Denbury Resources Inc (DNR) SEC Annual Report (10-K) for 2012

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

2012 FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2012

OR

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

For the transition period from _________ to________

Commission file number   1-12935

(Exact name of Registrant as specified in its charter)

Securities registered pursuant to Section 12(b) of the Act:

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

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

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 ☑    No o

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

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

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 ☑    Accelerated filer o    Non-accelerated filer o   Smaller reporting company o

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

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 $5,050,462,439.

The number of shares outstanding of the registrant's Common Stock as of January 31, 2013 , was 373,462,597.

DOCUMENTS INCORPORATED BY REFERENCE

2012 Annual Report on Form 10-K

 Table of Contents

Glossary and Selected Abbreviations

* This definition is an abbreviated version of the complete definition as defined by the SEC 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.

PART I

Item 1. Business and Properties

GENERAL

Denbury Resources Inc., a Delaware corporation, is a domestic independent oil and natural gas company with 409.4 MMBOE of estimated proved oil and natural gas reserves as of December 31, 2012 , of which 80% is oil.  Our primary focus is on enhanced oil recovery utilizing CO 2 , and our operations are focused in two key operating areas: the Gulf Coast region and Rocky Mountain region. We are the largest combined oil and natural gas producer in both Mississippi and Montana, and we own the largest reserves of CO 2 used for tertiary oil recovery east of the Mississippi River.  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:

Denbury became a Canadian public company in 1992.  In 1999, we moved our corporate domicile from Canada to the United States as a Delaware corporation and have been publicly traded in the United States since 1995 and on the New York Stock Exchange since May 1997.

Our corporate headquarters is located at 5320 Legacy Drive, Plano, Texas 75024, and our phone number is 972-673-2000. At December 31, 2012 , we had 1,432 employees, 766 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 BUSINESS DEVELOPMENTS

$195.2 million. As of February 21, 2013, we had spent a total of $521.0 million to repurchase an aggregate of 34.6 million shares, or approximately 8.6% of our outstanding shares as of September 30, 2011, at an average cost of $15.05 per share.

In two separate transactions earlier in 2012, which were also structured as like-kind exchanges for federal income tax purposes, we completed the following:

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 $1.3 billion in cash (after preliminary closing adjustments) and EOR assets (the "Bakken Exchange Transaction"). By exchanging these non-tertiary Bakken area assets for EOR assets, we are able to more purely focus our attention on tertiary recovery operations.

The Bakken area assets we sold had proved reserves of approximately 109 MMBOE at the time of sale, of which 66% was undeveloped, and 2012 production through the third quarter of 15,850 BOE/d. The EOR assets acquired in the Bakken Exchange Transaction include: (1) Webster Field, a planned future tertiary field, located in southeastern Texas, with nearly 100% working interest and 80% net revenue interest, proved reserves of 3.7 MMBOE and production of approximately 1,000 BOE/d; (2) Hartzog Draw Field, a planned future tertiary field located in Wyoming, consisting of an 83% working interest and 71% net revenue interest in the oil-producing Shannon Sandstone zone and a 67% working interest and 53% net revenue interest in the natural gas-producing Big George Coal zone, with proved reserves of 5.2 MMBOE and production of approximately 2,600 BOE/d; and (3) approximately a one-third overriding royalty ownership interest in ExxonMobil's CO 2 reserves in LaBarge Field in Wyoming with proved reserves of 1.3 Tcf and estimated deliverability of up to 115 MMcf/d.

Pending CCA Acquisition. In January 2013, we entered into an agreement to acquire producing assets in the CCA of Montana and North Dakota from a wholly-owned subsidiary of ConocoPhillips for $1.05 billion in cash, before standard closing adjustments primarily for revenues and costs of the properties to be purchased from the January 1, 2013 effective date to the closing date. We plan to fund the acquisition with a portion of the cash proceeds from the Bakken Exchange Transaction in order to qualify the acquisition for like-kind-exchange treatment under federal income tax rules. We expect the Pending CCA Acquisition to close near the end of the first quarter of 2013.

The assets we plan to purchase from ConocoPhillips include both additional interests in certain of our existing operated fields in CCA as well as operating interests in other CCA fields. We currently estimate on a preliminary basis that, as of December 31, 2012, the proved conventional (non-tertiary) reserves associated with the acquired assets, net to our acquired interests, were approximately 42 MMBOE, of which approximately 99% is oil and natural gas liquids, with average daily production of approximately 11,000 BOE/d during the fourth quarter of 2012. We plan to incorporate the newly acquired CCA assets into our CO 2 development plan that is currently being designed and to extend the Greencore pipeline north and southwest in order to deliver the CO 2 necessary to flood the CCA assets.

Acquisition of Thompson Field. In June 2012, we acquired a nearly 100% working interest and 84.7% net revenue interest in Thompson Field for $366.2 million after preliminary closing adjustments. The field is located approximately 18 miles west of our Hastings Field, which we are currently flooding with CO 2 , and which is the current terminus of the Green Pipeline which transports CO 2 from natural sources in the Jackson Dome area of Mississippi. Thompson Field is similar to Hastings Field, producing oil from the Frio zone at similar depths, and is a planned future tertiary field.

Sale of Non-Core Assets. On April 9, 2012, we completed the sale of certain non-operated assets in the Paradox Basin of Utah for $68.5 million cash after final closing adjustments. On February 29, 2012, we completed the sale of certain non-core assets primarily located in central and southern Mississippi and in southern Louisiana for $141.8 million, after final closing adjustments. We structured the sale of our non-core assets and the purchase of Thompson Field as a like-kind-exchange transaction for federal income tax purposes and anticipate deferral of a majority of the taxable gain recognized on the sale of the non-core assets.

2010 ENCORE ACQUISITION AND RELATED DISPOSITIONS

On March 9, 2010, we acquired Encore Acquisition Company ("Encore") pursuant to an Agreement and Plan of Merger (the "Encore Merger Agreement") in a stock and cash transaction valued at approximately $4.8 billion at the acquisition date, including the assumption of Encore debt and the value of the non-controlling interest in Encore Energy Partners LP ("ENP"). Under the Encore Merger Agreement, Encore was merged with and into Denbury (the "Encore Merger"), with Denbury surviving the Encore Merger.  Pursuant to our stated intent, at the time of acquisition, to divest certain non-strategic legacy Encore properties, certain oil and gas properties in the Permian Basin, Mid-continent area and East Texas Basin were sold in May 2010.  We subsequently divested our production and acreage in the Cleveland Sand Play and Haynesville Play during 2010 as well.  In addition to the property sales, we sold our ownership interests in ENP on December 31, 2010.  Collectively, we received approximately $1.5 billion in total consideration from these divestitures in 2010, excluding the bank debt of ENP that was assumed by the purchaser in the sale. In 2012, we exchanged the Bakken area assets acquired in the Encore Merger for cash and other assets with an estimated value of approximately $2.0 billion (see 2012 Business Developments – Bakken Exchange Transaction above).

OIL AND NATURAL GAS OPERATIONS

Summary. Our oil and natural gas properties are concentrated in the Gulf Coast and Rocky Mountain regions of the United States.  Currently our properties with proved and producing reserves in the Gulf Coast region are situated in Mississippi, Texas, Louisiana and Alabama, and in the Rocky Mountain region in Montana, North Dakota and Wyoming.  Our primary focus is using CO 2 in EOR, which we have been doing since we acquired Little Creek Field in the Gulf Coast region in 1999.  EOR, which we also refer to as "tertiary recovery" (as opposed to primary and secondary recovery), is a term used to represent techniques for extracting incremental oil out of existing oil fields.  We acquired Encore during 2010 with the intent to employ our tertiary recovery strategy using CO 2 in the Rocky Mountain region.  Our current portfolio of properties provides us significant growth potential for more than a decade.

Our Gulf Coast EOR operations are driven by CO 2 produced from natural sources in the Jackson Dome area of Mississippi, which is transported to our Gulf Coast tertiary fields.  In late 2012, we received first deliveries of anthropogenic (man-made) CO 2 into the Gulf Coast pipeline system from an industrial facility in Port Arthur, Texas. The CO 2 for our Rocky Mountain EOR operations will initially be supplied from the Lost Cabin gas plant in Wyoming and from an overriding royalty interest equivalent to an approximate one-third ownership interest in ExxonMobil's CO 2 reserves in LaBarge Field, which overriding royalty interest we acquired during 2012 in the Bakken Exchange Transaction. In the future, we intend to utilize CO 2 from our Riley Ridge CO 2 source. In 2012, we completed the initial 232-mile segment of the 20-inch Greencore Pipeline, which will serve as part of the planned CO 2 trunk line in the region. Although our development of tertiary fields, CO 2 sources and pipelines in the Rocky Mountain

region is just beginning, we believe that our significant CO 2 sources and planned pipeline infrastructure in the area will allow us to utilize CO 2 injection to potentially recover significant amounts of incremental oil from mature oil fields.  Each of our significant development areas and planned activities is discussed in more detail below.

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, 2012 , and average daily production and net revenue interest ("NRI") for 2012 .  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 net revenue interest due to royalties and other burdens.  For additional reserve information, see Estimated Net Quantities of Proved Oil and Natural Gas Reserves and Present Value of Estimated Future Net Revenues below.

NYMEX oil was $94.71 per Bbl, adjusted to prices received by field, and for natural gas was a Henry Hub cash price of $2.85 per MMBtu, also adjusted to prices received by field.

Enhanced Oil Recovery Overview. CO 2 used in EOR is one of the most efficient tertiary recovery mechanisms for producing crude oil.  The CO 2 acts somewhat like a solvent, mixing with the oil and ultimately freeing the oil from the formation as the CO 2 passes through reservoir rock.  CO 2 tertiary floods are unique in that they require large volumes of CO 2 .  To our knowledge, the location of large quantities of naturally occurring CO 2 in the United States is limited to a few geological basins.

While enhanced oil recovery projects utilizing CO 2 may not be considered a new technology, we apply several concepts we have learned over the years to fields to improve and increase sweep efficiency within the reservoirs, which include: (1) well evaluation and monitoring methods, (2) CO 2 injection conformance, (3) new completion techniques, (4) varied operating equipment and operating conditions, and (5) application of intense reservoir management and production techniques.  We began our CO 2 operations in August 1999, when we acquired Little Creek Field, followed by our acquisition of Jackson Dome CO 2 reserves and the NEJD pipeline in 2001.  Based upon our success at Little Creek and the ownership of the CO 2 reserves, we began to transition our capital spending and acquisition efforts to focus a greater percentage on CO 2 EOR and, over time, transformed our strategy to focus primarily, and then almost exclusively, on CO 2 EOR projects.  With the sale of our Bakken area assets in late 2012, our asset base today almost entirely relates to current or planned tertiary oil operations.  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, 2012 are proved tertiary oil reserves; (2) approximately 54% of our forecasted 2013 production is expected to come from tertiary oil operations (on a BOE basis); and (3) approximately 85% of our 2013 planned capital expenditures are related to our tertiary oil operations.  At year-end 2012 , the proved oil reserves in our tertiary recovery oil fields had an estimated PV-10 Value of approximately $6.8 billion , using 12-month first-day-of-the-month unweighted average NYMEX pricing during calendar 2012 of $94.71 per Bbl.  In addition, there are significant probable and possible reserves at several other fields for which tertiary operations are under way or planned.  Although the up-front cost of infrastructure and time to construct such is greater than in conventional oil recovery, we believe tertiary recovery has several favorable, offsetting and unique attributes including: (1) it has a lower risk, as we are operating oil fields that have significant historical production and reservoir and geological data, (2) our investments provide a reasonable rate of return at relatively low oil prices (we estimate our economic break-even point on a per-barrel basis before corporate-related overhead and expenses on our Gulf Coast projects at current oil prices is in the $40-per-barrel range, depending on the specific field and area), (3) we have limited competition for this type of activity in our geographic regions, and (4) our EOR activities could be considered more eco-friendly than other current oil and gas development, as we develop existing oil fields thereby not disturbing new habitats, drill fewer new wellbores, do not utilize hydraulic fracturing in our oil and natural gas development operations, and have the ability to geologically store CO 2 captured from industrial facilities.

We have been conducting and expanding EOR operations on our assets in the Gulf Coast region since 1999, and as a result, they are more developed from an EOR perspective than our assets in the Rocky Mountain region. In the Gulf Coast region, we

own what is, to our knowledge, the only significant naturally occurring source of CO 2 , and these large volumes of CO 2 have allowed us to significantly grow our production in that region. In addition to the sources of CO 2 we currently own, we are pursuing anthropogenic (man-made) sources of CO 2 to use in our tertiary operations, which we believe will not only help us recover additional oil, but will also provide an economical and eco-friendly way to store CO 2 . We started receiving our first anthropogenic CO 2 in the fourth quarter of 2012 from an industrial facility in Port Arthur, Texas and expect the amount of CO 2 we use in our operations coming from anthropogenic sources to grow in the future.

Through December 31, 2012 , we have invested a total of $3.0 billion in tertiary fields in our Gulf Coast region (including allocated acquisition costs and amounts assigned to goodwill) and have recovered all of these costs, with excess net cash flow (revenue less operating expenses and capital expenditures, excluding pipeline-related capital expenditures) of $1.1 billion.  Of this total invested amount, approximately $185 million (6%) was spent on fields that did not yet have any appreciable proved reserves at December 31, 2012 .  The proved oil reserves in our Gulf Coast tertiary oil fields have a year-end 2012 PV-10 Value of $6.8 billion , using the 12-month first-day-of-the-month unweighted average NYMEX pricing during calendar 2012 of $94.71 per Bbl.  These amounts do not include the capital costs or related depreciation and amortization of our CO 2 -producing properties or CO 2 pipelines, but do include CO 2 source field lease operating and transportation costs.  Including the Green Pipeline, which currently services our Hastings and Oyster Bayou fields, we have invested a total of $2.0 billion in CO 2 -producing assets and pipelines in the Gulf Coast region.

We began operations in the Rocky Mountain region in March 2010 as part of the Encore Merger, and as such, we have significantly fewer oil fields and less CO 2 pipeline infrastructure in that region, although we are aggressively developing both.  We currently have four properties in the Rocky Mountain region that we plan to flood with CO 2 : Bell Creek Field, Grieve Field, Hartzog Draw Field, and Cedar Creek Anticline.  The Cedar Creek Anticline is a geological structure over 126 miles in length consisting of 10 different operating units. We have contracted to purchase CO 2 from the Lost Cabin gas plant in central Wyoming and completed construction of the first section of the Greencore Pipeline in late 2012 to deliver CO 2 from such gas plant to our Bell Creek Field.  We currently expect to begin purchasing CO 2 from the Lost Cabin plant during the first quarter of 2013 and start injections at Bell Creek Field during the second quarter of 2013.  Our Riley Ridge acquisitions in 2010 and 2011 and ExxonMobil CO 2 acquisition in 2012 provide us additional sources of CO 2 for our currently planned and future potential projects in the area.

Tertiary Oil Properties

Gulf Coast Region

CO 2 Sources and Pipelines

Jackson Dome. Our primary Gulf Coast CO 2 source, Jackson Dome, located near Jackson, Mississippi, was discovered during the 1970s while being explored for hydrocarbons.  This significant and relatively pure source of CO 2 (98% CO 2 ) is, to our knowledge, the only significant deposit of CO 2 in the United States east of the Mississippi River, and we believe that it provides us a significant strategic advantage in the acquisition of other properties in Mississippi, Louisiana and Texas that could be further exploited through tertiary recovery.

We acquired Jackson Dome in February 2001 for $42 million, a purchase that also gave us ownership and control of the NEJD CO 2 pipeline.  This acquisition provided the platform to significantly expand our CO 2 tertiary recovery operations by assuring that CO 2 would be available to us on a reliable basis and at a reasonable and predictable cost.  Since February 2001, we have acquired and drilled numerous CO 2 -producing wells, significantly increasing our estimated proved Gulf Coast CO 2 reserves from approximately 800 Bcf at the time of acquisition to approximately 6.1 Tcf as of December 31, 2012 .  The CO 2 reserve estimates are based on a gross working interest of the CO 2 reserves, of which our net revenue interest is approximately 4.8 Tcf and is included in the evaluation of proved CO 2 reserves prepared by our outside reserve engineer, DeGolyer and MacNaughton.  In discussing our available CO 2 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 CO 2 production stream.

In addition to the proved reserves, we estimate that we have 2.4 Tcf of probable CO 2 reserves at Jackson Dome, and significant other possible reserves.  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 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 CO 2 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 CO 2 reserves will be developed.

Although our current proved CO 2 reserves are quite large, in order to continue our tertiary development of oil fields in the Gulf Coast region, incremental deliverability of CO 2 is required.  In order to obtain additional CO 2 deliverability, we have conducted several 3D seismic surveys in the area over the past several years, and anticipate drilling five development wells in 2013 that are intended to increase productive capacity, three of which could potentially add incremental CO 2 reserves. 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 CO 2 through our controlled pipeline network. We expect our current proved reserves of CO 2 , coupled with a risked drilling program at Jackson Dome and expected anthropogenic sources, to provide more than enough CO 2 for our existing and currently planned phases of operations in the Gulf Coast, including several fields we own and plan to flood that do not have proven tertiary reserves. Additionally, in the future, we believe that once a CO 2 flood reaches its productive economic limit, we could recycle a portion of the CO 2 that remains in that reservoir and utilize it in another tertiary flood.

In addition to using CO 2 for our Gulf Coast tertiary operations, we sell CO 2 to third-party industrial users under long-term contracts and currently have three CO 2 volumetric production payment contracts.  Approximately 91% of our average daily CO 2 production in 2012 and 2011 and 87% in 2010 was used in our tertiary recovery operations on our own behalf and on behalf of other working interest owners and royalty owners in our enhanced recovery fields, with the balance delivered to third-party industrial users.  During 2012 , we sold an average of 92 MMcf/d of CO 2 to commercial users, and we used an average of 933 MMcf/d for our tertiary activities.  We are continuing to increase our CO 2 production, which averaged 1,100 MMcf/d during the fourth quarter of 2012 , a 7% increase over the fourth quarter of 2011 .

Gulf Coast Anthropogenic CO 2 Sources.   In addition to our natural source of CO 2 , we are currently party to five long-term contracts to purchase man-made CO 2 from five plants that either exist, are currently under construction, or are planned, in the Gulf Coast region.  In late 2012, we received first deliveries of anthropogenic CO 2 into the Gulf Coast pipeline system from an industrial facility in Port Arthur, Texas, and we anticipate taking deliveries from another existing plant in 2013 and a plant currently under construction in early 2014. We estimate these three sources will supply approximately 200 MMcf/d of CO 2 to our EOR operations, although under certain circumstances they could provide higher volumes.  If the remaining two plants as to which we have long-term CO 2 purchase contracts also were to be built, we currently estimate our anthropogenic CO 2 sources could potentially provide us with aggregate CO 2 volumes of up to 600 MMcf/d.  Construction of these two plants is considered probable, although is contingent on the satisfactory resolution of various matters, including financing.  While both of these plants may not be constructed, other plants currently being planned could provide us additional anthropogenic CO 2 .  We are in ongoing discussions with, and/or have entered into contractual arrangements to purchase CO 2 from, several of these other potential sources.

In addition to potential CO 2 sources discussed above, we continue to have ongoing discussions with owners of existing plants of various types that emit CO 2 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 CO 2 , generally less than the proposed gasification plants, but such volumes may still be attractive if the source is located near CO 2 pipelines.  The capture of CO 2 could also be influenced by potential federal legislation, which could impose economic penalties for the emission of CO 2 .  We believe that we are a likely purchaser of CO 2 captured in our areas of operation because of the scale of our tertiary operations, our CO 2 pipeline infrastructure and our large natural sources of CO 2 , which can act as a swing CO 2 source to balance CO 2 supply and demand.

Gulf Coast CO 2 Pipelines . We acquired the 183-mile NEJD CO 2 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 CO 2 pipelines, which give us the ability to deliver CO 2 throughout the Gulf Coast.  As of December 31, 2012 , we have access to over 920 miles of CO 2 pipelines in the Gulf Coast region. In addition to the NEJD CO 2 pipeline, the major pipelines are the Free State Pipeline (90 miles), the Delta Pipeline (110 miles) and the Green Pipeline (325 miles).

Completion of the Green Pipeline facilitated the first CO 2 injection into the Hastings Field, located near Houston, Texas, in late 2010.  The completion of the Green Pipeline gives us the ability to deliver CO 2 to oil fields all along the Gulf Coast from Baton Rouge, Louisiana, to Alvin, Texas.  At the present time, most of the CO 2 flowing in the Green Pipeline is delivered from the Jackson Dome are a , but we recently began receiving anthropogenic CO 2 from a plant in Port Arthur, Texas, and will transport a third party's CO 2 for a fee to the sales point at Hastings Field.  We expect the volume of anthropogenic CO 2 flowing through the Green Pipeline to increase in future years.

Tertiary Properties with Tertiary Production and Tertiary Reserves at December 31, 2012

Mature properties. Mature properties include several fields along our NEJD CO 2 pipeline and the Free State pipeline, which run through east Mississippi, southwest Mississippi and into Louisiana.  This grouping includes some of our most mature CO 2 floods, including our initial CO 2 field, Little Creek, as well as several other areas (Brookhaven, Cranfield, Eucutta, Lockhart Crossing, Mallalieu, Martinville, McComb and Soso fields).  These fields accounted for approximately 44% of our total 2012 CO 2 EOR production and 27% of our proved tertiary reserves.  These fields have been producing for some time, and their production is generally on decline. Many of these fields contain multiple reservoirs that are amenable to CO 2 EOR. In 2013, we plan to invest approximately $90 million in our mature properties.

Most of the development work is complete in this area; however, there are some additional areas at McComb, Cranfield, Brookhaven and Little Creek that we currently plan to develop.  EOR operations in Eucutta and Martinville fields were initiated in 2006 following completion of the Free State Pipeline, and the fields are mostly developed in the reservoir(s) under flood at the present time. In addition to the developed reservoirs, these fields have potential development targets in other vertically segregated reservoirs. As these fields have matured, we have experimented with a variety of techniques to maximize the recovery of oil from these reservoirs, gathering knowledge that we will utilize in all areas of our EOR operations.  All of the techniques we are employing are intended to improve the overall sweep efficiency in the formation and hence to maximize production.

Due to the lower viscosity of CO 2 when compared to oil, CO 2 will tend to follow the path of least resistance.  This may result in high producing gas-oil ratios sooner than anticipated.  In order to address this issue, 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 CO 2 for a given volume and then CO 2 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 as appropriate.

From inception through December 31, 2012 , 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 was $1.7 billion.  As of December 31, 2012 , the estimated PV-10 Value of our mature properties was $1.9 billion .

Delhi Field. Delhi Field is located southwest of Tinsley Field and east of Monroe, Louisiana.  During May 2006, we purchased Delhi for $50 million, plus an approximate 25% reversionary interest to the seller after we achieve $200 million in net operating income.  We began well and facility development in 2008 and began delivering CO 2 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 March 2010.  Current trend and performance data indicate that Delhi Field is acting as predicted and continues to provide a positive outlook for this field. Production from Delhi in the fourth quarter of 2012 averaged 5,237 Bbls/d, up from 3,778 Bbls/d in the year-ago period.  In 2013 , we plan to invest approximately $40 million to drill 15 wells and optimize existing development patterns at Delhi Field. Based on our current estimates, we expect the reversionary interest to come into effect some time in the latter part of 2013, which will reduce our net revenue interest in the field at that time.

From inception through December 31, 2012 , 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 Delhi Field was $122 million. As of December 31, 2012 , the estimated PV-10 Value of Delhi Field was $989.6 million .

Hastings Field.   Hastings Field is located just south of Houston, Texas.  We acquired a majority interest in this field in February 2009 for approximately $247 million.  Due to the large vertical oil column that exists in the field, we are developing the Frio reservoir using dedicated CO 2 injection and producing wells for each of the major sand intervals. We initiated CO 2 injection in the West Hastings Unit during December 2010 upon completion of the construction of the Green Pipeline.  We began producing

oil from our EOR operations at Hastings Field in January 2012, and we booked proved tertiary reserves of 42.6 MMBbl for the West Hastings Unit in 2012.  During the fourth quarter of 2012 , tertiary production from Hastings Field averaged 3,409 Bbls/d, compared to zero in the year-ago period. In 2013 , we plan to invest approximately $90 million to continue developing the West Hastings Unit, including the development of additional patterns and expansion of the processing facilities.  Significant additional capital expenditures will be required over several years to fully develop the field.

From inception through December 31, 2012 , 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 $331 million.  As of December 31, 2012 , the estimated PV-10 Value of Hastings Field was $1.2 billion .

Heidelberg Field.   In 2008, we began CO 2 injections at Heidelberg Field, which is located in Mississippi and consists of an East and West Unit.  Construction of the CO 2 facility, connecting pipeline and well work commenced on the West Heidelberg Unit during 2008, with our first CO 2 injections beginning in December 2008.  Our first tertiary oil production response occurred during May 2009.  During 2010, we added injection patterns and expanded the central processing facility.  Production from the West Unit began to decline in 2011 and we determined that CO 2 was not reaching all the targeted zones, broadly described as "conformance issues."  In 2011, we modified our development pattern to address the conformance issues by redirecting CO 2 into previously unswept intervals in the West Heidelberg Unit, and we believe this work has been successful.  During the fourth quarter of 2012 , tertiary production at Heidelberg Field averaged 3,930 Bbls/d, compared to 3,728 Bbls/d in the year-ago period.  In 2012, we continued the development of our East Heidelberg Unit, which is larger and contains more oil in place than the West Heidelberg Unit, by initiating the second phase of the Eutaw development and the first phase of the Christmas development.  In 2013, we plan to invest approximately $100 million to continue developing the East Heidelberg Unit, including an expansion of our development of the Eutaw and Christmas zones, and we plan to invest $20 million in the West Heidelberg Unit to optimize our development in the area.

From inception through December 31, 2012 , we have recovered all our costs relating to the CO 2 flood at Heidelberg Field, and the excess net cash flow (revenue less operating expenses and capital expenditures, including the acquisition costs) from the field was $51 million.  As of December 31, 2012 , the estimated PV-10 Value of Heidelberg Field was $1.2 billion .

Oyster Bayou Field.   Oyster Bayou Field, of which we acquired a majority interest in 2007, is located in southeast Texas on the east side of Galveston Bay.  Oyster Bayou Field was unitized in the spring of 2010 and we began CO 2 injections there in June 2010.  Oyster Bayou Field is somewhat unique when compared to our other CO 2 EOR projects because the field covers a relatively small area of 3,912 acres and was designed to be developed in essentially one stage.  We commenced production from Oyster Bayou Field in December 2011 and booked initial proved tertiary reserves for the field of 14.1 MMBbl in 2012.  During the fourth quarter of 2012, tertiary production at Oyster Bayou Field averaged 1,826 Bbls/d, compared to 18 Bbls/d in the year-ago period. In 2013 , we plan to invest approximately $5 million to increase our CO 2 injection and water disposal capacity at Oyster Bayou Field.

From inception through December 31, 2012 , 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 $165 million.  As of December 31, 2012 , the estimated PV-10 Value of Oyster Bayou Field was $ 496.5 million .

Tinsley Field.   Tinsley Field was acquired in January 2006, is located in Mississippi, and was first developed in the 1930s.  As is the case with the majority of fields in Mississippi, Tinsley produces from multiple reservoirs.  Our primary target in Tinsley for CO 2 enhanced oil recovery operations is the Woodruff formation, although there is additional potential in the Perry sandstone and other smaller reservoirs.  We initiated limited CO 2 injections in January 2007 through a previously existing 8-inch pipeline, but replaced the use of the 8-inch line in 2008 upon the completion of the 24-inch Delta Pipeline to Tinsley Field.  We had our first tertiary oil production from Tinsley Field in April 2008.  As of December 31, 2012 , we have completed the development of the West and East Fault Blocks. In 2012, we installed and began injection into three patterns of the North Fault Block of Tinsley. We also installed trunklines and a test site to support future North Fault Block development. In 2013, we expect to invest approximately $40 million to continue our development of the North Fault Block at Tinsley Field.  During the fourth quarter of 2012 , the average tertiary oil production was 8,166 Bbls/d as compared to 6,338 Bbls/d in the year-ago period.

From inception through December 31, 2012 , 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 $151 million.  As of December 31, 2012 , the estimated PV-10 Value of Tinsley Field was $1.1 billion .

Future Tertiary Properties with No Tertiary Production or Tertiary Reserves at December 31, 2012

Webster Field. We acquired our interest in Webster Field in November 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 CO 2 . The acquired Webster Field interests had estimated proved conventional reserves of approximately 3.7 MMBOE at December 31, 2012.  In December 2012, conventional production at Webster Field averaged 1,104 BOE/d net to our acquired interest.  Webster Field is geologically similar to our Hastings and Thompson fields, producing oil from the Frio zone at similar depths, and is believed to be an ideal candidate for a CO 2 flood. In 2013 we plan to invest approximately $20 million on conventional infill drilling opportunities and recompletions along with preliminary CO 2 flood scoping at Webster Field. We currently plan to commence CO 2 injections at Webster Field in 2015, with first tertiary production expected 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 approximately $271 million in cash and 11.6 million shares of Denbury common stock, for a total aggregate value of $439 million.  The acquired Conroe Field interests had estimated proved conventional reserves of approximately 12.5 MMBOE at December 31, 2012 , nearly all of which are proved developed.  During the fourth quarter of 2012 , production at Conroe Field averaged 2,745 BOE/d net to our acquired interest, compared to 2,587 BOE/d in the year-ago period.  Given the size of the Conroe Field of approximately 20,000 acres, the volume of CO 2 that could be injected is quite sizable, much larger than any field we have developed to date.  Therefore, the pace of development will partly be dictated by the amount of available CO 2 .

A pipeline must be constructed so that CO 2 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 $200 million to $240 million.  With our acquisition of Webster Field in 2012, we deferred our construction plans for the Conroe pipeline by two years thus similarly deferring development plans for Conroe Field. We now plan to construct this pipeline in 2016 and to commence CO 2 injections at Conroe Field in 2017 with first tertiary production expected that same year. In 2013, we plan to determine the pipeline path, continue the acquisition of rights-of-way, and engineer and design the pipeline while refining and finalizing our CO 2 EOR plan for Conroe Field. In 2013 we also plan to invest $15 million on conventional infill drilling opportunities and recompletions at Conroe Field.

Thompson Field. We acquired our interest in Thompson Field in June 2012 for $366.2 million. The field is located in Texas, approximately 18 miles west of our Hastings Field. The acquired Thompson Field interests had estimated proved conventional reserves of approximately 16.7 MMBOE at December 31, 2012 , of which approximately 55% are proved developed.  In December 2012, conventional production at Thompson Field averaged 1,507 BOE/d net to our interest. Thompson Field is geologically similar to Hastings Field, producing oil from the Frio zone at similar depths; it is also expected to be an ideal candidate for a CO 2 flood. Under the terms of the Thompson Field acquisition agreement, after the initiation of CO 2 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 2013, we plan to invest $15 million on conventional infill drilling opportunities and recompletions at Thompson Field. We currently plan to commence CO 2 injections at Thompson Field in mid-2018, with first tertiary production expected in 2019.

Rocky Mountain Region

CO 2 Sources and Pipelines

LaBarge Field.   LaBarge Field is located in southwestern Wyoming. The gas composition from LaBarge Field is approximately 65% CO 2 , 20% natural gas, 5% hydrogen sulfide (H 2 S), less than one percent helium, and the remainder other gases.

We acquired an overriding royalty interest equivalent to an approximate one-third ownership interest in ExxonMobil's CO 2 reserves in LaBarge Field in southwestern Wyoming in December 2012 as part of the Bakken Exchange Transaction. Based on the current capacity of ExxonMobil's Shute Creek gas processing plant at LaBarge Field and subject to availability, we expect to

receive up to approximately 115 MMcf/d of CO 2 from such plant. We will pay ExxonMobil a fee to process and deliver the CO 2 , which will initially be used to flood our Bell Creek, Grieve and Hartzog Draw fields. As of December 31, 2012, our interest in LaBarge Field consisted of approximately 1.3 Tcf of proved CO 2 reserves.

The Riley Ridge Federal Unit is also located in southwestern Wyoming and will produce gas from LaBarge Field. We acquired interests in Riley Ridge in two phases.  In 2010, we acquired a 42.5% non-operated working interest for $132.3 million.  This initial purchase included a 42.5% interest in a gas plant under construction that will separate the helium and natural gas from the gas stream.  In 2011, we acquired the remaining 57.5% working interest in Riley Ridge and the remaining interest in the gas plant.  As a result of the consummation of the second phase of the transaction, we became the operator of the project.  The purchase price for the second phase was $214.8 million.  We currently expect the gas plant to be operational in mid-2013 once all engineering safety systems are in place. We plan to invest approximately $40 million at Riley Ridge in 2013 to complete the initial phase of the facilities and drill one producing well and complete one injection well.

As of December 31, 2012 , our interest in Riley Ridge and minor surrounding acreage contained net proved reserves of 416 Bcf ( 69 MMBOE ) of natural gas and 2.2 Tcf of CO 2 reserves.  The CO 2 reserve estimates are based on the gross working interest of the CO 2 reserves, in which our net revenue interest is approximately 1.6 Tcf.  The helium reserves at Riley Ridge are owned by the U.S. government; however, we have the right to produce and sell the helium reserves on behalf of the government in exchange for a fee.  As of December 31, 2012 , we estimate that Riley Ridge contains proved helium reserves of 12.7 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 plant currently under construction at Riley Ridge will separate the natural gas and helium from the full well stream, and the remaining gases, including CO 2 , will initially be reinjected into the producing formation until a planned CO 2 capture facility and pipeline can be built.  We have initiated the engineering and design of the CO 2 capture facility, which is estimated to initially capture up to 130 MMcf/d of CO 2 , and we currently plan to double this capacity within the next decade. We currently project that we will start to use CO 2 from Riley Ridge around 2017.

Other Rocky Mountain CO 2 Sources.   We have ongoing discussions with, and are actively pursuing, several sources for CO 2 supply in the Rocky Mountain region.  We have contracted to purchase CO 2 from the Lost Cabin plant in central Wyoming, which agreement will provide as much as 50 MMcf/d of CO 2 from the Lost Cabin plant.  We have completed all necessary work to receive the CO 2 and expect first CO 2 deliveries from Lost Cabin in the first quarter of 2013.

In 2011, we entered into a long-term supply contract to purchase anthropogenic CO 2 from a proposed plant in southeastern Wyoming.  We estimate the proposed plant could initially supply approximately 100 MMcf/d, and potentially up to 200 MMcf/d of CO 2 for our enhanced oil recovery operations in Wyoming and Montana.  We would expect to begin taking delivery of CO 2 approximately four years following commencement of construction of this plant.  The purchase price of CO 2 will fluctuate based on changes in the price of oil.  As is the case with all of our long-term supply contracts to purchase CO 2 from proposed plants, the agreement is subject to various contingencies, and completion of the plant is contingent upon securing debt financing and equity commitments, along with receipt of all necessary consents and approvals.

Greencore Pipeline.   The 20-inch Greencore Pipeline in Wyoming is the first CO 2 pipeline constructed by Denbury in the Rocky Mountain region.  As currently planned, the pipeline will serve as our trunk-line in the Rocky Mountain region, eventually connecting our Lost Cabin, LaBarge and Riley Ridge CO 2 sources (see Rocky Mountain region CO 2 Sources and Pipelines above) to the Cedar Creek Anticline in eastern Montana, and may connect to other potential anthropogenic CO 2 sources in the region.  The initial 232-mile section of the Greencore Pipeline begins at the Lost Cabin gas plant and terminates at our Bell Creek oil field in Montana.  We completed construction of this section of the pipeline in late 2012 and expect to receive first CO 2 deliveries from the Lost Cabin gas plant in the first quarter of 2013.  In 2013, we plan to build an interconnect between our Greencore Pipeline and an existing third-party CO 2 pipeline owned by another party in Wyoming. We plan to transport CO 2 from LaBarge Field to the Greencore Pipeline through this existing pipeline for use in planned CO 2 floods at Bell Creek and Hartzog Draw fields.

Future Tertiary Properties with No Tertiary Production or Tertiary Reserves at December 31, 2012

Bell Creek Field.   Bell Creek Field is located in southeast Montana.  We acquired our interest in Bell Creek through the Encore Merger.  As of December 31, 2012 , the majority of the work in this field has involved re-activating wells and injecting

additional water into the reservoir to raise reservoir pressure in anticipation of future CO 2 injections.  The original operator of the field temporarily abandoned wells in such a way as to preserve the mechanical integrity of the wellbore and to minimize the cost of re-entering the wells.  We expect to have first CO 2 injections in Bell Creek Field in the first half of 2013 and anticipate first tertiary oil production in the second half of 2013.  The producing reservoir in Bell Creek Field is a sandstone reservoir very similar to our Gulf Coast reservoirs.  Conventional production, net to our interest, during the fourth quarter of 2012 averaged 781 Bbls/d, as compared to 840 Bbls/d in the year-ago period.  In 2013 , we plan to invest approximately $100 million to install compression equipment and facilities and continue the development of injection patterns at Bell Creek Field.

Hartzog Draw Field. We acquired our interest in Hartzog Draw Field in November 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. The acquired Hartzog Draw interests had estimated proved reserves of approximately 5.2 MMBOE at December 31, 2012, 1.9 MMBOE of which relate to the natural gas producing Big George coal zone.  In December 2012, conventional production at Hartzog Draw Field averaged 2,444 BOE/d net to our acquired interest.  The oil reservoir characteristics of Hartzog Draw Field make the field an ideal candidate for a CO 2 flood. In 2013, we plan to invest approximately $13 million on conventional infill drilling opportunities and recompletions at Hartzog Draw Field. We must obtain regulatory approval and construct a 12-mile CO 2 pipeline from our existing Greencore Pipeline to Hartzog Draw Field before we can commence an EOR flood. We anticipate that we will be able to commence CO 2 injections at Hartzog Draw Field in 2016 with first tertiary production expected that same year.

Cedar Creek Anticline.   CCA 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 10 producing oil units, each of which could be considered a field by itself.  We acquired our initial interest in CCA as part of the Encore Merger, and it is currently the largest potential EOR field we own.  Production, net to our interest, during the fourth quarter of 2012 from all of the units in CCA averaged 8,493 BOE/d, compared to 8,858 BOE/d in the year-ago period.  The conventional proved reserves associated with CCA were 66.8 MMBbls of oil and 0.4 Bcf of gas as of December 31, 2012 . In January 2013, we entered into a definitive agreement with a wholly-owned subsidiary of ConocoPhillips whereby we plan to add to our CCA assets through the purchase of ConocoPhillips' assets in the field. See 2012 Business Developments – Pending Cedar Creek Anticline Acquisition above and Note 2 , Acquisitions and Divestitures , to the Consolidated Financial Statements for further discussion of this transaction and information as to other recent acquisitions and divestitures by Denbury. The Pending CCA Acquisition is expected to add approximately 42 MMBOE of incremental proved reserves at CCA; production associated with these assets averaged approximately 11,000 BOE/d during the fourth quarter of 2012.

CCA is located approximately 110 miles north of Bell Creek Field, and we expect to ultimately connect this field to our Greencore Pipeline.  In 2013, we plan to invest approximately $115 million to improve waterfloods of CCA through well and facility work, recomplete existing wells, and develop plans for our planned future CO 2 flood of the field. We currently plan to commence first CO 2 injections into the field in 2017 with first tertiary production expected that same year.

Grieve Field. In May 2011, we entered into a farm-in agreement, under which we have the right to acquire up to 65% of the working interest in the Grieve Field, located in Natrona County, Wyoming.  We are overseeing design, construction and operations of the field.  We completed the required three-mile CO 2 pipeline to deliver CO 2 from an existing CO 2 pipeline to the Grieve Field in December 2012, and are contracting for the construction of the CO 2 recycle facility.  We estimate first CO 2 injection at Grieve Field in the first quarter of 2013 and first tertiary production late in 2014 or early in 2015.

Non-Tertiary Oil Properties

Our non-tertiary production in 2012 totaled 36,483 BOE/d, or 51% of total production. Excluding production from the non-core asset divestitures discussed above, our continuing non-tertiary production totaled 21,636 BOE/d or 38% of our continuing production in 2012. A substantial portion of this production is generated from fields we intend to flood with CO 2 in the future, and which are discussed above under Tertiary Oil Properties – Gulf Coast Region – Future Tertiary Properties with No Tertiary Production or Tertiary Reserves at December 31, 2012 and Tertiary Oil Properties – Rocky Mountain Region – Future Tertiary Properties with No Tertiary Production or Tertiary Reserves at December 31, 2012 .

Gulf Coast Region

Other Non-Tertiary Fields. We have been active in East Mississippi since Denbury was founded in 1990 and are the largest oil producer in the state.  Conventional or non-tertiary production during the fourth quarter of 2012 averaged approximately 3,663 BOE/d from this area (6% of our total continuing production), and we had proved reserves of 11.1 MMBOE as of December 31, 2012 (3% of our Company total).  Since we have generally owned these properties in East Mississippi longer than properties in our other regions, these East Mississippi properties tend to be more fully developed.  In 2012, we completed the sale of certain non-core assets with proved reserves of 6.4 MMBOE primarily located in central and southern Mississippi and in southern Louisiana for $141.8 million.

Our largest field in the region is the Heidelberg Field located in Mississippi, which for the fourth quarter of 2012 produced an average of 1,947 BOE/d of conventional or non-tertiary production.  This compares to 3,129 BOE/d in the year-ago period, with most of the decline in production due to the conversion of conventional areas of the field to a CO 2 flood and the decline in natural gas production in the Selma Chalk.  Most of the past and current production comes from the Eutaw, Selma Chalk and Christmas sands at depths from 3,500 feet to 5,000 feet.  The majority of the conventional oil production at Heidelberg Field is from waterflood units that produce from the Eutaw formation (at approximately 4,400 feet).  We have converted all of the waterflood units in West Heidelberg to CO 2 EOR and are in the process of converting the East Heidelberg waterflood units to CO 2 EOR. Heidelberg Field also produces natural gas from the Selma Chalk, which was a fairly active area of development for us prior to 2009.  The Selma Chalk is a natural gas reservoir at approximately 3,700 feet that is developed with horizontal wells and, prior to 2012, hydraulic fracturing.  The Selma Chalk is estimated to contain 28.2 Bcf of proved natural gas reserves as of December 31, 2012 .  Natural gas production from the Selma Chalk was 10.5 MMcf/d during the fourth quarter of 2012 , compared to 13.4 MMcf/d in the year-ago period.  The decline in production is due to a decrease in drilling activity over the past several years, combined with a rapid decline rate in the Selma Chalk wells.

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, 2012 :

Our net undeveloped acreage that is subject to expiration over the next three years, if not renewed, is approximately 35% in 2013 , 2% in 2014 and 4% in 2015 .

Productive Wells

The following table sets forth our gross and net productive oil and natural gas wells as of December 31, 2012 :

Drilling Activity

The following table sets forth the results of our drilling activities over the last three years.  As of December 31, 2012 , we had 19 gross (13.3 net) wells in progress.

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, 2012 , 2011 and 2010 :

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 – Operating Results , included herein.

TITLE TO PROPERTIES

Customarily in the oil and natural gas industry, only a perfunctory title examination is conducted at the time properties believed to be suitable for drilling operations are first acquired.  Prior to commencement of drilling operations, a thorough drill site title examination is normally conducted, and curative work is performed with respect to significant defects.  Typically, in connection with acquisitions, title reviews are performed on selected higher-value properties.  We believe that we have good title to our oil and natural gas properties, some of which are subject to encumbrances, easements and restrictions which we do not believe are material to our operations.

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 years ended December 31, 2012 , 2011 and 2010 , two purchasers accounted for 10% or more of our oil and natural gas revenues: Marathon Petroleum Company LLC ( 39% , 43% and 46% in 2012 , 2011 and 2010 , respectively) and Plains Marketing LP ( 17% , 16% and 14% in 2012 , 2011 and 2010 , respectively).

Our ability to market oil and natural gas depends on many factors beyond our control, including the extent of domestic production and imports of oil and gas, the proximity of our oil and natural gas production to pipelines, the available capacity in such pipelines, the demand for oil and natural gas, the effects of weather, and the effects of state and federal regulation.  Our production in the Gulf Coast region is primarily from developed fields close to major pipelines or refineries and established infrastructure.  Our production in the Rocky Mountain region is dependent on, among other factors, limited transportation options caused by oversubscribed pipelines and market centers that are distant from producing properties.  As of December 31, 2012 , 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 2012 and 2011, our light sweet oil production in this area, on average, sold for more than $11.50 per Bbl over NYMEX.  The light and medium sour crude production has also benefited from the continued strength of other Gulf Coast grades relative to NYMEX, with production in 2012 selling at a premium to NYMEX of $6.69 per Bbl.  Historically, LLS pricing and NYMEX pricing have been much closer together than the spread we have experienced over the last two years. The market dynamics of the region suggest the possibility of divergence from the current premiums currently being realized 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, and 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 have currently been allocated 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 increased stability of oil differentials in the area, although recent events resulting in wider than usual differentials in the current markets are expected to remain in place until incremental takeaway capacity comes on line.  For the year ended December 31, 2012 , the discount for our oil production in the Rocky Mountain region averaged $11.86 per Bbl, compared to $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 2012 , we sold approximately 40% of our crude oil at prices based on the LLS index price, approximately 22% 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. On a pro forma basis excluding Bakken area assets sold in 2012, we sold approximately 49% of our crude oil at prices based on the LLS index price and approximately 27% at prices partially tied to the LLS index price.

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.  Our 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, 2012 , the amount received per Mcf for our Mississippi natural gas production was consistent with NYMEX prices.  In the Texas Gulf Coast region, due primarily to its location, the price we received for the year ended December 31, 2012 averaged $0.08 per Mcf below NYMEX prices.  The Rocky Mountain region natural gas production 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.  For the year ended December 31, 2012 , we averaged $0.55 per Mcf over NYMEX prices for our Rocky Mountain region natural gas production due primarily to the natural gas liquids extracted from the gas stream, improving the net price we receive.

Helium Marketing

We expect production to commence at Riley Ridge Field in mid-2013, after which 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, and CO 2 properties; marketing of oil and natural gas; and obtaining 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.  Gathering systems are the only practical method for the intermediate transportation of natural gas. Therefore, competition for natural gas delivery is presented by other pipelines and gas gathering systems.  Competition is also presented to a lesser extent by alternative fuel sources, including heating oil and other fossil fuels.  Because of the primary nature of our core assets (our tertiary operations) and our ownership of relatively uncommon significant natural sources of CO 2 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 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 extensive and our personnel costs have been escalating at a rate higher than general inflation. There have also been 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.  Higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services.  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 or restrict our ability to drill those wells and conduct those operations that we currently have planned and budgeted.

FEDERAL AND STATE REGULATIONS

Numerous federal and state 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 costly, and substantial penalties may be incurred for noncompliance.  The following sections describe some specific laws and regulations that may affect us.  We cannot predict the impact of these or other future legislative or regulatory initiatives.

Management believes that we are in substantial compliance with all laws and regulations applicable to our operations and that continued compliance with existing requirements will not have a material adverse impact on us.  The future annual cost of complying with the regulations applicable to our operations is uncertain and will be governed by several factors, including future changes to regulatory requirements.  However, management 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 compliance and regulatory approval could cause delays or otherwise impede operations.

Regulation of Natural Gas and Oil Exploration and Production

Our operations are subject to various types of regulation at the federal, state and local levels.  Such regulation includes requiring permits for drilling wells; maintaining bonding requirements in order to drill or operate wells and regulating the location of wells; the method of drilling and casing wells; the surface use and restoration of properties upon which wells are drilled; the plugging and abandoning of wells; and the composition or disposal of chemicals and fluids used in connection with operations.  Our operations are also subject to various conservation laws and regulations.  These include regulation of the size of drilling, spacing or proration units and the density of wells that may be drilled in those units, and the unitization or pooling of oil and gas properties.  In addition, state conservation laws, which establish maximum rates of production from oil and gas wells, generally prohibit or restrict the venting or flaring of natural gas and impose certain requirements regarding the ratability of production.  The effect of these 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 and certain sales of natural gas in interstate commerce are heavily regulated by agencies of the U.S. federal government and are affected by the availability, terms and cost of transportation.  In particular, 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 rules and regulations affecting the natural gas industry.  Some of FERC's proposals 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.  We cannot predict when or if any such proposals might become effective and their effect, 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 CO 2 pipelines, which safety standards could affect our operations and the costs thereof. The DOT has not yet promulgated any such new minimum safety standards.  In the future, Congress may create new incentives for alternative energy sources and may also consider legislation to reduce emissions of CO 2 or other greenhouse gases.  If enacted, such legislation could (1) impose a tax or other economic penalty on the production of fossil fuels that, when used, ultimately release CO 2 , (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 CO 2 or other greenhouse gases could also create economic incentives for technologies and practices that reduce or avoid such emissions, including processes that sequester CO 2 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.  Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Federal, State or Indian Leases

Our operations on federal, state or Indian oil and gas leases, especially those in the Rocky Mountains, 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

Public interest in the protection of the environment has increased dramatically in recent years.  Our oil and natural gas production, saltwater disposal operations, injection of CO 2 , and the processing, handling and disposal of materials such as hydrocarbons and naturally occurring radioactive materials ("NORM") are subject to stringent regulation.  We could incur significant costs, including cleanup costs resulting from a release of product, third-party claims for property damage and personal injuries, or penalties and other sanctions as a result of any violations or liabilities under environmental or other laws applicable to our operations.  Changes in, or more stringent enforcement of, environmental laws and other laws applicable to our operations could also result in delays or additional operating costs and capital expenditures.

Various federal, state and local laws and regulations controlling the discharge of materials into the environment or otherwise relating to the protection of the environment directly impact our oil and gas exploration, development and production operations.  These include, among others, (1) regulations adopted by the EPA and various state agencies regarding approved methods of disposal for certain hazardous and nonhazardous wastes; (2) the Comprehensive Environmental Response, Compensation, and Liability Act and analogous state laws that regulate the removal or remediation of previously disposed wastes (including wastes disposed of or released by prior owners or operators), property contamination (including groundwater contamination), and remedial plugging operations to prevent future contamination; (3) the Clean Air Act and comparable state and local requirements already applicable to our operations and new restrictions on air emissions from our operations, including those that could discourage the production of fossil fuels that, when used, ultimately release CO 2 ; (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 endangered and threatened species (and their related habitats) including certain species, which 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 in material compliance with applicable environmental laws and regulations.  Management 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 cause our expected production rates and cash flows to be less than anticipated.

Hydraulic Fracturing

We previously used a hydraulic fracturing process to stimulate production in our Bakken area and Selma Chalk properties.  We sold our Bakken area properties during the fourth quarter of 2012 and have no current plans to hydraulically fracture any of our remaining oil and gas wells, including our Selma Chalk properties, during 2013.  During 2012, we fracture stimulated 41 operated wells in the Bakken utilizing water-based fluids with no diesel fuel component.  In these operations, we are cognizant of environmental laws and continually monitor all of our operations for possible environmental impact.  During 2012 , we derived

in the range of 15% to 20% of our revenues from properties that have been fracture stimulated at some point in the useful life of the properties.

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 reserve 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 38 years of experience in oil and gas reservoir studies and evaluations.  Our Senior Vice President – Planning, Technology and Business Development is primarily responsible for overseeing the independent petroleum engineering firm during the process.  Our Senior Vice President – Planning, Technology and Business Development has a Bachelor of Science degree in Petroleum Engineering from Louisiana State University and over 31 years of industry experience working with petroleum reserve estimates.  D&M relies on various data provided by our internal reserve engineering team in preparing their 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 reserve 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 reserve team reports directly to our Senior Vice President – Planning, Technology and Business Development.  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 33 years of industry experience, with responsibilities including reserves preparation and approval.

Oil and Natural Gas Reserves Estimates

D&M prepared estimates of our net proved oil and natural gas reserves as of December 31, 2012 , 2011 and 2010 .  See the summary of D&M's report as of December 31, 2012 , 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 2012 , we provided oil and gas reserve estimates for 2011 to the United States Energy Information Agency, which were substantially the same as the reserve estimates included in our Form 10-K for the year ended December 31, 2011 .

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, 2012 , our estimated proved undeveloped reserves totaled approximately 162.7 MMBOE, or approximately 40% of our estimated total proved reserves, a decline of 38.5 MMBOE from December 31, 2011 levels.  Our proved undeveloped oil reserves primarily relate to our CO 2 tertiary operations (72.8 MMBOE) and our proved undeveloped natural gas reserves are primarily located in our Riley Ridge Field ( 69.4 MMBOE) acquired in 2010 and 2011.  Our December 31, 2012 proved undeveloped reserves also include 10.5 MMBOE of proved undeveloped reserves at our CCA fields acquired in 2010 and 7.4 MMBOE of

proved undeveloped reserves we acquired at Thompson Field during 2012. We consider the CO 2 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 2012 , we spent approximately $875 million to convert 40.5 MMBOE of proved undeveloped reserves to proved developed reserves.  Proved undeveloped reserves were converted primarily through the expansion of our tertiary floods (25.0 MMBOE) and through additional drilling in the Bakken.  During 2012, proved undeveloped reserve additions of 89.1 MMBOE, primarily related to the initial recognition of reserves associated with new tertiary floods (62.6 MMBOE) and the acquisition of Thompson Field (7.4 MMBOE), were partially offset by the decrease in proved undeveloped reserves resulting from the sale of our Bakken area assets (73.5 MMBOE).

As of December 31, 2012 , 16.6 MMBOE of our total proved undeveloped reserves are not scheduled to be developed within five years of initial booking, all of which are part of CO 2 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 CO 2 EOR projects and (3) we have an historical record of completing the development of comparable long-term projects.

data determined in accordance with FASC Topic 932.  The difference between these two amounts, the discounted estimated future income tax (in thousands) was $3,495,212 at December 31, 2012 , $3,551,534 at December 31, 2011 , and $2,374,417 at December 31, 2010 .  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 Abbreviation s for the definition of "PV-10 Value" and see Note 14 , 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 Note 14 , Supplemental Oil and Natural Gas Disclosures (Unaudited) , to the Consolidated Financial Statements.

Item 1A.  Risk Factors

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

Our future financial condition, results of operations, cash flows and the carrying value of our oil and natural gas properties depend primarily upon the prices we receive for our oil and natural gas production.  Oil and natural gas prices historically have been volatile and may continue to be volatile in the future, especially given current world geopolitical conditions.  Oil and natural gas prices have continued their volatility between year-end 2011 and year-end 2012 , with NYMEX oil prices per Bbl decreasing 7% , and NYMEX natural gas prices per MMBtu increasing by 12% .  Future decreases in commodity prices 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 and natural gas.  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 are likely to affect us more than natural gas prices because oil comprised approximately 93% of our 2012 production and 80% of our December 31, 2012 proved reserves, with oil being an even larger percentage of our current production and future potential reserves and projects due to our primary focus on tertiary operations.

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:

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 and 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 our financial obligations or make planned expenditures.

Over the past five 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.  Oil prices then reversed course, generally increasing through the past several years, ending 2011 at a NYMEX price of $98.83 per Bbl and ending 2012 at a NYMEX price of $91.82 per Bbl.  Due to the volatility of oil prices, oil prices could decline to a level that makes our tertiary projects uneconomical.  If that were to happen, we may decide to suspend future expansion projects, and if prices were to drop below the cash break-even point for an extended period of time, we may 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 reduced commodity prices to reflect the reduced cash flow, which could reduce or eliminate our growth. We have a practice of hedging approximately 15 to 24 months (from the current quarter) of forecasted production to mitigate the risks associated with price fluctuations (see Note 9 , Derivative Instruments and Hedging Activities , to the Consolidated Financial Statements for details regarding our commodity derivative contracts).  As of February 21, 2013 , we have oil commodity derivative contracts in place covering approximately 55,000 Bbls/d during 2013 and 50,000 Bbls/d during 2014 .  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.  Based on prior history, we estimate our economic break-even point (before corporate overhead, and based on expenses on these projects at current oil prices) occurs at per barrel dollar costs in the $40-per-barrel range, depending on the specific field and area.

The prices we receive for our crude oil often do not correlate with NYMEX prices.  The prices we receive for our crude oil production can vary from NYMEX oil 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 $9 per Bbl above NYMEX oil prices to approximately $4 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 followed a different path during the last few years, with current prices depressed as a result of weak demand and significant natural gas storage in place, leading to excess gas supply.  NYMEX natural gas prices averaged $4.40 per MMBtu during 2010 , $4.03 per MMBtu during 2011 , and $2.82 per MMBtu during 2012 , and ended 2012 at $3.35 per MMBtu.  As of February 21, 2013 , we do not have any natural gas commodity derivative contracts in place.

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

Our long-term growth strategy is focused on our CO 2 tertiary recovery operations. The crude oil production from our tertiary recovery projects depends on having access to sufficient amounts of CO 2 .  Our ability to produce this oil would be hindered if our supply of CO 2 were limited due to problems with our current CO 2 producing wells and facilities, including compression equipment, or catastrophic pipeline failure.  Our anticipated future crude oil production is also dependent on our ability to increase the production volumes of CO 2 and inject adequate amounts of CO 2 into the proper formation and area within each oil field. The production of crude oil from tertiary operations is highly dependent on the timing, volumes and location of the CO 2 injections.  If our crude oil production were to decline, it could have a material adverse effect on our financial condition, results of operations and cash flows.

Our planned tertiary operations and the related construction of necessary CO 2 pipelines could be delayed by difficulties in obtaining pipeline rights-of-way, permits, or by the listing of certain species as threatened or endangered.

The production of crude oil from our planned tertiary operations is also dependent upon having access to pipelines to transport available CO 2 to our oil fields at a cost that is economically viable.  Our ongoing construction of CO 2 pipelines will require us to

obtain rights-of-way not only from private landowners, but in certain areas, from the federal government if the proposed pipelines cross federal lands.  Certain states where we operate are considering the adoption of laws and regulations that would limit or eliminate a state's 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 that have species, such as the sage grouse, that could be listed as threatened or endangered under the Endangered Species Act, which could lead to material restrictions as to federal land use.  These laws, regulations and court decisions, 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 our ability to secure rights-of-way or access land for current or future pipeline construction projects.  As a result, obtaining rights-of-way may require additional regulatory and environmental compliance and additional expenditures, which could delay our CO 2 pipeline construction schedule and initiation of operations of our pipelines, and/or increase the costs of constructing our pipelines.

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

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, possibly resulting in our bankruptcy. Our ability to meet our obligations will depend 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.

As of February 21, 2013 , we had outstanding $2.9 billion (principal amount) of subordinated notes at interest rates ranging from 4.625% to 9.75% at a weighted average interest rate of 6.61% and no amounts outstanding under our bank credit facility.  We currently have a borrowing base of $1.6 billion under our bank credit facility, and at February 21, 2013, nearly all of this amount was available on such facility.  The next regularly scheduled semiannual redetermination of the borrowing base for our bank credit facility will be in May 2013.  Our bank borrowing base is adjusted at the banks' discretion and is based in part upon external factors, such as commodity prices, over which we have no control.  If our then redetermined borrowing base is less than our outstanding borrowings under the facility, we will be required to repay the deficit over a period not to exceed four months.

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

Product price derivative contracts may expose us to potential financial loss.

To reduce our exposure to fluctuations in the prices of oil and natural gas, we currently, and may in the future, enter into derivative contracts in order to economically hedge a portion of our oil and natural gas production.  Derivative contracts expose us to risk of financial loss in some circumstances, including when:

In addition, these derivative contracts may limit the benefit we would receive from increases in the prices for oil and natural gas.  Information as to these activities is set forth under Item 7. Market Risk Management in Management's Discussion and Analysis of Financial Condition and Results of Operations, and in Note 9 , Derivative Instruments and Hedging Activities , to the Consolidated Financial Statements.

A worldwide financial downturn or negative credit market conditions may have lasting effects on our liquidity, business and financial condition that we cannot 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 the sovereign debt crisis in Europe and related 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 reviews, as well as unscheduled reviews, of our borrowing base under our bank credit facility, and we do not know the results of future redeterminations or the effect of then-current oil and natural gas prices on that process.  The 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 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, 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 CO 2 for tertiary recovery and the related infrastructure requires significant capital investment, up to four or five years prior to any resulting 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 meet expectations.

During the last few years, we have acquired several fields at a significant cost because we believe that they have significant additional potential through tertiary flooding; we paid a premium price for these properties based on that assumption.  In addition, 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 the potential oil in these acquired fields, it would negatively affect the return on our investment on these acquisitions and could severely reduce our ability to obtain additional capital for the future, fund future acquisitions, and negatively affect our financial results to a significant degree.

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

Drilling activities are subject to many risks, including the risk that new wells drilled by us will not discover 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:

Our operations are subject to all the risks normally incident to the operation and development of oil and natural gas properties and the drilling of oil and natural gas wells, including encountering well blowouts, cratering and explosions, pipe failure, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, release of contaminants into the environment and other environmental hazards and risks.

The nature of these risks is such that some liabilities could exceed our insurance policy limits, or, as in the case of environmental fines and penalties, 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 CO 2 tertiary recovery projects require a significant amount of electricity to operate the 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 involve CO 2 injections into fields with wells plugged and abandoned by prior operators.  It is often difficult to determine whether a well has been properly plugged prior to commencing injections and pressuring the oil reservoirs.  If wells have not been properly plugged, we will have to modify the wells, which can increase costs, delay our operations and reduce our production.

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 are conducted in areas subject to extreme weather conditions and often in difficult terrain. As a result, our operations may be delayed because of cold, snow and wet conditions, and certain operations may be practical only during non-winter months.  Unusually severe weather could delay certain of these operations, including the construction of CO 2 pipelines, the drilling of new wells and production from existing wells, and depending on the severity of the weather, could have a negative effect on our results of operations in this region. Further, certain of our operations are limited to certain time periods due to environmental regulations, which can slow down our operations, cause delays 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 to drill wells and conduct field operations, 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 extensive 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 equipment used in our tertiary facilities, drilling rigs and other equipment, as demand for rigs and equipment has increased along with higher commodity prices.  Higher oil and natural gas prices

generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, oilfield equipment and services, and personnel in our exploration and production operations.  These types of shortages or price increases could significantly decrease our profit margin, cash flow and operating results and/or restrict or delay our ability to drill those wells and conduct those operations that we currently have planned and budgeted, causing us to miss our forecasts and projections.

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 affect the costs, manner, and feasibility of our operations and require us to make significant expenditures in our efforts 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, or 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, including an EPA proposal to apply New Source Performance Standards for petroleum refineries expected in 2013; (2) proposals contained in the President's budget, along with legislation introduced in Congress, none of which have passed Congress, 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, 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 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 CO 2 pipelines, any of which could affect our operations, and the costs thereof.  Generally, any future laws and regulations could result in increased costs or additional operating restrictions and 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 implemented, it is not possible to gauge their impact on our future operations or our results of operations and financial condition.

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

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

The recent adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to hedge risks associated with our business.

The Dodd-Frank Act requires the Commodities Futures Trading Commission, and the SEC to promulgate rules and regulations establishing federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. These new rules and regulations could significantly increase the cost or decrease the liquidity of energy-related derivatives we use to hedge against commodity price fluctuations. Although we believe the derivative contracts that we enter into should not be materially impacted by these new statutory and regulatory requirements, because derivatives regulations have not been finalized, final regulations could negatively affect to our detriment the economics and terms of derivative instruments available from counterparties in the marketplace.

The loss of more than one of our large oil and natural gas purchasers could have a material adverse effect on our operations.

For the year ended December 31, 2012 , two purchasers individually accounted for 10% or more of our oil and natural gas revenues and, in the aggregate, for 56% of such revenues.  The loss of a large single purchaser could potentially reduce the competition for our oil and natural gas production, which in turn could negatively impact the prices we receive.

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 regulation.  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 or the oil and natural gas industry in general are subject.  Any significant inaccuracies in these interpretations or assumptions or changes of conditions could result in a reduction of the quantities and net present value of our reserves.

The reserve data included in documents incorporated by reference represent only estimates.  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, operating results and cash flows.  Actual future prices and costs may be materially higher or lower than the prices and cost used in the estimate.

As of December 31, 2012 , approximately 40% of our estimated proved reserves were undeveloped.  Recovery of undeveloped reserves requires significant capital expenditures and may require successful drilling operations.  The reserve 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.

Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. At December 31, 2012 , the Company's goodwill balance totaled $1.3 billion and represented approximately 11.5% 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, however there can be no assurance that we will not suffer such losses in the future.  As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any cyber-vulnerabilities.

Item 1B.  Unresolved Staff Comments

There are no unresolved written SEC staff comments regarding our periodic or current reports under the Securities Exchange Act of 1934 received 180 days or more before the end of the fiscal year to which this annual report on Form 10-K relates.

Item 2.  Properties

Information regarding the Company's properties called for by this item is included in Item 1 , Business and Properties – Oil and Natural Gas Operations .  We also have various operating leases for rental of office space, office and field equipment, and vehicles.  See Off-Balance Sheet Agreements – Commitments and Obligations in Management's Discussion and Analysis of Financial Condition and Results of Operations , 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 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 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.

PART II

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

Common Stock Trading Summary

The following table summarizes the high and low reported sales prices on days in which there were trades of Denbury's common stock on the New York Stock Exchange ("NYSE") for each quarterly period for the last two fiscal years.  As of January 31, 2013, 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 1,643.  On February 27, 2013, the last reported sale price of Denbury's common stock, as reported on the NYSE, was $17.99 per share.

We have never paid any dividends on our common stock.  Also, our bank credit facility limits the aggregate amount of (i) dividends we can pay on our common stock and (ii) our common stock we can repurchase. Under our bank credit facility, we had $679.0 million available as of February 21, 2013 that can be used to pay dividends or repurchase shares of Denbury's common stock. No unregistered securities were sold by the Company during 2012 .

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

Between early October 2011, when we announced the commencement of a common share repurchase program for up to $500 million of Denbury common stock, and December 31, 2012 , we repurchased 31,090,618 shares of Denbury common stock (approximately 7.7% of our outstanding shares of common stock at September 30, 2011) for $461.9 million , or $14.86 per share.  The program was increased to $771.2 million in 2012, 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.

All other repurchases of our common stock during the fourth quarter of 2012 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.

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, 2012 , 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) from December 31, 2007 to December 31, 2012 .

COMPARISON OF 5-YEAR CUMULATIVE TOTAL RETURN

(1) Copyright© 2012 S&P, a division of The McGraw-Hill Companies Inc. All rights reserved.

(2) Copyright© 2012 Dow Jones & Co. All rights reserved.

Item 6. Selected Financial Data