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.
HIGHLIGHTS
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.
MANAGEMENT
COMMENT
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.”
EXPLOITATION UPDATE
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.
PRELIMINARY 2017 FOURTH QUARTER AND
ANNUAL PRODUCTION
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.
PRELIMINARY 2017 CAPITAL
EXPENDITURES
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 |
|
2017PreliminaryCapitalExpenditures(1) |
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 |
|
- Capital expenditure amounts include accrued capital.
- Includes capitalized internal acquisition, exploration and
development costs and pre-production tertiary startup costs.
2017 PROVED RESERVES
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.
|
|
|
Oil(MMBbl) |
|
Gas(Bcf) |
|
MMBOE |
|
PV-10(1) |
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.
2018 CAPITAL BUDGET AND PRODUCTION
ESTIMATES
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.
CONFERENCE PRESENTATION
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 www.denbury.com.
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 www.denbury.com.
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.
DENBURY RESOURCES
INC.SUPPLEMENTAL NON-GAAP FINANCIAL MEASURE
(UNAUDITED)
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 |
|
DENBURY RESOURCES
INC.PRODUCTION HIGHLIGHTS (UNAUDITED)
|
|
|
|
|
|
|
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 |
|
- Mature properties include Brookhaven, Cranfield, Eucutta,
Little Creek, Lockhart Crossing, Mallalieu, Martinville, McComb and
Soso fields.
- 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, Executive Vice President and Chief Financial Officer, 972.673.2000
John Mayer, Director of Investor Relations, 972.673.2383
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