Denbury Resources Reviews Third Quarter 2009 Earnings, Operations
Denbury Resources has announced its third quarter 2009 financial and operating results. The Company posted net income for the third quarter of 2009 of $26.9 million, or $0.11 per basic common share, as compared to net income of $157.5 million, or $0.64 per basic common share, in the comparative third quarter of 2008. The reduction in net income between the periods is primarily due to lower oil and natural gas commodity prices coupled with reduced natural gas production due to the sale of 60% of the Company's Barnett Shale natural gas assets in mid-2009, and a $108.4 million net decrease in the fair value changes in commodity derivative contracts in the comparative periods.
The current quarter results include a non-cash charge of $22.3 million ($13.8 million after taxes) for the change in fair value of the Company's commodity derivative contracts as compared to a non-cash gain of $86.1 million ($53.4 million after taxes) in the prior year period. Excluding these non-cash fair value adjustments, the Company's adjusted net income (a non-GAAP measure) for the third quarter of 2009 would have been $40.7 million, or $0.16 per basic common share, as compared to $123.0 million, or $0.50 per basic common share, earned in the prior year quarter, after adjusting for that quarter's non-cash fair value gain on commodity derivative contracts and a $30.4 million ($18.9 million after taxes) charge related to the cancelled Conroe Field acquisition in the prior year period.
Adjusted cash flow from operations (cash flow from operations before changes in operating assets and liabilities, a non-GAAP measure) for the third quarter of 2009 was $134.3 million, a decrease of 36% from third quarter 2008 adjusted cash flow from operations of $211.2 million. Net cash flow provided by operations, the GAAP measure, totaled $142.9 million during the third quarter of 2009, as compared to $262.4 million during the third quarter of 2008. Adjusted cash flow and cash flow from operations differ in that the latter measure includes the changes in receivables, accounts payable and accrued liabilities during the quarter.
Oil and natural gas production for the third quarter of 2009 averaged 42,659 BOE/d, a 10% increase from third quarter 2008 production, after adjusting for the 2009 sale of 60% of the Company’s Barnett Shale natural gas assets. The increase over the prior year third quarter period was primarily due to a 23% increase in tertiary oil production and production from Hastings Field (2,083 BOE/d in the current year quarter), which the Company acquired in February 2009, offset in part by the expected decrease in the Company’s non-tertiary Mississippi production. The non-tertiary Mississippi production decline was primarily from the Selma Chalk natural gas production as a result of limited drilling activity there in 2009 and non-tertiary Heidelberg oil as additional areas of the field were shut-in in order to expand the tertiary flooding to those areas. On a sequential basis, the Company's oil and natural gas production decreased 4%, primarily due to the decreases in non-tertiary Mississippi production offset in part by a slight increase in the Company's tertiary production.
During the third quarter of 2009, the Company's tertiary production averaged 24,347 Bbls/d, which included 829 Bbls/d from tertiary production response at Heidelberg Field. During the quarter, the Company had strong production increases compared to the prior quarter, at Tinsley (averaging 3,558 Bbls/d, a 5% increase), Soso (averaging 2,813 Bbls/d, a 9% increase), Lockhart Crossing (averaging 882 Bbls/d, a 26% increase), and Cranfield (averaging 572 Bbls/d, a 69% increase). These increases were offset in part by planned downtime at Mallalieu Field for facility expansion during the quarter, and the Company also expanded its facilities at Tinsley Field, earlier than originally planned, reducing the production rate of growth at that field during the third quarter.
Third Quarter 2009 Financial Results
Oil and natural gas revenues, excluding the impact of any derivative contracts, decreased 45% between the respective third quarters as lower commodity prices decreased revenues by 38% and lower production (primarily due to the sale of 60% of the Company’s Barnett Shale natural gas assets), decreased revenues by 7%. On a sequential basis, oil and natural gas revenues increased 5% between the second and third quarters of 2009, as higher commodity prices in the third quarter increased revenues by 22% and lower production decreased revenues by 17%.
The Company received $18.5 million on its derivative contract settlements in the third quarter of 2009, as compared to cash payments of $24.1 million made on derivative contracts during the third quarter of 2008. During the first and second quarters of 2009, the Company collected $85.8 million and $42.0 million, respectively, on its derivative contracts. Approximately 80% of the Company's 2009 oil production is hedged using a collar with a $75 floor and a $115 ceiling per barrel, therefore commodity price fluctuations outside of that range have very little impact on cash flow.
The Company recorded a $22.3 million non-cash fair value charge to earnings in the third quarter of 2009 on its commodity derivative contracts as compared to an $86.1 million gain in the third quarter of 2008. The Company also had non-cash fair value charges of $106.4 million and $194.8 million during the first and second quarters of 2009, respectively, on its commodity derivative contracts.
Company-wide oil price differentials (Denbury's net oil price received as compared to NYMEX prices) improved during the third quarter of 2009 as compared to differentials in the second quarter of 2009, averaging $3.47 per Bbl below NYMEX as compared to $5.30 per Bbl below NYMEX during the second quarter of 2009, both significantly better than the differential during the third quarter of 2008, which averaged $6.06 per Bbl below NYMEX. The lower differential in the current quarter was primarily due to the reduced natural gas liquid production associated with the sold Barnett Shale properties which have a significantly higher differential to NYMEX.
Lease operating expenses decreased 2% between the comparable third quarters on an absolute basis, but increased on a per BOE basis primarily due to the Barnett Shale property sale in mid-2009. Lease operating expenses averaged $21.22 per BOE in the third quarter of 2009, compared to $19.90 per BOE in the second quarter of 2009 and $22.88 per BOE in the third quarter of 2008 (both comparable amounts adjusted for the Barnett Shale property sale). The Company’s lease operating expenses on its tertiary properties averaged $23.14 per Bbl during the third quarter of 2009, lower than the prior year’s third quarter average of $26.81 per Bbl, but higher than the second quarter 2009 average of $20.86 per Bbl. The decrease in per barrel tertiary operating costs from the prior year period is primarily due to lower oil prices, which reduces the Company’s cost of CO2. The increase in per BOE tertiary operating costs from the second to third quarter of 2009 is primarily due to an increase in workover expenses between the sequential periods, an increase in the cost of CO2 as a result of higher oil prices during the third quarter, and incremental equipment leases.
Production taxes and marketing expenses decreased during the third quarter of 2009 as compared to those costs in the prior year third quarter, generally due to the decrease in commodity prices and production levels.
General and administrative expenses increased between the comparative third quarters of 2009 and 2008, averaging $6.12 per BOE in the third quarter of 2009, up from $3.55 per BOE in the third quarter of 2008. Our G&A costs increased $9.0 million from the prior year third quarter levels, due primarily to higher employee costs and to the expensing of approximately $3.6 million associated with our compensation arrangement with certain management of Genesis. In addition, the G&A costs per BOE increased in the third quarter of 2009 as a result of the Barnett Shale sale, which reduced overall production.
Interest expense decreased in the third quarter of 2009 as compared to both the third quarter of 2008 and the second quarter of 2009. The decrease in interest expense between the respective third quarters is due to increased interest capitalization relating mainly to the Company's CO2 pipelines currently under construction, offset in part by higher average debt levels. Interest capitalization was $20.9 million during the third quarter of 2009, $15.5 million during the second quarter of 2009, and $6.7 million during the third quarter of 2008.
Depletion, depreciation and amortization ("DD&A") expenses decreased $2.8 million (5%) in the third quarter of 2009 as compared to DD&A in the prior year third quarter. The DD&A rate on oil and natural gas properties in the third quarter of 2009 was $11.66 per BOE, up from $11.42 per BOE in the second quarter of 2009, but down slightly from the prior year's third quarter level of $11.69 per BOE.
The Company recognized a current income tax benefit in the third quarter of 2009 and a slightly lower tax rate as a result of return to provision revisions and to the Company’s estimated taxes related to its Barnett Shale property sale completed in the second and third quarters of 2009.
In light of the recently announced acquisition of Encore Acquisition Company, the Company has entered into crude oil derivative contracts for the second half of 2010 and calendar 2011 as follows: 5,000 barrels per day during the third and fourth quarters of 2010 with a floor price of $70 per barrel and an average ceiling price of $96.50 per barrel, and 25,000 barrels per day during 2011 with a floor price of $70 per barrel and an average ceiling price of $102.58 per barrel.
As previously announced, as a result of the sale of 60% of the Company’s Barnett Shale properties, the Company lowered its 2009 production guidance to an adjusted full year 2009 average of 47,500 BOE/d, and the Company is reaffirming this annual target. Also previously announced, as a result of a combination of minor factors, the Company reduced its 2009 tertiary production guidance by 1%, from 24,500 Bbls/d to 24,200 Bbls/d, which represents a 25% increase over its 2008 average tertiary production level. The Company's tertiary production has continued to increase early in the fourth quarter and has averaged between 25,500 Bbls/d and 26,000 Bbls/d during the last two weeks of October 2009, on track to meet its revised annual target of 24,200 Bbls/d. The Company anticipates that its average 2010 tertiary production will be approximately 27,000 Bbls/d, a projected 12% increase over 2009 projected levels. The Company plans to give overall total Company production guidance for 2010 at its forthcoming analyst meeting on November 12th and 13th, as well as a 2010 capital budget. Excluding the $201 million Hastings Field acquisition, Denbury's 2009 capital budget remains at approximately $750 million (excluding capitalized interest and assuming $100 million in equipment leases), of which approximately 90% is related to tertiary operations and over two-thirds for CO2 pipelines. Any acquisitions made by the Company would be in addition to these current capital budget amounts. At October 31, 2009, Denbury had $951 million of subordinated debt and approximately $25 million of net bank debt.
Phil Rykhoek, Chief Executive Officer, said, "While our tertiary production is slightly below target this quarter, the tertiary production response during October was strong, putting us on a path to end 2009 with 25% tertiary growth year over year. Our Gulf Coast tertiary program is working well, in-line with projections. We have completed our Delta Pipeline and expect to commence CO2 injection at Delhi Field next week. First tertiary oil production from Delhi is anticipated around mid-year 2010 and we should be able to recognize proved reserves there before year-end 2010. Our Green Pipeline is on schedule for completion to Oyster Bayou Field during the first quarter of 2010 and is expected to be completed to Hastings Field by late next year. We should begin CO2 injections at Oyster Bayou around mid-year 2010 with initial production response expected there in early 2011."
"For 2010, we expect our tertiary production to increase approximately 12% over 2009 projections, a strong increase considering the majority of our capital expenditures were on pipelines during this year. Although the precise numbers are not quite finalized, we expect to increase the spending on our tertiary fields significantly in 2010 and expect to reap the results of that investment in 2011, where tertiary production growth is expected to be toward the upper end of our range. Our goal is to prove-up some of our Jackson Dome probable reserves next year with the first of three planned wells scheduled to commence drilling early in the year. At our analyst meeting next week, we will discuss our 2010 plans in more detail."
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