Pacific Energy Resources has announced its first quarter financial and operating results for the quarter ended March 31, 2009.
The Company's net loss from continuing operations was $41.2 million for the first quarter of 2009 compared to a net loss of $88.7 million in the first quarter of 2008. Included in the net loss for the 2009 period was $9.6 million of restructuring expenses and an inventory write down of $3.2 million. Included in the first quarter of 2008 results were the acceleration of expensing of accretion and amortization of deferred financing costs of $48.4 million. Net loss from continuing operations for the fourth quarter of 2008 was $185.1 million, including impairment charges of $131.4 million.
Adding the results of discontinued operations in the prior quarters resulted in a net loss of $88.2 million for the quarter ended March 31, 2008 and $185.3 million for the quarter ended December 31, 2008.
The net loss for the quarter ended March 31, 2009 was adversely affected by low oil prices, reduced production and sales volumes in the Company's Alaskan operations, restructuring costs and high interest expense.
Oil and gas production revenue was $20.5 million before hedging income for the first quarter of 2009, down 61.1% from the year ago quarter due to a 7.8% decrease in sales volumes and a 60.1% decrease in realized price of oil before hedging gains (losses).
Despite the increase in volume resulting from Platform Eureka partially returning to production in April 2008, the decline in oil sales was due to a 44.8% decrease in Alaska sales, attributable to mechanical issues and timing of oil sales.
Production volumes were down 8.0% from the quarter ended December 31, 2008, due to Alaskan mechanical problems. Sales volumes were off 22.9% due to lower production. The Company estimates that 1,100 boe/d are currently down in its operated assets in Alaska due to mechanical failures at four wells with an estimated cost of $9 million to return the wells to producing status. These could be repaired during the summer timeframe, contingent on additional funding.
Realized prices before hedging were $37.01 per barrel of oil in the first quarter of 2009, down 27.9% in the first quarter of 2009 compared to the fourth quarter of 2008 and down 60.1% from the first quarter of 2008.
The realized gain on derivatives was $3.0 million in the first quarter of 2009 compared to $2.2 million in the fourth quarter of 2008 and a loss of $10.5 million in the first quarter of 2008. Adding the realized price included in oil and gas production revenues above with the hedging gain or loss, resulted in average prices realized after hedging gains (losses) of $42.89 per boe for the first quarter of 2009, compared to $54.63 per boe in the fourth quarter of 2008 and $74.99 per boe in the year ago period.
Royalty expense of $2.6 million for the first quarter of 2009 decreased 74.2% and 63.2% from the first and fourth quarters of 2008, respectively, as a result of significantly lower oil prices and lower production. Royalty expense is a function of oil and gas prices, production and royalty rates. With lower oil prices, the Company benefited from a lower royalty rate at the Beta Unit. In addition, the first quarter of 2009 benefited from a $1.4 million credit from prior periods to correct certain royalties in Alaska. However, 2
Lease operating expenses ("LOE") decreased 9.8% to $38.26 per boe, compared to the first quarter of 2008, due to the increased production from the Beta Unit's Platform Eureka which more than offset lower production in Alaska. Beta's lease operating expenses declined 59.7% to $16.48 per boe from the year ago period, while Alaska's lease operating expenses increased 44.4% to $62.26 per boe due to the 24.9% decline in production from the year ago period.
Compared to the fourth quarter of 2008, lease operating expenses decreased 4.6% to $38.26 per boe, with the Beta Unit's decrease of 31.8% to $16.48 per boe more than offsetting Alaska’s 13.5% increase to $62.26 per barrel.
General and administrative expense of $4.1 million in the first quarter of 2009 was down from the year ago period by 2.2% and from the fourth quarter of 2008 by 29.5%. The fourth quarter of 2008 included $2.5 million of legal and other costs associated with the forbearance agreement. The restructuring costs for the first quarter of 2009 are reported separately in reorganization expenses.
Reorganization expense of $9.6 million in the first quarter of 2009 includes $4.1 million of legal costs, restructuring advisory fees and investment banking costs associated with our chapter 11 filing and asset sales processes. In addition, this expense includes $5.4 million of interest-related expenses consisting of $1.6 million of accelerated accretion of discount for the senior subordinated accreting note and loan from a stockholder, and $3.8 million for make-whole interest on repayment of the Beta senior secured facility with proceeds of debtor-in-possession financing.
For the quarter ended March 31, 2009, compared to the first quarter of 2008 (for continuing operations):
Lease operating expenses per boe for the quarter ended March 31, 2009 decreased on a company-wide basis by 9.8% to $38.26, with Beta lease operating expenses decreasing by 59.7% to $16.48 per boe.
Beta Field, California
The Company returned three additional wells to production at the Beta Unit in late March and April 2009 with recent production levels peaking on certain days above 4,000 barrels per day. The Company made progress on its cost cutting initiatives in the first quarter of 2009 for its California and Alaskan operations, and in corporate costs (before considering the added costs of reorganization).
Including both Platforms Eureka and Ellen, total Beta Field production was 3,415 boe/d for the first quarter. The first quarter production level is up 88.3% from the first quarter of 2008 and was flat from the fourth quarter of 2008. The production increase is attributable to returning Platform Eureka to production in April 2008 and returning additional wells on Platform Eureka to production subsequently. LOE for the Beta Field was $16.48/boe for the first quarter of 2009. First quarter 2009 LOE decreased 31.8% from the fourth quarter of 2008 and 59.7% from the first quarter of 2008, as a result of the production increases. Capital spending for the first quarter 2009 was $1.4 million.
Cook Inlet, Alaska
Lower production levels were caused by higher than average mechanical problems during the winter months which resulted in higher unit costs. Furthermore, as a result of volcanic activity at Mt. Redoubt interrupting normal operations at the Company’s 50%-owned Cook Inlet Pipe Line Company ("CIPL") (which provides pipeline and terminaling services), Chevron was forced to shut in production on jointly-owned properties in early April 2009. The Company's 100% owned and operated properties have 3 sufficient storage to allow production to continue until the end of June 2009. Chevron operates CIPL and is evaluating opportunities to resume transportation of oil to market.
Production in Alaska was 3,099 boe/d for the first quarter of 2009. The first quarter production level is down 15.8% from the fourth quarter of 2008 and 24.9% from the first quarter of 2008. The decline is due to some mechanical pump failures. The failures are considered normal wear and tear and certain of the failures may be repaired in the summer season dependent on volcanic activity limitations; others for operated properties are also dependent on additional funding. LOE for the Alaska properties was $62.26/boe for the first quarter of 2009. First quarter 2009 LOE increased 13.5% from the fourth quarter of 2008 and 44.4% from the first quarter of 2008. The increase is due to the decline in production and increased maintenance projects at the properties operated by Chevron.
Capital spending for the first quarter of 2009 was $3.6 million, including $3.4 million on the Chevron-operated properties which amount was not currently funded by the Company. The Company estimates that $9 million of capital will be required to return the down wells at its operated Alaskan assets to producing status representing an expected gain of approximately 1,100 boe/d. This could be achieved during the summer timeframe, contingent on receiving additional funding.
As previously announced, on March 9, 2009, the Company and its wholly-owned subsidiaries filed with the Delaware Bankruptcy Court voluntary petitions for reorganization under Chapter 11. The Company entered into a Debtor-In-Possession credit facility ("DIP Financing") with its secured lenders, which provides $44.0 million in new funding, $9.6 million of which was approved under an interim order, with the balance subject to a final hearing scheduled for May 21, 2009.
In addition to obtaining bankruptcy protection in the U.S., the Company obtained protection in Canada under the Companies' Creditors Arrangement Act ("CCAA") on March 12, 2009.
The Company and its secured lenders continue to evaluate options for both operated and non-operated Alaskan properties, given their ongoing cash losses. Our DIP Financing contains only limited funding both in dollars and duration. No capital is being provided to repair certain operated wells. Options going forward include an extension of DIP funding of cash losses on operated properties (if the lenders agree), sale of some or all of the properties, and restructuring of the Company through the Chapter 11 process to allow sufficient working capital to repair certain wells to get to cash breakeven.
The Company is currently marketing for sale both its asset groups in California and Alaska. In addition, the Company is pursuing the alternative of a significant equity infusion. There is no assurance that any of these alternatives will realize sufficient proceeds to repay the Company's secured lenders and pre-petition unsecured creditors in full, nor is there assurance the Company will recover the carrying value of its assets.
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