Attached files
| file | filename |
|---|---|
| 8-K - FORM 8-K - DENBURY INC | form8k.htm |
Exhibit 99.1
DENBURY REPORTS SECOND QUARTER 2012 RESULTS
ADDS INITIAL PROVED TERTIARY OIL RESERVES AT HASTINGS FIELD
INCREASES TERTIARY OIL PRODUCTION BY 6% SEQUENTIALLY
PLANO, TX – August 2, 2012 – Denbury Resources Inc. (NYSE: DNR) ("Denbury" or the "Company") today announced adjusted net income (a non-GAAP measure)1 of $138 million for the second quarter of 2012, or $0.35 per diluted share, on quarterly revenues of $597 million. This compares to $147 million of adjusted net income, or $0.36 per diluted share, on revenues of $596 million for the prior year second quarter, and $161 million of adjusted net income, or $0.41 per diluted share, on revenues of $640 million for the first quarter of 2012. Second quarter of 2012 net income (the GAAP measure) was $212 million, or $0.54 per diluted share. This compares to net income of $259 million, or $0.64 per diluted share, for the prior year second quarter, and net income of $113 million, or $0.29 per diluted share, for the first quarter of 2012.
Adjusted cash flow from operations (a non-GAAP measure)1 for the second quarter of 2012 was $362 million. This compares to $344 million of the same measure for the prior year second quarter, and $352 million for the first quarter of 2012. Net cash provided by operating activities (the GAAP measure) was $441 million for the second quarter of 2012, compared to $399 million of this same measure for the prior year second quarter and $292 million for the first quarter of 2012.
Key highlights for the second quarter of 2012 include:
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·
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Increased average continuing total production to 72,280 barrels of oil equivalent per day (“BOE/d”), 16% higher than 2011’s second quarter level and 4% higher than first quarter 2012 levels.
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·
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Grew average tertiary oil production to a record level of 35,208 barrels per day (“Bbls/d”), 14% higher than 2011’s second quarter level and 6% higher than first quarter 2012 levels.
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·
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Increased average tertiary oil production from the most recently commenced floods at Hastings and Oyster Bayou to a combined 3,217 Bbls/d, a 115% increase from first quarter 2012 levels.
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·
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Added estimated proved tertiary oil reserves2 at Hastings Field of approximately 43 million barrels with an estimated PV-10 Value1,2 of $1.05 billion at quarter end.
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·
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Increased internally estimated proved reserves quantities to 516 million barrels of oil equivalent (“MMBOE”) at quarter end, representing a 12% increase over year-end 2011 levels.
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1 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 internal estimates calculated using the trailing 12-month average of first-day-of-the-month prices as of June 30, 2012 of $95.67 per Bbl of oil, before field differential adjustments. Reserve volume estimates are prepared based upon applicable SEC rules and regulations on reserve estimation and evaluation.
- 1 -
Phil Rykhoek, Denbury’s President and CEO, commented, "We continued to execute our unique and profitable oil production growth strategy in the second quarter. Total tertiary production reached a new record level due to strong contributions from our newest floods at Hastings and Oyster Bayou and continued growth at Tinsley. Given Hastings’ strong tertiary production response, we booked initial proved tertiary reserves for the field sooner than expected. Our proved reserve additions at Hastings, Oyster Bayou, and the Bakken in the first half of 2012 drove a 12% increase in our estimates of proved reserves at mid-year 2012 from year-end 2011 levels. The positive results we are experiencing at Hastings bode well for the carbon dioxide (“CO2”) flood we have planned for the recently acquired Thompson Field, which is approximately 18 miles from Hastings Field and produces oil from the same geologic formation. While our Bakken production increased by 99% from the year ago quarter, the rate of sequential quarterly production growth slowed as expected in the quarter primarily due to the reduction in our operated rig count in the area to four from a peak of seven in 2011. With our solid second quarter results, we remain confident that both our tertiary and total production should be in the upper half of our estimated 2012 production ranges.”
Production
Second quarter of 2012 continuing total production averaged 72,280 BOE/d, up 16% from the prior year period level, and up 4% from the first quarter of 2012 level. The comparative quarterly increases were the result of gains in tertiary and Bakken production, which were offset by reductions in conventional production. Excluded from second quarter 2012 continuing production volumes are 57 BOE/d of production from non-core properties sold in April 2012. Average production from non-core assets sold in the first half of 2012 was 2,591 BOE/d in the second quarter of 2011 and 1,762 BOE/d in the first quarter of 2012. Including production from these divested assets, production averaged 72,337 BOE/d in the second quarter of 2012, up 11% from 64,919 BOE/d produced in the prior year period, and up 1% from the 71,532 BOE/d produced in the first quarter of 2012.
Second quarter of 2012 production from tertiary operations averaged 35,208 Bbls/d, a 14% increase from the prior year second quarter level, and a 6% increase from the first quarter of 2012 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 Heidelberg fields. Bakken production averaged 15,208 BOE/d in the second quarter of 2012, a 99% increase from the prior year second quarter level, and a small increase from the first quarter of 2012 level. The rapid year-over-year growth in Bakken production is a result of Denbury’s active drilling program in the region. The slowdown in sequential quarterly growth primarily reflects the impact of a planned reduction in Denbury’s operated rig count in the Bakken to four from a peak of seven in 2011.
Review of Financial Results
Denbury’s second quarter of 2012 oil and natural gas revenues, excluding the impact of derivative contracts, were generally unchanged compared to revenues in the prior year second quarter, as higher production drove an 11% increase in revenues while lower realized oil and natural gas prices drove an 11% decrease in revenues. During the second quarter of 2012, 93% of the Company’s production was oil which was up slightly from the prior year second quarter level of 92%.
Denbury’s oil price differential (the difference between the average price at which the Company sold its production and the average NYMEX price) declined from the prior year second quarter level as improvements in the Light Louisiana Sweet ("LLS") index premium were more than offset by wider Bakken differentials. Company-wide oil price differentials in the second quarter of 2012 were $2.14 per Bbl above NYMEX prices, compared to $3.72 per Bbl above NYMEX in the prior year second quarter. For the second quarter of 2012, the LLS index differential averaged a positive $18.14 per Bbl on a trade-month basis, compared to a positive $15.32 per Bbl in the prior year second quarter. The LLS premium impacts a large portion of the Company’s Gulf Coast tertiary oil production, which was sold at an average premium of $13.60 per Bbl to NYMEX in the second quarter of 2012, up from a $9.69 per Bbl premium in the prior year second quarter. In the Bakken, differentials averaged $20.16 per Bbl below NYMEX in the second quarter of 2012, significantly lower than the $9.62 per Bbl below NYMEX realized in the prior year second quarter. During the second 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.
- 2 -
Lease operating expenses decreased 11% on a per BOE basis to $18.92 per BOE in the second quarter of 2012 from $21.34 per BOE in the second quarter of 2011. The decrease from the prior year second quarter was primarily due to increased Bakken production, the sale of non-core Gulf Coast and Rocky Mountain properties during the first half of 2012 which had relatively high operating costs per BOE, and a change in classification of the Company’s equipment leases during the second quarter of 2012 which reduced lease operating expense in the current period by $1.26 per BOE. Tertiary operating expenses averaged $22.95 per Bbl in the second quarter of 2012 compared to $22.87 per Bbl in the prior year second quarter. The change in the classification of equipment leases reduced tertiary operating expenses in the second quarter of 2012 by $2.57 per Bbl. Excluding the impact of the change in lease classification, 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 their production increases.
General and administrative (“G&A”) expenses totaled $35 million, or $5.29 per BOE, in the second quarter of 2012, compared to $29 million, or $4.86 per BOE, in the prior year second quarter. The increase in G&A expense was due primarily to higher headcount and employee-related costs.
Interest expense in the second quarter of 2012 was $42 million, unchanged from the prior year second quarter level as a $5 million increase in capitalized interest to $18 million and reduction in average interest rates to 7.6% from 8.8% was offset by a $659 million increase in average debt outstanding. The increase in capitalized interest between the second quarter of 2011 and the second quarter of 2012 was primarily the result of incremental capitalized interest on new projects under development, particularly the Riley Ridge facility, Greencore Pipeline, and Bell Creek Field.
Depletion, depreciation and amortization of oil and natural gas properties was $16.88 per BOE in the second quarter of 2012, compared to $15.85 per BOE in the prior year second quarter. The increase was primarily due to higher finding and development costs per barrel associated with the Company’s Bakken assets.
Denbury recorded a pre-tax $132 million non-cash fair value gain to earnings in the second quarter of 2012 due to increases in the fair value of its derivative contracts, compared to a pre-tax $184 million non-cash fair value gain in the prior year second quarter. Also, Denbury recorded a pre-tax $4 million charge related to the expected delay in delivery of helium under a supply agreement as a result of delays in completing its Riley Ridge facility until near the end of 2012. Lastly, Denbury corrected the classification of its outstanding equipment leases from operating to capital which resulted in a one-time, pre-tax $8 million charge and a $164 million increase in total debt.
2012 Production Estimates and Capital Expenditures
Denbury’s 2012 production estimates are unchanged at the levels shown in the following table. The Company continues to expect tertiary and total production to be in the upper half of estimated ranges. This would represent a 14% to 18% increase in total continuing production, which is adjusted for asset divestitures, from full-year 2011 levels.
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Operating Area
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2012 Estimated Production (BOE/d)
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Tertiary
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33,000 – 36,000
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Bakken
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14,350 – 16,350
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Other
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22,000
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Total Continuing Production
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69,350 – 74,350
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Production Sold
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425
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Total Production
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69,775 – 74,775
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Denbury’s 2012 capital expenditure budget remains $1.5 billion, approximately two-thirds of which is for tertiary projects, with the remainder for the Bakken. The budgeted amount excludes acquisitions, capitalized interest and tertiary start-up costs and is net of a projected $75 million of proceeds from equipment sale/leasebacks. Of the $1.5 billion budgeted, approximately half had been spent through the second quarter of 2012.
- 3 -
Conference Call and Conference Presentation
The public is invited to listen to a webcast of Denbury’s conference call to review the results today at 10:00 A.M. (Central). The webcast will be accessible in the ‘Investor Relations’ section of www.denbury.com. The call will be archived on the website for at least 90 days and a telephonic replay will be accessible for one month after the call by dialing 800.475.6701 or 320.365.3844 and entering access code 220095.
Denbury also announced that Phil Rykhoek will be presenting at EnerCom’s The Oil & Gas Conference on Tuesday, August 14, 2012 at 9:15 A.M. (Mountain) in Denver and at the Barclays CEO Energy-Power Conference on Tuesday, September 4, 2012 at 1:05 P.M. (Eastern) in New York. A link to the webcast presentations will be available at www.denbury.com. The replays and slide presentations will be available on the website for approximately 30 days thereafter.
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 proved oil and natural gas reserves quantities and the PV-10 net present values thereof, estimated 2012 production and capital expenditures, and potential proceeds from 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, Senior Vice President 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 three and six month periods ended June 30 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.
- 4 -
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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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June 30,
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Percentage
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2012
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2011
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Change
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Revenues and other income
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Oil sales
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587,191
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575,928
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+
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2%
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Natural gas sales
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4,950
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15,171
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-
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67%
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CO2 sales and transportation fees
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5,301
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5,343
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-
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1%
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Interest income and other income
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4,339
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4,955
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-
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12%
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Total revenues and other income
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601,781
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601,397
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+
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0%
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Expenses
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Lease operating expenses
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124,511
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126,085
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-
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1%
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Marketing expenses
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12,218
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6,270
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+
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95%
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CO2 discovery and operating expenses
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1,062
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1,693
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-
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37%
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Taxes other than income
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38,812
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39,632
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-
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2%
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General and administrative
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34,826
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28,709
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+
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21%
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Interest expense, net
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41,604
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42,249
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-
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2%
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Depletion, depreciation, and amortization
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132,289
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103,495
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+
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28%
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Derivatives income
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(139,109)
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(172,904)
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-
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20%
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Loss on early extinguishment of debt
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—
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348
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-
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100%
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Impairment of assets
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215
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—
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N/A
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Other expenses
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12,552
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2,018
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+
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>100%
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Total expenses
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258,980
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177,595
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+
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46%
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Income before income taxes
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342,801
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423,802
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-
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19%
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Income tax provision
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Current income taxes
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784
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12,028
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-
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93%
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Deferred income taxes
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130,152
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152,528
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-
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15%
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Net income
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211,865
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259,246
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-
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18%
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Net income per common share:
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Basic
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0.55
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0.65
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-
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15%
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Diluted
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0.54
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0.64
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-
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16%
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Weighted average common shares outstanding:
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Basic
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387,159
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398,631
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-
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3%
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Diluted
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390,702
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403,919
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-
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3%
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Production (daily – net of royalties):
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Oil (barrels)
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67,476
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59,538
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+
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13%
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Gas (mcf)
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29,163
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32,283
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-
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10%
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BOE (6:1)
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72,337
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64,919
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+
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11%
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Unit sales price (including derivative settlements):
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Oil (per barrel)
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95.51
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103.17
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-
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7%
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Gas (per mcf)
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4.88
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|
7.22
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-
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32%
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BOE (6:1)
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91.06
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98.21
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-
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7%
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Unit sales price (excluding derivative settlements):
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Oil (per barrel)
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95.63
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106.30
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-
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10%
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Gas (per mcf)
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1.87
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5.16
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-
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64%
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BOE (6:1)
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89.96
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100.06
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-
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10%
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- 5 -
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Three Months Ended
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June 30,
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Percentage
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2012
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2011
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Change
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Derivative contracts
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Cash receipt (payment) on settlements
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7,282
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(10,942)
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+
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>100%
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Non-cash fair value adjustments on commodity derivatives
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131,827
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183,846
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-
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28%
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Total income from derivative contracts
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139,109
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172,904
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-
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20%
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Non-GAAP financial measure1 – adjusted net income
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Net income (GAAP measure)
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211,865
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259,246
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-
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18%
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Non-cash fair value adjustments on commodity derivatives (net of taxes)
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(81,733)
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|
(113,985)
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-
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28%
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Impairment of assets (net of taxes)
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133
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|
—
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N/A
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Cumulative effect of equipment lease correction (net of taxes)
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5,240
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|
—
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N/A
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Contractual helium nonperformance payment (net of taxes)
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2,542
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—
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N/A
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Loss on early extinguishment of debt (net of taxes)
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—
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|
216
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|
|
-
|
100%
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Transaction and other costs related to the Encore merger (net of taxes)
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—
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1,251
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|
-
|
100%
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Adjusted net income (non-GAAP measure)
|
138,047
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|
146,728
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-
|
6%
|
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|
|
|
|
|
|
|
|
|
|
|
|
Non-GAAP financial measure1 – adjusted cash flow from operations
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|
|
|
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|
|
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Net income (GAAP measure)
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211,865
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|
259,246
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|
-
|
18%
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Adjustments to reconcile to cash flow from operations:
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Depletion, depreciation, and amortization
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132,289
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|
103,495
|
|
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+
|
28%
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|
|
|
Deferred income taxes
|
130,152
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|
152,528
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|
|
-
|
15%
|
|
|
|
Non-cash fair value adjustments on commodity derivatives
|
(131,827)
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|
(183,846)
|
|
|
-
|
28%
|
|
|
|
Impairment of assets
|
215
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|
—
|
|
|
|
N/A
|
|
|
|
Cumulative effect of equipment lease correction
|
8,452
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|
—
|
|
|
|
N/A
|
|
|
|
Contractual helium nonperformance payment
|
4,100
|
|
—
|
|
|
|
N/A
|
|
|
|
Loss on early extinguishment of debt
|
—
|
|
348
|
|
|
-
|
100%
|
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|
|
Other
|
6,595
|
|
12,287
|
|
|
-
|
46%
|
|
|
Adjusted cash flow from operations (non-GAAP measure)
|
361,841
|
|
344,058
|
|
|
+
|
5%
|
||
|
|
Net change in assets and liabilities relating to operations
|
79,125
|
|
54,463
|
|
|
+
|
45%
|
|
|
Cash flow from operations (GAAP measure)
|
440,966
|
|
398,521
|
|
|
+
|
11%
|
||
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas capital expenditures
|
271,762
|
|
281,305
|
|
|
-
|
3%
|
||
|
Acquisitions of oil and natural gas properties2
|
153,774
|
|
2,681
|
|
|
+
|
>100%
|
||
|
CO2 capital expenditures
|
22,620
|
|
4,892
|
|
|
+
|
>100%
|
||
|
Pipelines and plants capital expenditures
|
109,234
|
|
59,340
|
|
|
+
|
84%
|
||
|
Net proceeds from sales of properties and equipment3
|
5,730
|
|
6,443
|
|
|
-
|
11%
|
||
|
|
|
|
|
|
|
|
|
|
|
|
BOE data (6:1)
|
|
|
|
|
|
|
|
||
|
|
Oil and natural gas revenues
|
89.96
|
|
100.06
|
|
|
-
|
10%
|
|
|
|
Gain (loss) on settlements of derivative contracts
|
1.10
|
|
(1.85)
|
|
|
+
|
>100%
|
|
|
|
Lease operating expenses
|
(18.92)
|
|
(21.34)
|
|
|
-
|
11%
|
|
|
|
Marketing expenses, net of third party purchases
|
(1.26)
|
|
(1.06)
|
|
|
+
|
19%
|
|
|
|
|
Production netback
|
70.88
|
|
75.81
|
|
|
-
|
7%
|
|
|
CO2 sales, net of operating expenses
|
0.65
|
|
0.62
|
|
|
+
|
5%
|
|
|
|
Taxes other than income
|
(5.90)
|
|
(6.71)
|
|
|
-
|
12%
|
|
|
|
General and administrative expenses
|
(5.29)
|
|
(4.86)
|
|
|
+
|
9%
|
|
|
|
Net cash interest expense and other income
|
(5.10)
|
|
(5.54)
|
|
|
-
|
8%
|
|
|
|
Other
|
(0.27)
|
|
(1.08)
|
|
|
-
|
75%
|
|
|
|
Changes in assets and liabilities relating to operations
|
12.02
|
|
9.22
|
|
|
+
|
30%
|
|
|
|
|
Cash flow from operations
|
66.99
|
|
67.46
|
|
|
-
|
1%
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
See "Non-GAAP Measures" at the end of this report.
|
||||||||
|
2
|
For the three months ended June 30, 2012, excludes $212.5 million of cash which was held by a qualified intermediary to support a like-kind exchange transaction.
|
||||||||
|
3
|
For the three months ended June 30, 2012, excludes $72.4 million of cash which was held by a qualified intermediary to support a like-kind exchange transaction.
|
||||||||
- 6 -
|
SIX MONTH FINANCIAL HIGHLIGHTS
|
|
|
|
|
|
|
|||
|
(Amounts in thousands of U.S. dollars, except per share and unit data)
|
|
|
|
|
|
|
|||
|
(Unaudited)
|
|
|
|
|
|
|
|
||
|
|
|
|
Six Months Ended
|
|
|
|
|
||
|
|
|
|
June 30,
|
|
Percentage
|
||||
|
|
|
|
2012
|
|
2011
|
|
Change
|
||
|
Revenues and other income
|
|
|
|
|
|
|
|
||
|
|
Oil sales
|
1,210,897
|
|
1,068,766
|
|
|
+
|
13%
|
|
|
|
Natural gas sales
|
14,745
|
|
28,525
|
|
|
-
|
48%
|
|
|
|
CO2 sales and transportation fees
|
12,096
|
|
10,267
|
|
|
+
|
18%
|
|
|
|
Interest income and other income
|
9,159
|
|
8,004
|
|
|
+
|
14%
|
|
|
|
|
Total revenues and other income
|
1,246,897
|
|
1,115,562
|
|
|
+
|
12%
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses
|
|
|
|
|
|
|
|
||
|
|
Lease operating expenses
|
262,475
|
|
249,882
|
|
|
+
|
5%
|
|
|
|
Marketing expenses
|
23,048
|
|
11,573
|
|
|
+
|
99%
|
|
|
|
CO2 discovery and operating expenses
|
7,267
|
|
3,639
|
|
|
+
|
100%
|
|
|
|
Taxes other than income
|
82,506
|
|
72,115
|
|
|
+
|
14%
|
|
|
|
General and administrative
|
71,433
|
|
71,028
|
|
|
+
|
1%
|
|
|
|
Interest expense, net
|
77,918
|
|
91,026
|
|
|
-
|
14%
|
|
|
|
Depletion, depreciation, and amortization
|
253,184
|
|
197,089
|
|
|
+
|
28%
|
|
|
|
Derivatives income
|
(93,834)
|
|
(2,154)
|
|
|
+
|
>100%
|
|
|
|
Loss on early extinguishment of debt
|
—
|
|
16,131
|
|
|
-
|
100%
|
|
|
|
Impairment of assets
|
17,515
|
|
—
|
|
|
|
N/A
|
|
|
|
Other expenses
|
23,272
|
|
4,377
|
|
|
+
|
>100%
|
|
|
|
|
Total expenses
|
724,784
|
|
714,706
|
|
|
+
|
1%
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
522,113
|
|
400,856
|
|
|
+
|
30%
|
||
|
|
|
|
|
|
|
|
|
|
|
|
Income tax provision
|
|
|
|
|
|
|
|
||
|
|
Current income taxes
|
29,492
|
|
11,180
|
|
|
+
|
>100%
|
|
|
|
Deferred income taxes
|
167,289
|
|
144,620
|
|
|
+
|
16%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
325,332
|
|
245,056
|
|
|
+
|
33%
|
||
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share:
|
|
|
|
|
|
|
|
||
|
|
Basic
|
0.84
|
|
0.62
|
|
|
+
|
35%
|
|
|
|
Diluted
|
0.83
|
|
0.61
|
|
|
+
|
36%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding:
|
|
|
|
|
|
|
|
||
|
|
Basic
|
386,764
|
|
398,032
|
|
|
-
|
3%
|
|
|
|
Diluted
|
390,823
|
|
403,703
|
|
|
-
|
3%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (daily – net of royalties):
|
|
|
|
|
|
|
|
||
|
|
Oil (barrels)
|
67,167
|
|
59,002
|
|
|
+
|
14%
|
|
|
|
Gas (mcf)
|
28,608
|
|
31,579
|
|
|
-
|
9%
|
|
|
|
BOE (6:1)
|
71,934
|
|
64,265
|
|
|
+
|
12%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit sales price (including derivative settlements):
|
|
|
|
|
|
|
|
||
|
|
Oil (per barrel)
|
98.33
|
|
98.02
|
|
|
+
|
0%
|
|
|
|
Gas (per mcf)
|
5.72
|
|
7.20
|
|
|
-
|
21%
|
|
|
|
BOE (6:1)
|
94.09
|
|
93.53
|
|
|
+
|
1%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit sales price (excluding derivative settlements):
|
|
|
|
|
|
|
|
||
|
|
Oil (per barrel)
|
99.06
|
|
100.08
|
|
|
-
|
1%
|
|
|
|
Gas (per mcf)
|
2.83
|
|
4.99
|
|
|
-
|
43%
|
|
|
|
BOE (6:1)
|
93.62
|
|
94.33
|
|
|
-
|
1%
|
|
- 7 -
|
|
|
Six Months Ended
|
|
|
|
|
|||
|
|
|
June 30,
|
|
Percentage
|
|||||
|
|
|
2012
|
|
2011
|
|
Change
|
|||
|
Derivative contracts
|
|
|
|
|
|
|
|
||
|
Cash receipt (payment) on settlements
|
6,092
|
|
(9,354)
|
|
|
+
|
>100%
|
||
|
Non-cash fair value adjustments on commodity derivatives
|
87,742
|
|
11,508
|
|
|
+
|
>100%
|
||
|
|
Total income from derivative contracts
|
93,834
|
|
2,154
|
|
|
+
|
>100%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-GAAP financial measure1 – adjusted net income
|
|
|
|
|
|
|
|
||
|
Net income (GAAP measure)
|
325,332
|
|
245,056
|
|
|
+
|
33%
|
||
|
Non-cash fair value adjustments on commodity derivatives (net of taxes)
|
(54,400)
|
|
(7,135)
|
|
|
+
|
>100%
|
||
|
Impairment of assets (net of taxes)
|
10,859
|
|
—
|
|
|
|
N/A
|
||
|
Cumulative effect of equipment lease correction (net of taxes)
|
5,240
|
|
—
|
|
|
|
N/A
|
||
|
Contractual helium nonperformance payment (net of taxes)
|
4,960
|
|
—
|
|
|
|
N/A
|
||
|
CO2 exploration costs (net of taxes)
|
3,053
|
|
—
|
|
|
|
N/A
|
||
|
Allowance for collectability on outstanding loans (net of taxes)
|
2,283
|
|
—
|
|
|
|
N/A
|
||
|
Loss on sale of Vanguard common units (net of taxes)
|
1,945
|
|
—
|
|
|
|
N/A
|
||
|
Loss on early extinguishment of debt (net of taxes)
|
—
|
|
10,001
|
|
|
-
|
100%
|
||
|
Transaction and other costs related to the Encore merger (net of taxes)
|
—
|
|
2,714
|
|
|
-
|
100%
|
||
|
|
Adjusted net income (non-GAAP measure)
|
299,272
|
|
250,636
|
|
|
+
|
19%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-GAAP financial measure1 – adjusted cash flow from operations
|
|
|
|
|
|
|
|
||
|
Net income (GAAP measure)
|
325,332
|
|
245,056
|
|
|
+
|
33%
|
||
|
Adjustments to reconcile to cash flow from operations:
|
|
|
|
|
|
|
|
||
|
|
Depletion, depreciation, and amortization
|
253,184
|
|
197,089
|
|
|
+
|
28%
|
|
|
|
Deferred income taxes
|
167,289
|
|
144,620
|
|
|
+
|
16%
|
|
|
|
Non-cash fair value adjustments on commodity derivatives
|
(87,742)
|
|
(11,508)
|
|
|
+
|
>100%
|
|
|
|
Impairment of assets
|
17,515
|
|
—
|
|
|
|
N/A
|
|
|
|
Cumulative effect of equipment lease correction
|
8,452
|
|
—
|
|
|
|
N/A
|
|
|
|
Contractual helium nonperformance payment
|
8,000
|
|
—
|
|
|
|
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
|
—
|
|
16,131
|
|
|
-
|
100%
|
|
|
|
Other
|
15,215
|
|
23,887
|
|
|
-
|
36%
|
|
|
Adjusted cash flow from operations (non-GAAP measure)
|
714,065
|
|
615,275
|
|
|
+
|
16%
|
||
|
|
Net change in assets and liabilities relating to operations
|
18,555
|
|
(91,922)
|
|
|
+
|
>100%
|
|
|
Cash flow from operations (GAAP measure)
|
732,620
|
|
523,353
|
|
|
+
|
40%
|
||
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas capital expenditures
|
574,008
|
|
471,601
|
|
|
+
|
22%
|
||
|
Acquisitions of oil and natural gas properties2
|
154,366
|
|
32,482
|
|
|
+
|
>100%
|
||
|
CO2 capital expenditures
|
53,313
|
|
32,042
|
|
|
+
|
66%
|
||
|
Pipelines and plants capital expenditures
|
169,675
|
|
98,237
|
|
|
+
|
73%
|
||
|
Net proceeds from sales of properties and equipment2
|
32,302
|
|
18,432
|
|
|
+
|
75%
|
||
|
Cash and cash equivalents
|
28,113
|
|
121,792
|
|
|
-
|
77%
|
||
|
Total assets
|
10,935,416
|
|
9,339,423
|
|
|
+
|
17%
|
||
|
Total borrowings under bank credit facility and senior
|
|
|
|
|
|
|
|
||
|
|
subordinated notes (principal only)
|
2,571,349
|
|
2,051,348
|
|
|
+
|
25%
|
|
|
Financing and capital leases
|
412,085
|
|
252,123
|
|
|
+
|
63%
|
||
|
|
Total debt (principal only)
|
2,983,434
|
|
2,303,471
|
|
|
+
|
30%
|
|
|
Total stockholders' equity
|
5,153,197
|
|
4,648,314
|
|
|
+
|
11%
|
||
|
|
|
|
|
|
|
|
|
|
|
|
BOE data (6:1)
|
|
|
|
|
|
|
|
||
|
|
Oil and natural gas revenues
|
93.62
|
|
94.33
|
|
|
-
|
1%
|
|
|
|
Gain (loss) on settlements of derivative contracts
|
0.47
|
|
(0.80)
|
|
|
+
|
>100%
|
|
|
|
Lease operating expenses
|
(20.05)
|
|
(21.48)
|
|
|
-
|
7%
|
|
|
|
Marketing expenses, net of third party purchases
|
(1.46)
|
|
(0.99)
|
|
|
+
|
47%
|
|
|
|
|
Production netback
|
72.58
|
|
71.06
|
|
|
+
|
2%
|
|
|
CO2 sales, net of operating expenses
|
0.36
|
|
0.57
|
|
|
-
|
37%
|
|
|
|
Taxes other than income
|
(6.30)
|
|
(6.20)
|
|
|
+
|
2%
|
|
|
|
General and administrative expenses
|
(5.46)
|
|
(6.11)
|
|
|
-
|
11%
|
|
|
|
Net cash interest expense and other income
|
(4.69)
|
|
(6.31)
|
|
|
-
|
26%
|
|
|
|
Other
|
(1.96)
|
|
(0.12)
|
|
|
+
|
>100%
|
|
|
|
Changes in assets and liabilities relating to operations
|
1.42
|
|
(7.90)
|
|
|
+
|
>100%
|
|
|
|
|
Cash flow from operations
|
55.95
|
|
44.99
|
|
|
+
|
24%
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
See "Non-GAAP Measures" at the end of this report.
|
||||||||
|
2
|
For the six months ended June 30, 2012, excludes $212.5 million of cash which was held by a qualified intermediary to support a like-kind exchange transaction.
|
||||||||
- 8 -
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 Value is a non-GAAP measure of the discounted net present value of oil and gas reserves that is different than the Standardized Measure of Discounted Future Net Cash Flows ("Standardized Measure") presented in the Company’s Form 10-K reports, in that PV-10 Value is a pre-tax number, while the Standardized Measure includes the effect of estimated future income taxes. The Company believes that PV-10 Value is a useful disclosure because it is not practical to calculate the Standardized Measure on a property-by-property basis and is a widely used measure within the industry that is commonly used by securities analysts and others to evaluate the estimated future net cash flows from proved reserves on a comparative basis across companies or specific properties. PV-10 Value is not a measure of financial or operating performance under GAAP, and does not purport to represent the fair value of the oil and natural gas reserves in connection with which the value is estimated.
| - 9 - |