exclusively in the
United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on
undeveloped properties, costs of drilling both productive and nonproductive wells, capitalized interest on
qualifying projects, and general and administrative expenses directly related to exploration and development
activities, and do not include any costs related to production, general corporate overhead or similar activities.
We assign the purchase price of oil and natural gas properties we acquire to proved and unevaluated properties
based on the estimated fair values as defined in the Financial Accounting Standards Board Codification (“FASC”)
Fair Value Measurements and Disclosures topic. Proceeds received from disposals are credited against accumulated
costs except when the sale represents a significant disposal of reserves, in which case a gain or loss would be
recognized. A disposal of 25% or more of our proved reserves would be considered significant.
Depletion and Depreciation. The costs capitalized, including production equipment and future development costs,
are depleted or depreciated using the unit-of-production method, based on proved oil and natural gas reserves as
determined by independent petroleum engineers. Oil and natural gas reserves are converted to equivalent units on a
basis of 6,000 cubic feet of natural gas to one barrel of crude oil.
Under full cost accounting, we may exclude certain unevaluated costs from the amortization base pending
determination of whether proved reserves can be assigned to such properties. The costs classified as unevaluated are
transferred to the full cost amortization base as the properties are developed, tested and evaluated.
Ceiling Test. The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost
or the cost center ceiling. The cost center ceiling is defined as (1) the present value of estimated future net revenues
from proved oil and natural gas reserves before future abandonment costs (discounted at 10%), based on the average
first-day-of-the-month oil and natural gas price for each month during the 12-month period prior to the end of a
particular reporting period; plus (2) the cost of properties not being amortized; plus (3) the lower of cost or estimated
fair value of unproved properties included in the costs being amortized, if any; less (4) related income tax effects.
Our future net revenues from proved oil and natural gas reserves are not reduced for development costs related to
the cost of drilling for and developing CO2 reserves nor those related to the cost of constructing CO2 pipelines, as
those costs have previously been incurred by the Company. Therefore, we include in the ceiling test, as a reduction
of future net revenues, that portion of our capitalized CO2 costs related to CO2 reserves and CO2 pipelines that we
estimate will be consumed in the process of producing our proved oil and natural gas reserves. The fair value of our
oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts
as hedge instruments for accounting purposes. The cost center ceiling test is prepared quarterly. We did not have a
ceiling test write-down during the years ended December 31, 2013, 2012 or 2011.
Joint Interest Operations. Substantially all of our oil and natural gas exploration and production activities are
conducted jointly with others. These financial statements reflect only our proportionate interest in such activities, and
any amounts due from other partners are included in trade receivables.
Tertiary Injection Costs. Our tertiary operations are conducted in reservoirs that have already produced significant
amounts of oil over many years; however, in accordance with the SEC rules and regulations for recording proved
reserves, we cannot recognize proved reserves associated with enhanced recovery techniques, such as CO2 injection,
until there is a production response to the injected CO2, or unless the field is analogous to an existing flood.
We capitalize, as a development cost, injection costs in fields that are in their development stage, which means we
have not yet seen incremental oil production due to the CO2 injections (i.e., a production response). These
capitalized development costs are included in our unevaluated property costs if there are not already proved tertiary
reserves in that field. After we see a production response to the CO2 injections (i.e., the production stage),
injection costs are expensed as incurred, and once proved reserves are recognized, previously deferred unevaluated
development costs become subject to depletion.
CO2 Properties
We own and produce CO2 reserves, a non-hydrocarbon resource, that are used in our tertiary oil recovery
operations on our own behalf and on behalf of other interest owners in enhanced recovery fields, with a portion sold
to third-party industrial users. We record revenue from our sales of CO2 to third parties when it is produced and
sold. Expenses related to the production of CO2 are allocated between volumes sold to third parties and volumes
consumed internally that are directly related to our tertiary production. The expenses related to third-party sales are
recorded in “CO2 discovery and operating expenses,” and the expenses related to internal use are recorded in
“Lease operating expenses” in the Consolidated Statements of Operations, or are capitalized as oil and gas properties
in our Consolidated Balance Sheets, depending on the stage of the tertiary flood that is receiving the CO2 (see
Tertiary Injection Costs above for further discussion).
Costs incurred to search for CO2 are expensed as incurred until proved or probable reserves are established. Once
proved or probable reserves are established, costs incurred to obtain those reserves are capitalized and classified
as “CO2 properties” on our Consolidated Balance Sheets. Capitalized CO2 costs are aggregated by geologic formation
and depleted on a unit-of-production basis over proved and probable reserves.
During 2010 and 2011, we acquired interests in the Riley Ridge Federal Unit (“Riley Ridge”), which contains helium
and CO2 reserves (non-hydrocarbon resources) as well as natural gas reserves (a hydrocarbon resource). It is not
possible to separately identify the capitalized costs related to the development of each product in the commingled
gas stream; thus, these costs are allocated to each product based on the relative future revenue value of each
product line and classified accordingly on the Consolidated Balance Sheets.
The portion of our capitalized CO2 costs related to CO2 reserves and CO2 pipelines that we estimate will be
consumed in the process of producing our proved oil reserves is included in the ceiling test as a reduction to future
net revenues. The remaining net capitalized CO2 properties, equipment and pipelines balance is evaluated for
impairment by comparing the net carrying costs to the expected future net revenues from (1) the production of our
probable and possible tertiary oil reserves and (2) the sale of CO2 to third-party industrial users.
Pipelines and Plants
CO2 used in our tertiary floods is transported to our fields through CO2 pipelines. Costs of CO2 pipelines under
construction are not depreciated until the pipelines are placed into service. Pipelines are depreciated on a straight-line
basis over their estimated useful lives, which range from 15 to 50 years.
Pipelines and plants include the Riley Ridge gas processing facility in southwestern Wyoming. We placed the
Riley Ridge gas processing facility in service in the fourth quarter of 2013. Individual components of the plant are
depreciated on a straight-line basis over their estimated useful lives, which range from 20 to 50 years.
Property and Equipment – Other
Other property and equipment, which includes furniture and fixtures, vehicles, computer equipment and software,
and capitalized leases, is depreciated principally on a straight-line basis over each asset’s estimated useful life.
Vehicles and furniture and fixtures are generally depreciated over a useful life of five to ten years, and computer
equipment and software are generally depreciated over a useful life of three to five years. Leasehold improvements
are amortized over the shorter of the estimated useful life or the remaining lease term.
Leased property meeting certain capital lease criteria is capitalized, and the present value of the related lease
payments is recorded as a liability. Amortization of capitalized leased assets is computed using the straight-line
method over the shorter of the estimated useful life or the initial lease term.
Maintenance and repair costs that do not extend the useful life of the property or equipment are charged to expense
as incurred.
Asset Retirement Obligations
In general, our future asset retirement obligations relate to future costs associated with plugging and abandoning
our oil, natural gas and CO2 wells, removing equipment and facilities from leased acreage, and returning land to
its original condition. The fair value of a liability for an asset retirement obligation is recorded in the period in which
it is incurred, discounted to its present value using our credit-adjusted-risk-free interest rate, and a corresponding
amount capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted each
period, and the capitalized cost is depreciated over the useful life of the related asset. Revisions to estimated
retirement obligations will result in an adjustment to the related capitalized asset and corresponding liability. If the
liability is settled for an amount other than the recorded amount, the difference is recorded to the full cost pool,
unless significant.
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Asset retirement obligations are estimated at the present value of expected future net cash flows and are discounted
using our credit-adjusted-risk-free rate. We utilize unobservable inputs in the estimation of asset retirement
obligations that include, but are not limited to, costs of labor and materials, profits on costs of labor and materials,
the effect of inflation on estimated costs, and the discount rate. Accordingly, asset retirement obligations are
considered a Level 3 measurement under the FASC Fair Value Measurements and Disclosures topic.
Commodity Derivative Contracts
We utilize oil and natural gas derivative contracts to mitigate our exposure to commodity price risk associated with
our future oil and natural gas production. These derivative contracts have historically consisted of options, in the
form of price floors or collars, and fixed price swaps. Our derivative financial instruments are recorded on the balance
sheet as either an asset or a liability measured at fair value. We do not apply hedge accounting to our oil and
natural gas derivative contracts; accordingly, the changes in the fair value of these instruments are recognized in our
Consolidated Statements of Operations in the period of change.
Financial Instruments with Off-Balance-Sheet Risk and Concentrations of Credit Risk
Our financial instruments that are exposed to concentrations of credit risk consist primarily of cash equivalents,
trade and accrued production receivables, and the derivative instruments discussed above. Our cash equivalents
represent high-quality securities placed with various investment-grade institutions. This investment practice limits our
exposure to concentrations of credit risk. Our trade and accrued production receivables are dispersed among
various customers and purchasers; therefore, concentrations of credit risk are limited. We evaluate the credit ratings
of our purchasers, and if customers are considered a credit risk, letters of credit are the primary security obtained
to support lines of credit. We attempt to minimize our credit risk exposure to the counterparties of our oil and natural
gas derivative contracts through formal credit policies, monitoring procedures and diversification. All of our
derivative contracts are with banks, which are part of the syndicate of banks in our bank credit facility, or with their
affiliates. There are no margin requirements with the counterparties of our derivative contracts.
Goodwill and Other Intangible Assets
Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in
the acquisition of a business. Goodwill is not amortized; rather, it is tested for impairment annually during the fourth
quarter and when events or changes in circumstances indicate that it is more likely than not the fair value of a
reporting unit with goodwill has been reduced below its carrying value. The impairment test requires allocating
goodwill and other assets and liabilities to reporting units. However, we have only one reporting unit. To assess
impairment, we have the option to qualitatively assess if it is more likely than not that the fair value of the reporting
unit is less than the carrying value. Absent a qualitative assessment, or, through the qualitative assessment,
if we determine it is more likely than not that the fair value of the reporting unit is less than the carrying value, a
quantitative assessment is prepared to calculate the fair market value of the reporting unit. If it is determined that
the fair value of the reporting unit is less than the carrying value, the recorded goodwill is impaired to its implied fair
value with a charge to operating expense. We completed our annual goodwill impairment assessment during the
fourth quarter of 2013 and did not record any goodwill impairment during 2013, nor have we recorded a goodwill
impairment historically.
The following table summarizes the changes in goodwill for the years ended December 31, 2013 and 2012:
In thousands
Beginning of year balance
Goodwill related to the Thompson Field acquisition
End of year balance
Year Ended December 31,
2013
2012
$ 1,283,590
—
$ 1,283,590
$ 1,236,318
47,272
$ 1,283,590
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Our intangible assets subject to amortization primarily consist of amounts assigned in purchase accounting to
helium production rights at the Riley Ridge Federal Unit in Wyoming and a CO2 purchase contract with ConocoPhillips
to offtake CO2 from the Lost Cabin gas plant in Wyoming. We amortize our helium production rights on a unit-of-
production basis over estimated helium reserves and amortize the CO2 contract intangible asset on a straight-line
basis over the contract term. Total amortization expense related to these assets was $1.3 million during the year
ended December 31, 2013. The following table summarizes the intangible asset value and related accumulated
amortization as of December 31, 2013 and 2012:
In thousands
December 31, 2013
Intangible asset value
Accumulated amortization
Net book value as of December 31, 2013
December 31, 2012
Intangible asset value
Accumulated amortization
Net book value as of December 31, 2012
Helium
Production
Rights
CO2
Purchase
Contract
Total
$ 55,266
—
$ 55,266
$ 55,266
—
$ 55,266
$ 33,931
(1,319)
$ 32,612
$ 89,197
(1,319)
$ 87,878
$ 33,901
—
$ 33,901
$ 89,167
—
$ 89,167
At December 31, 2013, our estimated amortization expense for our intangible assets subject to amortization over
the next five years is as follows:
In thousands
2014
2015
2016
2017
2018
$ 2,748
2,843
2,915
2,915
3,568
The recoverability of the carrying amount of intangible assets is assessed whenever events or changes in
circumstances indicate that the carrying amount of the asset or asset group may not be recoverable. An impairment
loss would be assessed when estimated undiscounted future cash flows from the operation and disposition of the
asset group are less than the carrying amount of the asset group. Measurement of an impairment loss is based on
the excess of the carrying amount of the asset group over its fair value. Fair value is measured using discounted cash
flows or independent appraisals, as appropriate.
Revenue Recognition
Revenue Recognition. Revenue is recognized at the time oil and natural gas is produced and sold. Any amounts
due from purchasers of oil and natural gas are included in accrued production receivable.
We follow the sales method of accounting for our oil and natural gas revenue, whereby we recognize revenue on
all oil or natural gas sold to our purchasers regardless of whether the sales are proportionate to our ownership in
the property. A receivable or liability is recognized only to the extent that we have an imbalance on a specific
property greater than the expected remaining proved reserves. As of December 31, 2013 and 2012, our aggregate oil
and natural gas imbalances were not material to our consolidated financial statements.
We recognize revenue and expenses of purchased producing properties at the time we assume effective control,
commencing from either the closing or purchase agreement date, depending on the underlying terms and
agreements. We follow the same methodology in reverse when we sell properties by recognizing revenue and
expenses of the sold properties until the closing date.
Significant Oil and Natural Gas Purchasers. 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 do not expect that the loss of any purchaser would have a
material adverse effect upon our operations. For the year ended December 31, 2013, three purchasers accounted for
10% or more of our oil and natural gas revenues: Marathon Petroleum Company (33%), Plains Marketing LP (15%), and
Eighty-Eight Oil LLC (10%). For the years ended December 31, 2012 and 2011, two purchasers accounted for 10%
or more of our oil and natural gas revenues: Marathon Petroleum Company (39% and 43% in 2012 and 2011,
respectively) and Plains Marketing LP (17% and 16% in 2012 and 2011, respectively).
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Income Taxes
Income taxes are accounted for using the asset and liability method, under which deferred income taxes are
recognized for the future tax effects of temporary differences between the financial statement carrying amounts and
the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year end. The effect
on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date.
A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the
deferred tax asset will not be realized.
We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position
will be sustained upon examination by the taxing authorities, based on the technical merits of the position. The tax
benefits recognized in the financial statements from such a position are measured based on the largest benefit that
has a greater than 50% likelihood of being realized upon ultimate settlement.
Net Income Per Common Share
Basic net income per common share is computed by dividing the net income attributable to common stockholders
by the weighted average number of shares of common stock outstanding during the period. Diluted net income
per common share is calculated in the same manner, but includes the impact of potentially dilutive securities.
Potentially dilutive securities consist of stock options, stock appreciation rights (“SARs”), nonvested restricted stock
and nonvested performance equity awards. For each of the three years in the period ended December 31, 2013,
there were no adjustments to net income for purposes of calculating basic and diluted net income per common share.
The following is a reconciliation of the weighted average shares used in the basic and diluted net income per
common share calculations for the periods indicated:
In thousands
Basic weighted average common shares
Potentially dilutive securities:
Restricted stock, stock options, SARs and
performance-based equity awards
Diluted weighted average common shares
Year Ended December 31,
2013
2012
2011
366,659
385,205
396,023
3,218
369,877
3,733
388,938
4,935
400,958
Basic weighted average common shares excludes shares of nonvested restricted stock. As these restricted shares
vest, they will be included in the shares outstanding used to calculate basic net income per common share (although
all restricted stock is issued and outstanding upon grant). For purposes of calculating diluted weighted average
common shares, the nonvested restricted stock is included in the computation using the treasury stock method, with
the deemed proceeds equal to the average unrecognized compensation during the period, adjusted for any
estimated future tax consequences recognized directly in equity. Stock options and SARs of 3.6 million, 4.1 million
and 5.0 million shares for the years ended December 31, 2013, 2012 and 2011, respectively, were not included in
the computation of diluted net income per share as their effect would have been antidilutive.
Environmental and Litigation Contingencies
The Company makes judgments and estimates in recording liabilities for contingencies such as environmental
remediation or ongoing litigation. Liabilities are recorded when it is both probable that a loss has been incurred and
such loss is reasonably estimable. Assessments of liabilities are based on information obtained from independent
and in-house experts, loss experience in similar situations, actual costs incurred, and other case-by-case factors. Any
related insurance recoveries are recognized in our financial statements during the period received or at the time
receipt is determined to be virtually certain.
Recent Accounting Pronouncements
Balance Sheet-Offsetting Assets and Liabilities. In December 2011, the Financial Accounting Standards Board
(“FASB”) issued Accounting Standards Update (“ASU”) 2011-11, Disclosure about Offsetting Assets and Liabilities
(“ASU 2011-11”). ASU 2011-11 requires an entity to disclose information about offsetting and related arrangements to
enable users of its financial statements to understand the effect of those arrangements on its financial position. In
January 2013, the FASB issued ASU 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities
(“ASU 2013-01”). The update clarifies that the scope of ASU 2011-11 applies to derivatives accounted for in
accordance with the Derivatives and Hedging topic of the FASC, including bifurcated embedded derivatives,
repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending
transactions that are either offset or subject to an enforceable master netting arrangement or similar agreement.
ASU 2011-11 and ASU 2013-01 became effective for our fiscal year beginning January 1, 2013, and have been
applied retrospectively for all comparative periods presented. The adoption of ASU 2011-11 and ASU 2013-01 did
not affect our consolidated financial statements, but required additional disclosures in the notes thereto.
Note 2. Acquisitions and Divestitures
Fair Value
The FASC Fair Value Measurements and Disclosures topic defines fair value as the price that would be received
to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement
date (often referred to as the “exit price”). The fair value measurement is based on the assumptions of market
participants and not those of the reporting entity. Therefore, entity-specific intentions do not impact the measurement
of fair value unless those assumptions are consistent with market participant views.
The fair value of oil and natural gas properties is based on significant inputs not observable in the market, which
the FASC Fair Value Measurements and Disclosures topic defines as Level 3 inputs. Key assumptions may include
(1) NYMEX oil and natural gas futures (this input is observable); (2) dollar-per-acre values of recent sale transactions
(this input is observable); (3) projections of the estimated quantities of oil and natural gas reserves, including those
classified as proved, probable and possible; (4) estimated oil and natural gas pricing differentials; (5) projections of
future rates of production; (6) timing and amount of future development and operating costs; (7) projected costs
of CO2 (to a market participant); (8) projected reserve recovery factors; and (9) risk-adjusted discount rates.
2013 Acquisition
Cedar Creek Anticline Acquisition. In January 2013, we entered into an agreement to acquire producing assets
in the Cedar Creek Anticline (“CCA”) of Montana and North Dakota from a wholly-owned subsidiary of ConocoPhillips
Company (“ConocoPhillips”) for $1.05 billion ($1.0 billion after final closing adjustments primarily for revenues
and costs of the purchased properties from the January 1, 2013 effective date to the closing date). We closed the
acquisition on March 27, 2013, funding the purchase price with a portion of the cash proceeds from the Bakken
Exchange Transaction (described below). This acquisition meets the definition of a business under the FASC Business
Combinations topic. Accordingly, we estimated the fair value of assets acquired and liabilities assumed as of the
closing date of the acquisition, using a discounted future net cash flow model.
We finalized our estimate of the fair value of assets acquired and liabilities assumed during 2013, after
consideration of final closing adjustments, evaluation of oil and natural gas properties, other assets and related asset
retirement obligations. The following table presents a summary of the fair value of assets acquired and liabilities
assumed in the CCA acquisition:
In thousands
Consideration
Cash consideration (1)
Fair value of assets acquired and liabilities assumed
Oil and natural gas properties
Proved properties
Unevaluated properties
Other assets
Asset retirement obligations
$ 1,001,707
783,507
222,820
2,589
(7,209)
$ 1,001,707
(1) See Note 6, Income Taxes, for additional information regarding the like-kind-exchange transaction utilized to fund this purchase and Note 13,
Supplemental Cash Flow Information, for supplemental cash flow information regarding the cash payment.
For the period from March 27, 2013 to December 31, 2013, we recognized $268.3 million of oil, natural gas,
and related product sales from the property interests acquired in the CCA acquisition; during that same period,
we recognized $194.2 million of net field operating income (defined as oil, natural gas and related product
sales less lease operating expenses, production and ad valorem taxes, and marketing expenses) related to the
CCA acquisition.
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2012 Acquisitions and Divestitures
Bakken Exchange Transaction. In late 2012, we closed a sale and exchange transaction (the “Bakken Exchange
Transaction”) with Exxon Mobil Corporation and its wholly-owned subsidiary XTO Energy Inc. (collectively,
“ExxonMobil”) in which we sold to ExxonMobil our Bakken area assets in North Dakota and Montana in exchange for
(1) $1.3 billion in cash (after closing adjustments), (2) ExxonMobil’s operating interests in Webster Field in Texas
and Hartzog Draw Field in Wyoming, and (3) approximately a one-third overriding royalty ownership interest in
ExxonMobil’s CO2 reserves in LaBarge Field in Wyoming.
This acquisition meets the definition of a business under the FASC Business Combinations topic. We finalized our
estimate of the fair value of assets acquired and liabilities assumed during 2013, after consideration of final closing
adjustments and evaluation of reserves. The following table presents a summary of the fair value of assets acquired
and liabilities assumed in the Bakken Exchange Transaction:
In thousands
Consideration
Fair value of net assets transferred
Less: Fair value of assets acquired and liabilities assumed
Cash (1)
Oil and natural gas properties
Proved properties
Unevaluated properties
CO2 properties
Other property and equipment
Other assets
Other liabilities
Asset retirement obligations
Fair value of net assets acquired
$ 1,866,107
1,277,041
182,289
90,690
314,505
23,424
477
(8,528)
(13,791)
$ 1,866,107
(1) See Note 13, Supplemental Cash Flow Information, for additional information regarding the placement of $1.05 billion of the proceeds in a qualified
trust in order to enable a like-kind exchange transaction for federal income tax purposes.
Thompson Field Acquisition. In June 2012, we acquired a nearly 100% working interest and 84.7% net revenue
interest in Thompson Field for $366.2 million after closing adjustments. The field is located in close proximity to
Hastings Field (an enhanced oil recovery field that we are currently flooding with CO2), which is the current terminus
of the Green Pipeline, which transports CO2 both from the Jackson Dome area near Jackson, Mississippi, and
from various anthropogenic sources along the route of the pipeline. Thompson Field is similar to Hastings Field,
producing oil from the Frio zone at similar depths, and is also a planned future tertiary field. Under the terms of
the Thompson Field acquisition agreement, the seller will retain approximately a 5% gross revenue interest (less
severance taxes) once average monthly oil production exceeds 3,000 Bbls/d after the initiation of CO2 injection.
This acquisition meets the definition of a business under the FASC Business Combinations topic. The fair values
assigned to assets acquired and liabilities assumed in this acquisition have been finalized, and no adjustments have
been made to fair value amounts previously disclosed in our Form 10-K for the period ended December 31, 2012.
The following table presents a summary of the fair value of assets acquired and liabilities assumed in the Thompson
Field acquisition:
In thousands
Consideration
Cash consideration (1)
Less: Fair value of assets acquired and liabilities assumed
Oil and natural gas properties
Proved properties
Unevaluated properties
Pipelines and plants
Other assets
Asset retirement obligations
Goodwill
$ 366,179
305,233
12,023
2,000
2,957
(3,306)
318,907
$ 47,272
(1) See Note 6, Income Taxes, for additional information regarding the like-kind-exchange transaction utilized to fund this purchase and Note 13,
Supplemental Cash Flow Information, for supplemental cash flow information regarding the cash payment.
Unaudited Pro Forma Acquisition Information. The following combined pro forma total revenues and other
income and net income are presented as if the previously discussed CCA acquisition, Bakken Exchange Transaction
and Thompson Field acquisition had occurred on January 1, 2012:
In thousands, except per-share data
Pro forma total revenues and other income
Pro forma net income
Pro forma net income per common share
Basic
Diluted
Year Ended December 31,
2013
2012
$ 2,599,301
437,616
$ 2,570,829
582,033
$
1.19
1.18
$
1.51
1.50
Other 2012 Divestitures. In April 2012, we completed the sale of certain non-operated assets in the Paradox Basin
of Utah for $68.5 million, after final closing adjustments. The sale had an effective date of January 1, 2012. In
February 2012, we completed the sale of certain non-core assets primarily located in central and southern Mississippi
and in southern Louisiana for net proceeds of $141.8 million, after final closing adjustments. The sale had an
effective date of December 1, 2011. We did not record a gain or loss on these divestitures in accordance with the full
cost method of accounting. Certain of our 2012 divestitures were structured as like-kind-exchange transactions for
federal income tax purposes. See Note 6, Income Taxes, for further details.
Note 3. Asset Retirement Obligations
The following table summarizes the changes in our asset retirement obligations for the years ended December 31,
2013 and 2012:
In thousands
Beginning asset retirement obligation
Liabilities incurred and assumed during period
Revisions in estimated retirement obligations
Liabilities settled and sold during period
Accretion expense
Ending asset retirement obligation
Less: current asset retirement obligation (1)
Long-term asset retirement obligation
Year Ended December 31,
2013
2012
$ 106,430
22,216
4,730
(15,523)
8,448
126,301
(6,413)
$ 119,888
$ 93,468
50,956
5,334
(50,556)
7,228
106,430
(3,700)
$ 102,730
(1) Included in “Accounts payable and accrued liabilities” in our Consolidated Balance Sheets.
Liabilities incurred and assumed generally relate to the drilling of incremental wells and liabilities assumed upon
the purchase of additional interests in the CCA during 2013 and the acquisition of Thompson, Webster and Hartzog
Draw fields during 2012. Liabilities settled and sold in 2012 include the plugging of old wells in the Tinsley Field
and sales of non-core assets located in the Paradox Basin of Utah, Gulf Coast region and Bakken area assets in
North Dakota and Montana.
We have escrow accounts that are legally restricted for certain of our asset retirement obligations. The balances of
these escrow accounts were $36.0 million and $35.2 million at December 31, 2013 and 2012, respectively. These
balances are primarily invested in U.S. Treasury bonds, are recorded at amortized cost and are included in “Other
assets” in our Consolidated Balance Sheets. The carrying value of these investments approximates their estimated
fair market value at December 31, 2013 and 2012.
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Note 4. Property and Equipment
The following table presents a summary of our net property and equipment balances as of December 31, 2013
and 2012:
In thousands
Oil and natural gas properties
Proved properties
Unevaluated properties
Total
Accumulated depletion and depreciation
Net oil and natural gas properties
CO2 properties
CO2 properties
Accumulated depletion and depreciation
Net CO2 properties
Pipelines and plants
CO2 pipelines (1)
Plants
Total
Accumulated depletion and depreciation
Net plants and pipelines
Other property and equipment
Other property and equipment
Accumulated depletion and depreciation
Net other property and equipment
Net property and equipment
December 31,
2013
2012
$ 8,945,326
780,481
9,725,807
(3,219,500)
6,506,307
$ 6,963,211
809,154
7,772,365
(2,827,256)
4,945,109
1,117,167
(150,968)
966,199
1,032,653
(119,784)
912,869
1,681,774
527,786
2,209,560
(134,697)
2,074,863
466,969
(163,060)
303,909
$ 9,851,278
1,632,255
402,871
2,035,126
(99,185)
1,935,941
417,207
(134,016)
283,191
$ 8,077,110
(1) Amounts include $48.4 million of CO2 pipelines at December 31, 2013 that were under construction and not subject to depreciation during 2013.
A summary of the unevaluated property costs excluded from oil and natural gas properties being amortized at
December 31, 2013, and the year in which the costs were incurred follows:
In thousands
2013
2012
2011
2010 and Prior
Total
Property acquisition costs
Exploration and development
Capitalized interest
Total
$ 215,822
41,157
25,222
$ 282,201
$ 109,275
22,080
12,084
$ 143,439
$ 12,543
7,408
6,018
$ 25,969
$ 317,226
10,825
821
$ 328,872
$ 654,866
81,470
44,145
$ 780,481
December 31, 2013
Costs Incurred During:
Our 2013 property acquisition costs were primarily related to the fair value allocated to the purchase of additional
interests in the CCA. Our 2012 property acquisition costs were primarily related to the fair value allocated to our
Hartzog Draw and Thompson fields. Property acquisition costs for 2010 and prior were primarily related to the fair
value allocated to CO2 tertiary potential at our Cedar Creek Anticline properties, acquired as part of the merger
with Encore Acquisition Company (“Encore”), as well as CO2 tertiary potential at Conroe Field. Exploration and
development costs shown as uneva luated properties are primarily associated with our tertiary oil fields that are under
development but did not have proved reserves at December 31, 2013. The most significant development costs
incurred during 2013, 2012 and 2011 relate to development in preparation for the CO2 flood at Grieve field, which
began in 2013. We have not yet recognized proved reserves in this field.
During 2013, we established proved reserves at Bell Creek Field and, as a result, transferred $417.6 million of costs
incurred on these projects into the amortization base. Costs are transferred into the amortization base on an
ongoing basis as projects are evaluated and proved reserves established or impairment determined. We review the
excluded properties for impairment at least annually. We currently estimate that evaluation of most of these
properties and the inclusion of their costs in the amortization base is expected to be completed within five to ten
years. Until we are able to determine whether there are any proved reserves attributable to the above costs, we are
not able to assess the future impact on the amortization rate of the full cost pool.
Note 5. Long-Term Debt
The following long-term debt and capital lease obligations were outstanding as of December 31, 2013 and 2012:
In thousands
Bank Credit Agreement
91/2% Senior Subordinated Notes due 2016, including premium of $9,118
93/4% Senior Subordinated Notes due 2016, including discount of $13,569
81/4% Senior Subordinated Notes due 2020
63/8% Senior Subordinated Notes due 2021
45/8% Senior Subordinated Notes due 2023
Other Subordinated Notes, including premium of $16 and $25, respectively
Pipeline financings
Capital lease obligations
Total
Less: current obligations
Long-term debt and capital lease obligations
December 31,
2013
2012
$
340,000
—
—
996,273
400,000
1,200,000
3,823
228,167
128,519
3,296,782
(36,157)
$ 3,260,625
$
700,000
234,038
412,781
996,273
400,000
—
3,832
236,244
158,260
3,141,428
(36,966)
$ 3,104,462
The ultimate parent company in our corporate structure, Denbury Resources Inc. (“DRI”), is the sole issuer of all
of our outstanding senior subordinated notes. DRI has no independent assets or operations. Each of the subsidiary
guarantors of such notes is 100% owned, directly or indirectly, by DRI; any subsidiaries of DRI other than the
subsidiary guarantors are minor subsidiaries, and the guarantees of the notes are full and unconditional and joint
and several.
$1.6 Billion Revolving Credit Agreement
In March 2010, we entered into a $1.6 billion revolving credit agreement with JPMorgan Chase Bank, N.A.
(“JPMorgan”), as administrative agent, and other lenders party thereto (as amended, the “Bank Credit Agreement”).
Availability under the Bank Credit Agreement is subject to a borrowing base, which is redetermined semi-annually
on or prior to May 1 and November 1 of each year, and additionally upon requested special redeterminations.
The borrowing base is adjusted at the lenders’ discretion and is based in part upon external factors over which
we have no control (including approval by the lenders party to the Bank Credit Agreement). If our outstanding
credit under the Bank Credit Agreement exceeds the then effective borrowing base, we would be required to repay
the excess amount over a period not to exceed four months. As part of the semi-annual review completed in
October 2013 pursuant to the terms of the Bank Credit Agreement, our borrowing base was reaffirmed at $1.6 billion
effective November 1, 2013, with approval by all of the lenders. The weighted average interest rate on borrowings
outstanding as of December 31, 2013 under the Bank Credit Agreement was 1.9%. Loans under the Bank Credit
Agreement mature in May 2016.
The Bank Credit Agreement is secured by substantially all of the proved oil and natural gas properties of DRI’s
restricted subsidiaries (which does not include minor subsidiaries) and by the equity interests of such restricted
subsidiaries. In addition, our obligations under the Bank Credit Agreement are guaranteed jointly and severally by
DRI’s restricted subsidiaries.
The Bank Credit Agreement contains several restrictive covenants including, among others:
• a requirement to maintain a current ratio, as determined under the Bank Credit Agreement, of not less than
1.0 to 1.0;
• a requirement to maintain a maximum permitted ratio of consolidated total debt to Consolidated EBITDA
(as defined in the Bank Credit Agreement) of DRI and its restricted subsidiaries of not more than 4.25 to 1.0;
• a prohibition against incurring debt, subject to permitted exceptions; and
• a limitation on the aggregate amount of forecasted oil and natural gas production that can be economically
hedged with oil or natural gas derivative contracts.
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Under the Bank Credit Agreement, we are permitted to make unlimited distributions in the form of repurchases of
Denbury common stock and payments of cash dividends on Denbury common stock, provided that (1) prior to
and after making any such distribution (a) no default or borrowing base deficiency exists, and (b) we are in
compliance with the first two financial covenants described immediately above (calculated on a pro forma basis after
giving effect to the making of any such distribution), and (2) we have minimum availability of at least 10% of our
borrowing base on the date such distribution is made.
Loans under the Bank Credit Agreement are subject to varying rates of interest based on (1) the total outstanding
credit in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan. Eurodollar
loans bear interest at the Adjusted Eurodollar Rate (as defined in the Bank Credit Agreement) plus the applicable
margin in a range from 1.5% to 2.5% based on the ratio of outstanding credit to the borrowing base, and base rate
loans bear interest at the Base Rate (as defined in the Bank Credit Agreement) plus the applicable margin in a range
from 0.5% to 1.5% based on the ratio of outstanding credit to the borrowing base. The “Eurodollar rate” for any
interest period (either one, two, three, six, and, if available to all lenders, nine or twelve months, as selected by us)
is the rate per year equal to LIBOR, as published by Reuters or another source designated by JPMorgan, for
deposits in dollars for a similar interest period. The “base rate” is calculated as the highest of (1) the annual rate of
interest announced by JPMorgan as its “prime rate,” (2) the federal funds effective rate plus 0.5%, and (3) the
Adjusted Eurodollar Rate (as defined in the Bank Credit Agreement) for a one-month interest period plus 1.0%. We
incur a commitment fee of either 0.375% or 0.5%, based on the ratio of outstanding credit to the borrowing base,
on the unused availability under the Bank Credit Agreement.
Senior Subordinated Notes
Repurchase and Redemption of 9½% Notes and 9¾% Notes. In January 2013, we commenced cash tender
offers to purchase the outstanding $426.4 million principal amount of our 9¾% Senior Subordinated Notes due 2016
(the “9¾% Notes”) at 105.425% of par and the outstanding $224.9 million principal amount of our 9½% Senior
Subordinated Notes due 2016 (the “9½% Notes”) at 106.869% of par. During February 2013, we accepted for purchase
$191.7 million principal amount of the outstanding 9¾% Notes and $186.7 million principal amount of the
outstanding 9½% Notes. The purchases under these tender offers were funded by a portion of the proceeds received
in February 2013 from the issuance of our 4 5/8% Senior Subordinated Notes due 2023 (the “2023 Notes”). In
March 2013, we repurchased all of the remaining $234.7 million principal amount outstanding of our 9¾% Notes at
104.875% of par. In May 2013, we repurchased all of the remaining $38.2 million principal amount outstanding of
our 9½% Notes at 104.75% of par.
We recognized a loss associated with the debt repurchases of $44.7 million during the year ended December 31,
2013, consisting of both premium payments made to repurchase or redeem the 9¾% Notes and 9½% Notes and
the elimination of unamortized debt issuance costs, discounts and premiums related to these notes. The loss is
included in our Consolidated Statement of Operations under the caption “Loss on early extinguishment of debt”.
8¼% Senior Subordinated Notes due 2020. In February 2010, we issued $1.0 billion of 8¼% Senior Subordinated
Notes due 2020 (the “2020 Notes”) for net proceeds after underwriting discounts and commissions of $980 million.
The 2020 Notes, which carry a coupon rate of 8.25%, were sold at par. We subsequently redeemed $3.7 million
principal amount of the 2020 Notes, as required under the indenture governing the 2020 Notes.
The 2020 Notes mature on February 15, 2020, and interest is payable on February 15 and August 15 of each year.
We may redeem the 2020 Notes in whole or in part at our option beginning February 15, 2015, at a redemption price
of 104.125% of the principal amount, and at declining redemption prices thereafter, as specified in the indenture.
Prior to February 15, 2015, we may redeem 100% of the principal amount of the 2020 Notes at a price equal to 100%
of the principal amount plus a “make-whole” premium and accrued and unpaid interest. The 2020 Notes are not
subject to any sinking fund requirements.
6 3/8% Senior Subordinated Notes due 2021. In February 2011, we issued $400 million of 6 3/8% Senior
Subordinated Notes due 2021 (“2021 Notes”). The 2021 Notes, which carry a coupon rate of 6.375%, were sold at par.
The net proceeds of $393 million were used to repurchase a portion of our 7½% Senior Subordinated Notes due
2013 (the “2013 Notes”) and 7½% Senior Subordinated Notes due 2015 (the “2015 Notes”) (see 2011 Redemption of
2013 Notes and 2015 Notes below).
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The 2021 Notes mature on August 15, 2021, and interest is payable on February 15 and August 15 of each year.
We may redeem the 2021 Notes in whole or in part at our option beginning August 15, 2016 at a redemption price of
103.188% of the principal amount, and at declining redemption prices thereafter, as specified in the indenture.
Prior to August 15, 2014, we may at our option redeem up to an aggregate of 35% of the principal amount of the 2021
Notes at a price of 106.375% of par with the proceeds of certain equity offerings. In addition, at any time prior to
August 15, 2016, we may redeem 100% of the principal amount of the 2021 Notes at a price equal to 100% of the
principal amount plus a “make-whole” premium and accrued and unpaid interest. The 2021 Notes are not subject
to any sinking fund requirements.
4 5/8% Senior Subordinated Notes due 2023. In February 2013, we issued $1.2 billion of 2023 Notes. The 2023
Notes, which carry a coupon rate of 4.625%, were sold at par. The net proceeds, after issuance costs, of $1.18 billion
were used to repurchase or redeem our 9½% Notes and 9¾% Notes (see Repurchase and Redemption of 9½% Notes
and 9¾% Notes above) and to pay down a portion of outstanding borrowings under our Bank Credit Agreement.
The 2023 Notes mature on July 15, 2023, and interest is payable on January 15 and July 15 of each year,
commencing July 15, 2013. We may redeem the 2023 Notes in whole or in part at our option beginning January 15,
2018, at a redemption price of 102.313% of the principal amount, and at declining redemption prices thereafter, as
specified in the indenture. Prior to January 15, 2016, we may at our option redeem up to an aggregate of 35% of the
principal amount of the 2023 Notes at a redemption price of 104.625% of par with the proceeds of certain equity
offerings. In addition, at any time prior to January 15, 2018, we may redeem 100% of the principal amount of the 2023
Notes at a redemption price equal to 100% of the principal amount plus a “make-whole” premium and accrued and
unpaid interest.
Restrictive Covenants in Indentures for Senior Subordinated Notes. Each of the indentures for the 2020 Notes,
2021 Notes and 2023 Notes contains certain covenants which are generally consistent and which restrict our ability
and the ability of our restricted subsidiaries to take or permit certain actions, including restrictions on our ability and
the ability of our restricted subsidiaries to (1) incur additional debt; (2) make investments; (3) create liens on our
assets or the assets of our restricted subsidiaries; (4) create restrictions on the ability of our restricted subsidiaries to
pay dividends or make other payments to DRI or other restricted subsidiaries; (5) engage in transactions with our
affiliates; (6) transfer or sell assets or subsidiary stock; (7) consolidate, merge or transfer all or substantially all of our
assets and the assets of our restricted subsidiaries; and (8) make restricted payments (which includes paying
dividends on our common stock or redeeming, repurchasing or retiring such stock or subordinated debt), provided
that the restricted payments covenant in the indenture for the 2023 Notes (the “2023 Indenture”) permits us in certain
circumstances to make unlimited restricted payments so long as we maintain a ratio of total debt to EBITDA (both
as defined in the 2023 Indenture) of at least 2.5 to 1 (both before and after giving effect to any restricted payment),
although we will not be able to realize the practical benefit of the restricted payment covenant flexibility in the 2023
Indenture until the 2020 Notes and 2021 Notes have been redeemed or retired.
2011 Redemption of 2013 Notes and 2015 Notes. Pursuant to cash tender offers, during 2011 we repurchased
$225 million in principal of our 2013 Notes and $300 million in principal of our 2015 Notes. We recognized a $16.1 million
loss during the year ended December 31, 2011 associated with the debt repurchases, which is included in our
Consolidated Statement of Operations under the caption “Loss on early extinguishment of debt”.
Pipeline Financings
In May 2008, we closed two transactions with Genesis Energy, L.P. (“Genesis”) involving two of our pipelines.
The NEJD Pipeline system included a 20-year financing lease, and the Free State Pipeline included a long-term
transportation service agreement. We recorded both of these transactions as financing leases.
Debt Issuance Costs
In connection with the issuance of our outstanding long-term debt, we have incurred debt issuance costs, which
are being amortized to interest expense using the effective interest method over the term of each related facility.
Remaining unamortized debt issuance costs were $58.9 million and $56.5 million at December 31, 2013 and 2012,
respectively. These balances are included in “Other assets” in our Consolidated Balance Sheets.
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Indebtedness Repayment Schedule
At December 31, 2013, our indebtedness, including our capital and financing lease obligations but excluding the
discount and premium on our senior subordinated debt, is payable over the next five years and thereafter as follows:
In thousands
2014
2015
2016
2017
2018
Thereafter
Total indebtedness
Note 6. Income Taxes
Our income tax provision (benefit) is as follows:
In thousands
Current income tax expense (benefit)
Federal
State
Total current income tax expense
Deferred income tax expense (benefit)
Federal
State
Total deferred income tax expense
Total income tax expense
$
36,156
37,634
377,933
36,855
31,899
2,776,288
$ 3,296,765
Year Ended December 31,
2013
2012
2011
$
393
9,864
10,257
222,559
(33)
222,526
$ 232,783
$ 57,720
18,034
75,754
239,862
15,881
255,743
$ 331,497
$ (12,552)
20,801
8,249
329,715
12,748
342,463
$ 350,712
For federal income tax purposes, we structured the 2012 divestitures of our Bakken area assets and certain non-
core assets as like-kind-exchange transactions for interests acquired in Thompson, Webster, Hartzog Draw and
LaBarge fields in 2012 and the CCA Acquisition in 2013 (see Note 2, Acquisitions and Divestitures), thereby deferring
the majority of the taxable gain on those divestitures. The increase in current taxes during 2012 is primarily
due to the taxable gain recognized in the Bakken Exchange Transaction that we were unable to defer through a
like-kind-exchange transaction.
At December 31, 2013, we had tax-effected federal net operating loss carryforwards (“NOLs”) totaling
$20.2 million, state NOLs totaling $41.4 million, an estimated $15.0 million of enhanced oil recovery credits to carry
forward related to our tertiary operations, and $34.8 million of alternative minimum tax credits. Our state NOLs
expire in various years, starting in 2018, although most do not begin to expire until 2024. Our enhanced oil recovery
credits will begin to expire in 2025.
At December 31, 2013, we had $13.0 million of excess tax benefits related to stock-based compensation that was
not recorded as an increase to additional paid-in capital in the period that the stock award vested and/or was
exercised. At the time these excess tax benefits reduce current taxes payable and thus, are deemed to be realized by
the Company, a corresponding increase to additional paid-in capital will be recognized.
Deferred income taxes reflect the available tax carryforwards and the temporary differences based on tax laws and
statutory rates in effect at the December 31, 2013 and 2012 balance sheet dates. We believe that we will be able
to realize all of our deferred tax assets at December 31, 2013, and therefore, have provided no valuation allowance
against our deferred tax assets.
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Significant components of our deferred tax assets and liabilities as of December 31, 2013 and 2012 are as follows:
In thousands
Deferred tax assets
Loss carryforwards – federal
Loss carryforwards – state
Tax credit carryover
Derivative contracts
Enhanced oil recovery credit carryforwards
Stock-based compensation
Other
Total deferred tax assets
Deferred tax liabilities
Property and equipment
Other
Total deferred tax liabilities
Total net deferred tax liability
$
December 31,
2013
2012
20,247
41,379
34,837
21,341
14,974
34,635
37,679
205,092
$
—
35,007
34,837
7,252
17,346
28,387
37,226
160,055
(2,541,426)
(10,206)
(2,551,632)
$ (2,346,540)
(2,277,388)
(6,963)
(2,284,351)
$ (2,124,296)
Our reconciliation of income tax expense computed by applying the U.S. federal statutory rate and the reported
effective tax rate on income from continuing operations is as follows:
In thousands
Year Ended December 31,
2013
2012
2011
Income tax provision calculated using the federal statutory income tax rate
State income taxes, net of federal income tax benefit
Effect of statutory rate change
Other
Total income tax expense
$ 224,833
13,518
(4,178)
(1,390)
$ 232,783
$ 299,900
30,955
(429)
1,071
$ 331,497
$ 323,416
29,555
(578)
(1,681)
$ 350,712
We file consolidated and separate income tax returns in the U.S. federal jurisdiction and in many state
jurisdictions. Our income tax returns for tax years ending 2010 through 2012 currently remain subject to examination
by the appropriate taxing authorities. We have not paid any significant interest or penalties associated with our
income taxes.
Note 7. Stockholders’ Equity
Stock Repurchase Program
In October 2011, we commenced a common share repurchase program for up to $500 million of Denbury
common shares, as approved by the Company’s Board of Directors. 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 $1.162 billion. The program has no pre-established ending date and may be suspended or discontinued at any
time. We are not obligated to repurchase any dollar amount or specific number of shares of our common stock under
the program. The following table presents a summary of repurchases under our share repurchase program:
Dollar amounts in thousands, except per-share data
Total amount repurchased
Weighted average price per share
Denbury common stock repurchased (shares)
Total Repurchases
Since Inception
Year Ended December 31,
2013
2012
2011
739,652
$
$
15.55
47,559,266
277,768
$
$
16.87
16,468,648
$ 266,657
$
15.71
16,978,008
$ 195,227
$
13.83
14,112,610
As of December 31, 2013, we were authorized to repurchase an additional $422.3 million of common stock
under this repurchase program. We account for treasury stock using the cost method and include treasury stock as
a component of stockholders’ equity. See Note 14, Subsequent Events, for additional information.
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Employee Stock Purchase Plan
We have an Employee Stock Purchase Plan that is authorized to issue up to 11,900,000 shares of common stock.
As of December 31, 2013, there were 1,601,230 authorized shares remaining to be issued under the plan. In accordance
with the plan, eligible employees may contribute up to 10% of their base salary, and we match 75% of their
contribution. The combined funds are used to purchase previously unissued Denbury common stock or treasury stock
that we purchased in the open market for that purpose, in either case, based on the market value of our common
stock at the end of each quarter. We recognize compensation expense for the 75% Company match portion, which
totaled $6.5 million, $5.7 million and $4.8 million for the years ended December 31, 2013, 2012 and 2011, respectively.
This plan is administered by the Compensation Committee of our Board of Directors.
401(k) Plan
We offer a 401(k) plan to which employees may contribute tax-deferred earnings subject to IRS limitations. We
match 100% of an employee’s contribution, up to 6% of compensation, as defined by the plan, which is vested
immediately. During 2013, 2012 and 2011, our matching contributions to the 401(k) Plan were approximately $9.0 million,
$8.0 million and $7.1 million, respectively.
Note 8. Stock Compensation Plans
Stock Incentive Plans
We have two stock compensation plans. The first plan (providing only for the issuance of stock options) has been
in existence since 1995 (the “1995 Plan”) and expired in August 2005 (although options granted under the 1995 Plan
prior to that time can remain outstanding for up to 10 years). The second plan, the 2004 Omnibus Stock and Incentive
Plan (the “2004 Plan”), was approved by the stockholders in May 2004 and will expire in May 2024. The 2004 Plan
provides for the issuance of incentive and non-qualified stock options, restricted stock awards, restricted stock units,
SARs settled in stock, and performance awards that may be issued to officers, employees, directors and consultants.
Awards covering a total of 34.5 million shares of common stock have been authorized for issuance pursuant to the
2004 Plan, of which awards covering no more than 27.2 million shares may be issued in the form of restricted stock
or performance-vesting awards. At December 31, 2013, 10.8 million shares were available under the 2004 Plan for
future issuance of awards, all of which could be issued in the form of restricted stock or performance vesting awards.
Our incentive compensation program is administered by the Compensation Committee of our Board of Directors.
Prior to January 1, 2006, we granted incentive and non-qualified stock options to our employees. Effective January
1, 2006, we completely replaced the use of stock options for employees with SARs settled in stock, as SARs are less
dilutive to our stockholders while providing an employee with essentially the same economic benefits as stock
options. The stock options and SARs generally become exercisable over a three- or four-year vesting period, with the
specific terms of vesting determined at the time of grant based on guidelines established by the Compensation
Committee of the Board of Directors. The stock options and SARs expire over terms not to exceed 10 years from the
date of grant, 90 days after termination of employment, 90 days or one year after permanent disability, depending
on the plan, or one year after the death of the optionee. The stock options and SARs are granted at the fair market
value at the time of grant, which is defined in the 2004 Plan as the closing price on the NYSE on the date of grant.
Holders of restricted stock awards have the rights and privileges of owning the shares (including voting rights)
except that the holders are not entitled to delivery of a portion thereof until certain requirements are met. Beginning
in 2014, restricted stock awards granted by the Company provide the holders with forfeitable dividend rights until
the award vests. Restricted stock awards vest over three-to-four-year vesting periods, with the specific terms of vesting
determined at the time of grant.
Annually, the Board of Directors grants performance-based equity awards to officers of Denbury. These
performance-based awards generally vest over 1.25 to 3.25 years and the number of performance-based shares earned
(and eligible to vest) during the performance period will depend upon two sets of factors: (1) our level of success
in achieving specifically identified performance targets (“Performance-based Operational Awards”) and (2) performance
of our stock relative to that of a designated peer group (“Performance-based TSR Awards”). Generally, one-half
of the maximum number of shares that could be earned under the performance-based awards will be earned for
performance at the designated target levels (100% target vesting levels) or upon any earlier change of control,
and twice the number of shares will be earned if the maximum target levels are met. If performance is below the
designated minimum levels for all performance targets, no performance-based shares will be earned.
Performance-based Operational Awards are valued using the fair market value of Denbury stock on the grant date,
and Performance-based TSR Awards are valued using a Monte Carlo simulation.
Stock-based compensation expense associated with our field employees is included in “Lease operating
expense,” while such expense associated with non-field employees is included in “General and administrative
expenses” in the Consolidated Statements of Operations. Stock-based compensation associated with our
employees involved in exploration and drilling activities is capitalized as part of “Oil and natural gas properties”
in the Consolidated Balance Sheets.
Stock-based compensation costs for the years ended December 31, 2013, 2012 and 2011, are as follows:
In thousands
Stock-based compensation expensed:
General and administrative expenses
Lease operating expenses
Other expenses
Total stock-based compensation expensed
Stock-based compensation capitalized
Total cost of stock-based compensation arrangements
Year Ended December 31,
2013
2012
2011
$ 30,429
2,574
—
33,003
9,088
$ 42,091
$ 26,463
2,847
—
29,310
8,587
$ 37,897
$ 30,256
2,621
313
33,190
6,998
$ 40,188
Income tax benefit recognized for stock-based compensation arrangements
$ 12,541
$ 11,284
$ 12,612
Stock Options and SARs
The fair value of each SAR award is estimated on the date of grant using the Black-Scholes option pricing model
with the assumptions noted in the following table. The risk-free rate for periods within the contractual life of the
option is based on the U.S. Treasury yield curve in effect at the time of grant. The expected life of stock options and
SARs granted was derived from examination of our historical option grants and subsequent exercises. The
contractual terms (cliff vesting and graded vesting) are evaluated separately for the expected life, as the exercise
behavior for each is different. Expected volatilities are based on the historical volatility of our common stock. Implied
volatility was not used in this analysis, as our tradable call option terms are short and the trading volume is low.
Weighted average fair value of SARs granted
Risk-free interest rate
Expected life
Expected volatility
Dividend yield
2013
$6.72
0.67%
2012
$8.90
0.79%
2011
$9.68
1.74%
3.6 to 4.8 years
4.0 to 5.0 years
4.0 to 5.0 years
50.4%
—%
64.9%
—%
63.3%
—%
The following is a summary of our stock option and SAR activity:
Outstanding at December 31, 2012
Granted
Exercised
Forfeited
Expired
Outstanding at December 31, 2013
Exercisable at end of period
Number
of Awards
10,445,135
720,859
(1,970,426)
(113,509)
(95,144)
8,986,915
6,632,141
Weighted
Average
Exercise Price
$ 14.75
16.95
9.33
17.31
22.74
16.00
$ 15.51
Weighted
Average
Remaining
Contractual
Life
(in years)
Aggregate
Intrinsic
Value
(in thousands)
3.3
2.7
$ 19,319
$ 18,970
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The following is a summary of the total intrinsic value of stock options and SARs exercised and grant-date fair
value of stock options and SARs vested:
In thousands
Intrinsic value of stock options exercised
Grant-date fair value of stock options and SARs vested
Year Ended December 31,
2013
$ 17,287
12,852
2012
2011
$ 17,315
26,391
$ 20,463
11,416
As of December 31, 2013, there was $8.0 million of total compensation cost to be recognized in future periods
related to nonvested stock option and SAR share-based compensation arrangements. The cost is expected to
be recognized over a weighted-average period of 1.7 years. The following is a summary of cash received from stock
option exercises under share-based payment arrangements and tax benefits realized from the exercises of stock
options and SARs:
In thousands
Cash received from stock option exercises
Tax benefit realized for the exercises of stock options and SARs
Restricted Stock – 2004 Plan
Year Ended December 31,
2013
$ 5,487
437
2012
$ 6,022
458
2011
$ 4,685
539
As of December 31, 2013, there was $30.6 million of unrecognized compensation expense related to nonvested
restricted stock grants. This unrecognized compensation cost is expected to be recognized over a weighted-
average period of 2.1 years. The following is a summary of the total vesting date fair value of restricted stock
under the 2004 Plan:
In thousands
Fair value of restricted stock vested
Year Ended December 31,
2013
2012
2011
$ 21,529
$ 22,332
$ 12,355
A summary of the status of our nonvested restricted stock grants issued under our 2004 Plan and the changes
during the year ended December 31, 2013 is presented below:
Nonvested at December 31, 2012
Granted
Vested
Forfeited
Nonvested at December 31, 2013
Restricted Stock – Legacy Encore Plan
Number
of Shares
3,406,207
1,805,467
(1,310,347)
(165,917)
3,735,410
Weighted
Average
Grant-Date
Fair Value
$ 15.60
16.96
16.21
17.23
15.97
In February 2010, prior to the consummation of the merger with Encore, Encore issued a restricted stock grant to
its employees under the Encore Acquisition Company 2008 Incentive Stock Plan (“Encore Plan”). At the time of the
merger with Encore, the shares were converted into shares of Denbury restricted stock. The shares vest ratably over
a four-year graded vesting period; however, legacy Encore employees who terminated their employment for Good
Reason, as defined by Encore’s legacy Employee Severance Protection Plan, automatically vested in their awards
upon termination. The remaining nonvested restricted stock issued under the Encore Plan is scheduled to vest during
the first quarter of 2014. The following is a summary of the total vesting date fair value of restricted stock under the
Encore Plan:
In thousands
Fair value of restricted stock vested
Year Ended December 31,
2013
$ 512
2012
$ 584
2011
$ 2,259
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A summary of the status of the non-vested restricted stock grants under the Encore Plan and the changes during
the year ended December 31, 2013 is presented below:
Nonvested at December 31, 2012
Vested
Forfeited
Nonvested at December 31, 2013
Performance-Based Equity Awards
Number
of Shares
56,258
(31,140)
(3,377)
21,741
Weighted
Average
Grant-Date
Fair Value
$ 15.43
15.43
15.43
15.43
During 2013 and 2012, we granted Performance-Based Operational Awards and Performance-Based TSR Awards to
our officers. As of December 31, 2013, there was $5.4 million of unrecognized compensation expense related to
nonvested performance-based equity awards. This unrecognized compensation cost is expected to be recognized
over a weighted-average period of 1.6 years. The range of assumptions used in the Monte Carlo simulation valuation
approach for Performance-based TSR Awards, which were granted for the first time during 2012, are as follows:
Weighted average fair value of Performance-based TSR Award granted
Risk-free interest rate
Expected life
Expected volatility
Dividend yield
December 31,
2013
$ 20.08
0.41%
2012
$ 24.68
0.42%
3.0 years
2.8 years
42.3%
—%
45.2%
—%
A summary of the status of the nonvested performance-based equity awards (presented at the target level) during
the year ended December 31, 2013 is as follows:
Nonvested at December 31, 2012
Granted
Vested (1)
Forfeited
Nonvested at December 31, 2013
Performance-Based
Operational Awards
Performance-Based
TSR Awards
Number
of Awards
100,193
215,258
(100,193)
(5,784)
209,474
Weighted
Average
Grant-Date
Fair Value
$ 17.27
16.77
17.27
16.77
16.77
Number
of Awards
86,917
209,474
—
—
296,391
Weighted
Average
Grant-Date
Fair Value
$ 24.68
20.08
—
—
21.43
(1) During 2013, the 2012 annual Performance-based Operational Awards vested, and award holders received shares equivalent to 136% of the
number of target-level shares.
The following is a summary of the total vesting date fair value of performance-based equity awards:
In thousands
Vesting date fair value of Performance-based Operational Awards
Year Ended December 31,
2013
$ 2,541
2012
2011
$ 2,191
$ 10,892
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Note 9. Commodity Derivative Contracts
We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; therefore, the changes
in the fair values of these instruments are recognized in income in the period of change. These fair value changes,
along with the cash settlements of expired contracts, are shown under “Commodity derivatives expense (income)” in
our Consolidated Statements of Operations.
From time to time, we enter into various oil and natural gas derivative contracts to provide an economic hedge of
our exposure to commodity price risk associated with anticipated future oil and natural gas production. We do not
hold or issue derivative financial instruments for trading purposes. These contracts have consisted of price floors,
collars and fixed price swaps. The production that we hedge has varied from year to year depending on our levels of
debt and financial strength and expectation of future commodity prices. We currently employ a strategy to hedge a
portion of our forecasted production approximately 18 months to two years in the future from the current quarter, as
we believe it is important to protect our future cash flow to provide a level of assurance for our capital spending in
those future periods in light of current worldwide economic uncertainties and commodity price volatility.
We manage and control market and counterparty credit risk through established internal control procedures that
are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal
credit policies, monitoring procedures, and diversification, and all of our commodity derivative contracts are with
parties that are lenders under our Bank Credit Agreement. As of December 31, 2013, all of our outstanding
derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts
can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy
to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject
to enforceable master netting arrangements.
The following table summarizes our commodity derivative contracts, none of which are classified as
hedging instruments:
Contract Prices (1)
Year
Months
Type of
Contract
Pricing
Index
Volume (2)
Range
Weighted Average Price
Floor
Swap
Ceiling
Oil Contracts:
2014
2015
Jan – Mar
Apr – June
July – Sept
Oct – Dec
Jan – Mar
Jan – Mar
Apr – June
Apr – June
July – Sept
July – Sept
Swap
Swap
Swap
Swap
Collar
Collar
Collar
Collar
Collar
Collar
NYMEX
NYMEX
NYMEX
NYMEX
NYMEX
LLS
NYMEX
LLS
NYMEX
LLS
58,000
58,000
58,000
58,000
38,000
20,000
38,000
20,000
38,000
20,000
$ 91.67 – 95.95
91.67 – 95.95
90.00 – 93.50
90.00 – 93.50
$ 80.00 – 100.90
85.00 – 104.00
80.00 – 95.25
85.00 – 103.00
80.00 – 95.25
85.00 – 102.60
$ 93.53
93.53
92.52
92.52
$ —
—
—
—
—
—
$ —
—
—
—
$ 80.00
85.00
80.00
85.00
80.00
85.00
$ —
—
—
—
$ 96.96
101.45
94.62
102.01
95.04
100.69
Natural Gas Contracts:
2014
Jan – Dec
Collar
NYMEX
14,000
$ 4.00 –
4.47
$ —
$ 4.00
$ 4.45
(1) Contract prices are stated in $/Bbl and $/MMBtu for oil and natural gas contracts, respectively.
(2) Contract volumes are stated in Bbl/d and MMBtu/d for oil and natural gas contracts, respectively.
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Note 10. Fair Value Measurements
The FASC Fair Value Measurements and Disclosures topic defines fair value as the price that would be received
to sell an asset or would be paid to transfer a liability in an orderly transaction between market participants at the
measurement date (exit price). We utilize market data or assumptions that market participants would use in
pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation
technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily
apply the market approach for recurring fair value measurements and endeavor to utilize the best available
information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize
the use of unobservable inputs. We are able to classify fair value balances based on the observability of those
inputs. The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The
hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities
(Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of
the fair value hierarchy are as follows:
• Level 1 — Quoted prices in active markets for identical assets or liabilities as of the reporting date.
• Level 2 — Pricing inputs are other than quoted prices in active markets included in Level 1, which are either
directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are
valued using models or other valuation methodologies. Instruments in this category include non-exchange-
traded oil and natural gas derivatives that are based on NYMEX pricing. Our swap contracts are valued using a
discounted cash flow model based upon forward commodity price curves. Our costless collars are valued
using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such
as contractual prices for the underlying instruments, including maturity, quoted forward prices for
commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic
measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of
the instrument, can be derived from observable data or are supported by observable levels at which
transactions are executed in the marketplace.
• Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources.
These inputs may be used with internally developed methodologies that result in management’s best estimate
of fair value. At December 31, 2013, instruments in this category include non-exchange-traded oil collars that
are based on regional pricing other than NYMEX (i.e., Louisiana Light Sweet). Our costless collars are valued
using the Black-Scholes model, which is described above. We obtain and ensure the appropriateness of the
significant inputs to the calculation, including contractual prices for the underlying instruments, maturity, forward
prices for commodities, interest rates, volatility factors and credit worthiness, and the fair value estimate is
prepared and reviewed on a quarterly basis. Implied volatilities utilized in the valuation of Level 3 instruments
are developed using a benchmark, which is considered a significant unobservable input. A one percent
increase or decrease in implied volatility would result in a change of approximately $0.1 million in the fair value
of these instruments as of December 31, 2013.
We adjust the valuations from the valuation model for nonperformance risk, using our estimate of the
counterparty’s credit quality for asset positions and our credit quality for liability positions. We use multiple sources
of third-party credit data in determining counterparty nonperformance risk, including credit default swaps.
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The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were
accounted for at fair value on a recurring basis as of December 31, 2013 and 2012:
In thousands
December 31, 2013
Assets:
Oil and natural gas derivative contracts – current
Oil and natural gas derivative contracts – long-term
Total Assets
Liabilities:
Oil and natural gas derivative contracts – current
Oil and natural gas derivative contracts – long-term
Total Liabilities
December 31, 2012
Assets:
Oil and natural gas derivative contracts – current
Oil and natural gas derivative contracts – long-term
Total Assets
Liabilities:
Oil and natural gas derivative contracts – current
Oil and natural gas derivative contracts – long-term
Total Liabilities
Fair Value Measurements Using:
Quoted Prices
in Active
Markets
(Level 1)
Significant
Significant
Other Observable Unobservable
Inputs
(Level 2)
Inputs
(Level 3)
Total
$ —
—
$ —
$ —
—
$ —
$ —
—
$ —
$ —
—
$ —
$
5
3,034
$ 3,039
$ —
6,908
$ 6,908
$
5
9,942
$ 9,947
$ (53,822)
(3,214)
$ (57,036)
$ —
(199)
$ (199)
$ (53,822)
(3,413)
$ (57,235)
$ 19,477
36
$ 19,513
$ (2,659)
(23,781)
$ (26,440)
$ —
—
$ —
$ —
—
$ —
$ 19,477
36
$ 19,513
$ (2,659)
(23,781)
$ (26,440)
The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the years
ended December 31, 2013 and 2012:
In thousands
Fair value of Level 3 instruments, beginning of year
Fair value adjustments on commodity derivatives
Receipt on settlements of commodity derivatives
Fair value of Level 3 instruments, end of year
December 31,
2013
$ —
6,709
—
$ 6,709
2012
$ 23,950
3,921
(27,871)
—
$
The amount of total gains for the period included in earnings attributable
to the change in unrealized gains relating to assets still held at the reporting date
$ 6,709
$
—
Since we do not use hedge accounting for our commodity derivative contracts, any gains and losses on our assets
and liabilities are included in “Commodity derivatives expense (income)” in the accompanying Consolidated
Statements of Operations.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
During 2012, we recorded a $15.1 million impairment charge for an investment in the preferred stock of an entity
that was created to develop a gasification plant (in which we would offtake its CO2 to use in our tertiary oil
operations) as a result of this project not moving forward. This charge is classified as “Impairment of assets” in the
Consolidated Statement of Operations for the year ended December 31, 2012.
Other Fair Value Measurements
The carrying value of our revolving bank credit facility approximates fair value, as it is subject to short-term floating
interest rates that approximate the rates available to us for those periods. We use a market approach to determine
fair value of our fixed-rate debt using observable market data. The fair values of our senior subordinated notes
are based on quoted market prices. The estimated fair value of our total long-term debt as of December 31, 2013 and
2012, excluding pipeline financing and capital lease obligations, is $2,956.8 million and $2,956.9 million, respectively.
We have other financial instruments consisting primarily of cash, cash equivalents, short-term receivables
and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.
Note 11. Commitments and Contingencies
Leases
We lease office space, equipment and vehicles that have non-cancelable lease terms. Currently, our outstanding
leases have terms up to 12 years. We have subleased part of the office space included in our operating leases for
which we received rental payments. The following table summarizes operating lease payments paid and received
during the periods indicated:
In thousands
Operating lease payments
Sublease rental receipts
Year Ended December 31,
2013
$ 37,211
2,237
2012
$ 33,606
2,685
2011
$ 52,317
2,398
In addition, we expect to receive approximately $14.6 million for 2014 through 2019 under these sublease agreements.
The following table summarizes by year the remaining non-cancelable future payments under these leases as of
December 31, 2013:
In thousands
2014
2015
2016
2017
2018
Thereafter
Total minimum lease payments
Less: Amount representing interest
Present value of minimum lease payments
In thousands
2014
2015
2016
2017
2018
Thereafter
Total minimum lease payments
Commitments
Pipeline
and Capital
Leases
$ 62,929
62,254
60,819
55,409
50,750
280,272
572,433
(215,748)
$ 356,685
Operating
Leases
$ 11,695
12,542
12,510
12,774
12,730
67,832
$ 130,083
We have entered into long-term commitments to purchase CO2 that are either non-cancelable or cancelable only
upon the occurrence of specified future events. The commitments continue for up to 20 years. The price we will
pay for CO2 generally varies depending on the amount of CO2 delivered and the price of oil. Our annual commitment
under these contracts could range from $100 million to $170 million per year, assuming a $90 per Bbl NYMEX
oil price.
We are party to long-term contracts that require us to deliver CO2 to our industrial CO2 customers at various
contracted prices, plus we have a CO2 delivery obligation to Genesis related to three CO2 volumetric production
payments (“VPPs”). Based upon the maximum amounts deliverable as stated in the industrial contracts and the
VPPs, we estimate that we may be obligated to deliver up to 367 Bcf of CO2 to these customers over the next
15 years. The maximum volume required in any given year is approximately 119 MMcf/d, which we judge to be minor
given the size of our Jackson Dome proven CO2 reserves at December 31, 2013, our current production capabilities
and our projected levels of CO2 usage for our own tertiary flooding program.
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In conjunction with the August 2011 Riley Ridge acquisition, we assumed the 20-year helium supply contract under
which the original participants in Riley Ridge agreed to supply helium to a third-party purchaser. After the
commencement date, the contract provides for the delivery of a minimum contracted quantity of helium, subject to
adjustment after start-up of the Riley Ridge gas processing facility, which, if not supplied in accordance with the
terms of the contract, may obligate us to compensate the third-party helium purchaser for the amount of the shortfall
in an amount not to exceed $8.0 million per year, or $46.0 million over the term of the contract.
Delhi Field Release
In June 2013, a release of well fluids, consisting of a mixture of carbon dioxide, saltwater, natural gas and oil, was
discovered and reported within an area of the Denbury-operated Delhi Field located in northern Louisiana. Denbury
immediately took remedial action to stop the release and contain and recover well fluids in the affected area. We
have determined that the release originated from one or more wells in the affected area of the field that we believed
had been previously and properly plugged and abandoned by a prior operator of the field. We completed our
remediation efforts during the fourth quarter of 2013; however, we will continue to monitor the area to ensure the
remediation efforts were successful.
During the year ended December 31, 2013, we recorded $114.0 million of lease operating expenses related to
this release in our Consolidated Statement of Operations, and as of December 31, 2013, we had a corresponding
$22.0 million liability classified as “Accounts payable and accrued liabilities” in our Consolidated Balance Sheet.
These expenses represent our current estimate of the costs related to this release, including remediation costs, based
on actual costs incurred through December 31, 2013 of approximately $92.0 million, plus the Company’s estimate
of future costs related to the satisfaction of known claims and liabilities. Due to the possibility of new claims being
asserted in the future in connection with the release, as well as variability in the estimated cost to continue to
monitor the area to ensure the remediation efforts were successful, we cannot reliably estimate at this time the full
extent of the costs that may ultimately be incurred by the Company related to this release. Although the Company
maintains insurance policies that we believe cover certain of the costs, damages and claims related to the
release, and we currently and preliminarily estimate that one-third to two-thirds of our current cost estimate may be
recoverable under such insurance policies, we have not reached any agreement with our insurance carriers as to
recoverable amounts, and accordingly have not recognized any insurance recoveries in our financial statements as of
December 31, 2013. Insurance recoveries will be recognized in our financial statements during the period received
or at the time receipt is determined to be virtually certain.
Litigation
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 financial position or overall trends in results of operations or cash flows, litigation
is subject to inherent uncertainties. If an unfavorable ruling were to occur, there exists the possibility of a material
adverse impact on our net income in the period in which the ruling occurs. We provide accruals for litigation and
claims if we determine that a loss is probable and the amount can be reasonably estimated.
Other Contingencies
We are subject to audits in the various states in which we operate for sales and use taxes and severance taxes,
and from time to time receive assessments for potential taxes that we may owe. In the past, settlement of these
matters has not had a material adverse financial impact on us, and currently we have no material assessments for
potential taxes.
We are subject to various possible contingencies that arise primarily from interpretation of federal and state laws
and regulations affecting the oil and natural gas industry. Such contingencies include differing interpretations
as to the prices at which oil and natural gas sales may be made, the prices at which royalty owners may be paid
for production from their leases, environmental issues and other matters. Although we believe that we have
complied with the various laws and regulations, administrative rulings and interpretations thereof, adjustments
could be required as new interpretations and regulations are issued. In addition, production rates, marketing and
environmental matters are subject to regulation by various federal and state agencies.
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Note 12. Additional Balance Sheet Details
Allowance for Doubtful Accounts
We record an allowance for doubtful accounts for receivables that we determine to be uncollectible based on
the specific identification basis. The allowance for doubtful accounts, which is netted against “Trade and other
receivables” on the Consolidated Balance Sheets, was $0.3 million at December 31, 2013 and 2012.
Accounts Payable and Accrued Liabilities
In thousands
Accrued exploration and development costs
Accrued interest
Accounts payable
Accrued lease operating expenses
Accrued compensation
Taxes payable
Other
Total
December 31,
2013
$ 100,564
68,871
63,263
59,762
55,043
28,019
35,021
$ 410,543
2012
$ 109,939
60,698
86,051
23,862
48,451
27,523
58,144
$ 414,668
Note 13. Supplemental Cash Flow Information
Supplemental Cash Flow Information
In thousands
Supplemental cash flow information:
Cash paid for interest, expensed
Cash paid for interest, capitalized
Cash paid for income taxes
Cash received from income tax refunds
Noncash investing activities:
Increase in asset retirement obligations
Increase (decrease) in liabilities for capital expenditures
Increase in restricted cash (1)
Decrease in restricted cash (2)
Year Ended December 31,
2013
2012
2011
$ 117,442
79,253
28,895
(17,087)
26,946
(18,321)
—
1,050,328
$ 137,950
77,432
99,194
(38,004)
56,290
(26,882)
1,262,559
212,544
$ 137,259
60,540
45,912
(24,677)
24,694
74,697
—
—
(1) During 2012, $212.5 million of proceeds from the sale of certain non-core assets in the Gulf Coast Region and $1.05 billion of the cash proceeds
from the Bakken Exchange Transaction were paid by the respective purchaser directly to a qualified intermediary to facilitate a like-kind-exchange
transaction for federal income tax purposes. See Note 2, Acquisitions and Divestitures, for additional details regarding these transactions.
(2) During 2012 and 2013, proceeds from the sales of our oil and natural gas property dispositions in 2012, which were held by a qualified intermediary,
were released in 2012 to fund the Thompson Field acquisition and in 2013 primarily to fund a portion of the CCA acquisition and certain post-closing
costs under the Bakken Exchange Transaction. See Note 2, Acquisitions and Divestitures, for additional details regarding these transactions.
Note 14. Subsequent Events
Stock Repurchase Program
Between January 1, 2014 and February 20, 2014, the Company repurchased an additional 11.8 million shares
of Denbury common stock under the share repurchase program for $191.6 million, or $16.17 per share. See Note 7,
Stockholders’ Equity, for additional information regarding the Company’s share repurchase program.
Equity Award Grant
In January 2014, we granted equity incentive awards to our employees under the 2004 Plan. The grants included
1,633,898 shares of restricted stock valued at $16.55 per share (the closing price of Denbury’s common stock on
January 3, 2014). The awards generally vest 33% per year over a three-year period.
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Dividend Declaration
On January 28, 2014, the Board of Directors declared a dividend of $0.0625 per share on our common stock,
payable to stockholders of record at the close of business on February 25, 2014.
Supplemental Oil and Natural Gas Disclosures (Unaudited)
Costs Incurred
The following table summarizes costs incurred and capitalized in oil and natural gas property acquisition,
exploration and development activities. Property acquisition costs are those costs incurred to purchase, lease or
otherwise acquire property, including both undeveloped leasehold and the purchase of reserves in place. Exploration
costs include costs of identifying areas that may warrant examination and examining specific areas that are
considered to have prospects containing oil and natural gas reserves, including costs of drilling exploratory wells,
geological and geophysical costs, and carrying costs on undeveloped properties. Development costs are incurred
to obtain access to proved reserve costs, including the cost of drilling development wells, and to provide facilities for
extracting, treating, gathering and storing the oil and natural gas, and the cost of improved recovery systems.
We capitalize interest on unevaluated oil and natural gas properties that have ongoing development activities.
Included in costs incurred in the table below is capitalized interest of $41.3 million in 2013, $36.5 million in 2012 and
$44.9 million in 2011. Costs incurred also include new asset retirement obligations established, as well as
changes to asset retirement obligations resulting from revisions in cost estimates or abandonment dates. Asset
retirement obligations included in the table below were $17.1 million in 2013, $38.8 million in 2012 and $24.2 million
in 2011. See Note 3, Asset Retirement Obligations, for additional information.
Costs incurred in oil and natural gas activities were as follows:
In thousands
Property acquisitions:
Proved
Unevaluated
Exploration
Development
Total costs incurred (1)
Year Ended December 31,
2013
2012
2011
$ 803,837
221,173
2,103
913,093
$ 1,940,206
$ 491,041
115,270
12,019
1,111,314
$ 1,729,644
$
86,465
17,858
31,483
1,144,243
$ 1,280,049
(1) Capitalized general and administrative costs that directly relate to exploration and development activities were $55.4 million, $49.2 million and
$35.0 million for the years ended December 31, 2013, 2012 and 2011, respectively.
Oil and Natural Gas Operating Results
Results of operations from oil and natural gas producing activities, excluding corporate overhead and interest
costs, were as follows:
In thousands, except per BOE data
Oil, natural gas, and related product sales
Lease operating costs
Marketing expenses, net of third-party purchasers
Taxes other than income
Depletion, depreciation and amortization
CO2 properties and pipelines depletion and depreciation (1)
Commodity derivatives expense (income)
Net operating income
Income tax provision
Results of operations from oil and natural gas producing activities
Year Ended December 31,
2013
2012
2011
$ 2,466,234
730,574
37,754
162,791
426,668
52,932
41,024
1,014,491
385,507
$ 628,984
$ 2,409,867
532,359
41,936
149,919
448,424
42,064
(4,834)
1,199,999
462,000
$ 737,999
$ 2,269,151
507,397
26,047
138,419
369,075
24,460
(52,497)
1,256,250
477,375
$ 778,875
Depletion, depreciation and amortization per BOE
$
18.71
$
18.69
$
16.42
(1) Represents an allocation of the depletion, depreciation and amortization of our CO2 properties and pipelines associated with our tertiary oil
producing activities.
Oil and Natural Gas Reserves
Net proved oil and natural gas reserve estimates for all years presented were prepared by DeGolyer and
MacNaughton, independent petroleum engineers located in Dallas, Texas. 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. See Standardized
Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves
below for a discussion of the effect of the different prices on reserve quantities and values. Operating costs, production
and ad valorem taxes, and future development costs were based on current costs.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future
rates of production and timing of development expenditures. The following reserve data represents estimates only
and should not be construed as being exact. Moreover, the present values should not be construed as the current
market value of our oil and natural gas reserves or the costs that would be incurred to obtain equivalent reserves.
Estimates of reserves as of year-end 2013, 2012 and 2011 were prepared using an average price equal to the
unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month
within the applicable fiscal 12-month period. All of our reserves are located in the United States.
Estimated Quantities of Proved Reserves
2013
Oil
(MBbl)
Gas
(MMcf)
Total
(MBOE)
Oil
(MBbl)
2012
Gas
(MMcf)
2011
Total
(MBOE)
Oil
(MBbl)
Gas
(MMcf)
Total
(MBOE)
Year Ended December 31,
Balance at beginning of year
329,124
481,641
409,398
357,733
625,208
461,934
338,276
357,893
397,925
Revisions of previous
estimates
Revisions due to change
4,704
60
4,714
(7,099)
(16,720)
(9,886)
(4,478)
(14,058)
(6,821)
in sales prices
665
14,100
3,015
(401)
(37,969)
(6,729)
2,558
485
2,639
Extensions and discoveries
Improved recovery (1)
Production
Acquisition of minerals
118
34,015
—
—
118
14,910
10,005
16,579
42,936
52,339
51,658
34,015
69,543
—
69,543
264
—
264
(24,194)
(8,666)
(25,639)
(24,462)
(10,654) (26,238) (22,169)
(10,783)
(23,966)
in place
42,227
2,819
42,697
24,677
20,598
28,110
346
239,332
40,235
Sales of minerals in place
—
—
—
(105,777)
(108,827) (123,915)
—
—
—
Balance at end of year
386,659
489,954
468,318
329,124
481,641
409,398
357,733
625,208
461,934
Proved Developed Reserves:
Balance at beginning of year 236,009
64,191
246,708
239,741
125,970
260,736
219,077
110,516
237,496
Balance at end of year
276,392
72,095
288,408
236,009
64,191
246,708
239,741
125,970
260,736
(1) Improved recovery reflects reserve additions that result from the application of secondary recovery methods such as water flooding, or tertiary
recovery methods such as CO2 flooding. In order to recognize proved tertiary oil reserves, we must either have an oil production response to
CO2 injections or the field must be analogous to an existing tertiary flood. The magnitude of proved reserves that we can book in any given year
will depend on our progress with new floods and the timing of the production response.
Acquisitions of minerals in place during 2013 were primarily related to the acquisition of additional interests in
certain of our existing operated fields in CCA, as well as operating interests in other CCA fields. Reserves added as a
result of improved recovery represent initial proved tertiary oil reserves at Bell Creek Field.
We added 114.2 MMBOE of estimated proved reserves during 2012, including tertiary reserves of 69.5 MMBbls,
primarily at Hastings and Oyster Bayou fields; 25.9 MMBOE from the acquisition of interests in the Thompson,
Webster and Hartzog Draw fields; and 11.5 MMBOE from our Bakken area assets prior to their sale in the fourth
quarter of 2012. These increases were offset by the disposition of 123.9 MMBOE of reserves associated with
disposed properties, including our Bakken area assets, and non-core assets in the Gulf Coast region and Paradox
Basin in Utah.
Acquisitions of minerals in place during 2011 were primarily related to the acquisition of the remaining interest in
Riley Ridge, and extensions and discoveries that year primarily included proved undeveloped reserves added primarily
through additional drilling in the Bakken.
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Standardized Measure of Discounted Future Net Cash Flows and Changes Therein
Relating to Proved Oil and Natural Gas Reserves
The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and
Natural Gas Reserves (“Standardized Measure”) does not purport to present the fair market value of our oil and
natural gas properties. An estimate of such value should consider, among other factors, anticipated future prices of
oil and natural gas, the probability of recoveries in excess of existing proved reserves, the value of probable reserves
and acreage prospects, and perhaps different discount rates. It should be noted that estimates of reserve quantities,
especially from new discoveries, are inherently imprecise and subject to substantial revision.
Under the Standardized Measure, future cash inflows were estimated by applying a first-day-of-the-month
12-month average price to the estimated future production of year-end proved reserves. The product prices used
in calculating these reserves have varied widely during the three-year period. These prices have a significant
impact on both the quantities and value of the proved reserves, as reductions in oil and natural gas prices can cause
wells to reach the end of their economic life much sooner and can make certain proved undeveloped locations
uneconomical, both of which reduce the reserves. The following representative oil and natural gas prices were used
in the Standardized Measure. These prices were adjusted by field to arrive at the appropriate corporate net price.
Oil (NYMEX price per Bbl)
Natural Gas (Henry Hub price per Mcf)
December 31,
2013
2012
2011
$ 96.94
3.67
$ 94.71
2.85
$ 96.19
4.16
Future cash inflows were reduced by estimated future production, development and abandonment costs based on
current cost, with no escalation to determine pre-tax cash inflows. Our future net inflows do not include a reduction
for cash previously expended on our capitalized CO2 assets that will be consumed in the production of proved tertiary
reserves. Future income taxes were computed by applying the statutory tax rate to the excess of net cash inflows
over our tax basis in the associated proved oil and natural gas properties. Tax credits and net operating loss
carryforwards were also considered in the future income tax calculation. Future net cash inflows after income taxes
were discounted using a 10% annual discount rate to arrive at the Standardized Measure.
In thousands
Future cash inflows
Future production costs
Future development costs
Future income taxes
Future net cash flows
10% annual discount for estimated timing of cash flows
Standardized measure of discounted future net cash flows
2013
$ 40,065,019
(16,053,734)
(2,552,194)
(6,937,773)
14,521,318
(7,392,574)
$ 7,128,744
December 31,
2012
$ 34,779,549
(13,114,740)
(2,034,174)
(6,672,857)
12,957,778
(6,543,398)
$ 6,414,380
2011
$ 38,165,122
(12,570,015)
(3,026,898)
(7,379,972)
15,188,237
(8,180,632)
$ 7,007,605
The following table sets forth an analysis of changes in the Standardized Measure of Discounted Future Net Cash
Flows from proved oil and natural gas reserves:
In thousands
Beginning of year
Sales of oil and natural gas produced, net of production costs (1)
Net changes in prices and production costs
Extensions and discoveries, less applicable future development
and production costs
Improved recovery (2)
Previously estimated development costs incurred
Change in future development costs
Revisions due to timing and other
Accretion of discount
Acquisition of minerals in place
Sales of minerals in place
Net change in income taxes
End of year
Year Ended December 31,
2013
2012
2011
$ 6,414,380
(1,649,113)
(170,571)
$ 7,007,605
(1,673,253)
(597,512)
$ 4,917,927
(1,597,288)
4,231,076
4,902
739,019
393,537
(301,162)
(446,586)
1,072,113
1,082,050
—
(9,825)
$ 7,128,744
291,558
1,901,109
376,199
(454,140)
(330,849)
875,383
767,267
(1,805,309)
56,322
$ 6,414,380
762,370
15,708
354,228
(591,570)
(666,703)
729,234
29,737
—
(1,177,114)
$ 7,007,605
(1) Production costs exclude $114 million of lease operating expenses recorded during the year ended December 31, 2013 related to the Delhi Field release.
(2) Improved recovery additions result from the application of secondary recovery methods such as water flooding or tertiary recovery methods such
as CO2 flooding.
Supplemental CO2 And Helium Disclosures (Unaudited)
Based on engineering reports prepared by DeGolyer and MacNaughton, proved CO2 reserves, and helium reserves
associated with our helium production rights, were estimated as follows (in MMcf):
In thousands
CO2 reserves
Gulf Coast region (1)
Rocky Mountain region (2)
Helium reserves associated with Denbury’s production rights
Rocky Mountain region (3)
Year Ended December 31,
2013
2012
2011
6,070,619
3,272,428
6,073,175
3,495,534
6,685,412
2,195,534
13,251
12,712
12,004
(1) Proved CO2 reserves in the Gulf Coast region consist of reserves from our reservoirs at Jackson Dome and are presented on a gross working
interest (8/8ths) basis, of which our net revenue interest was approximately 4.8 Tcf, 4.8 Tcf and 5.3 Tcf at December 31, 2013, 2012 and 2011,
respectively, and include reserves dedicated to volumetric production payments of 28.9 Bcf, 57.1 Bcf and 84.7 Bcf at December 31, 2013, 2012 and
2011, respectively.
(2) Proved CO2 reserves in the Rocky Mountain region consist of our reserves at Riley Ridge (presented on a gross working interest (8/8ths) basis) and
our overriding royalty interest in LaBarge Field, of which our net revenue interest was approximately 2.9 Tcf, 2.9 Tcf and 1.6 Tcf at December 31,
2013, 2012 and 2011, respectively.
(3) Reserves associated with helium production rights include helium reserves located in acreage in the Rocky Mountain region for which we have the
right to extract the helium on behalf of the U.S. government, who owns the helium. Our extraction agreement with the U.S. government gives us
the ability to produce the helium on behalf of the U.S. government in exchange for a fee, which amount fluctuates based upon the realized sales
proceeds we receive. The estimate of helium reserves is reduced to reflect the estimated fee we will remit to the U.S. government. Our extraction
agreement with the U.S. government has a minimum term extending 20 years from first production and continuing thereafter until either party
terminates the contract. Reserve volumes presented herein assume that the term of this helium extraction agreement continues beyond 20 years,
given the benefit to both parties to the agreement.
Unaudited Quarterly Information
In thousands, except per share amounts
March 31
June 30
September 30
December 31
2013
Revenues and other income
Commodity derivatives expense (income)
Other expenses
Net income
Net income per share:
Basic
Diluted
Cash flow provided by operating activities
Cash flow used for investing activities
Cash flow provided by (used for) financing activities
2012
Revenues and other income
Commodity derivatives expense (income)
Other expenses
Net income
Net income per share:
Basic
Diluted
Cash flow provided by operating activities
Cash flow used for investing activities
Cash flow provided by (used for) financing activities
$ 583,086
11,929
429,222
87,571
0.24
0.23
269,176
(320,646)
15,228
$ 645,116
45,275
420,529
113,467
0.29
0.29
291,654
(288,883)
55,902
$ 650,084
(45,501)
484,279
129,980
0.35
0.35
437,568
(344,927)
(79,045)
$ 601,781
(139,109)
398,089
211,865
0.55
0.54
440,966
(560,341)
70,122
$ 684,835
80,446
445,024
102,054
0.28
0.28
305,465
(286,130)
(68,652)
$ 600,371
61,631
399,361
85,367
0.22
0.22
293,506
(388,748)
91,163
$ 599,122
(5,850)
475,198
89,992
0.25
0.25
348,986
(323,606)
(39,741)
$ 609,204
27,369
386,470
114,661
0.30
0.30
384,765
(138,869)
(171,419)
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Item 9. Changes in and Disagreements with
Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation
of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) was performed under
the supervision and with the participation of management, including our Chief Executive Officer and our Chief
Financial Officer. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our
disclosure controls and procedures were effective as of December 31, 2013, to ensure that information that is
required to be disclosed in the reports the Company files and submits under the Securities Exchange Act of 1934 is
recorded; that it is processed, summarized and reported within the time periods specified in the SEC’s rules and
forms; and that information that is required to be disclosed under the Exchange Act is accumulated and
communicated to management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate
to allow timely decisions regarding required disclosure.
Evaluation of Changes in Internal Control over Financial Reporting
Under the supervision and with the participation of our management, including our Chief Executive Officer and our
Chief Financial Officer, we have determined that, during the fourth quarter of fiscal 2013, there were no changes in
our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect,
our internal control over financial reporting.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting
as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Under the supervision
and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer,
we assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by
this report based on the framework in “Internal Control – Integrated Framework” (1992) issued by the Committee
of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Officer
and our Chief Financial Officer concluded that our internal control over financial reporting was effective to provide
reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial
statements for external purposes in accordance with U.S. generally accepted accounting principles.
The effectiveness of our internal control over financial reporting as of December 31, 2013, has been audited
by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in the report that
appears herein.
Important Considerations
The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is
subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions
about the likelihood of future events, the soundness of our systems, the possibility of human error, and the risk
of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls
may become inadequate because of changes in conditions and the risk that the degree of compliance with policies
or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any system
of disclosure controls and procedures or internal control over financial reporting will be successful in
preventing all errors or fraud or in making all material information known in a timely manner to the appropriate
levels of management.
Item 9B. Other Information
None.
Item 10. Directors, Executive Officers and
Corporate Governance
Except as disclosed below, information as to Item 10 will be set forth in the Proxy Statement (“Proxy Statement”)
for the Annual Meeting of Shareholders to be held May 20, 2014 (“Annual Meeting”) and is incorporated herein
by reference.
Code of Ethics
We have adopted a Code of Ethics for Senior Financial Officers and the Principal Executive Officer. This Code of
Ethics, including any amendments or waivers, is posted on our website at www.denbury.com.
Item 11. Executive Compensation
Information as to Item 11 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated
herein by reference.
Item 12. Security Ownership of
Certain Beneficial Owners and Management
and Related Stockholder Matters
Information as to Item 12 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated
herein by reference.
Item 13. Certain Relationships and
Related Transactions, and Director Independence
Information as to Item 13 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated
herein by reference.
Item 14. Principal Accountant Fees and Services
Information as to Item 14 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated
herein by reference.
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Item 15. Exhibits and Financial Statement Schedules
Financial Statements and Schedules. Financial statements and schedules filed as a part of this report are
presented on page 67. All financial statement schedules have been omitted because they are not applicable, or the
required information is presented in the financial statements or the notes to consolidated financial statements.
Exhibits. The following exhibits are included as part of this report.
Exhibit No.
Exhibit
2(a)
2(b)
2(c)
2(d)
3(a)
3(b)
4(a)
4(b)
4(c)**
4(d)
4(e)
4(f)
Exchange Agreement, dated as of September 19, 2012, by and among Denbury Onshore, LLC, XTO
Energy Inc., and Exxon Mobil Corporation (incorporated by reference to Exhibit 2.1 of Form 8-K filed
by the Company on September 25, 2012, File No. 001-12935).
Closing Agreement and Amendment, dated as of November 30, 2012, by and among Denbury
Onshore, LLC, XTO Energy Inc., and Exxon Mobil Corporation (incorporated by reference to Exhibit
2.2 of Form 8-K filed by the Company on December 6, 2012, File No. 001-12935).
Second Closing Agreement and Amendment, dated as of December 21, 2012, by and among Denbury
Onshore, LLC, XTO Energy Inc., and Exxon Mobil Corporation (incorporated by reference to Exhibit
2.1 of Form 8-K filed by the Company on December 26, 2012, File No. 001-12935).
Purchase and Sale Agreement, dated as of January 14, 2013, by and between Burlington Resources
Oil & Gas Company LP and Denbury Onshore, LLC (incorporated by reference to Exhibit 2.1 of Form
8-K filed by the Company on January 15, 2013, File No. 001-12935).
Second Restated Certificate of Incorporation of Denbury Resources Inc. filed with the Delaware
Secretary of State on August 21, 2012 (incorporated by reference to Exhibit 3(a) of Form 10-Q filed by
the Company on November 8, 2012, File No. 001-12935).
Amended and Restated Bylaws of Denbury Resources Inc. as of May 15, 2012 (incorporated by
reference to Exhibit 3.2 of Form 8-K filed by the Company on May 21, 2012, File No. 001-12935).
Indenture for 9.75% Senior Subordinated Notes due 2016, dated as of February 13, 2009, by and
among Denbury Resources Inc., certain of its subsidiaries, and The Bank of New York Mellon Trust
Company, N.A., as Trustee (incorporated by reference to Exhibit 4.1 of Form 8-K filed by the
Company on February 17, 2009, File No. 001-12935).
First Supplemental Indenture for 9.75% Senior Subordinated Notes due 2016, dated as of June 30,
2009, by and among Denbury Resources Inc., certain of its subsidiaries, and The Bank of New York
Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4(h) of Form 10-K filed
by the Company on March 1, 2010, File No. 001-12935).
9.75% Senior Subordinated Note due 2016, issued on June 30, 2009, to Gareth Roberts (incorporated
by reference to Exhibit 10.2 of Form 8-K filed by the Company on July 7, 2009, File No. 001-12935).
Second Supplemental Indenture for 9.75% Senior Subordinated Notes due 2016, dated as of March 9,
2010, by and among Denbury Resources Inc., certain of its subsidiaries, and The Bank of New York
Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.6 of Form 8-K filed by
the Company on March 12, 2010, File No. 001-12935).
Third Supplemental Indenture for 9.75% Senior Subordinated Notes due 2016, dated as of February 3,
2011, by and among Denbury Resources Inc., certain of its subsidiaries, and The Bank of New York
Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4(p) of Form 10-K filed
by the Company on March 1, 2011, File No. 001-12935).
Indenture for 8¼% Senior Subordinated Notes due 2020, dated as of February 10, 2010, by and
among Denbury Resources Inc., certain of its subsidiaries, and Wells Fargo Bank, National
Association, as Trustee (incorporated by reference to Exhibit 4.1 of Form 8-K filed by the Company
on February 12, 2010, File No. 001-12935).
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Exhibit No.
Exhibit
4(g)
4(h)
4(i)
4(j)
4(k)
4(l)
4(m)
4(n)
4(o)
4(p)
4(q)
4(r)
First Supplemental Indenture for 8¼% Senior Subordinated Notes due 2020, dated as of March 9,
2010, by and among Denbury Resources Inc., certain of its subsidiaries, and Wells Fargo Bank,
National Association, as Trustee (incorporated by reference to Exhibit 4.7 of Form 8-K filed by the
Company on March 12, 2010, File No. 001-12935).
Second Supplemental Indenture for 8¼% Senior Subordinated Notes due 2020, dated as of
February 3, 2011, by and among Denbury Resources Inc., certain of its subsidiaries, and Wells Fargo
Bank, National Association, as Trustee (incorporated by reference to Exhibit 4(s) of Form 10-K filed
by the Company on March 1, 2011, File No. 001-12935).
Indenture for 6.25% Senior Subordinated Notes Due 2014, dated as of April 2, 2004, by and among
Encore Acquisition Company, certain of its subsidiaries, and Wells Fargo Bank, National Association,
as Trustee (incorporated by reference to Exhibit 4.1.1 of Form 8-K filed by the Company on
March 12, 2010, File No. 001-12935).
First Supplemental Indenture for 6.25% Senior Subordinated Notes Due 2014, dated as of January 2,
2008, by and among Encore Acquisition Company, certain of its subsidiaries, and Wells Fargo Bank,
National Association, as Trustee (incorporated by reference to Exhibit 4.1.2 of Form 8-K filed by the
Company on March 12, 2010, File No. 001-12935).
Second Supplemental Indenture for 6.25% Senior Subordinated Notes Due 2014, dated as of January
27, 2010, by and among Encore Acquisition Company, certain of its subsidiaries, and Wells Fargo
Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1.3 of Form 8-K filed by
the Company on March 12, 2010, File No. 001-12935).
Third Supplemental Indenture for 6.25% Senior Subordinated Notes Due 2014, dated as of March 10,
2010, by and among Denbury Resources Inc., certain of its subsidiaries, and Wells Fargo Bank,
National Association, as Trustee (incorporated by reference to Exhibit 4.1.4 of Form 8-K filed by the
Company on March 12, 2010, File No. 001-12935).
Fourth Supplemental Indenture for 6.25% Senior Subordinated Notes Due 2014, dated as of
February 3, 2011, by and among Denbury Resources Inc., certain of its subsidiaries, and Wells Fargo
Bank, National Association, as Trustee (incorporated by reference to Exhibit 4(x) of Form 10-K filed
by the Company on March 1, 2011, File No. 001-12935).
Indenture for 6.0% Senior Subordinated Notes due 2015, dated as of July 13, 2005, by and among
Encore Acquisition Company, certain of its subsidiaries, and Wells Fargo Bank, National Association,
as Trustee (incorporated by reference to Exhibit 4.2.1 of Form 8-K filed by the Company on
March 12, 2010, File No. 001-12935).
First Supplemental Indenture for 6.0% Senior Subordinated Notes due 2015, dated as of January 2,
2008, by and among Encore Acquisition Company, certain of its subsidiaries, and Wells Fargo Bank,
National Association, as Trustee (incorporated by reference to Exhibit 4.2.2 of Form 8-K filed by
the Company on March 12, 2010, File No. 001-12935).
Second Supplemental Indenture for 6.0% Senior Subordinated Notes due 2015, dated as of January
27, 2010, by and among Encore Acquisition Company, certain of its subsidiaries, and Wells Fargo
Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2.3 of Form 8-K filed
by the Company on March 12, 2010, File No. 001-12935).
Third Supplemental Indenture for 6.0% Senior Subordinated Notes due 2015, dated as of March 10,
2010, by and among Denbury Resources Inc., certain of its subsidiaries, and Wells Fargo Bank,
National Association, as Trustee (incorporated by reference to Exhibit 4.2.4 of Form 8-K filed by the
Company on March 12, 2010, File No. 001-12935).
Fourth Supplemental Indenture for 6.0% Senior Subordinated Notes due 2015, dated as of February
3, 2011, by and among Denbury Resources Inc., certain of its subsidiaries, and Wells Fargo Bank,
National Association, as Trustee (incorporated by reference to Exhibit 4(cc) of Form 10-K filed by the
Company on March 1, 2011, File No. 001-12935).
99
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Exhibit No.
Exhibit
4(s)
4(t)
4(u)
4(v)
4(w)
4(x)
4(y)
4(z)
4(aa)
4(bb)
10(a)
10(b)
Indenture for Subordinated Debt Securities, dated as of November 16, 2005, by and among Encore
Acquisition Company, certain of its subsidiaries, and Wells Fargo Bank, National Association, as
Trustee (incorporated by reference to Exhibit 4.3.1 of Form 8-K filed by the Company on March 12,
2010, File No. 001-12935).
First Supplemental Indenture for 7.25% Senior Subordinated Notes due 2017, dated as of
November 23, 2005, by and among Encore Acquisition Company, certain of its subsidiaries, and
Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3.2
of Form 8-K filed by the Company on March 12, 2010, File No. 001-12935).
Second Supplemental Indenture for 7.25% Senior Subordinated Notes due 2017, dated as of
January 2, 2008, by and among Encore Acquisition Company, certain of its subsidiaries, and Wells
Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3.3 of
Form 8-K filed by the Company on March 12, 2010, File No. 001-12935).
Third Supplemental Indenture for 9.5% Senior Subordinated Notes due 2016, dated as of April 27,
2009, by and among Encore Acquisition Company, certain of its subsidiaries, and Wells Fargo Bank,
National Association, as Trustee (incorporated by reference to Exhibit 4.3.4 of Form 8-K filed by
the Company on March 12, 2010, File No. 001-12935).
Fourth Supplemental Indenture for Senior Subordinated Notes, dated as of January 27, 2010, by and
among Encore Acquisition Company, certain of its subsidiaries, and Wells Fargo Bank, National
Association, as Trustee (incorporated by reference to Exhibit 4.3.5 of Form 8-K filed by the Company
on March 12, 2010, File No. 001-12935).
Fifth Supplemental Indenture for Senior Subordinated Notes, dated as of March 10, 2010, by and
among Denbury Resources Inc., certain of its subsidiaries, and Wells Fargo Bank, National
Association, as Trustee (incorporated by reference to Exhibit 4.3.6 of Form 8-K filed by the Company
on March 12, 2010, File No. 001-12935).
Sixth Supplemental Indenture for Senior Subordinated Notes, dated as of February 3, 2011, by and
among Denbury Resources Inc., certain of its subsidiaries, and Wells Fargo Bank, National
Association, as Trustee (incorporated by reference to Exhibit 4(jj) of Form 10-K filed by the Company
on March 1, 2011, File No. 001-12935).
Seventh Supplemental Indenture for Senior Subordinated Notes, dated as of February 5, 2013, by
and among Denbury Resources Inc., certain of its subsidiaries, and Wells Fargo Bank, National
Association, as Trustee (incorporated by reference to Exhibit 4.2 of Form 8-K filed by the Company
on February 5, 2013, File No. 001-12935).
Indenture for 6 3/8% Senior Subordinated Notes due 2021, dated as of February 17, 2011, by and
among Denbury Resources Inc., certain of its subsidiaries, and Wells Fargo Bank, National
Association, as Trustee, (incorporated by reference to Exhibit 4.1 of Form 8-K filed by the Company
on February 22, 2011, File No. 001-12935).
Indenture for 4 5/8% Senior Subordinated Notes due 2023, dated as of February 5, 2013, by and among
Denbury Resources Inc., certain of its subsidiaries, and Wells Fargo Bank, National Association, as
Trustee (incorporated by reference to Exhibit 4.1 of Form 8-K filed by the Company on February 5,
2013, File No. 001-12935).
Credit Agreement, dated as of March 9, 2010, by and among Denbury Resources Inc., as Borrower,
JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions party thereto
(incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on March 12, 2010, File
No. 001-12935).
First Amendment to Credit Agreement, dated as of May 13, 2010, by and among Denbury Resources
Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions
party thereto (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on
May 19, 2010, File No. 001-12935).
Exhibit No.
Exhibit
10(c)
10(d)
10(e)
10(f)
10(g)
10(h)
10(i)
10(j)
10(k)
10(l)*
10(m)
10(n)
Second Amendment to Credit Agreement, dated as of September 30, 2010, by and among Denbury
Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial
institutions party thereto (incorporated by reference to Exhibit 10.1 of Form 10-Q filed by the
Company on November 9, 2010, File No. 001-12935).
Third Amendment to Credit Agreement, dated as of December 17, 2010, by and among Denbury
Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial
institutions party thereto (incorporated by reference to Exhibit 10(d) of Form 10-K filed by the
Company on March 1, 2011, File No. 001-12935).
Fourth Amendment to Credit Agreement, dated as of February 1, 2011, by and among Denbury
Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial
institutions party thereto (incorporated by reference to Exhibit 10(e) of Form 10-K filed by the
Company on March 1, 2011, File No. 001-12935).
Fifth Amendment to Credit Agreement, dated as of May 19, 2011, by and among Denbury Resources
Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions
party thereto (incorporated by reference to Exhibit 99.1 of Form 8-K filed by the Company on
May 20, 2011, File No. 001-12935).
Sixth Amendment to Credit Agreement, dated as of September 1, 2011, by and among Denbury
Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial
institutions party thereto (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company
on September 8, 2011, File No. 001-12935).
Seventh Amendment to Credit Agreement, dated as of April 11, 2012, by and among Denbury
Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial
institutions party thereto (incorporated by reference to Exhibit 4(a) of Form 10-Q filed by the
Company on May 10, 2012, File No. 001-12935).
Eighth Amendment to Credit Agreement, dated as of July 26, 2012, by and among Denbury
Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial
institutions party thereto (incorporated by reference to Exhibit 4(a) of Form 10-Q filed by the
Company on August 8, 2012, File No. 001-12935).
Ninth Amendment to Credit Agreement, dated as of November 2, 2012, by and among Denbury
Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial
institutions party thereto (incorporated by reference to Exhibit 10(a) of Form 10-Q filed by the
Company on November 8, 2012, File No. 001-12935).
Tenth Amendment to Credit Agreement, dated as of January 18, 2013, by and among Denbury
Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial
institutions party thereto (incorporated by reference to Exhibit 10(k) of Form 10-K filed by the
Company on February 28, 2013, File No. 001-12935).
Eleventh Amendment to Credit Agreement, dated as of November 8, 2013, by and among Denbury
Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial
institutions party thereto.
Pipeline Financing Lease Agreement, dated as of May 30, 2008, by and between Genesis NEJD
Pipeline, LLC, as Lessor, and Denbury Onshore, LLC, as Lessee (incorporated by reference to Exhibit
99.1 of Form 8-K filed by the Company on June 5, 2008, File No. 001-12935).
Transportation Services Agreement, dated as of May 30, 2008, by and between Genesis Free State
Pipeline, LLC and Denbury Onshore, LLC (incorporated by reference to Exhibit 99.2 of Form 8-K filed
by the Company on June 5, 2008, File No. 001-12935).
10(o)**
Denbury Resources Inc. Amended and Restated Stock Option Plan, effective as of December 5, 2007
(incorporated by reference to Exhibit 99.2 of Form 8-K filed by the Company on December 11, 2007,
File No. 001-12935).
101
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Exhibit No.
Exhibit
10(p)**
10(q)**
Denbury Resources Inc. Amended and Restated Employee Stock Purchase Plan, effective as of May
22, 2013 (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on May 28,
2013, File No. 001-12935).
Form of Indemnification Agreement, dated as of July 28, 1999, by and between Denbury Resources
Inc. and its officers and directors (incorporated by reference to Exhibit 10 of Form 10-Q filed by the
Company on August 11, 1999, File No. 001-12935).
10(r)* **
Denbury Resources Inc. Director Deferred Compensation Plan, as amended and restated effective as
of December 12, 2013.
10(s)**
Denbury Resources Inc. Severance Protection Plan, as amended and restated effective as of
December 13, 2012 (incorporated by reference to Exhibit 10(v) of Form 10-K filed by the Company on
February 28, 2013, File No. 001-12935).
10(t)* **
Denbury Resources Inc. 2004 Omnibus Stock and Incentive Plan, as amended and restated as of
December 12, 2013.
10(u)**
10(v)**
10(w)**
10(x)**
10(y)**
2004 Form of Restricted Stock Award that vests on retirement for grants to officers pursuant to the
2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. (incorporated by reference to
Exhibit 10(l) of Form 10-K filed by the Company on March 15, 2005, File No. 001-12935).
2009 Form of Stock Appreciation Rights Agreement to certain officers that cliff vests on March 31,
2012 pursuant to the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc.
(incorporated by reference to Exhibit 10(f) of Form 10-Q filed by the Company on May 11, 2009,
File No. 001-12935).
2009 Form of Stock Appreciation Rights Agreement without change of control vesting pursuant to
the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. (incorporated by reference to
Exhibit 10(g) of Form 10-Q filed by the Company on May 11, 2009, File No. 001-12935).
2011 Form of Performance Stock Award pursuant to the 2004 Omnibus Stock and Incentive Plan
(incorporated by reference to Exhibit 10(a) to Form 10-Q filed by the Company on May 10, 2011,
File No. 001-12935).
2011 Form of Performance Cash Award pursuant to the 2004 Omnibus Stock and Incentive Plan
(incorporated by reference to Exhibit 10(b) to Form 10-Q filed by the Company on May 10, 2011,
File No. 001-12935).
10(z)* ** Officer Resignation Agreement, effective as of December 31, 2013, by and between Denbury
Resources Inc. and Robert L. Cornelius.
10(aa)**
2012 Form of Performance Stock Award pursuant to the 2004 Omnibus Stock and Incentive Plan
(incorporated by reference to Exhibit 10(a) of Form 10-Q filed by the Company on May 10, 2012,
File No. 001-12935).
10(bb)**
2012 Form of Performance Cash Award pursuant to the 2004 Omnibus Stock and Incentive Plan
(incorporated by reference to Exhibit 10(b) of Form 10-Q filed by the Company on May 10, 2012,
File No. 001-12935).
10(cc)**
2012 Form of TSR Performance Award pursuant to the 2004 Omnibus Stock and Incentive Plan
(incorporated by reference to Exhibit 10(c) of Form 10-Q filed by the Company on May 10, 2012,
File No. 001-12935).
10(dd)**
2013 Form of Performance Share Award pursuant to the 2004 Omnibus Stock and Incentive Plan
(incorporated by reference to Exhibit 10(a) of Form 10-Q filed by the Company on May 10, 2013,
File No. 001-12935).
10(ee)**
2013 Form of Performance Cash Award pursuant to the 2004 Omnibus Stock and Incentive Plan
(incorporated by reference to Exhibit 10(b) of Form 10-Q filed by the Company on May 10, 2013,
File No. 001-12935).
Exhibit No.
Exhibit
10(ff)**
2013 Form of TSR Performance Award pursuant to the 2004 Omnibus Stock and Incentive Plan
(incorporated by reference to Exhibit 10(c) of Form 10-Q filed by the Company on May 10, 2013,
File No. 001-12935).
10(gg)**
2013 Form of Stock Appreciation Rights Agreement pursuant to the 2004 Omnibus Stock and
Incentive Plan (incorporated by reference to Exhibit 10(e) of Form 10-Q filed by the Company on
May 10, 2013, File No. 001-12935).
10(hh)**
2013 Form of Restricted Share Award to officers pursuant to the 2004 Omnibus Stock and Incentive
Plan (incorporated by reference to Exhibit 10(d) of Form 10-Q filed by the Company on May 10, 2013,
File No. 001-12935).
10(ii)**
10(jj)**
2013 Form of Restricted Share Award to non-employee directors pursuant to the 2004 Omnibus Stock
and Incentive Plan (incorporated by reference to Exhibit 10(c) of Form 10-Q filed by the Company on
August 6, 2013, File No. 001-12935).
2013 Form of Deferred Stock Unit Award pursuant to the Director Deferred Compensation Plan
(with respect to deferred long-term incentive awards) (incorporated by reference to Exhibit 10(d) of
Form 10-Q filed by the Company on August 6, 2013, File No. 001-12935).
10(kk)**
2013 Form of Deferred Stock Unit Agreement pursuant to the Director Deferred Compensation Plan
(with respect to deferred director fees) (incorporated by reference to Exhibit 10(e) of Form 10-Q filed
by the Company on August 6, 2013, File No. 001-12935).
21*
List of subsidiaries of Denbury Resources Inc.
23(a)*
Consent of PricewaterhouseCoopers LLP.
23(b)*
Consent of DeGolyer and MacNaughton.
31(a)*
Certification of Chief Executive Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002.
31(b)*
Certification of Chief Financial Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002.
32*
99*
Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
The summary of DeGolyer and MacNaughton’s Report as of December 31, 2013, on oil and gas
reserves (SEC Case) dated January 31, 2014.
** Included herewith.
** Compensation arrangements.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Denbury Resources
Inc. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
DENBURY RESOURCES INC.
/s/ Mark C. Allen
February 28, 2014
/s/ Alan Rhoades
February 28, 2014
Mark C. Allen
Sr. Vice President and Chief Financial Officer
Alan Rhoades
Vice President and Chief Accounting Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the
following persons on behalf of Denbury Resources Inc. and in the capacities and on the dates indicated.
/s/ Phil Rykhoek
February 28, 2014
/s/ John P. Dielwart
February 28, 2014
Phil Rykhoek
Director, President and Chief Executive Officer
(Principal Executive Officer)
John P. Dielwart
Director
/s/ Mark C. Allen
February 28, 2014
/s/ Ronald G. Greene
February 28, 2014
Mark C. Allen
Sr. Vice President and Chief Financial Officer
(Principal Financial Officer)
Ronald G. Greene
Director
/s/ Alan Rhoades
February 28, 2014
/s/ Gregory L. McMichael
February 28, 2014
Alan Rhoades
Vice President and Chief Accounting Officer
(Principal Accounting Officer)
Gregory L. McMichael
Director
/s/ Wieland F. Wettstein
February 28, 2014
/s/ Kevin O. Meyers
February 28, 2014
Wieland F. Wettstein
Director
Kevin O. Meyers
Director
/s/ Michael L. Beatty
February 28, 2014
/s/ Randy Stein
February 28, 2014
Michael L. Beatty
Director
Randy Stein
Director
/s/ Michael B. Decker
February 28, 2014
/s/ Laura A. Sugg
February 28, 2014
Michael B. Decker
Director
Laura A. Sugg
Director
104
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Exhibit 21
LIST OF SUBSIDIARIES
Name Of Subsidiary
Jurisdiction Of Organization
Denbury Operating Company
Denbury Onshore, LLC
Denbury Pipeline Holdings, LLC
Denbury Holdings, Inc.
Denbury Green Pipeline – Texas, LLC
Greencore Pipeline Company, LLC
Denbury Gulf Coast Pipelines, LLC
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
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Exhibit 23(a)
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 333-01006,
333-27995, 333-55999, 333-70485, 333-39172, 333-39218, 333-39224, 333-63198, 333-90398, 333-106253,
333-116249, 333-143848, 333-160178, 333-167480, 333-175273 and 333-189438) and Form S-3 (No. 333-186112) of
Denbury Resources Inc. of our report dated February 28, 2014 relating to the consolidated financial statements
and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Dallas, Texas
February 28, 2014
106
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Exhibit 23(b)
DEGOLYER AND MACNAUGHTON
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244
February 26, 2014
DENBURY RESOURCES INC.
5320 Legacy Drive
Plano, Texas 75024
Ladies and Gentlemen:
We hereby consent to the use of the name DeGolyer and MacNaughton, to references to DeGolyer and
MacNaughton, to the inclusion of our Letter Report dated January 31, 2014, regarding the proved reserves of
Denbury Resources, and to the inclusion of information taken from our “Appraisal Report as of December 31, 2013
on Certain Properties owned by Denbury Resources Inc. SEC Case”, “Appraisal Report as of December 31, 2012
on Certain Properties owned by Denbury Resources Inc. SEC Case”, and “Appraisal Report as of December 31, 2011
on Certain Properties owned by Denbury Resources Inc. SEC Case”, in the Annual Report on Form 10-K of
Denbury Resources Inc. for the year ended December 31, 2013.
Very truly yours,
/s/ DeGolyer and MacNaughton
DeGolyer and MacNaughton
Texas Registered Engineering Firm F-716
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Exhibit 31(a)
CERTIFICATION UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Phil Rykhoek, certify that:
1.
I have reviewed this report on Form 10-K of Denbury Resources Inc. (the registrant);
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;
4.
The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to
be designed under our supervision, to ensure that material information relating to the registrant, including
its consolidated subsidiaries, is made known to us by others within those entities, particularly during the
period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability
of financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of
the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred
during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s
internal control over financial reporting; and
5.
The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of
directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process,
summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant
role in the registrant’s internal control over financial reporting.
/s/ Phil Rykhoek
February 28, 2014
Phil Rykhoek
President and Chief Executive Officer
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Exhibit 31(b)
CERTIFICATION UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Mark C. Allen, certify that:
1.
I have reviewed this report on Form 10-K of Denbury Resources Inc. (the registrant);
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;
4.
The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to
be designed under our supervision, to ensure that material information relating to the registrant, including
its consolidated subsidiaries, is made known to us by others within those entities, particularly during the
period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability
of financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of
the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred
during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s
internal control over financial reporting; and
5.
The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of
directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process,
summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant
role in the registrant’s internal control over financial reporting.
/s/ Mark C. Allen
February 28, 2014
Mark C. Allen
Senior Vice President, Chief Financial Officer, Treasurer,
and Assistant Secretary
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Exhibit 32
CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER
PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the accompanying Annual Report on Form 10-K for the year ended December 31, 2013 (the
Report) of Denbury Resources Inc. (Denbury) as filed with the Securities and Exchange Commission, each of the
undersigned, in his capacity as an officer of Denbury, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to his knowledge:
1.
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of
1934, as amended; and
2.
information contained in the Report fairly presents, in all material respects, the financial condition and results
of operations of Denbury.
/s/ Phil Rykhoek
February 28, 2014
Phil Rykhoek
President and Chief Executive Officer
/s/ Mark C. Allen
February 28, 2014
Mark C. Allen
Senior Vice President, Chief Financial Officer, Treasurer,
and Assistant Secretary
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Corporate Information
4
Stock Exchange Listing
Financial Information Requests
New York Stock Exchange (“NYSE”)
For additional information and to receive
Ticker Symbol: DNR
Corporate Headquarters
Denbury Resources Inc.
5320 Legacy Drive
Plano, Texas 75024
972. 673. 2000
www.denbury.com
Stock Transfer Agent & Registrar
additional copies of the Annual Report on
Form 10-K as filed with the Securities and
Exchange Commission (“SEC”) or to obtain
other Denbury public documents, please
contact:
Denbury Resources Inc.
Investor Relations
5320 Legacy Drive
Plano, Texas 75024
972. 673. 2000
For questions concerning dividends, stock
Email: ir@denbury.com
certificates, transfer procedures or address
Our Form 10-K filed with the SEC is
changes, please contact:
American Stock Transfer and Trust Company
6201 15th Avenue
Brooklyn, NY 11219
800. 937. 5449
Email: info@amstock.com
www.amstock.com
Investor Inquiries
Phil Rykhoek
President & Chief Executive Officer
972. 673. 2000
Mark Allen
Senior Vice President &
Chief Financial Officer
972. 673. 2000
Jack Collins
Executive Director, Finance and
Investor Relations
972. 673. 2028
Email: jack.collins@denbury.com
Annual Certifications
During 2013, our Chief Financial Officer
certified to the NYSE that he is not
aware of any violation by the Company
included herein, excluding all exhibits
other than our Section 302, 404 and 906
certifications by the CEO and CFO. We will
send shareholders our Form 10-K exhibits
and any of our corporate governance
documents, without charge, upon request.
These documents are also available on our
website at www.denbury.com.
Annual Meeting
The Annual Meeting of Stockholders will be
held on Tuesday, May 20, 2014, at 3:00 P.M. CDT
at the Dallas/Plano Marriott at Legacy Town
Center, located at 7121 Bishop Road, Plano,
Texas 75024.
Legal Counsel
Baker & Hostetler LLP
Bankers
J.P. Morgan (Agent)
Auditors
PricewaterhouseCoopers LLP
Reserve Engineers
of the NYSE’s corporate governance
DeGolyer and MacNaughton
listing standards.
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D
2013 ANNUAL REPORTOPERATIONS OVERVIEW
Denbury Resources Inc.
5320 Legacy Drive | Plano, Texas 75024 | 972.673.2000 | www.denbury.com