DENVER, Nov. 3 /PRNewswire-FirstCall/ -- Venoco, Inc. (NYSE: VQ) today reported financial and operational results for the third quarter of 2009. Highlights include the following:
-- Daily production of 20,264 barrels of oil equivalent (BOE) compared to 20,434 BOE for the second quarter of 2009 and 19,560 for the third quarter of 2008 (pro forma for the sale of Hastings). -- Third quarter lease operating expense (LOE) of $13.55 per BOE, up from $12.46 per BOE in the second quarter of 2009, and down 10% from $15.04 per BOE in the third quarter of 2008 (pro forma for the sale of Hastings). -- Nine month LOE of $12.48 per BOE is down 9% compared to $13.68 per BOE through nine months of 2008 (both pro forma for the sale of Hastings).
The company reported a net loss of $5 million for the quarter on oil and gas revenues of $69 million and realized commodity derivative gains of $17 million. Adjusted EBITDA was $48 million in the third quarter of 2009, up 9% from $44 million in the second quarter of 2009 and down 32% from $71 million in the third quarter of 2008. Through nine months of 2009, the company reported Adjusted EBITDA of $145 million.
Adjusted Earnings were $6 million, up from $0.5 million for the second quarter of 2009 and down from $11 million in the third quarter of 2008. Through nine months of 2009, the company reported Adjusted Earnings of $13 million. Adjusted Earnings adjusts the net income (loss) for, among other things, the effects of unrealized commodity and interest derivatives gains and losses. Please see the end of this release for definitions of Adjusted Earnings and Adjusted EBITDA and a reconciliation of those measures to net income (loss).
"It's shaping up to be a nice year for Venoco," commented Tim Marquez, Venoco's Chairman and CEO. "We've paid down debt, extended the maturity of our two largest debt instruments, and barring an unexpected event occurring in the next 60 days, we will meet or beat our annual guidance."
2009 Production
Daily production in the third quarter of 2009 was down slightly from the second quarter of 2009, due in part to a planned shutdown at platform Holly in the South Ellwood field. The company has not scheduled additional downtime at any of its offshore platforms for the remainder of the year. Production in the third quarter of 2009 increased 4% over the third quarter of 2008 (pro forma for the sale of Hastings). Through nine months of 2009, production averaged 20,803 BOE per day, which is up 9% over the same period of 2008 (pro forma for the sale of Hastings).
The following table details the company's daily production by region (BOE/d): Quarter Ended ------------- Full-year 2009 Region 9/30/08 6/30/09 9/30/09 Guidance ------ --------- --------- ---------- --------- Sacramento Basin 9,363 9,988 10,498 Southern California 8,606 8,676 8,207 Texas (and other) 3,980 1,770 1,559 ----- ----- ----- Total 21,949 20,434 20,264 20,250 ====== ====== ====== ====== Total excluding Hastings 19,560 20,434 20,264 ====== ====== ======
2009 Capital Investment
Total capital costs incurred for the company's E&P operations were $28 million for the third quarter, including $15 million for drilling and rework activities, $4 million for facilities, and $9 million for seismic, leasehold, capitalized G&A costs and asset retirement obligations.
The company spent $14 million or 52% of its third quarter capital expenditures in the Sacramento Basin. Through the first nine months of 2009, the company has spud 57 wells and completed 162 workovers / recompletions in the Basin. The company expects to operate the remainder of the year with one drilling rig and four workover / completion rigs in the Basin, and to have drilled over 60 wells and performed approximately 200 workovers / recompletions by the end of the year.
"As planned, our drilling activity in the Basin slowed in the second half of the year. We continue to pursue an aggressive workover and recompletion program in the Basin and plan to maintain that pace through year-end and into 2010," explained Mr. Marquez. "The workover program presents tremendous economics and we're encouraged to see production hold steady despite the slower drilling activity."
The company spent $8 million or 30% of the company's third quarter capital expenditures in Southern California. Drilling began in late September on the first of two West Montalvo wells planned for the second half of the year.
Approximately $2 million or 8% of the company's third quarter capital expenditures were spent in Texas, primarily for the drilling of a well in the South Liberty field that is currently being evaluated.
The company's proved reserves as of June 30th, 2009 were 94.3 MMBOE, up 9%, adjusted for first half production, from year-end 2008 reserves (pro forma for the sale of Hastings). The company realized reserve additions across its three business units during the first 6 months of 2009, with the most significant additions coming as a result of capital spent at West Montalvo and in the Sacramento Basin.
2010 Capital Expenditures
The company's 2010 exploration, exploitation and development capital expenditures are forecast to be $180 million. Approximately $73 million (41%) of the capital budget will be deployed in the Sacramento Basin, $72 million (40%) in Southern California, $9 million (5%) in Texas and the remaining $26 million (14%) going toward exploration activities related to the company's onshore Monterey shale development in Southern California.
"Our focus in 2010 will shift more toward development of our robust inventory of oil projects. Advancing our oil projects in Southern California requires more time for implementation than the natural gas projects we've pursued in the Sacramento Basin in recent years. As a result much of the production growth from next year's capital program will not be realized until after 2010," explained Mr. Marquez. "Our 2010 production guidance is the same as 2009 - 20,250 BOE per day."
Drilling and workover activity during 2010 in the Sacramento Basin will be similar to 2009 activity levels. In Southern California, the company plans to drill three onshore wells at West Montalvo, two wells at the Sockeye field, and perform five workovers and recompletions on wells at South Ellwood. In Texas, the company plans to participate in up to four new development wells and return five wells to production.
"Next year, we plan to perform our first hydraulic fractures of our offshore Monterey shale wells at Sockeye," commented Mr. Marquez. "We believe one of the Monterey shale zones producing at Sockeye is highly analogous to areas we've targeted with our onshore Monterey shale leasing. These wells appear to be ideal candidates for fracturing, but modern fracture technology has never been tested on them."
Venoco expects to drill five wells next year as part of the company's multi-year development plan for the onshore Monterey shale formation that is extensive in Southern California. The company has an onshore acreage position approaching 100,000 net acres with plans to increase that position to around 200,000 net acres by the end of next year.
"As a company we have been operating in Southern California for over 15 years, and have been producing from the offshore Monterey shale for 12 years. We know the formation can produce oil; our task next year is to advance the drilling and completion science that will enhance the productive capacity from the shale," said Mr. Marquez.
Costs and Expenses
Venoco's third quarter 2009 LOE of $13.55 per BOE remained substantially lower than 2008, down 24% from $17.89 per BOE in the third quarter of 2008. Compared to the previous quarter, third quarter LOE was up 9% from $12.46 per BOE. LOE of $12.59 per BOE for the first nine months of 2009 was down 21% from $16.03 per BOE for the same period of 2008. Unit operating costs have been lower compared to 2008 due to the sale of the Hastings Complex (which was one of the company's highest operating cost fields), and realized cost savings from vendors and service providers.
Nine Months Full Quarter Ended Ended Year ------------- ----------- 2009 UNAUDITED (per BOE) 9/30/08 6/30/09 9/30/09 9/30/08 9/30/09 Guidance ------------------- ------- ------- ------- ------- ------- -------- Lease Operating Expenses $17.89 $12.46 $13.55 $16.03 $12.59 $13.50 Production/Property Taxes 3.12 1.27 1.48 2.37 1.55 1.90 DD&A Expense 16.31 11.08 11.79 16.09 11.49 12.00 G&A Expense (1) 4.80 4.36 4.82 4.64 4.34 4.50 Interest Expense (2) 8.62 8.41 7.97 8.69 8.16 9.20 ---- ---- ---- ---- ---- ---- Total $50.74 $37.58 $39.61 $47.82 $38.13 $41.10 ====== ====== ====== ====== ====== ====== (1) Net of amounts capitalized and excluding share-based compensation and MLP write off costs in 2008. See the end of this release for a GAAP reconciliation of G&A per BOE to G&A. (2) Includes interest expense, realized (gain) loss on interest rate swap and amortization of deferred loan costs.
"Our LOE has been consistently below 2008 levels, so we reduced our annual guidance accordingly earlier this year. We expected per unit costs to increase in the third quarter partly due to the downtime offshore, but overall our annual guidance of $13.50 per BOE is still valid," added Mr. Marquez.
Senior Unsecured Notes
In October, the company issued $150 million in aggregate principal amount of senior unsecured notes due 2017. The net proceeds of the issuance, together with additional borrowings under the company's revolving credit facility and cash on hand, were used to satisfy and discharge all of the company's existing secured 8.75% senior notes due 2011. As a result of the refinancing, the maturity of the company's second lien term loan will be automatically extended to May 2014. Subsequent to the refinancing, the company entered into a revised interest rate swap agreement which extended the terms of the existing interest rate swap through the extended maturity date of the term loan.
"Issuance of the new senior unsecured notes enables us to achieve our stated goal of extending the maturity of our second-lien term loan from September 2011 to May 2014," explained Tim Ficker, CFO. "As a result, we have no maturities on any of our term debt for over 4 years and we further benefit from the flexibility of the unsecured structure of the new notes. In addition, amounts borrowed up to $500 million will effectively bear interest at a fixed rate of approximately 7.8% until May 2014."
Earnings Conference Call
Venoco will host a conference call to discuss results today, Tuesday, November 3, 2009 at 11:00 a.m. Eastern time (9 a.m. Mountain). The conference call will be webcast and those wanting to listen may do so by using a link on the Investor Relations page of the company's website at http://www.venocoinc.com. Those wanting to participate in the Q & A portion can call (866) 825-3209 and use conference code 87884704. International participants can call (617) 213-8061 and use the same conference code.
A replay of the conference call will be available for one week by calling (888) 286-8010 or, for international callers, (617) 801-6888, and using passcode 44214984. The replay will also be available on the Venoco website for 30 days.
About the Company
Venoco is an independent energy company primarily engaged in the acquisition, exploitation and development of oil and natural gas properties in California and Texas. Venoco operates three offshore platforms in the Santa Barbara Channel, has non-operated interests in three other platforms, operates four onshore properties in Southern California, has extensive operations in Northern California's Sacramento Basin and operates thirteen fields in Texas.
Forward-looking Statements
Statements made in this news release relating to Venoco's future production, expenses, capital expenditures and development projects, and all other statements except statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These statements are based on assumptions and estimates 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 uncertainties and there is no assurance that these goals and projections can or will be met. Any number of factors could cause actual results to differ materially from those in the forward-looking statements, including, but not limited to, the timing and extent of changes in oil and gas prices, the timing and results of drilling and other development activities, the availability and cost of obtaining drilling equipment and technical personnel, risks associated with the availability of acceptable transportation arrangements and the possibility of unanticipated operational problems, delays in completing production, treatment and transportation facilities, higher than expected production costs and other expenses, and pipeline curtailments by third parties. All forward-looking statements are made only as of the date hereof and the company undertakes no obligation to update any such statement. Further information on risks and uncertainties that may affect the Company's operations and financial performance, and the forward-looking statements made herein, is available in the company's filings with the Securities and Exchange Commission, which are incorporated by this reference as though fully set forth herein.
OIL AND NATURAL GAS PRODUCTION AND PRICES Quarter Ended Quarter Ended ------------- ------------- % % UNAUDITED 6/30/09 9/30/09 Change 9/30/08 9/30/09 Change --------- ------- ------- ------ ------- ------- ------ Production Volume: Oil (MBbls) (1) 848 811 -4% 1,036 811 -22% Natural Gas (MMcf) 6,069 6,320 4% 5,900 6,320 7% ----- ----- --- ----- ----- --- MBOE 1,860 1,864 0% 2,019 1,864 -8% ===== ===== === ===== ===== === Daily Average Production Volume: Oil (Bbls/d) 9,319 8,815 -5% 11,261 8,815 -22% Natural Gas (Mcf/d) 66,692 68,696 3% 64,130 68,696 7% ------ ------ --- ------ ------ --- BOE/d 20,434 20,264 -1% 21,949 20,264 -8% ====== ====== === ====== ====== === Oil Price per Barrel Produced (in dollars): Realized price before hedging $49.67 $58.09 17% $109.08 $58.09 -47% Realized hedging gain (loss) (0.30) (4.66) 1453% (32.08) (4.66) -85% ----- ------ ---- ------ ------ --- Net realized price $49.37 $53.43 8% $77.00 $53.43 -31% ====== ====== === ====== ====== === Natural Gas Price per Mcf (in dollars): Realized price before hedging $3.20 $3.17 -1% $8.92 $3.17 -64% Realized hedging gain (loss) 3.16 3.24 3% (0.15) 3.24 -2260% ---- ---- --- ------ ---- ------ Net realized price $6.36 $6.41 1% $8.77 $6.41 -27% ===== ===== === ===== ===== === Expense per BOE (in dollars): Lease operating expenses (2) $12.46 $13.55 9% $17.89 $13.55 -24% Production and property taxes (2) $1.27 $1.48 17% $3.12 $1.48 -53% Transportation expenses $0.41 $0.61 49% $0.82 $0.61 -26% Depreciation, depletion and amortization $11.08 $11.79 6% $16.31 $11.79 -28% General and administrative (3) $4.60 $5.15 12% $5.07 $5.15 2% Interest expense $5.26 $5.00 -5% $6.59 $5.00 -24% Nine Months Ended ----------------- % UNAUDITED 9/30/08 9/30/09 Change --------- ------- ------- ------ Production Volume: Oil (MBbls) (1) 2,995 2,593 -13% Natural Gas (MMcf) 17,110 18,518 8% ------ ------ --- MBOE 5,846 5,679 -3% ===== ===== === Daily Average Production Volume: Oil (Bbls/d) 10,931 9,498 -12% Natural Gas (Mcf/d) 62,445 67,832 9% ------ ------ --- BOE/d 21,339 20,803 -3% ====== ====== === Oil Price per Barrel Produced (in dollars): Realized price before hedging $104.81 $46.80 -55% Realized hedging gain (loss) (29.69) 1.90 -106% ------ ---- ---- Net realized price $75.12 $48.70 -35% ====== ====== === Natural Gas Price per Mcf (in dollars): Realized price before hedging $9.07 $3.59 -60% Realized hedging gain (loss) (0.08) 2.76 -3550% ------ ---- ------ Net realized price $8.99 $6.35 -29% ===== ===== === Expense per BOE (in dollars): Lease operating expenses (2) $16.03 $12.59 -21% Production and property taxes (2) $2.37 $1.55 -35% Transportation expenses $0.74 $0.52 -30% Depreciation, depletion and amortization $16.09 $11.49 -29% General and administrative (3) $5.38 $4.61 -14% Interest expense $7.02 $5.33 -24% (1) Amounts shown are oil production volumes for offshore properties and sales volumes for onshore properties (differences between onshore production and sales volumes are minimal). Revenue accruals are adjusted for actual sales volumes since offshore oil inventories can vary significantly from month to month based on the timing of barge deliveries, oil in tank and pipeline inventories, and oil pipeline sales nominations. (2) Lease operating expense and property and production taxes are combined to comprise oil and natural gas production expenses on the condensed consolidated statements of operations. (3) Net of amounts capitalized.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS Quarter Ended Quarter Ended UNAUDITED ($ in thousands, ------------- ------------- except per share amounts) 6/30/09 9/30/09 9/30/08 9/30/09 ------- ------- ------- ------- REVENUES: Oil and natural gas sales $62,011 $69,284 $158,041 $69,284 Other 803 859 1,112 859 ---- ---- ----- ---- Total revenues 62,814 70,143 159,153 70,143 ------ ------ ------- ------ EXPENSES: Oil and natural gas production 25,539 28,015 42,418 28,015 Transportation expense 764 1,144 1,655 1,144 Depletion, depreciation and amortization 20,608 21,974 32,931 21,974 Accretion of asset retirement obligation 1,388 1,429 1,044 1,429 General and administrative 8,559 9,607 10,235 9,607 ----- ----- ------ ----- Total expenses 56,858 62,169 88,283 62,169 ------ ------ ------ ------ Income from operations 5,956 7,974 70,870 7,974 FINANCING COSTS AND OTHER: Interest expense 9,777 9,327 13,305 9,327 Interest rate derivative realized (gains) losses 5,130 4,781 3,371 4,781 Interest rate derivative unrealized (gains) losses 2,823 10 (626) 10 Amortization of deferred loan costs 738 751 735 751 Loss on extinguishment of debt 582 - - - Commodity derivative realized (gains) losses (16,288) (16,675) 34,095 (16,675) Commodity derivative unrealized (gains) losses and amortization of derivative premiums 66,771 24,252 (337,147) 24,252 ------ ------ -------- ------ Total financing costs and other 69,533 22,446 (286,267) 22,446 ------ ------ -------- ------ Income (loss) before taxes (63,577) (14,472) 357,137 (14,472) Income tax provision (benefit) (4,100) (9,200) 136,200 (9,200) ------ ------ ------- ------ Net income (loss) $(59,477) $(5,272) $220,937 $(5,272) ======== ======= ======== ======= Weighted average common shares outstanding: Basic 50,781 50,826 50,670 50,826 Diluted 50,781 50,826 51,839 50,826 Nine Months Ended UNAUDITED ($ in thousands, except ----------------- per share amounts) 9/30/08 9/30/09 -------------------------------- -------- ------- REVENUES: Oil and natural gas sales $461,838 $188,726 Other 2,812 2,547 ----- ----- Total revenues 464,650 191,273 ------- ------- EXPENSES: Oil and natural gas production 107,565 80,280 Transportation expense 4,334 2,954 Depletion, depreciation and amortization 94,047 65,265 Accretion of asset retirement obligation 3,065 4,174 General and administrative 31,466 26,164 ------ ------ Total expenses 240,477 178,837 ------- ------- Income from operations 224,173 12,436 FINANCING COSTS AND OTHER: Interest expense 41,063 30,282 Interest rate derivative realized (gains) losses 7,095 13,851 Interest rate derivative unrealized (gains) losses (287) (160) Amortization of deferred loan costs 2,623 2,224 Loss on extinguishment of debt - 582 Commodity derivative realized (gains) losses 90,214 (63,748) Commodity derivative unrealized (gains) losses and amortization of derivative premiums 46,153 73,249 ------ ------ Total financing costs and other 186,861 56,280 ------- ------ Income (loss) before taxes 37,312 (43,844) Income tax provision (benefit) 14,400 (4,300) ------ ------ Net income (loss) $22,912 $(39,544) ======= ========= Weighted average common shares outstanding: Basic 50,416 50,770 Diluted 51,641 50,770
CONDENSED CONSOLIDATED BALANCE SHEET INFORMATION UNAUDITED ($ in thousands) 12/31/08 9/30/09 ------------------------ -------- ------- ASSETS Cash and cash equivalents $191 $4,473 Accounts receivable 41,306 30,559 Inventories 12,361 4,886 Prepaid expenses and other current assets 4,314 4,730 Income tax receivable 546 5,462 Commodity derivatives 57,247 29,017 ------ ------ Total current assets 115,965 79,127 Net property, plant and equipment 702,734 604,576 Total other assets 45,555 31,466 ------ ------ TOTAL ASSETS $864,254 $715,169 ======== ======== LIABILITIES AND STOCKHOLDERS' EQUITY Accounts payable and accrued liabilities $75,400 $43,389 Undistributed revenue payable 8,277 7,530 Interest payable 5,325 4,844 Current maturities of long-term debt 2,598 - Commodity and interest derivatives 21,284 36,364 ------ ------ Total current liabilities 112,884 92,127 LONG-TERM DEBT 797,670 689,178 COMMODITY AND INTEREST DERIVATIVES 9,363 15,673 ASSET RETIREMENT OBLIGATIONS 79,504 87,195 ------ ------ Total liabilities 999,421 884,173 Total stockholders' equity (135,167) (169,004) -------- -------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $864,254 $715,169 ======== ========
GAAP RECONCILIATIONS
In addition to net income (loss) determined in accordance with GAAP, we have provided in this release our Adjusted Earnings and Adjusted EBITDA for recent periods. Both Adjusted Earnings and Adjusted EBITDA are non-GAAP financial measures that we use as supplemental measures of our performance.
We define Adjusted Earnings as net income (loss) before the items listed in the Adjusted Earnings reconciliation set forth in the table below. We believe that Adjusted Earnings facilitates comparisons to earnings forecasts prepared by stock analysts and other third parties. Such forecasts generally exclude the effects of items that are difficult to predict or to measure in advance and are not directly related to our ongoing operations.
We define Adjusted EBITDA as net income (loss) before the items listed in the Adjusted EBITDA reconciliation set forth in the table below. Because the use of Adjusted EBITDA facilitates comparisons of our historical operating performance on a more consistent basis, we use this measure for business planning and analysis purposes, in assessing acquisition opportunities and in determining how potential external financing sources are likely to evaluate our business.
We present Adjusted Earnings and Adjusted EBITDA because we consider them to be important supplemental measures of our performance. Neither Adjusted Earnings nor Adjusted EBITDA is a measurement of our financial performance under GAAP and neither should be considered as an alternative to net income (loss), operating income or any other performance measure derived in accordance with GAAP, as an alternative to cash flow from operating activities or as a measure of our liquidity. You should not assume that the Adjusted Earnings or Adjusted EBITDA amounts shown are comparable to similarly named measures disclosed by other companies.
Quarter Ended Nine Months Ended UNAUDITED ($ in ------------- ----------------- thousands) 9/30/08 6/30/09 9/30/09 9/30/08 9/30/09 --------------- ------- ------- ------- ------- ------- Adjusted Earnings Reconciliation Net Income $220,937 $(59,477) $(5,272) $22,912 $(39,544) Plus: Unrealized commodity (gains) losses (338,773) 60,723 18,253 40,998 56,587 Unrealized interest rate derivative (gains) losses (626) 2,823 10 (287) (160) Write-off of MLP offering costs - - - 2,695 - Early Extinguishment of debt - 582 - - 582 Tax effects 129,435 (4,136) (7,276) (16,445) (4,733) ------- ------ ------ ------- ------ Adjusted Earnings $10,973 $515 $5,715 $49,873 $12,732 ======= ==== ====== ======= =======
Quarter Ended Nine Months Ended UNAUDITED ($ in ------------- ----------------- thousands) 9/30/08 6/30/09 9/30/09 9/30/08 9/30/09 ------- ------- ------- ------- ------- Adjusted EBITDA Reconciliations: Net income $220,937 $(59,477) $(5,272) $22,912 $(39,544) Interest expense 13,305 9,777 9,327 41,063 30,282 Interest rate derivative (gains) losses - realized 3,371 5,130 4,781 7,095 13,851 Income taxes 136,200 (4,100) (9,200) 14,400 (4,300) DD&A 32,931 20,608 21,974 94,047 65,265 Amortization of deferred loan costs 735 738 751 2,623 2,224 Loss on extinguishment of debt - 582 - - 582 Share-based payments 710 644 806 2,094 2,000 Amortization of derivative premiums and other comprehensive loss 2,046 6,628 6,608 6,189 18,474 Unrealized commodity derivative (gains) losses (338,773) 60,723 18,253 40,998 56,587 Unrealized interest rate derivative (gains) losses (626) 2,823 10 (287) (160) ----- ----- ----- ----- ----- Adjusted EBITDA $70,836 $44,076 $48,038 $231,134 $145,261 ======= ======= ======= ======== ========
We also provide per BOE G&A expenses excluding costs associated with the terminated MLP offering and non-cash share-based compensation charges. We believe that these non-GAAP measures are useful in that the items excluded do not represent cash expenses directly related to our ongoing operations. These non-GAAP measures should not be viewed as an alternative to per BOE G&A expenses as determined in accordance with GAAP.
UNAUDITED ($ in thousands, Quarter Ended Nine Months Ended except per BOE amounts) ------------- ----------------- G&A per BOE Reconciliation 9/30/08 6/30/09 9/30/09 9/30/08 9/30/09 ------- ------- ------- ------- ------- G&A Expense $10,235 $8,559 $9,607 $31,466 $26,164 Less: Share-based Compensation Expense (550) (454) (616) (1,674) (1,490) MLP Write Off - - - (2,695) - ------ ----- ----- ------ ------ G&A Expense Excluding Share-based Comp / MLP 9,685 8,105 8,991 27,097 24,674 MBOE 2,019 1,860 1,864 5,846 5,679 ----- ----- ----- ----- ----- G&A Expense per BOE Excluding Share-based Comp / MLP $4.80 $4.36 $4.82 $4.64 $4.34 ===== ===== ===== ===== =====
SOURCE Venoco, Inc.