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Denbury Provides Operational Update and Results of Successful Mission Canyon Exploitation Well, 2018 Capital and Estimated Production

PLANO, Texas, Feb. 12, 2018 (GLOBE NEWSWIRE) -- Denbury Resources Inc. (NYSE:DNR) (“Denbury” or the “Company”) today announced its preliminary year-end 2017 proved reserves, production and capital expenditures, the initial results of its successful first Mission Canyon exploitation well in the Cedar Creek Anticline, and its 2018 capital budget and estimated annual production.


/EIN News/ -- 2017 preliminary production, capital expenditures, and proved reserves

  • Q4 2017 production – 61,144 barrels of oil equivalent per day (“BOE/d”), 97% oil
  • FY 2017 production – 60,298 BOE/d, 97% oil
  • 2017 development capital – $241 million, below capital budget of $250 million
  • 2017 proved reserves – 260 million barrels of oil equivalent (“MMBOE”), representing a 127% replacement of 2017 annual production
  • Year-end 2017 preliminary PV-10 Value(1) – $2.5 billion, up from $1.5 billion at year-end 2016

Mission Canyon exploitation well

  • Successful first Mission Canyon well opens additional development in Cedar Creek Anticline
  • 30-day initial production rate of 1,050 barrels of oil per day (“Bbls/d”)
  • Plans to drill 6 additional wells in 2018

2018 capital budget and production

  • 2018 development capital budget – $300 million to $325 million, fully funded from currently expected operating cash flows
  • Estimated production range – 60,000 to 64,000 BOE/d, 3% above preliminary 2017 production at the midpoint

(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.


Chris Kendall, Denbury’s President and CEO commented, “Our 2017 accomplishments improved the full spectrum of our business, positively positioning us heading into 2018.  We returned to production growth in the 3rd quarter and are set to continue that growth in 2018.  We strengthened our core, replacing 127% of our 2017 production.  We significantly lowered our cost structure and streamlined our organization, providing greater upside to an improving oil market.  Operational execution was strong, delivering high-return projects on time and on budget, increasing field reliability, and optimizing costs.  Capital allocation was highly disciplined, with our final spend nearly 4% below guidance.  Capping off the year, Mission Canyon, a significant new exploitation test, was a resounding success, with a 100% oil, 1,050 barrels of oil per day initial 30-day average rate on a $3.6 million investment.  This result highlights the short cycle, high value organic growth potential in our broad asset base, and opens the door for multiple follow-on wells across the area.

“As we look to 2018, we will continue to execute on our valuable project portfolio, focused on delivering long-term sustainability and growth.  We will maintain capital discipline, spending within cash flow while targeting production growth in the range of 3% from 2017 levels.  We plan to accelerate investment in our growing exploitation portfolio, including multiple additional wells at Mission Canyon and promising new tests in both operating regions.  We are excited to have our two newest CO2 floods starting up at West Yellow Creek and Grieve, and are highly focused on bringing initial EOR development at Cedar Creek Anticline to an investment decision in the first half of the year.  I believe 2018 will be a transformative year for Denbury.”


Denbury’s first Mission Canyon exploitation well was drilled during the fourth quarter in the Pennel Field in the Cedar Creek Anticline.  The well was drilled to a true vertical depth of 7,200’, with a 4,800’ lateral section geosteered in a 4’ target at the top of the Mission Canyon carbonate formation.  Reservoir quality and rock mechanics permitted an open-hole, non-stimulated completion, and the well began production through an electric submersible pump on December 30, 2017.  Average production over the initial 30-day production period was 1,050 Bbls/d of oil, exceeding initial productivity expectations.  The total cost to drill and complete the well was $3.6 million.

The success of the initial well de-risks additional locations, and the Company mobilized a rig in early February to begin drilling on a two-well pad, with first production from this pad expected in the second quarter.  A total of six additional Mission Canyon wells are planned for 2018, including four development wells and two wells designed to test other Mission Canyon opportunities.  The program is expected to continue beyond 2018 as the Company fully develops the play.


Denbury’s production averaged 61,144 BOE/d during the fourth quarter of 2017, in line with expectations, and was 97% oil, with CO2 tertiary properties accounting for 65% of overall production.  On a sequential-quarter basis, production in the fourth quarter of 2017 increased by 1% from the third quarter of 2017.

Denbury’s continuing production for full-year 2017 averaged 60,298 BOE/d, down 4% from the prior-year’s level when excluding properties sold in 2016.  Approximately 1% of the decline was attributable to weather-related shut-in production from Hurricane Harvey.  Further production information is provided on page 8 of this press release.


Denbury’s 2017 development capital expenditures totaled $241 million, nearly 4% below the $250 million budget amount.  Total capital expenditures for 2017 also included property acquisition costs of $89 million and capitalized interest of $31 million.

A breakdown of preliminary estimated 2017 capital expenditures is shown in the following table:

In millions   2017
Capital expenditures by project    
Tertiary oil fields   $ 129  
Non-tertiary fields   54  
Capitalized internal costs(2)   53  
Oil and natural gas capital expenditures   236  
CO2 pipelines, sources and other   5  
Capital expenditures, before acquisitions and capitalized interest   241  
Acquisitions of oil and natural gas properties   89  
Capital expenditures, before capitalized interest   330  
Capitalized interest   31  
Capital expenditures, total   $ 361  
  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, 2017 were 260 MMBOE, consisting of 253 million barrels of crude oil, condensate and natural gas liquids (together, “liquids”), and 43 billion cubic feet (7 MMBOE) of natural gas.  Reserves were 97% liquids and 88% proved developed, with 59% of total proved reserves attributable to Denbury’s CO2 tertiary operations.  Total proved reserves increased by 28 MMBOE on a gross basis, a net 6 MMBOE increase after 2017 production, representing a 127% replacement of 2017 production.  The increase was primarily due to 15 MMBOE of positive revisions of previous estimates associated with changes in commodity prices, operating costs and performance, and 11 MMBOE due to properties acquired during the year.


Balance at December 31, 2016   247     44     254     $1.5 billion
Revisions of previous estimates   14     3     15      
Improved recovery   2         2      
2017 production   (21 )   (4 )   (22 )    
Acquisition of minerals or other revisions   11         11      
Balance at December 31, 2017   253     43     260     $2.5 billion

Year-end 2017 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 $51.34 per Bbl for oil (based on NYMEX prices) and $2.98 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 2016 were $42.75 per Bbl of oil and $2.55 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, 2017 (“Standardized Measure”) was $2.2 billion compared to $1.4 billion at December 31, 2016.  PV-10 Value(1) was $2.5 billion at December 31, 2017, compared to $1.5 billion at December 31, 2016, which represents a 64% year-over-year increase.  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.

(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.

Denbury’s estimated proved CO2 reserves at year-end 2017, on a gross or 8/8th’s basis for operated fields, together with its overriding royalty interest in LaBarge Field in Wyoming, totaled 6.4 trillion cubic feet (“Tcf”), slightly lower than CO2 reserves of 6.5 Tcf as of December 31, 2016.  Of these total CO2 reserves, 5.2 Tcf are located in the Gulf Coast region and 1.2 Tcf in the Rocky Mountain region.  In addition to these proved CO2 reserves, Denbury is currently purchasing CO2 from two industrial facilities in the Gulf Coast region and a gas processing facility in the Rocky Mountain region, all under long-term contractual agreements.  Although there are no proved CO2 reserves associated with these long-term agreements, they currently supply over 90 million cubic feet per day, or roughly 15% of the CO2 Denbury is using for its tertiary operations.


Denbury’s 2018 capital budget, excluding acquisitions and capitalized interest, is between $300 million and $325 million, roughly 30% above the Company’s 2017 capital spending levels.  The budget provides for approximate spending as follows:

  • $155 million for tertiary oil field expenditures;
  • $95 million for other areas, primarily non-tertiary oil field expenditures including exploitation projects;
  • $20 million for CO2 sources and pipelines; and
  • $45 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 2018 is estimated at approximately $30 million.  At this spending level, the Company anticipates 2018 production of between 60,000 and 64,000 BOE/d, an increase of 3% at the mid-point over the Company’s preliminary 2017 average production rate.


Chris Kendall, President and CEO, and Mark Allen, Executive Vice President and CFO, will be attending the 23rd Annual Credit Suisse Energy Summit and delivering a Company presentation on Tuesday, February 13, 2018 at 10:55 A.M. Mountain Time.  An updated corporate presentation for the conference will be posted to the Company’s website on the evening of Monday, February 12, 2018 and a link to the live webcast of the presentation will be available in the investor relations section of the Company’s website at

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 CO2 enhanced oil recovery operations.  For more information about Denbury, please visit

In this press release, Denbury provides estimated year-end 2017 proved reserves information, preliminary production and capital expenditures information for its fiscal year 2017 and preliminary exploitation well production results.  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 2018 production and capital expenditures, estimated cash generated from operations in 2018, 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 2017 and 2016 year-end estimated proved oil and natural gas reserves and proved CO2 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   2017   2016
Preliminary Standardized Measure (GAAP measure)   $ 2,232,429     $ 1,399,217  
Discounted estimated future income tax   301,369     142,467  
PV-10 Value (non-GAAP measure)   $ 2,533,798     $ 1,541,684  



    Quarter Ended   Year Ended
    December 31,   Sept. 30,   December 31,
Average Daily Volumes (BOE/d) (6:1)   2017   2016   2017   2017   2016
Tertiary oil production                    
Gulf Coast region                    
Mature properties(1)   7,232     8,440     7,450     7,629     9,040  
Delhi   4,906     4,387     4,619     4,869     4,155  
Hastings   5,747     4,552     4,867     4,830     4,829  
Heidelberg   4,751     4,924     4,927     4,851     5,128  
Oyster Bayou   4,868     4,988     4,870     5,007     5,083  
Tinsley   6,241     6,786     6,506     6,430     7,192  
Total Gulf Coast region   33,745     34,077     33,239     33,616     35,427  
Rocky Mountain region                    
Bell Creek   3,571     3,269     3,406     3,313     3,121  
Salt Creek   2,172         2,228     1,115      
Total Rocky Mountain region   5,743     3,269     5,634     4,428     3,121  
Total tertiary oil production   39,488     37,346     38,873     38,044     38,548  
Non-tertiary oil and gas production                    
Gulf Coast region                    
Mississippi   721     745     867     981     850  
Texas   4,617     5,143     4,024     4,493     4,906  
Other   483     569     515     489     528  
Total Gulf Coast region   5,821     6,457     5,406     5,963     6,284  
Rocky Mountain region                    
Cedar Creek Anticline   14,302     15,186     14,535     14,754     16,322  
Other   1,533     1,696     1,514     1,537     1,844  
Total Rocky Mountain region   15,835     16,882     16,049     16,291     18,166  
Total non-tertiary production   21,656     23,339     21,455     22,254     24,450  
Total continuing production   61,144     60,685     60,328     60,298     62,998  
Property sales                    
Property divestitures(2)                   1,005  
Total production   61,144     60,685     60,328     60,298     64,003  
  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.

                    Mark C. Allen, Executive Vice President and Chief Financial Officer, 972.673.2000
                    John Mayer, Director of Investor Relations, 972.673.2383

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