UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
 
FORM 8-K
 
CURRENT REPORT PURSUANT
TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

Date of Report (Date of earliest event reported): November 5, 2015
 
DENBURY RESOURCES INC.
(Exact name of registrant as specified in its charter)

Delaware
 
1-12935
 
20-0467835
(State or other jurisdiction of incorporation)
 
(Commission File Number)
 
(IRS Employer Identification No.)

5320 Legacy Drive
Plano, Texas
(Address of principal executive offices)

75024
(Zip code)

(972) 673-2000
(Registrant’s telephone number, including area code)

Not Applicable
(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):
o
 
Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
o
 
Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
o
 
Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
o
 
Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 





Section 2 – Financial Information

Item 2.02 – Results of Operations and Financial Condition

On November 5, 2015, Denbury Resources Inc. issued a press release announcing its 2015 third quarter financial and operating results. A copy of the press release is attached as Exhibit 99.1 to this Current Report on Form 8-K.

The information furnished in this Item 2.02 and in Exhibit 99.1 hereto shall not be deemed "filed" for purposes of the Securities Exchange Act of 1934, as amended (the "1934 Act"), and shall not be deemed incorporated by reference in any filing with the Securities and Exchange Commission (unless otherwise specifically provided therein), whether or not filed under the Securities Act of 1933, as amended, or the 1934 Act, regardless of any general incorporation language in any such document.


Section 9 – Financial Statements and Exhibits

Item 9.01 – Financial Statements and Exhibits

(d)
Exhibits.

The following exhibit is furnished in accordance with the provisions of Item 601 of Regulation S-K:
Exhibit Number
 
Description
99.1*
 
Denbury Press Release, dated November 5, 2015.

*
Included herewith.



- 2 -



SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

 
Denbury Resources Inc.
(Registrant)
 
Date: November 5, 2015
By:
/s/ James S. Matthews
 
 
James S. Matthews
 
 
Senior Vice President, General Counsel and Secretary



- 3 -



INDEX TO EXHIBITS

Exhibit Number
 
Description
99.1
 
Denbury Press Release, dated November 5, 2015.



- 4 -



News

DENBURY REPORTS THIRD QUARTER 2015 RESULTS

PLANO, TXNovember 5, 2015 – 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.

- 1 -


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


- 2 -


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


- 3 -


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


- 4 -


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


- 5 -


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


- 6 -


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.

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



- 7 -


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




- 8 -


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.



- 9 -


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
)



- 10 -


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.



- 11 -


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.



- 12 -


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




- 13 -


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.



- 14 -

This regulatory filing also includes additional resources:
dnr-20151105x8kearningsrel.pdf
Denbury Resources (NYSE:DNR)
Historical Stock Chart
From Feb 2024 to Mar 2024 Click Here for more Denbury Resources Charts.
Denbury Resources (NYSE:DNR)
Historical Stock Chart
From Mar 2023 to Mar 2024 Click Here for more Denbury Resources Charts.