Attached files
| file | filename |
|---|---|
| 8-K - FORM 8-K - DENBURY INC | form8k.htm |
Exhibit 99.1
DENBURY REPORTS FIRST QUARTER 2012 RESULTS
PLANO, TX – May 3, 2012 – Denbury Resources Inc. (NYSE: DNR) ("Denbury" or the "Company") today announced adjusted net income1 of $161 million for the first quarter of 2012, or $0.41 per diluted share, on record quarterly revenues of $640 million. This compares to $104 million of adjusted net income1, or $0.26 per diluted share, on revenues of $511 million for the prior year first quarter, and $175 million, or $0.45 per diluted share, on revenues of $612 million for the fourth quarter of 2011. Based on generally accepted accounting principles (“GAAP”), first quarter of 2012 net income was $113 million, or $0.29 per diluted share. This compares to a net loss of $14 million, or $0.04 per diluted share, for the prior year first quarter, and net income of $53 million, or $0.13 per diluted share, for the fourth quarter of 2011.
Adjusted cash flow from operations1 for the first quarter of 2012 was $352 million. This compares to $271 million of the same measure for the prior year first quarter, and $387 million for the fourth quarter of 2011. GAAP net cash provided by operating activities was $292 million for the first quarter of 2012, compared to $125 million of this same measure for the prior year first quarter and $366 million for the fourth quarter of 2011.
Key highlights for the first quarter of 2012 include:
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·
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Reported record quarterly tertiary oil production of 33,257 barrels per day (“Bbls/d”), a 7% increase from fourth quarter of 2011 levels.
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·
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Resumed full carbon dioxide (“CO2”) injections at Tinsley Field after completing remediation efforts, which drove the field’s quarterly oil production to a new record of 7,297 Bbls/d.
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·
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Reported record quarterly Bakken sales volumes of 15,114 barrels of oil equivalent per day (“BOE/d”), a 29% increase from fourth quarter of 2011 levels.
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·
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Realized an average oil sales price of $102.52 per barrel (“Bbl”), down from $103.08 per Bbl in the fourth quarter of 2011, as the Company’s average realized oil price differential moved to a negative $0.37 per Bbl in first quarter of 2012 compared to a positive $9.14 per Bbl in the fourth quarter of 2011.
|
|
·
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Added estimated proved reserves2 of approximately 18 million barrels of oil equivalent (“MMBOE”), including approximately 14 million barrels of oil at Oyster Bayou Field, based on its response to CO2 injections, and approximately 4 MMBOE in the Bakken. The Company estimates that the PV-101,2 value of the Oyster Bayou proved reserves added during the quarter was approximately $510 million at March 31, 2012.
|
|
·
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Strengthened the balance sheet and sharpened operational focus by divesting Vanguard units for approximately $84 million and selling non-core Gulf Coast properties for cash consideration of approximately $155 million, before purchase price adjustments.
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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 Reserve volumes and PV-10 value are estimated using pricing assumptions based on the trailing 12-month average first-day-of-the-month prices as of March 31, 2012 of $98.15 per Bbl of oil, before field differential adjustments, prepared on the basis of SEC rules and regulations.
Additional highlights subsequent to the first quarter of 2012:
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·
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Sold a non-core property for $75 million, before purchase price adjustments, completing the Company’s planned asset sales for 2012.
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·
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Increased the 2012 capital expenditure budget by $150 million, or 11%, to $1.5 billion, with an $80 million increase in Bakken development spending and the remainder primarily allocated to tertiary floods.
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·
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Agreed to acquire Thompson Field for $360 million in cash and a production payment. The field is approximately 18 miles from the Hastings Field and is expected to contribute approximately 2,200 Bbls/d to the Company’s oil production, while increasing the Company’s inventory of enhanced oil recovery projects in the Gulf Coast region.
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Phil Rykhoek, Denbury’s President and CEO, commented, "We are off to a strong start in 2012 as production from our tertiary oil and Bakken operations both reached new record levels in the first quarter. We expect continued tertiary production growth in 2012, while the rate of our Bakken production growth is expected to slow as we reduce our operated rig count in the area to four by mid-year from a peak of seven in 2011. As a result of our strong start to the year, we expect that our tertiary and total production will both be in the upper half of our estimated 2012 production ranges. Our quarterly revenue reached a new record level in the first quarter, increasing approximately 5% from fourth quarter 2011 levels, as higher oil production and NYMEX oil prices offset the impact of lower oil price differentials. With our asset sales complete, the positive start to the year and a favorable outlook, we have increased our 2012 capital budget by $150 million to $1.5 billion. The additional expenditures will primarily be split between our Bakken development program and tertiary floods. The additional spending will have an impact on our Bakken production late in 2012 and early 2013, while the higher tertiary spending will benefit 2013 production. Our recently announced acquisition of Thompson Field will allow us to further expand our leading position in Gulf Coast enhanced oil recovery and capitalize on the significant investments we have made in CO2 supply and infrastructure in the region. We remain focused on executing our unique, highly profitable, lower-risk, and long-term oil production growth strategy.”
Production
First quarter of 2012 production averaged 71,532 BOE/d, up 12% from 63,604 BOE/d produced in the prior year period, and up 6% from the 67,234 BOE/d produced in the fourth quarter of 2011. The comparative quarterly increases were the result of gains in Bakken and tertiary production, which were offset by reductions in conventional production and the impact of non-core asset sales. Included in first quarter 2012 production volumes are 1,762 BOE/d from non-core assets which Denbury sold in transactions that closed in late February and early April 2012. These same divested properties contributed 2,553 BOE/d in the first quarter of 2011 and 2,330 BOE/d of production in the fourth quarter of 2011.
First quarter of 2012 production from tertiary operations averaged 33,257 Bbls/d, an 8% increase from the prior year first quarter level, and a 7% increase from the fourth quarter of 2011 level. The growth in tertiary production was driven by contributions from new floods at Oyster Bayou and Hastings fields and existing floods at Tinsley and Delhi fields. Bakken production increased to 15,114 BOE/d in the first quarter of 2012, a 164% increase from the prior year first quarter level, and a 29% increase from the fourth quarter of 2011 level. The rapid growth in Bakken production is a result of Denbury’s active drilling program in the region.
Review of Financial Results
Denbury’s first quarter of 2012 oil and natural gas revenues, excluding the impact of derivative contracts, increased 25% compared to revenues in the prior year first quarter, with a 14% increase due to higher production and an 11% increase from higher realized oil prices. During the first quarter of 2012, 93% of the Company’s production was oil which was little changed from the prior year first quarter level of 92%.
Denbury’s oil price differential (the average price at which the Company sold its production compared to NYMEX prices) improved modestly from the prior year first quarter level as improvements in the Light Louisiana Sweet ("LLS") index premium were partly offset by widening Bakken differentials. Company-wide oil price differentials in the first quarter were $0.37 per Bbl below NYMEX prices, compared to $0.59 per Bbl below NYMEX in the prior year first quarter. For the first quarter of 2012, the LLS index differential averaged a positive $12.55 per Bbl on a trade-month basis, compared to a positive $9.28 per Bbl in the prior year first quarter. In the Bakken, differentials averaged $16.96 per Bbl below NYMEX in the first quarter of 2012, down from $11.55 per Bbl in the prior year first quarter. By the end of the first quarter of 2012, both differentials had improved, with the LLS to NYMEX premium increasing and Bakken to NYMEX discount shrinking. During the first quarter of 2012, the Company sold approximately 40% of its crude oil at prices based on the LLS index price, approximately 20% at prices tied to a combination of the LLS index price and other indexes, and the balance at prices based on various other indexes tied to NYMEX prices, primarily in the Rocky Mountain region.
Lease operating expenses decreased 2% on a per barrel of oil equivalent (“BOE”) basis between the first quarter of 2011 and first quarter of 2012. The decrease from the prior year first quarter was primarily due to increased Bakken production and the sale of non-core Gulf Coast properties during the first quarter of 2012 which had relatively high operating costs per BOE. These benefits more than offset higher tertiary operating expenses which averaged $26.74 per Bbl in the first quarter of 2012, compared to $24.93 per Bbl in the prior year first quarter. The increase in tertiary operating expenses between the periods was primarily due to the start up of new tertiary floods at Oyster Bayou and Hastings fields. Operating costs per barrel at these new tertiary oil fields are expected to decline as production from these new fields increase.
General and administrative (“G&A”) expenses totaled $37 million, or $5.62 per BOE, in the first quarter of 2012, compared to $42 million, or $7.39 per BOE, in the prior year first quarter. The decrease on a per BOE basis was driven by lower G&A expense and higher production. The decrease in G&A expense was due primarily to lower office related expenses and professional fees and an increase in capitalized exploration and development expenses, offset in part by higher compensation expense.
Interest expense declined by 26% in the first quarter of 2012 to $36 million, compared to $49 million in the prior year first quarter, as the benefit of an $8 million increase in capitalized interest and reduction in the average interest rate to 7.6% from 8.6% was offset by a $230 million increase in average debt outstanding. The increase in capitalized interest between the first quarter of 2011 and the first quarter of 2012 was primarily the result of incremental capitalized interest on projects under construction, particularly the Riley Ridge facility, Greencore Pipeline, and Conroe Field.
Depletion, depreciation and amortization of oil and natural gas properties was $16.71 per BOE in the first quarter of 2012, compared to $14.61 per BOE in the prior year first quarter. The increase was primarily due to higher finding costs per barrel associated with the Company’s Bakken assets and upward revisions in estimated future development costs primarily in the Bakken.
Denbury recorded a pre-tax $44 million non-cash fair value charge to earnings in the first quarter of 2012 due to decreases in the fair value of its derivative contracts, compared to a pre-tax $172 million non-cash fair value charge in the prior year first quarter.
During the first quarter of 2012, Denbury recorded total pre-tax asset impairment charges of $17 million, $15 million of which related to an investment in a proposed plant from which the Company would purchase CO2, with the remainder related to a CO2 property in the Rocky Mountain region. Also in the first quarter of 2012, Denbury recorded a pre-tax loss of $3 million on the sale of its Vanguard units, a $4 million charge related to an expected delay in delivery of helium under a supply agreement as a result of the delay in initial natural gas and helium sales at its Riley Ridge facility, and a $4 million allowance related to a loan receivable tied to future payments from natural gas producing wells acquired in the Encore acquisition.
Denbury’s effective tax rate for the first quarter of 2012 was approximately 37%, slightly lower than the estimated 38% statutory tax rate primarily due to the impact of the Company’s sale of its Vanguard units in January 2012, which allowed the Company to utilize a larger amount of preferential tax benefits.
2012 Production Estimates and Capital Expenditures
Denbury’s estimated 2012 production has been updated as follows:
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Operating Area
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2012 Estimated Production (BOE/d)
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||
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Tertiary (unchanged)
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33,000 – 36,000
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||
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Bakken
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14,350 – 16,350
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||
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Other*
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20,850
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||
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Total Continuing Production*
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68,200 – 73,200
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||
| Production Sold | 425 | ||
| Total Production | 68,625 – 73,625 |
* Does not include the contribution from properties Denbury agreed to acquire for $360 million in a transaction expected to close in June 2012. Daily net production from these assets is currently estimated at approximately 2,200 Bbls/d.
Overall, the Company is leaving its 2012 production estimates unchanged but has adjusted production estimates for the Bakken and “Other” production categories. The Company’s Bakken production range was increased by 1,600 BOE/d primarily due to more favorable than expected production to date from the area while the “Other” production category was reduced by 1,600 BOE/d due to the delayed start up of the Riley Ridge gas processing plant as the Company makes certain modifications identified during a pre-startup safety review. The Company now expects first production from Riley Ridge in the fourth quarter of 2012, which had previously been targeted for the second quarter of 2012. The adjustments to production estimates are expected to have a net positive impact on targeted 2012 revenues and cash flows, as previously projected natural gas production from Riley Ridge has been replaced primarily by oil production from the Bakken.
Denbury’s 2012 capital expenditure budget has been increased by $150 million to $1.5 billion. This amount excludes acquisitions, capitalized interest and tertiary start-up costs and is net of a projected $75 million of equipment sale/leasebacks. The increase is primarily split between Denbury’s Bakken properties and tertiary floods. In the Bakken, Denbury increased its projected capital spending from $400 million to $480 million, as it now plans to keep a fourth operated rig running in the second half of the year. Additional expenditures on tertiary floods will primarily accelerate projects previously planned for 2013.
Conference Call
The public is invited to listen to Denbury’s webcast and conference call today at 10:00 A.M. (central). The webcast is accessible on the ‘Investors’ section at www.denbury.com. The call will be archived on the Company’s website for approximately 30 days and will also be available for playback for one month after the call by dialing 800-475-6701 or 320-365-3844 and entering access code 220094.
Annual Meeting
Denbury’s 2012 Annual Meeting of Stockholders will be held on Tuesday, May 15th at 3:00 P.M. (central), at The Embassy Suites Dallas – Frisco Hotel located at 7600 John Q. Hammons Drive, Frisco, Texas. The record date for determination of shareholders entitled to vote at the annual meeting was the close of business on March 30, 2012.
Denbury Resources Inc. is a growing independent oil and natural gas company. The Company is the largest combined oil and natural gas operator in both Mississippi and Montana, owns the largest reserves of CO2 used for tertiary oil recovery east of the Mississippi River, and holds significant operating acreage in the Rocky Mountain and Gulf Coast regions. The Company's goal is to increase the value of acquired properties through a combination of exploitation, drilling and proven engineering extraction practices, with its most significant emphasis relating to tertiary 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 2012 production and capital expenditures and potential asset purchases and equipment sale/leasebacks and other risks and uncertainties detailed in the Company's filings with the Securities and Exchange Commission, including Denbury's most recent reports on Form 10-K and Form 10-Q. 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.
DENBURY CONTACTS:
Phil Rykhoek, President and CEO, 972-673-2000
Mark Allen, Sr. VP and CFO, 972-673-2000
Jack Collins, Executive Director, Investor Relations, 972-673-2028
Financial and Statistical Data Tables and Reconciliation Schedules
Following are unaudited financial highlights for the comparative first quarters of 2012 and 2011. All production volumes and dollars are expressed on a net revenue interest basis with gas volumes converted to equivalent barrels at 6:1.
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THREE MONTH FINANCIAL HIGHLIGHTS
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(Amounts in thousands of U.S. dollars, except per share and unit data)
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(Unaudited)
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Three Months Ended
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||
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March 31,
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Percentage
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||
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2012
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|
2011
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|
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Change
|
|
Revenues and other income
|
|
|
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|
|
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||
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Oil sales
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623,706
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|
492,838
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+
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27%
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|
|
|
Natural gas sales
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9,795
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|
13,354
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|
-
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27%
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|
|
|
CO2 sales and transportation fees
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6,795
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|
4,924
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+
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38%
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|
|
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Interest income and other income
|
4,820
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|
3,049
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+
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58%
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|
|
|
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Total revenues and other income
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645,116
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|
514,165
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+
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25%
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Expenses
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Lease operating expenses
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137,964
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123,797
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+
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11%
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Marketing expenses
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10,830
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5,303
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+
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>100%
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CO2 discovery and operating expenses
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6,205
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1,946
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+
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>100%
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Taxes other than income
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43,694
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32,483
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+
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35%
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General and administrative
|
36,607
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42,319
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-
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13%
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Interest expense, net
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36,314
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48,777
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-
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26%
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Depletion, depreciation and amortization
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120,895
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|
93,594
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+
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29%
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Derivatives expense
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45,275
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170,750
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-
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73%
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Loss on early extinguishment of debt
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—
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15,783
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-
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100%
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Impairment of assets
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17,300
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—
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N/A
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Other expenses
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10,720
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2,359
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+
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>100%
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Total expenses
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465,804
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537,111
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-
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13%
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Income (loss) before income taxes
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179,312
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(22,946)
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+
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>100%
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Income tax provision (benefit)
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Current income taxes
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28,708
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(848)
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+
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>100%
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Deferred income taxes
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37,137
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(7,908)
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+
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>100%
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Net income (loss)
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113,467
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(14,190)
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+
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>100%
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Net income (loss) per common share:
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Basic
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0.29
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(0.04)
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+
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>100%
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Diluted
|
0.29
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(0.04)
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+
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>100%
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Weighted average common shares:
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Basic
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386,367
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397,386
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-
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3%
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Diluted
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390,943
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397,386
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-
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2%
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Production (daily - net of royalties):
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Oil (barrels)
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66,857
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58,460
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+
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14%
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Gas (mcf)
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28,052
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30,866
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-
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9%
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BOE (6:1)
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71,532
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63,604
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+
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12%
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Unit sales price (including derivative settlements):
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Oil (per barrel)
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101.16
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92.72
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+
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9%
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Gas (per mcf)
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6.59
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|
7.19
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-
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8%
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BOE (6:1)
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97.14
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|
88.70
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+
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10%
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|
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Unit sales price (excluding derivative settlements):
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Oil (per barrel)
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102.52
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|
93.67
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+
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9%
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Gas (per mcf)
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3.84
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|
4.81
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-
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20%
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BOE (6:1)
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97.32
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|
88.42
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+
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10%
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Three Months Ended
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March 31,
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Percentage
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2012
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2011
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Change
|
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|
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|
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|
|
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Derivative contracts
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|
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Cash receipt (payment) on settlements
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(1,190)
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1,588
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-
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>100%
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Non-cash fair value derivative adjustments
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(44,085)
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(172,338)
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-
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74%
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Total expense from derivative contracts
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(45,275)
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(170,750)
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-
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73%
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|
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Non-GAAP financial measure1 – Adjusted net income
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Net income (loss) (GAAP measure)
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113,467
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(14,190)
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+
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>100%
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Non-cash fair value adjustments on derivative contracts (net of taxes)
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27,333
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|
106,850
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|
-
|
74%
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Impairment of assets (net of taxes)
|
10,726
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|
—
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N/A
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|
CO2 exploration costs (net of taxes)
|
3,053
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|
—
|
|
|
N/A
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Contractual helium nonperformance payment (net of taxes)
|
2,418
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|
—
|
|
|
N/A
|
||
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Allowance for collectability on outstanding loans (net of taxes)
|
2,283
|
|
—
|
|
|
N/A
|
||
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Loss on sale of Vanguard common units (net of taxes)
|
1,945
|
|
—
|
|
|
N/A
|
||
|
Loss on early extinguishment of debt (net of taxes)
|
—
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|
9,785
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|
-
|
100%
|
||
|
Transaction and other costs related to the Encore merger (net of taxes)
|
—
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|
1,463
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|
-
|
100%
|
||
|
|
Adjusted net income (non-GAAP measure)
|
161,225
|
|
103,908
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|
+
|
55%
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-GAAP financial measure1 – Adjusted cash flow from operations
|
|
|
|
|
|
|
||
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Net income (loss) (GAAP measure)
|
113,467
|
|
(14,190)
|
|
+
|
>100%
|
||
|
Adjustments to reconcile to cash flow from operations:
|
|
|
|
|
|
|
||
|
|
Depletion, depreciation and amortization
|
120,895
|
|
93,594
|
|
+
|
29%
|
|
|
|
Deferred income taxes
|
37,137
|
|
(7,908)
|
|
+
|
>100%
|
|
|
|
Non-cash fair value derivative adjustments
|
44,085
|
|
172,338
|
|
-
|
74%
|
|
|
|
Impairment of assets
|
17,300
|
|
—
|
|
|
N/A
|
|
|
|
Contractual helium nonperformance payment
|
3,900
|
|
—
|
|
|
N/A
|
|
|
|
Allowance for collectability on outstanding loans
|
3,683
|
|
—
|
|
|
N/A
|
|
|
|
Loss on sale of Vanguard common units
|
3,137
|
|
—
|
|
|
N/A
|
|
|
|
Loss on early extinguishment of debt
|
—
|
|
15,783
|
|
-
|
100%
|
|
|
|
Other
|
8,620
|
|
11,600
|
|
-
|
26%
|
|
|
Adjusted cash flow from operations (non-GAAP measure)
|
352,224
|
|
271,217
|
|
+
|
30%
|
||
|
|
Net change in assets and liabilities relating to operations
|
(60,570)
|
|
(146,385)
|
|
-
|
59%
|
|
|
Cash flow from operations (GAAP measure)
|
291,654
|
|
124,832
|
|
+
|
>100%
|
||
|
|
|
|
|
|
|
|
|
|
|
Oil & natural gas capital investments
|
302,838
|
|
220,097
|
|
+
|
38%
|
||
|
CO2 capital investments
|
30,693
|
|
27,150
|
|
+
|
13%
|
||
|
Pipelines and plants capital investments
|
60,441
|
|
38,897
|
|
+
|
55%
|
||
|
Proceeds from sales of properties
|
166,703
|
|
11,989
|
|
+
|
>100%
|
||
|
Cash and cash equivalents
|
77,366
|
|
127,857
|
|
-
|
39%
|
||
|
Total assets
|
10,342,062
|
|
9,111,419
|
|
+
|
14%
|
||
|
Total debt (principal amount excluding capital leases and
|
|
|
|
|
|
|
||
|
|
pipeline financings
|
2,496,350
|
|
2,106,797
|
|
+
|
18%
|
|
|
Financing leases
|
241,893
|
|
247,431
|
|
-
|
2%
|
||
|
Total stockholders' equity
|
4,928,442
|
|
4,381,365
|
|
+
|
12%
|
||
|
|
|
|
|
|
|
|
|
|
|
BOE data (6:1)
|
|
|
|
|
|
|
||
|
|
Oil and natural gas revenues
|
97.32
|
|
88.42
|
|
+
|
10%
|
|
|
|
Gain (loss) on settlements of derivative contracts
|
(0.18)
|
|
0.28
|
|
-
|
>100%
|
|
|
|
Lease operating expenses
|
(21.19)
|
|
(21.63)
|
|
-
|
2%
|
|
|
|
Marketing expenses
|
(1.66)
|
|
(0.93)
|
|
+
|
78%
|
|
|
|
|
Production netback
|
74.29
|
|
66.14
|
|
+
|
12%
|
|
|
CO2 discovery and operating expenses, net
|
0.08
|
|
0.52
|
|
-
|
85%
|
|
|
|
Taxes other than income
|
(6.71)
|
|
(5.67)
|
|
+
|
18%
|
|
|
|
General and administrative expenses
|
(5.62)
|
|
(7.39)
|
|
-
|
24%
|
|
|
|
Net cash interest expense and other income
|
(4.27)
|
|
(7.10)
|
|
-
|
40%
|
|
|
|
Other
|
(3.67)
|
|
0.88
|
|
-
|
>100%
|
|
|
|
Changes in assets and liabilities relating to operations
|
(9.30)
|
|
(25.57)
|
|
-
|
64%
|
|
|
|
|
Cash flow from operations
|
44.80
|
|
21.81
|
|
+
|
>100%
|
|
1
|
See "Non-GAAP Measures" at the end of this report.
|
Non-GAAP Measures
Adjusted net income is a non-GAAP measure. This measure reflects net income without regard to the fair value adjustments on the Company’s derivative contracts or other certain items that are generally non-cash and unusual or non-recurring in nature and are typically excluded by the investment community in preparing its published estimates. The Company believes that it is important to consider this measure separately as it is a better reflection of the ongoing comparable results of the Company, without regard to changes during the period in the market value of the Company’s derivative contracts or other typically excluded items.
Adjusted cash flow from operations is a non-GAAP measure that represents cash flow provided by operations before changes in assets and liabilities, as summarized from the Company’s Consolidated Statements of Cash Flows. Adjusted cash flow from operations measures the cash flow earned or incurred from operating activities without regard to the collection or payment of associated receivables or payables. The Company believes that it is important to consider this measure separately, as it believes it 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.
PV-10 is a non-GAAP measure and is different than the Standardized Measure of Discounted Future Net Cash Flows ("Standardized Measure") in that PV-10 is a pre-tax number, while the Standardized Measure includes the effect of estimated future income taxes.