PLANO, Texas, Feb. 14, 2017 (GLOBE NEWSWIRE) -- Denbury Resources Inc. (NYSE:DNR) ("Denbury" or the "Company") today announced that its 2017 capital budget, excluding acquisitions and capitalized interest, is currently estimated at approximately $300 million, 44% over 2016 capital spending levels.  The budget provides for:
  • $175 million allocated for tertiary oil field expenditures;
  • $60 million allocated for other areas, primarily non-tertiary oil field expenditures;
  • $10 million to be spent on CO 2 sources and pipelines; and
  • $55 million for other capital items such as capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.

In addition, capitalized interest for 2017 is currently estimated at approximately $20 million.  At this spending level, the Company anticipates 2017 production of between 58,000 and 62,000 barrels of oil equivalent per day ("BOE/d"), with the mid-point of such range roughly flat with the Company's 2016 exit rate of just under 60,000 BOE/d.


Phil Rykhoek, Denbury's CEO commented, "We are pleased with our progress over the past year, especially the improvements we made in reducing costs and enhancing the efficiency of our operations.  We also completed a robust review of all of our fields and identified multiple areas that we can exploit in the coming years, including both tertiary expansions and other opportunities.  We continue to be vigilant with our balance sheet and are limiting our capital spending to an amount near our expected cash flow.  Our capital spending in the current price environment continues to be primarily focused on expanding our existing CO 2 floods and other infill opportunities and, importantly, our planned 2017 capital projects have strong economics at $50 oil.  With our improved efficiencies, this $300 million capital budget should hold full-year 2017 production essentially flat with our 2016 exit rate and should put us on a trajectory to resume slight production growth in 2018, based on current assumptions and expectations.  We are encouraged by our future opportunities and are looking forward to 2017 as we continue to pursue ways to enhance our operating efficiency and de-lever our balance sheet."


Denbury's continuing production averaged 60,685 BOE/d during the fourth quarter of 2016, in line with our expectations, and was 96% oil, with CO 2 tertiary properties accounting for 62% of overall production.  On a sequential-quarter basis, continuing production in the fourth quarter of 2016 was essentially flat with continuing production in the third quarter of 2016, with production from our CO 2 tertiary properties increasing slightly.

Excluding sold properties, Denbury's continuing production for full-year 2016 averaged 62,998 BOE/d, down 11% from the prior-year's level.  Approximately one-third of the production decline was attributable to production shut-in due to economics and weather-related shut-in production at Thompson and Conroe fields, with the remainder largely due to natural production declines.  Further production information is provided on page 7 of this press release.


Denbury's 2016 development capital expenditures totaled $209 million, consisting of $206 million spent on oil and natural gas development, including $56 million related to capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs, with the remainder spent primarily on CO source wells and CO 2 infrastructure and pipelines.  These estimated capital expenditures exclude property acquisition costs of $11 million and capitalized interest of $26 million.

A breakdown of preliminary estimated 2016 capital expenditures is shown in the following table:
In millions   2016 Preliminary Capital Expenditures (1)
Capital expenditures by project    
Tertiary oil fields   $ 119  
Non-tertiary fields   31  
Capitalized internal costs (2)   56  
Oil and natural gas capital expenditures   206  
CO 2 pipelines, sources and other   3  
Capital expenditures, before acquisitions and capitalized interest   209  
Acquisitions of oil and natural gas properties   11  
Capital expenditures, before capitalized interest   220  
Capitalized interest   26  
Capital expenditures, total   $ 246  

(1) Capital expenditure amounts include accrued capital.(2) Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.


The Company's total estimated proved oil and natural gas reserves at December 31, 2016 were 254 million barrels of oil equivalent ("MMBOE"), consisting of 247 million barrels of crude oil, condensate and natural gas liquids (together, "liquids"), and 44 billion cubic feet (or 7 MMBOE) of natural gas.  Reserves were 97% liquids and 82% proved developed, with 58% of those reserves attributable to Denbury's CO 2 tertiary operations.  Total proved reserves declined by a net 35 MMBOE during 2016 primarily due to 23 MMBOE of production, with 7 MMBOE of downward revisions of previous estimates associated with changes in commodity prices, operating costs and performance, and 5 MMBOE due to properties sold during the year.
    Oil(MMBbl)   Gas (Bcf)   MMBOE
Balance at December 31, 2015   282     38     289  
Revisions of previous estimates   (9 )   16     (7 )
2016 production   (22 )   (6 )   (23 )
Sales of minerals or other revisions   (4 )   (4 )   (5 )
Balance at December 31, 2016   247     44     254  

Year-end 2016 estimated proved reserves and the discounted net present value of Denbury's proved reserves, using a 10% per annum discount rate ("PV-10 Value") (1) (a non-GAAP measure), were computed using first-day-of-the-month 12-month average prices of $42.75 per Bbl for oil (based on NYMEX prices) and $2.55 per million British thermal unit ("MMBtu") for natural gas (based on Henry Hub cash prices), adjusted for prices received at the field.  Comparative prices for year-end 2015 were $50.28 per Bbl of oil and $2.63 per MMBtu for natural gas, adjusted for prices received at the field.  The preliminary standardized measure of discounted estimated future net cash flows after income taxes of Denbury's proved reserves at December 31, 2016 ("Standardized Measure") was $1.4 billion compared to $1.9 billion at December 31, 2015.  PV-10 Value (1) was $1.5 billion at December 31, 2016, compared to $2.3 billion at December 31, 2015.  See the accompanying schedules for an explanation of the difference between PV-10 Value (1) and the preliminary Standardized Measure and the uses of this information.

Denbury's estimated proved CO 2 reserves at year-end 2016, on a gross or 8/8th's basis for operated fields, together with its overriding royalty interest in LaBarge Field in Wyoming, totaled 6.5 trillion cubic feet ("Tcf"), slightly lower than CO 2 reserves of 6.7 Tcf as of December 31, 2015.  Of these total CO 2 reserves, 5.3 Tcf are located in the Gulf Coast region and 1.2 Tcf in the Rocky Mountain region.  In addition to these proved CO 2 reserves, in the Gulf Coast region Denbury is currently purchasing CO 2 from two industrial facilities and expects purchases to begin in the near future from Mississippi Power's Kemper County plant; and in the Rocky Mountain region Denbury has the ability to purchase CO 2 from a gas processing facility, all under long-term contractual agreements.  Although there are no proved CO 2 reserves associated with these long-term agreements, they currently supply approximately 65 million cubic feet per day ("MMcf/d") of the CO 2 Denbury is using for its tertiary operations and could increase up to approximately 225 MMcf/d in a few years once the Kemper County plant is fully operational.

(1)    A non-GAAP measure.  See accompanying schedules that reconcile GAAP to non-GAAP measures along with a statement indicating why the Company believes the non-GAAP measures provide useful information for investors.


Phil Rykhoek, CEO, Chris Kendall, President and COO, and Mark Allen, Sr. VP and CFO, will be attending the 22 nd Annual Credit Suisse Energy Summit and delivering a Company presentation on Thursday, February 16, 2017 at 10:20 A.M. Mountain Time.  A link to the live webcast of the presentation and the presentation slides will be available the morning of Tuesday, February 14 th in the investor relations section of the Company's website at


Denbury management will host a conference call to review and discuss fourth quarter and full-year 2016 financial and operating results, together with its financial and operating outlook for 2017, on Thursday, February 23, 2017 at 10:00 A.M. (Central).  Additionally, Denbury will publish presentation materials on its website which will be referenced during the conference call.  Individuals who would like to participate should dial 800.230.1074 or 612.332.0226 ten minutes before the scheduled start time.  To access a live audio webcast of the conference call and accompanying slide presentation, please visit the investor relations section of the Company's website at  The webcast will be archived on the website, and a telephonic replay will be accessible for at least one month after the call by dialing 800.475.6701 or 320.365.3844 and entering confirmation number 361971.

Denbury is an independent oil and natural gas company with operations focused in two key operating areas: the Gulf Coast and Rocky Mountain regions.  The Company's goal is to increase the value of its properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to CO 2 enhanced oil recovery operations.  For more information about Denbury, please visit

In this press release, Denbury provides estimated year-end 2016 proved reserves information and preliminary production and capital expenditures information for its fiscal year 2016.  Denbury has prepared the summary preliminary data in this release based on the most current information available to management.  Denbury's normal closing and financial reporting processes with respect to the preliminary data herein have not been fully completed and, as a result, its actual results could be different from this summary preliminary information presented herein, and any such differences could be material .

This press release, other than historical financial information, contains forward-looking statements that involve risks and uncertainties including the preliminary information referenced above, estimated 2017 production and capital expenditures, estimated cash generated from operations in 2017, and other risks and uncertainties detailed in the Company's filings with the Securities and Exchange Commission, including Denbury's most recent report on Form 10-K.  These risks and uncertainties are incorporated by this reference as though fully set forth herein.  These statements are based on engineering, geological, financial and operating assumptions that management believes are reasonable based on currently available information; however, management's assumptions and the Company's future performance are both subject to a wide range of business risks, and there is no assurance that these goals and projections can or will be met.  Actual results may vary materially.  In addition, any forward-looking statements represent the Company's estimates only as of today and should not be relied upon as representing its estimates as of any future date.  Denbury assumes no obligation to update its forward-looking statements.



Reconciliation of the preliminary standardized measure of discounted estimated future net cash flows after income taxes (GAAP measure) to PV-10 Value (non-GAAP measure)

PV-10 Value is a non-GAAP measure and is different from the preliminary Standardized Measure in that PV-10 Value is a pre-tax number and the Standardized Measure is an after-tax number.  Denbury's 2016 and 2015 year-end estimated proved oil and natural gas reserves and proved CO 2 reserves quantities were prepared by the independent reservoir engineering firm of DeGolyer and MacNaughton.  The information used to calculate PV-10 Value is derived directly from data determined in accordance with FASC Topic 932.  Management believes 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 management and others in the industry to evaluate properties that are bought and sold, to assess the potential return on investment in the Company's oil and natural gas properties, and to perform impairment testing of oil and natural gas properties.  PV-10 Value is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for the Standardized Measure.  PV-10 Value and the preliminary Standardized Measure do not purport to represent the fair value of the Company's oil and natural gas reserves.
    December 31,
In thousands   2016   2015
Preliminary Standardized Measure (GAAP measure)   $ 1,399,217     $ 1,890,124  
Discounted estimated future income tax   142,467     428,431  
PV-10 Value (non-GAAP measure)   $ 1,541,684     $ 2,318,555  

    Quarter Ended   Year Ended
    December 31,   Sept. 30,   December 31,
Average Daily Volumes (BOE/d) (6:1)   2016   2015   2016   2016   2015
Tertiary oil production                    
Gulf Coast region                    
Mature properties (1)   8,440     10,403     8,653     9,040     10,830  
Delhi   4,387     3,898     4,262     4,155     3,688  
Hastings   4,552     5,082     4,729     4,829     5,061  
Heidelberg   4,924     5,635     5,000     5,128     5,785  
Oyster Bayou   4,988     5,831     4,767     5,083     5,898  
Tinsley   6,786     7,522     6,756     7,192     8,119  
Total Gulf Coast region   34,077     38,371     34,167     35,427     39,381  
Rocky Mountain region                    
Bell Creek   3,269     2,806     3,032     3,121     2,221  
Total Rocky Mountain region   3,269     2,806     3,032     3,121     2,221  
Total tertiary oil production   37,346     41,177     37,199     38,548     41,602  
Non-tertiary oil and gas production                    
Gulf Coast region                    
Mississippi   745     1,377     963     850     1,194  
Texas   5,143     6,470     4,234     4,906     6,443  
Other   569     800     538     528     889  
Total Gulf Coast region   6,457     8,647     5,735     6,284     8,526  
Rocky Mountain region                    
Cedar Creek Anticline   15,186     17,875     16,017     16,322     17,997  
Other   1,696     2,407     1,763     1,844     2,743  
Total Rocky Mountain region   16,882     20,282     17,780     18,166     20,740  
Total non-tertiary production   23,339     28,929     23,515     24,450     29,266  
Total continuing production   60,685     70,106     60,714     62,998     70,868  
Property sales                    
Williston Assets (2)       1,473     819     864     1,549  
Other property divestitures       423         141     444  
Total production   60,685     72,002     61,533     64,003     72,861  

(1) Mature properties include Brookhaven, Cranfield, Eucutta, Little Creek, Lockhart Crossing, Mallalieu, Martinville, McComb and Soso fields.(2) Includes non-tertiary production in the Rocky Mountain region related to the sale of remaining non-core assets in the Williston Basin of North Dakota and Montana, which closed in the third quarter of 2016.
DENBURY CONTACTS:Mark C. Allen, Senior Vice President and Chief Financial Officer, 972.673.2000John Mayer, Investor Relations, 972.673.2383

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