Denbury Resources Inc. (NYSE:DNR) (“Denbury” or the “Company”)
today announced adjusted net income(1) (a non-GAAP measure) of $63
million for the third quarter of 2015, or $0.18(1)(2) per diluted
share. On a GAAP basis, the Company recorded a net loss of
$2.2 billion, or $6.41 per diluted share. Adjusted net
income(1) for the third quarter of 2015 differs from GAAP net
income due to the exclusion of (1) a $1.8 billion ($1.1 billion
after tax) write-down of oil and natural gas properties, (2) a $1.3
billion ($1.2 billion after tax) impairment of goodwill, (3) a $69
million ($43 million after tax) loss on noncash fair value
adjustments on commodity derivatives(1) (a non-GAAP measure), and
(4) a $14 million lease operating expense reduction due to
insurance and other expense reimbursements.
Sequential and year-over-year comparisons of
selected quarterly financial items are shown in the following
table:
|
|
Quarter Ended |
(in
millions, except per share and unit data) |
|
Sept. 30, 2015 |
|
June 30, 2015 |
|
Sept. 30, 2014 |
Net income (loss) |
|
$ |
(2,244 |
) |
|
$ |
(1,148 |
) |
|
$ |
269 |
|
Adjusted net income(1)
(non-GAAP measure) |
|
|
63 |
|
|
|
47 |
|
|
|
91 |
|
Net income (loss) per
diluted share |
|
|
(6.41 |
) |
|
|
(3.28 |
) |
|
|
0.77 |
|
Adjusted net income per
diluted share(1)(2) (non-GAAP measure) |
|
|
0.18 |
|
|
|
0.13 |
|
|
|
0.26 |
|
Cash flows from
operations |
|
|
273 |
|
|
|
289 |
|
|
|
340 |
|
Adjusted cash flows
from operations(1)(3) (non-GAAP measure) |
|
|
243 |
|
|
|
252 |
|
|
|
316 |
|
|
|
|
|
|
|
|
Revenues |
|
$ |
300 |
|
|
$ |
374 |
|
|
$ |
633 |
|
Receipt (payment) on
settlements of commodity derivatives |
|
|
161 |
|
|
|
124 |
|
|
|
(25 |
) |
Revenues and commodity
derivative settlements combined |
|
$ |
461 |
|
|
$ |
498 |
|
|
$ |
608 |
|
|
|
|
|
|
|
|
Average realized oil
price per barrel (excluding derivative settlements) |
|
$ |
45.74 |
|
|
$ |
56.92 |
|
|
$ |
94.78 |
|
Average realized oil
price per barrel (including derivative settlements) |
|
$ |
71.32 |
|
|
$ |
76.30 |
|
|
$ |
90.92 |
|
|
|
|
|
|
|
|
Total production
(BOE/d) |
|
|
71,410 |
|
|
|
73,716 |
|
|
|
73,810 |
|
|
(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. |
(2)
Calculated using average diluted shares outstanding of 350.9
million and 351.1 million for the three months ended September 30,
2015 and June 30, 2015, respectively. |
(3)
Adjusted cash flows from operations reflects cash flows from
operations before working capital changes but is not adjusted for
nonrecurring items. |
Sequentially, adjusted net income(1) increased
$16 million for the third quarter of 2015 compared to second
quarter of 2015 levels, primarily driven by lower operating costs
and lower depletion, depreciation and amortization expense, offset
in part by the impact of lower oil and natural gas revenues and
commodity derivative settlements combined. Adjusted net
income(1) for the third quarter of 2015 decreased $28 million from
the prior-year third quarter, due to a decrease in oil revenues
(including commodity derivative settlements) between the quarters,
largely offset by reductions in all categories of expenses during
the third quarter of 2015. Adjusted cash flows from
operations(1)(3) (a non-GAAP measure) decreased $9 million on a
sequential-quarter basis and decreased $73 million from the level
in the prior-year third quarter, primarily as a result of the same
drivers of the changes in adjusted net income(1).
MANAGEMENT COMMENT
Phil Rykhoek, Denbury’s President and CEO,
commented, “We are continuing to see the benefits from the work of
our innovation and improvement teams and cost reduction efforts,
which have helped mitigate the impact of lower oil prices.
These efforts have resulted in the seventh consecutive quarterly
drop in lease operating expenses, to a normalized level in the
third quarter of $19.43 per barrel (“Bbl”) of oil equivalent
(“BOE”), and a decrease of 26% from the fourth quarter of 2013
level. A major factor in our operating expense improvement is
the continued reduction in our use of carbon dioxide (“CO2”), which
is down 11% sequentially and 31% from the first quarter of 2015
levels. Also, as a result of our cost reduction efforts and
capital discipline, we have been able to reduce our estimated 2015
development capital budget by a total of $95 million. We
reduced our 2015 capital estimate by $50 million a couple of months
ago and, as of today, we are lowering it an additional $45
million. We now estimate our 2015 total capital spending at
$475 million, comprised of $370 million in development capital
spending and $105 million of other capital costs, including
capitalized internal costs, capitalized interest and pre-production
startup costs. Although we experienced a slight decrease in
our production this quarter, primarily attributable to Tinsley and
Cedar Creek Anticline (“CCA”) fields, a portion of this drop is
temporary and is expected to come back online in the fourth
quarter. Also, we currently estimate that we have
approximately 1,100 BOE per day (“BOE/d”) of uneconomic production
shut-in. Due largely to this shut-in production and the
weather impacts at Thompson Field in the second and third quarters
of 2015, we refined our 2015 production expectations earlier in the
third quarter to indicate that we expect production will be in the
lower half of our guidance range. The bottom line is that we
are making decisions and taking actions that will improve our
business every day, even if those decisions and actions may have
some temporary impacts on production.
“During the third quarter, we announced the
suspension of our dividend in light of the current low oil price
environment and our desire to maintain financial strength and
flexibility. Although we have generated over $300 million of
excess cash flow after incurred capital expenditures and dividends
during the first nine months of this year, the cash flow benefit
from our hedges will begin to diminish in the fourth quarter, and
the suspension of the dividend frees up $88 million in cash
annually that we can judiciously deploy elsewhere. We have
applied much of our free cash this year to reducing our bank debt,
which is down to $210 million at the end of the third quarter, from
$395 million at year-end 2014. We remain committed to living
within cash flow for 2016 and prudently managing our bank debt,
which means, among other things, that our development capital
spending will likely be in the $300 million to $350 million range
for 2016 based on current oil price projections. I am excited about
our progress in this lower oil price environment and am confident
that we are paving the way for a much stronger Denbury when oil
prices recover.”
PRODUCTION
Denbury’s total production for the third quarter
of 2015 averaged 71,410 BOE/d, which included 40,834 Bbls per day
(“Bbls/d”) from tertiary properties and 30,576 BOE/d from
non-tertiary properties. Total production during the third
quarter of 2015 decreased 3% both sequentially and when compared to
the third quarter of 2014, primarily due to natural production
declines at the Company’s mature tertiary properties in the Gulf
Coast region and CCA in the Rocky Mountain region, as well as a
temporary production decline at Tinsley Field and a contractual
reversionary interest assignment at Delhi Field, each of which is
discussed in further detail below. In addition, the Company
currently estimates that approximately 1,100 BOE/d of production
(excluding Riley Ridge) is shut-in due to wells that are uneconomic
to either produce or repair at this time. These decreases in
production were partially offset by production increases at Oyster
Bayou Field in the Gulf Coast region and Bell Creek Field in the
Rocky Mountain region. Third quarter of 2015 production was
95% oil, compared to 96% oil in the same prior-year period.
Tertiary oil production during the third quarter
of 2015 decreased 4%, or 1,750 Bbls/d, on a sequential-quarter
basis and 2%, or 793 Bbls/d, from levels in the third quarter of
2014. On a sequential-quarter basis, the tertiary oil
production decrease was primarily driven by facility processing
constraints and impacts of warmer temperatures restricting CO2
injection and recycling at Tinsley Field; however, current
production from the field is increasing and fourth quarter
production is expected to be higher than production in the third
quarter of 2015. The sequential decrease was partially offset
by a production increase at Bell Creek Field. The
year-over-year quarterly production decrease was also impacted by
the contractual reversionary assignment in Delhi Field occurring on
November 1, 2014, which reduced third quarter of 2015 production by
approximately 1,200 Bbls/d, partially offset by production growth
at Oyster Bayou Field.
Non-tertiary oil-equivalent production was down
2%, or 556 BOE/d, on a sequential-quarter basis and 5%, or 1,607
BOE/d, from third quarter of 2014 levels. These decreases are
the result of natural production declines at CCA and the Company’s
other non-tertiary Rocky Mountain properties, as well as the impact
of shutting in certain uneconomic non-tertiary wells. The
year-over-year quarterly decrease was partially offset by increases
in production at Conroe Field.
REVIEW OF FINANCIAL RESULTS
Oil and natural gas revenues, excluding the
impact of derivative contracts, decreased 53% when comparing the
third quarters of 2015 and 2014, primarily due to a 50% decline in
realized commodity prices and a 3% decrease in production.
Denbury’s average realized oil price, excluding derivative
settlements, was $45.74 per Bbl in the third quarter of 2015,
compared to $56.92 per Bbl in the second quarter of 2015 and $94.78
per Bbl in the prior-year third quarter. Including derivative
settlements, Denbury’s average realized oil price was $71.32 per
Bbl in the third quarter of 2015, compared to $76.30 in the second
quarter of 2015 and $90.92 per Bbl in the prior-year third
quarter. The oil price realized relative to NYMEX oil prices
(the Company’s NYMEX oil price differential) in the third quarter
of 2015 was $0.96 per Bbl below NYMEX prices, compared to a
differential of $0.89 per Bbl below NYMEX in the second quarter of
2015 and $2.53 per Bbl below NYMEX in the third quarter of
2014.
The Company’s total lease operating expenses in
the third quarter of 2015 averaged $17.34 per BOE, which includes
insurance and other expense reimbursements recognized during the
quarter totaling approximately $14 million, comprised of a
reimbursement for a retroactive utility rate adjustment ($10
million) and an insurance reimbursement for previous well control
costs ($4 million). Lease operating expenses, excluding these
nonrecurring amounts, averaged $19.43 per BOE in the third quarter
of 2015, a decrease of 1% from the $19.70 per-BOE average in the
second quarter of 2015 and 20% from the $24.32 per-BOE average in
the third quarter of 2014. These decreases in lease operating
costs are primarily due to the Company’s cost reduction efforts
throughout 2014 and 2015, as well as general market decreases in
the prices of many of the components of these costs.
Taxes other than income, which includes ad
valorem, production, and franchise taxes, decreased $8 million on a
sequential-quarter basis and decreased $14 million from the
prior-year third quarter level. The levels of taxes other
than income during most periods are generally aligned with
fluctuations in oil and natural gas revenues.
General and administrative expenses were $33
million in the third quarter of 2015, decreasing $7 million, or
18%, from the prior-year third quarter level. This reduction
is due largely to an approximate 11% reduction in headcount since
January 1, 2015, which has resulted in lower employee compensation
and related costs, as well as other cost reduction efforts.
Interest expense, before capitalized interest,
was $47 million in the third quarter of 2015, compared to $51
million in the third quarter of 2014, due primarily to a $196
million decrease in average debt outstanding. Capitalized
interest was $8 million in the third quarter of 2015, compared to
$6 million in the prior-year third quarter, resulting in net
interest expense of $39 million in the third quarter of 2015,
compared to $45 million in the prior-year third quarter.
Excess cash flow from operations was used to pay down borrowings on
the Company’s bank credit facility, which ended the third quarter
of 2015 at $210 million, down from $395 million as of December 31,
2014.
As a result of the significant decrease in
commodity pricing from fourth quarter 2014 levels, the Company
recognized full cost pool ceiling test write-downs of $1.8 billion,
$1.7 billion and $0.2 billion during the three months ended
September 30, 2015, June 30, 2015, and March 31, 2015,
respectively. In determining these write-downs, the Company
is required to use the average of rolling first-day-of-the-month
oil and gas prices for the preceding 12 months, after adjustments
for market differentials by field. The preceding 12-month
price averaged $56.74 per Bbl for crude oil and $3.64 per thousand
cubic feet (“Mcf”) for natural gas for the period ended September
30, 2015. The Company currently estimates that the full cost
ceiling test write-down in the fourth quarter of 2015 will be in a
range of similar magnitude to the write-down recorded in the third
quarter of 2015 if oil and natural gas prices remain at or near
late-October 2015 levels for the remainder of 2015, depending
further, in part, upon changes relative to proved oil and natural
gas reserve volumes, future capital expenditures and operating
costs.
Based on the results of the Company’s goodwill
impairment test performed for the third quarter of 2015, the
Company recorded a goodwill impairment charge of $1.3 billion to
fully impair the carrying value of the Company’s goodwill. Of
the Company’s $1.3 billion goodwill balance, approximately $1.0
billion was associated with the Company’s 2010 merger with Encore
Acquisition Company. The significant decline in the Company's
enterprise value (market capitalization and fair value of debt) at
a rate greater than the decline in NYMEX oil futures prices between
June 30 and September 30, 2015, was a primary cause of the
impairment.
Denbury’s overall depletion, depreciation, and
amortization (“DD&A”) rate was $18.48 per BOE in the third
quarter of 2015, compared to $21.58 per BOE in the prior-year third
quarter and $22.05 per BOE in the second quarter of 2015, with the
decreases primarily driven by a reduction in depletable costs
associated with the Company’s reserves base resulting from the full
cost pool ceiling test write-downs recognized during the first half
of 2015. Based on full cost pool ceiling test write-downs
recognized during the nine months ended September 30, 2015, the
DD&A rate for the fourth quarter of 2015 is expected to
decrease further from the third quarter of 2015 rate.
Receipts on settlements of oil and natural gas
derivative contracts were $161 million in the third quarter of
2015, compared to receipts of $124 million in the second quarter of
2015 and payments of $25 million in the prior-year third
quarter. These settlements resulted in an increase in average
net realized oil prices of $25.58 per Bbl in the third quarter of
2015, an increase of $19.38 per Bbl in the second quarter of 2015,
and a decrease of $3.86 per Bbl in the third quarter of 2014.
Changes in the fair values of the Company’s derivative contracts in
the third quarter of 2015 resulted in a noncash pre-tax loss of $69
million, compared to a loss of $173 million in the second quarter
of 2015 and a gain of $277 million in the prior-year third
quarter.
Denbury’s effective tax rate for the third
quarter of 2015 was 24.6%, down from 38.4% in the prior-year third
quarter primarily as a result of the impairment of goodwill during
the quarter. As a significant portion of the $1.3 billion
goodwill balance that was written off for financial reporting
purposes did not have a related tax basis, there was no
corresponding tax benefit realized related to the impairment.
The Company’s estimated statutory rate remained at 38%, consistent
with the prior-year third quarter.
2015 PRODUCTION AND CAPITAL EXPENDITURE
ESTIMATES
Based on year-to-date production levels and
estimates for the remainder of 2015, the Company currently
estimates total annual production volumes will average in the lower
half of the Company’s prior estimated total production range shown
in the following table.
Operating
Area |
|
2015
Estimated Production(BOE/d) |
Tertiary |
|
42,100
– 43,700 |
Cedar Creek
Anticline |
|
18,000
– 18,800 |
Gulf Coast
Non-Tertiary |
|
8,300
– 8,700 |
Other Rockies
Non-Tertiary |
|
4,100 – 4,300 |
Total Production |
|
72,500
– 75,500 |
In the second half of 2015, the Company has
reduced its estimated 2015 development capital expenditure budget
by $95 million, offset in part by higher capitalized interest,
lowering its overall 2015 estimated capital spending budget to $475
million, down from the previously estimated total capital spending
amount of $550 million. The capital budget consists of
approximately $370 million of tertiary, non-tertiary, and CO2
supply and pipeline projects, plus approximately $105 million of
estimated capitalized costs (including capitalized internal
acquisition, exploration and development costs; capitalized
interest; and pre-production startup costs associated with new
tertiary floods). Of this combined capital expenditure
amount, approximately $313 million (66%) has been incurred through
the first nine months of 2015.
DIVIDEND SUSPENSION AND SHARE REPURCHASE
PROGRAM
In light of the continuing low oil price
environment and its desire to maintain the Company’s financial
strength and flexibility, on September 21, 2015, the Company’s
Board of Directors suspended the Company’s quarterly cash dividend
following payment of its third quarter dividend on September 29,
2015. Separately, the Company’s Board of Directors authorized
the reinstatement of the ability to repurchase shares under the
Company’s share repurchase program, which authorization had been
suspended in November of 2014. During September and October
of 2015, the Company repurchased 4.4 million shares of Denbury
common stock for approximately $12 million. Approximately
$210 million remains authorized for repurchases under the
program. The Company expects that any future repurchases
would be funded out of excess cash flow. There is no set
expiration date for the program and no requirement that the entire
authorized amount be used.
CONFERENCE CALL INFORMATION
Denbury management will host a conference call
to review and discuss third quarter 2015 financial and operating
results, as well as financial and operating guidance for the
remainder of 2015 and preliminary estimates of 2016 capital
expenditure levels, today, Thursday, November 5, at 10:00 A.M.
(Central). Additionally, Denbury has published presentation
materials which will be referenced during the conference
call. Individuals who would like to participate should dial
800.230.1096 or 612.332.0725 ten minutes before the scheduled start
time. To access a live webcast of the conference call and
accompanying slide presentation, please visit the investor
relations section of the Company’s website at
www.denbury.com. 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 324019.
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.
This press release, other than historical
financial information, contains forward-looking statements that
involve risks and uncertainties including estimated 2015 production
and capital expenditures, estimated cash generated from operations
in 2015, estimated 2016 capital expenditures, 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.
FINANCIAL AND STATISTICAL DATA TABLES
AND RECONCILIATION SCHEDULES
Following are unaudited financial highlights for
the comparative three and nine month periods ended September 30,
2015 and 2014. All production volumes and dollars are
expressed on a net revenue interest basis with gas volumes
converted to equivalent barrels at 6:1.
DENBURY RESOURCES INC. |
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED) |
|
The
following information is based on GAAP reported earnings, with
additional required disclosures included in the Company’s Form
10-Q: |
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
September 30, |
|
September 30, |
In
thousands, except per share data |
|
2015 |
|
2014 |
|
2015 |
|
2014 |
Revenues and
other income |
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
285,742 |
|
|
$ |
615,745 |
|
|
$ |
939,744 |
|
|
$ |
1,876,524 |
|
Natural gas sales |
|
4,646 |
|
|
6,260 |
|
|
15,005 |
|
|
26,356 |
|
CO2 and helium sales and
transportation fees |
|
9,144 |
|
|
11,378 |
|
|
23,268 |
|
|
33,961 |
|
Interest income and other
income |
|
4,068 |
|
|
4,274 |
|
|
9,926 |
|
|
14,680 |
|
Total revenues and other
income |
|
303,600 |
|
|
637,657 |
|
|
987,943 |
|
|
1,951,521 |
|
Expenses |
|
|
|
|
|
|
|
|
Lease operating expenses |
|
113,902 |
|
|
155,198 |
|
|
387,156 |
|
|
488,827 |
|
Marketing and plant operating
expenses |
|
14,458 |
|
|
15,328 |
|
|
40,358 |
|
|
50,263 |
|
CO2 and helium discovery and
operating expenses |
|
1,017 |
|
|
11,434 |
|
|
2,909 |
|
|
22,229 |
|
Taxes other than income |
|
25,607 |
|
|
39,966 |
|
|
85,841 |
|
|
136,761 |
|
General and administrative
expenses |
|
32,907 |
|
|
40,366 |
|
|
117,134 |
|
|
123,011 |
|
Interest, net of amounts
capitalized of $8,081, $5,862, $25,228 and $17,413,
respectively |
|
39,225 |
|
|
44,752 |
|
|
119,187 |
|
|
140,136 |
|
Depletion, depreciation, and
amortization |
|
121,406 |
|
|
146,560 |
|
|
419,304 |
|
|
435,854 |
|
Commodity derivatives expense
(income) |
|
(92,028 |
) |
|
(252,265 |
) |
|
(126,178 |
) |
|
(825 |
) |
Loss on early extinguishment of
debt |
|
— |
|
|
— |
|
|
— |
|
|
113,908 |
|
Write-down of oil and natural gas
properties |
|
1,760,600 |
|
|
— |
|
|
3,612,600 |
|
|
— |
|
Impairment of goodwill |
|
1,261,512 |
|
|
— |
|
|
1,261,512 |
|
|
— |
|
Total expenses |
|
3,278,606 |
|
|
201,339 |
|
|
5,919,823 |
|
|
1,510,164 |
|
Income (loss)
before income taxes |
|
(2,975,006 |
) |
|
436,318 |
|
|
(4,931,880 |
) |
|
441,357 |
|
Income tax provision
(benefit) |
|
|
|
|
|
|
|
|
Current income taxes |
|
1,184 |
|
|
214 |
|
|
1,063 |
|
|
532 |
|
Deferred income taxes |
|
(732,064 |
) |
|
167,356 |
|
|
(1,432,572 |
) |
|
168,967 |
|
Net income
(loss) |
|
$ |
(2,244,126 |
) |
|
$ |
268,748 |
|
|
$ |
(3,500,371 |
) |
|
$ |
271,858 |
|
|
|
|
|
|
|
|
|
|
Net income
(loss) per common share |
|
|
|
|
|
|
|
|
Basic |
|
$ |
(6.41 |
) |
|
$ |
0.77 |
|
|
$ |
(10.01 |
) |
|
$ |
0.78 |
|
Diluted |
|
$ |
(6.41 |
) |
|
$ |
0.77 |
|
|
$ |
(10.01 |
) |
|
$ |
0.77 |
|
|
|
|
|
|
|
|
|
|
Dividends
declared per common share |
|
$ |
0.0625 |
|
|
$ |
0.0625 |
|
|
$ |
0.1875 |
|
|
$ |
0.1875 |
|
|
|
|
|
|
|
|
|
|
Weighted
average common shares outstanding |
|
|
|
|
|
|
|
|
Basic |
|
350,052 |
|
|
348,454 |
|
|
349,787 |
|
|
348,993 |
|
Diluted |
|
350,052 |
|
|
350,918 |
|
|
349,787 |
|
|
351,347 |
|
DENBURY RESOURCES INC. |
SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES
(UNAUDITED) |
|
Reconciliation of net income (loss) (GAAP measure) to adjusted net
income (non-GAAP measure)(1): |
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
September 30, |
|
June 30, |
|
September 30, |
In
thousands |
|
2015 |
|
2014 |
|
2015 |
|
2015 |
|
2014 |
Net income (loss) (GAAP
measure) |
|
$ |
(2,244,126 |
) |
|
$ |
268,748 |
|
|
$ |
(1,148,499 |
) |
|
$ |
(3,500,371 |
) |
|
$ |
271,858 |
|
Noncash fair value adjustments on
commodity derivatives |
|
68,649 |
|
|
(277,179 |
) |
|
173,077 |
|
|
307,115 |
|
|
(103,080 |
) |
Lease operating expenses –
nonrecurring amounts |
|
(13,715 |
) |
|
(9,906 |
) |
|
— |
|
|
(13,715 |
) |
|
(9,906 |
) |
Loss on early extinguishment of
debt |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
113,908 |
|
Write-down of oil and natural gas
properties |
|
1,760,600 |
|
|
— |
|
|
1,705,800 |
|
|
3,612,600 |
|
|
— |
|
Impairment of goodwill |
|
1,261,512 |
|
|
— |
|
|
— |
|
|
1,261,512 |
|
|
— |
|
Estimated income taxes on above
adjustments to net income (loss) |
|
(769,497 |
) |
|
109,093 |
|
|
(713,973 |
) |
|
(1,563,874 |
) |
|
(350 |
) |
Valuation allowance on deferred
taxes |
|
— |
|
|
— |
|
|
30,500 |
|
|
30,500 |
|
|
— |
|
Adjusted net income
(non-GAAP measure) |
|
$ |
63,423 |
|
|
$ |
90,756 |
|
|
$ |
46,905 |
|
|
$ |
133,767 |
|
|
$ |
272,430 |
|
|
(1)
See “Non-GAAP Measures” at the end of this report. |
Reconciliation of cash flows from operations (GAAP measure) to
adjusted cash flows from operations (non-GAAP measure)(1): |
|
|
|
Three Months Ended |
|
Nine Months Ended |
In thousands |
|
September 30, |
|
June 30, |
|
September 30, |
|
2015 |
|
2014 |
|
2015 |
|
2015 |
|
2014 |
Net income (loss) (GAAP
measure) |
|
$ |
(2,244,126 |
) |
|
$ |
268,748 |
|
|
$ |
(1,148,499 |
) |
|
$ |
(3,500,371 |
) |
|
$ |
271,858 |
|
Adjustments to
reconcile to adjusted cash flows from operations |
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation, and
amortization |
|
121,406 |
|
|
146,560 |
|
|
147,940 |
|
|
419,304 |
|
|
435,854 |
|
Deferred income taxes |
|
(732,064 |
) |
|
167,356 |
|
|
(634,472 |
) |
|
(1,432,572 |
) |
|
168,967 |
|
Stock-based compensation |
|
7,670 |
|
|
8,887 |
|
|
7,118 |
|
|
22,637 |
|
|
26,104 |
|
Noncash fair value adjustments on
commodity derivatives |
|
68,649 |
|
|
(277,179 |
) |
|
173,077 |
|
|
307,115 |
|
|
(103,080 |
) |
Loss on early extinguishment of
debt |
|
— |
|
|
— |
|
|
— |
|
|
— |
|
|
113,908 |
|
Write-down of oil and natural gas
properties |
|
1,760,600 |
|
|
— |
|
|
1,705,800 |
|
|
3,612,600 |
|
|
— |
|
Impairment of goodwill |
|
1,261,512 |
|
|
— |
|
|
— |
|
|
1,261,512 |
|
|
— |
|
Other |
|
(1,129 |
) |
|
1,820 |
|
|
620 |
|
|
(647 |
) |
|
5,396 |
|
Adjusted cash flows
from operations (non-GAAP measure) |
|
242,518 |
|
|
316,192 |
|
|
251,584 |
|
|
689,578 |
|
|
919,007 |
|
Net change in assets and
liabilities relating to operations |
|
30,158 |
|
|
24,200 |
|
|
37,373 |
|
|
9,819 |
|
|
(33,910 |
) |
Cash flows from
operations (GAAP measure) |
|
$ |
272,676 |
|
|
$ |
340,392 |
|
|
$ |
288,957 |
|
|
$ |
699,397 |
|
|
$ |
885,097 |
|
|
(1)
See “Non-GAAP Measures” at the end of this report. |
DENBURY RESOURCES INC. |
SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES
(UNAUDITED) |
|
Reconciliation of commodity derivatives income (expense) (GAAP
measure) to noncash fair value adjustments on commodity derivatives
(non-GAAP measure)(1): |
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
September 30, |
|
June 30, |
|
September 30, |
In
thousands |
|
2015 |
|
2014 |
|
2015 |
|
2015 |
|
2014 |
Receipt (payment) on
settlements of commodity derivatives |
|
$ |
160,677 |
|
|
$ |
(24,914 |
) |
|
$ |
124,151 |
|
|
$ |
433,293 |
|
|
$ |
(102,255 |
) |
Noncash fair value
adjustments on commodity derivatives (non-GAAP measure) |
|
(68,649 |
) |
|
277,179 |
|
|
(173,077 |
) |
|
(307,115 |
) |
|
103,080 |
|
Commodity derivatives income
(expense) (GAAP measure) |
|
$ |
92,028 |
|
|
$ |
252,265 |
|
|
$ |
(48,926 |
) |
|
$ |
126,178 |
|
|
$ |
825 |
|
|
(1)
See “Non-GAAP Measures” at the end of this report. |
OPERATING HIGHLIGHTS (UNAUDITED) |
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
September 30, |
|
June 30, |
|
September 30, |
|
|
2015 |
|
2014 |
|
2015 |
|
2015 |
|
2014 |
Production
(daily – net of royalties) |
|
|
|
|
|
|
|
|
|
|
Oil (barrels) |
|
67,900 |
|
|
70,619 |
|
|
69,837 |
|
|
69,424 |
|
|
70,504 |
|
Gas (mcf) |
|
21,066 |
|
|
19,147 |
|
|
23,273 |
|
|
22,357 |
|
|
22,671 |
|
BOE (6:1) |
|
71,410 |
|
|
73,810 |
|
|
73,716 |
|
|
73,150 |
|
|
74,283 |
|
Unit sales
price (excluding derivative settlements) |
|
|
|
|
|
|
|
|
|
|
Oil (per barrel) |
|
$ |
45.74 |
|
|
$ |
94.78 |
|
|
$ |
56.92 |
|
|
$ |
49.58 |
|
|
$ |
97.49 |
|
Gas (per mcf) |
|
2.40 |
|
|
3.55 |
|
|
2.44 |
|
|
2.46 |
|
|
4.26 |
|
BOE (6:1) |
|
44.20 |
|
|
91.60 |
|
|
54.69 |
|
|
47.81 |
|
|
93.83 |
|
Unit sales
price (including derivative settlements) |
|
|
|
|
|
|
|
|
|
|
Oil (per barrel) |
|
$ |
71.32 |
|
|
$ |
90.92 |
|
|
$ |
76.30 |
|
|
$ |
72.31 |
|
|
$ |
92.22 |
|
Gas (per mcf) |
|
2.87 |
|
|
3.61 |
|
|
2.89 |
|
|
2.89 |
|
|
4.13 |
|
BOE (6:1) |
|
68.66 |
|
|
87.93 |
|
|
73.20 |
|
|
69.51 |
|
|
88.79 |
|
NYMEX
differentials |
|
|
|
|
|
|
|
|
|
|
Gulf Coast region |
|
|
|
|
|
|
|
|
|
|
Oil (per barrel) |
|
$ |
0.92 |
|
|
$ |
2.15 |
|
|
$ |
1.86 |
|
|
$ |
0.88 |
|
|
$ |
1.97 |
|
Gas (per mcf) |
|
(0.22 |
) |
|
(0.18 |
) |
|
(0.10 |
) |
|
(0.18 |
) |
|
0.09 |
|
Rocky Mountain region |
|
|
|
|
|
|
|
|
|
|
Oil (per barrel) |
|
$ |
(4.73 |
) |
|
$ |
(11.96 |
) |
|
$ |
(6.48 |
) |
|
$ |
(6.33 |
) |
|
$ |
(10.52 |
) |
Gas (per mcf) |
|
(0.55 |
) |
|
(0.66 |
) |
|
(0.68 |
) |
|
(0.52 |
) |
|
(0.48 |
) |
Total company |
|
|
|
|
|
|
|
|
|
|
Oil (per barrel) |
|
$ |
(0.96 |
) |
|
$ |
(2.53 |
) |
|
$ |
(0.89 |
) |
|
$ |
(1.52 |
) |
|
$ |
(2.16 |
) |
Gas (per mcf) |
|
(0.34 |
) |
|
(0.40 |
) |
|
(0.30 |
) |
|
(0.30 |
) |
|
(0.16 |
) |
DENBURY RESOURCES INC. |
OPERATING HIGHLIGHTS (UNAUDITED) |
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
September 30, |
|
June 30, |
|
September 30, |
Average Daily Volumes (BOE/d) (6:1) |
|
2015 |
|
2014 |
|
2015 |
|
2015 |
|
2014 |
Tertiary oil
production |
|
|
|
|
|
|
|
|
|
|
Gulf Coast
region |
|
|
|
|
|
|
|
|
|
|
Mature properties |
|
|
|
|
|
|
|
|
|
|
Brookhaven |
|
1,712 |
|
|
1,767 |
|
|
1,691 |
|
|
1,672 |
|
|
1,820 |
|
Eucutta |
|
1,922 |
|
|
2,224 |
|
|
2,054 |
|
|
1,961 |
|
|
2,185 |
|
Mallalieu |
|
1,427 |
|
|
1,869 |
|
|
1,537 |
|
|
1,512 |
|
|
1,848 |
|
Other mature properties (1) |
|
5,885 |
|
|
6,189 |
|
|
5,888 |
|
|
5,828 |
|
|
6,209 |
|
Total mature properties |
|
10,946 |
|
|
12,049 |
|
|
11,170 |
|
|
10,973 |
|
|
12,062 |
|
Delhi |
|
3,676 |
|
|
4,377 |
|
|
3,623 |
|
|
3,617 |
|
|
4,542 |
|
Hastings |
|
5,114 |
|
|
4,917 |
|
|
5,350 |
|
|
5,054 |
|
|
4,766 |
|
Heidelberg |
|
5,600 |
|
|
5,721 |
|
|
5,885 |
|
|
5,836 |
|
|
5,553 |
|
Oyster Bayou |
|
5,962 |
|
|
4,605 |
|
|
5,936 |
|
|
5,920 |
|
|
4,361 |
|
Tinsley |
|
7,311 |
|
|
8,310 |
|
|
8,740 |
|
|
8,320 |
|
|
8,419 |
|
Total Gulf Coast region |
|
38,609 |
|
|
39,979 |
|
|
40,704 |
|
|
39,720 |
|
|
39,703 |
|
Rocky Mountain
region |
|
|
|
|
|
|
|
|
|
|
Bell Creek |
|
2,225 |
|
|
1,648 |
|
|
1,880 |
|
|
2,025 |
|
|
1,108 |
|
Total Rocky Mountain region |
|
2,225 |
|
|
1,648 |
|
|
1,880 |
|
|
2,025 |
|
|
1,108 |
|
Total tertiary oil
production |
|
40,834 |
|
|
41,627 |
|
|
42,584 |
|
|
41,745 |
|
|
40,811 |
|
Non-tertiary
oil and gas production |
|
|
|
|
|
|
|
|
|
|
Gulf Coast
region |
|
|
|
|
|
|
|
|
|
|
Mississippi |
|
1,592 |
|
|
2,346 |
|
|
1,400 |
|
|
1,584 |
|
|
2,391 |
|
Texas |
|
6,508 |
|
|
5,537 |
|
|
6,304 |
|
|
6,434 |
|
|
6,160 |
|
Other |
|
846 |
|
|
1,083 |
|
|
906 |
|
|
919 |
|
|
1,056 |
|
Total Gulf Coast region |
|
8,946 |
|
|
8,966 |
|
|
8,610 |
|
|
8,937 |
|
|
9,607 |
|
Rocky Mountain
region |
|
|
|
|
|
|
|
|
|
|
Cedar Creek Anticline |
|
17,515 |
|
|
18,623 |
|
|
18,089 |
|
|
18,038 |
|
|
18,927 |
|
Other |
|
4,115 |
|
|
4,594 |
|
|
4,433 |
|
|
4,430 |
|
|
4,938 |
|
Total Rocky Mountain region |
|
21,630 |
|
|
23,217 |
|
|
22,522 |
|
|
22,468 |
|
|
23,865 |
|
Total non-tertiary
production |
|
30,576 |
|
|
32,183 |
|
|
31,132 |
|
|
31,405 |
|
|
33,472 |
|
Total
production |
|
71,410 |
|
|
73,810 |
|
|
73,716 |
|
|
73,150 |
|
|
74,283 |
|
|
(1) Other
mature properties include Cranfield, Little Creek, Lockhart
Crossing, Martinville, McComb and Soso fields. |
DENBURY RESOURCES INC. |
PER-BOE DATA (UNAUDITED) |
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
September 30, |
|
September 30, |
|
|
2015 |
|
2014 |
|
2015 |
|
2014 |
Oil and natural gas
revenues |
|
$ |
44.20 |
|
|
$ |
91.60 |
|
|
$ |
47.81 |
|
|
$ |
93.83 |
|
Receipt (payment) on
settlements of commodity derivatives |
|
24.46 |
|
|
(3.67 |
) |
|
21.70 |
|
|
(5.04 |
) |
Lease operating
expenses – excluding nonrecurring amounts |
|
(19.43 |
) |
|
(24.32 |
) |
|
(20.08 |
) |
|
(24.59 |
) |
Lease operating
expenses – nonrecurring amounts |
|
2.09 |
|
|
1.46 |
|
|
0.69 |
|
|
0.49 |
|
Production and ad
valorem taxes |
|
(3.19 |
) |
|
(5.34 |
) |
|
(3.69 |
) |
|
(6.22 |
) |
Marketing expenses, net
of third-party purchases, and plant operating expenses |
|
(1.91 |
) |
|
(1.63 |
) |
|
(1.75 |
) |
|
(1.82 |
) |
Production netback |
|
46.22 |
|
|
58.10 |
|
|
44.68 |
|
|
56.65 |
|
CO2 and helium sales,
net of operating and exploration expenses |
|
1.24 |
|
|
— |
|
|
1.02 |
|
|
0.57 |
|
General and
administrative expenses |
|
(5.01 |
) |
|
(5.94 |
) |
|
(5.87 |
) |
|
(6.07 |
) |
Interest expense,
net |
|
(5.97 |
) |
|
(6.59 |
) |
|
(5.97 |
) |
|
(6.91 |
) |
Other |
|
0.43 |
|
|
1.00 |
|
|
0.67 |
|
|
1.08 |
|
Changes in assets and
liabilities relating to operations |
|
4.59 |
|
|
3.56 |
|
|
0.49 |
|
|
(1.67 |
) |
Cash flows from operations |
|
41.50 |
|
|
50.13 |
|
|
35.02 |
|
|
43.65 |
|
DD&A |
|
(18.48 |
) |
|
(21.58 |
) |
|
(21.00 |
) |
|
(21.49 |
) |
Write-down of oil and
natural gas properties |
|
(267.99 |
) |
|
— |
|
|
(180.90 |
) |
|
— |
|
Impairment of
goodwill |
|
(192.02 |
) |
|
— |
|
|
(63.17 |
) |
|
— |
|
Deferred income
taxes |
|
111.43 |
|
|
(24.65 |
) |
|
71.74 |
|
|
(8.33 |
) |
Loss on early
extinguishment of debt |
|
— |
|
|
— |
|
|
— |
|
|
(5.62 |
) |
Noncash fair value
adjustments on commodity derivatives |
|
(10.45 |
) |
|
40.82 |
|
|
(15.38 |
) |
|
5.08 |
|
Other noncash
items |
|
(5.57 |
) |
|
(5.14 |
) |
|
(1.59 |
) |
|
0.12 |
|
Net income (loss) |
|
$ |
(341.58 |
) |
|
$ |
39.58 |
|
|
$ |
(175.28 |
) |
|
$ |
13.41 |
|
CAPITAL EXPENDITURE SUMMARY (UNAUDITED) (1) |
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
September 30, |
|
September 30, |
In
thousands |
|
2015 |
|
2014 |
|
2015 |
|
2014 |
Capital expenditures by
project |
|
|
|
|
|
|
|
|
Tertiary oil fields |
|
$ |
36,845 |
|
|
$ |
156,414 |
|
|
$ |
133,439 |
|
|
$ |
442,810 |
|
Non-tertiary fields |
|
22,620 |
|
|
63,727 |
|
|
75,199 |
|
|
186,708 |
|
Capitalized interest and internal
costs (2) |
|
23,736 |
|
|
21,735 |
|
|
72,235 |
|
|
67,437 |
|
Oil and natural gas capital
expenditures |
|
83,201 |
|
|
241,876 |
|
|
280,873 |
|
|
696,955 |
|
CO2 pipelines |
|
3,839 |
|
|
12,256 |
|
|
10,135 |
|
|
24,612 |
|
CO2 sources (3) |
|
7,204 |
|
|
9,265 |
|
|
17,686 |
|
|
37,502 |
|
CO2 capitalized interest and
other |
|
1,213 |
|
|
779 |
|
|
3,816 |
|
|
2,831 |
|
Capital expenditures,
before acquisitions |
|
95,457 |
|
|
264,176 |
|
|
312,510 |
|
|
761,900 |
|
Acquisitions of oil and
natural gas properties |
|
796 |
|
|
1,683 |
|
|
22,755 |
|
|
1,683 |
|
Capital expenditures,
total |
|
$ |
96,253 |
|
|
$ |
265,859 |
|
|
$ |
335,265 |
|
|
$ |
763,583 |
|
|
(1) Capital expenditure
amounts include accrued capital. |
(2) Includes capitalized
internal acquisition, exploration and development costs;
capitalized interest; and pre-production startup costs associated
with new tertiary floods. |
(3) Includes capital
expenditures related to the Riley Ridge gas processing
facility. |
DENBURY RESOURCES INC. |
SELECTED BALANCE SHEET AND CASH FLOW DATA
(UNAUDITED) |
|
|
|
September 30, |
|
December 31, |
In
thousands |
|
2015 |
|
2014 |
Cash and cash
equivalents |
|
$ |
12,212 |
|
|
$ |
23,153 |
|
Total assets |
|
7,355,152 |
|
|
12,727,802 |
|
|
|
|
|
|
Borrowings under bank
credit facility |
|
$ |
210,000 |
|
|
$ |
395,000 |
|
Borrowings under senior
subordinated notes (principal only) |
|
2,852,250 |
|
|
2,852,735 |
|
Financing and capital
leases |
|
295,095 |
|
|
323,624 |
|
Total debt (principal only) |
|
$ |
3,357,345 |
|
|
$ |
3,571,359 |
|
|
|
|
|
|
Total stockholders'
equity |
|
$ |
2,136,332 |
|
|
$ |
5,703,856 |
|
|
|
Nine Months Ended |
|
|
September 30, |
In
thousands |
|
2015 |
|
2014 |
Cash provided by (used
in) |
|
|
|
|
Operating activities |
|
$ |
699,397 |
|
|
$ |
885,097 |
|
Investing activities |
|
(427,540 |
) |
|
(788,923 |
) |
Financing activities |
|
(282,798 |
) |
|
(88,925 |
) |
|
|
|
|
|
Cash dividends
paid |
|
65,422 |
|
|
65,241 |
|
NON-GAAP MEASURES
Adjusted net income is a non-GAAP measure
provided as a supplement to present an alternative net income
measure which excludes expense and income items (and their related
tax effects) not directly related to the Company’s ongoing
operations. The excluded items for the periods presented are
those which reflect the write-down of oil and natural gas
properties, impairment of goodwill, noncash fair value adjustments
on the Company’s commodity derivative contracts, nonrecurring lease
operating expenses, the cost of early debt extinguishment, and a
valuation allowance on deferred taxes. Management believes
that adjusted net income may be helpful to investors, and is widely
used by the investment community, while also being used by
management, in evaluating the comparability of the Company’s
ongoing operational results and trends. Adjusted net income
should not be considered in isolation or as a substitute for net
income reported in accordance with GAAP, but rather to provide
additional information useful in evaluating the Company’s
operational trends and performance.
Adjusted cash flows from operations is a
non-GAAP measure that represents cash flows provided by operations
before changes in assets and liabilities, as summarized from the
Company’s Consolidated Statements of Cash Flows. Adjusted
cash flows from operations measures the cash flows earned or
incurred from operating activities without regard to the collection
or payment of associated receivables or payables. Management
believes that it is important to consider this additional measure,
along with cash flows from operations, as it believes the non-GAAP
measure can often be a better way to discuss changes in operating
trends in its business caused by changes in production, prices,
operating costs and so forth, without regard to whether the earned
or incurred item was collected or paid during that period.
Noncash fair value adjustments on commodity
derivatives is a non-GAAP measure and is different from “Commodity
derivatives expense (income)” in the Consolidated Statements of
Operations in that the noncash fair value adjustments on commodity
derivatives represents only the net change between periods of the
fair market values of open commodity derivative positions, and
excludes the impact of settlements on commodity derivatives during
the period. Management believes that noncash fair value
adjustments on commodity derivatives is a useful supplemental
disclosure to “Commodity derivatives expense (income)” because the
GAAP measure also includes settlements on commodity derivatives
during the period; the non-GAAP measure is widely used within the
industry and by securities analysts, banks and credit rating
agencies in calculating EBITDA and in adjusting net income to
present those measures on a comparative basis across companies, as
well as to assess compliance with certain debt covenants.
DENBURY CONTACTS:
Mark C. Allen, Senior Vice President and Chief Financial Officer, 972.673.2000
Ross M. Campbell, Manager of Investor Relations, 972.673.2825
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