Venoco, Inc. (NYSE:VQ) today reported financial and operating results for the third quarter of 2007. The company reported net income of $0.5 million in the period, which was affected by unrealized mark-to-market commodity derivative losses (non-cash) of $8.6 million ($5.2 million after-tax) and unrealized mark-to-market interest rate derivative losses (non-cash) of $8.3 million ($5.0 million after-tax). Without the effects of these items, after-tax, adjusted net income was $10.7 million for the period. Venoco's Adjusted EBITDA for the quarter reached a company high of $62.1 million, up 8.6% from the second quarter and up 70% from the third quarter of 2006. Please see the end of this release for both a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income, the most comparable GAAP financial measure.
Venoco's production for the third quarter of 2007 was 20,701 barrels of oil equivalent per day (BOE/d), a 22% increase over the third quarter of 2006. Third quarter production was a company-high of 1.90 million barrels of oil equivalent (BOE), up more than 100,000 BOE over the second quarter of 2007 - a 5.5% increase.
"We are pleased to see production continuing to increase this quarter, and to see the continued growth in Adjusted EBITDA," said Tim Marquez, Chairman and Chief Executive Officer.
In Coastal California, Venoco continues to focus on development activities in the West Montalvo field. The company drilled and completed a well from an onshore pad in the field to an offshore location. The well confirmed that the field boundary extends further offshore. Venoco continues to test and evaluate various zones in the well. The company is also pursuing a number of field performance improvement projects that include reactivating injection wells, expanding fluid processing capacity, returning idle wells to production, and working over existing wells.
On platform Grace in the Santa Clara field, Venoco has drilled and completed its first well, which will return the field to production after being idle for nearly a decade. The drilling rig has been moved onto the second well, which is expected to be spud shortly. First production from the field is expected in November.
In the South Ellwood field, the permitting process continues for the company's full-field development project, which includes an extension of an existing lease from the State of California. The draft Environmental Impact Report is expected by year end with project startup anticipated in 2009.
Activity levels remain high in Texas in both the Hastings complex and in the nearby Manvel field, which Venoco acquired earlier this year. Fluid processing capacity in the Hastings complex has increased from approximately 150,000 barrels per day (bpd) at the time of acquisition to about 300,000 bpd currently with a target of 500,000 bpd by year end. This expanded capacity will allow additional idle wells to be returned to production. The company is applying experience gained from operating in Hastings to design and execute its recompletion and workover plan for the Manvel field.
In the Sacramento Basin the company continued its active drilling and workover program. For the quarter, Venoco spud 33 wells for a nine-month total of 101 and worked-over 29 wells bringing the nine-month total to 71. The company is ahead of drilling projections and expects to drill more than 120 new wells and to recomplete at least 100 wells in the basin by year end. The company has recently initiated a hydraulic fracturing program in the basin. Early results are very encouraging and the frac program is expected to continue throughout 2008.
"Wells in the Sacramento Basin have historically utilized conventional cased and perforated completions. With more than 300 active producers and more than 500 wellbores in our Sac Basin fields, the upside potential from fracturing could be significant," said Mr. Marquez.
Venoco's lease acquisition efforts in the Northern Sacramento Basin continue, with the company acquiring approximately 6,500 net acres in the third quarter for a company total of approximately 187,000 net acres (235,000 gross).
2007 Capital Budget
"For the full year 2007, we now expect our capital expenditures to be around $320 million, up from our earlier estimate of $270 million," said Mr. Marquez. "This is largely due to drilling more wells than we originally planned in the Sacramento Basin, ramped-up activity in our West Montalvo field -- including the drilling of the F-2 well offshore -- and higher than expected capital expenditures associated with increasing our total fluid processing capacity in the Hastings complex. We are continuing full speed on all of these projects and remain confident in their ultimate value creation," he added.
2007 Production Expenses and General & Administrative Costs
Production expenses averaged $14.90 per BOE in the third quarter of 2007 compared to $14.53 per BOE in the second quarter of 2007. Third quarter 2007 production expenses reflect a full quarter of West Montalvo and Manvel operations, where expenses increased as remedial efforts accelerated in both fields. These efforts, coupled with a production curtailment at West Montalvo for facility vessel inspections and repairs, resulted in an increase in production expenses per BOE. The company expects production expenses to decrease on a per BOE basis in 2008 as a result of reduced remedial activities in the Hastings complex and as it realizes production volume increases in the Sacramento Basin, the Santa Clara field (platform Grace), the Hastings complex, as well as in the West Montalvo and Manvel fields.
General and administrative expenses were $3.97 per BOE for the first nine months of 2007 excluding charges under SFAS 123R of $0.70 per BOE. Increased G&A expenses in the third quarter of 2007 were offset by production growth. Excluding SFAS 123R charges, the company expects G&A expenses in 2008 to be similar to full year 2007 on a per BOE basis.
Conference Call and Webcast
The company will host a conference call on Monday, November 12, 2007 at 10:00 a.m. Mountain (12:00 p.m. Eastern) to discuss its third quarter 2007 results. The 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 (800) 659-2037 and use conference code 31033740. International participants can call (617) 614-2713 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 70987480. A replay will also be available on the Venoco website for 30 days.
The company will file a quarterly report on Form 10-Q for the period ended Sept 30, 2007. Interested parties may access the Form 10-Q and the company's other SEC filings through the company's website. Additionally, shareholders may receive a hard copy of the company's complete Form 10-Q free of charge. Requests can be made via the Company's website, via email sent to email@example.com by calling the corporate office at (303) 626-8300.
About the Company
Venoco is an independent energy company engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties in California and Texas. It has headquarters in Denver, Colorado and regional offices in Carpinteria, California and Houston, Texas. Venoco operates three offshore platforms in the Santa Barbara Channel, has non-operated interests in three other platforms, operates three onshore properties in Southern California, has extensive operations in Northern California's Sacramento Basin and operates eighteen fields in Texas.
Statements made in this news release relating to Venoco's future production, reserves, capital expenditures, development projects, production and G&A expenses, and all other statements other than 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 activity, 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. Costs anticipated on a per BOE basis are a function of total anticipated production volumes, changes to which can adversely affect the anticipated costs per barrel. 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 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.
This release is available on our website at http://www.venocoinc.com/.
OIL AND NATURAL GAS PRODUCTION AND PRICES
Quarter Ended Quarter Ended Year to Date
6/30/07 9/30/07 9/30/07
Oil (MBbls) 1,006 1,071 2,960
Natural Gas (MMcf) 4,681 5,001 13,926
MBOE 1,786 1,905 5,281
Daily Average Production Volume:
Oil (Bbls/d) 11,055 11,641 10,842
Natural Gas (Mcf/d) 51,440 54,359 51,011
BOE/d 19,628 20,701 19,344
Oil Price per Barrel Produced (in
Realized price before hedging $56.37 $66.73 $58.00
Realized hedging gain (loss) (0.10) (2.91) (0.99)
Net realized price $56.27 $63.82 $57.01
Natural Gas Price per Mcf (in
Realized price before hedging $6.96 $5.71 $6.56
Realized hedging gain (loss) (0.01) 0.73 0.25
Net realized price $6.95 $6.44 $6.81
Average Sale Price per BOE (1) $48.42 $50.90 $48.44
Expense per BOE:
Production expenses (2) $14.53 $14.90 $15.04
Transportation expenses 0.79 0.60 0.84
Depreciation, depletion and
amortization 13.19 13.32 13.17
General and administrative 4.05 4.00 4.67
(1) Average Sale Price is based upon oil and natural gas sales, net of inventory changes, realized commodity derivative losses and amortization of derivative premiums, divided by sales volumes.
(2) Production expenses are comprised of oil and natural gas production expenses and production taxes.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
UNAUDITED ($ in thousands)
Quarter Ended Quarter Ended Year to Date
6/30/07 9/30/07 9/30/07
Oil and natural gas sales 90,507 97,274 261,420
Commodity derivative gains (losses) (8,431) (11,289) (38,434)
Other 752 1,014 2,579
Total revenues 82,828 86,999 225,565
Oil and natural gas production 25,946 28,386 79,419
Transportation expense 1,407 1,141 4,425
Depletion, depreciation and
amortization 23,556 25,379 69,534
Accretion of asset retirement
obligation 844 895 2,512
General and administrative 7,238 7,625 24,658
Total expenses 58,991 63,426 180,548
Income from operations 23,837 23,573 45,017
Interest expense, net 16,379 15,496 44,653
Amortization of deferred loan costs 985 981 3,211
Change in fair value of derivative
instruments (367) 8,315 8,497
Loss on extinguishment of debt 12,063 - 12,063
Total financing costs 29,060 24,792 68,424
Income (loss) before taxes (5,223) (1,219) (23,407)
Income tax provision (benefit) (2,100) (1,700) (10,400)
Net income (loss) $(3,123) $481 $(13,007)
[DECEMBER 31, 2006 AND SEPTEMBER 30, 2007]
CONDENSED CONSOLIDATED BALANCE SHEET INFORMATION
UNAUDITED ($ in thousands)
Cash and cash equivalents $8,364 $818
Accounts receivable 48,042 61,917
Inventories 3,211 3,099
Prepaid expenses and other current
assets 7,226 6,293
Income tax receivable 8,098 5,814
Deferred income taxes 879 4,220
Commodity derivatives 10,348 8,182
Total current assets 86,168 90,343
PROPERTY, PLANT AND EQUIPMENT, AT COST:
Oil and gas properties 881,570 1,248,798
Drilling equipment 13,731 14,457
Other property and equipment 12,380 16,427
Total property, plant and equipment 907,681 1,279,682
Accumulated depletion, depreciation
and amortization (133,428) (202,899)
Net property, plant and equipment 774,253 1,076,783
Total other assets 32,772 23,078
TOTAL ASSETS $893,193 $1,190,204
LIABILITIES AND STOCKHOLDERS' EQUITY
Accounts payable and accrued liabilities $53,406 $71,158
Undistributed revenue payable 15,596 17,685
Accrued interest 5,295 6,860
Deferred income taxes - -
Current maturities of long-term debt 3,557 2,121
Commodity derivatives 8,907 26,829
Total current liabilities 86,761 124,653
LONG-TERM DEBT 529,616 660,210
DEFERRED INCOME TAXES 40,424 28,437
COMMODITY DERIVATIVES 7,092 30,672
ASSET RETIREMENT OBLIGATIONS 38,984 44,478
OTHER LONG TERM LIABILITIES - -
Total liabilities 702,877 888,450
Total stockholders' equity 190,316 301,754
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $893,193 $1,190,204
In addition to net income determined in accordance with GAAP, we have provided net income adjusted for certain items, a non-GAAP financial measure, which 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. A reconciliation between GAAP net income and net income adjusted for certain items is provided in the paragraph on page one of this release in which the non-GAAP measure is presented. Net income excluding the effects of certain items should not be considered a substitute for net income as reported in accordance with GAAP.
We use Adjusted EBITDA, as defined below, as a supplemental measure of our performance that is not required by, or presented in accordance with, GAAP. We define Adjusted EBITDA as net income (loss) before (i) net interest expense, (ii) loss on extinguishment of debt, (iii) income tax provision (benefit), (iv) depreciation, depletion and amortization, (v) amortization of deferred loan costs, (vi) the cumulative effect of change in accounting principle, (vii) pre-tax unrealized gains and losses on derivative instruments, (viii) non-cash expenses relating to the amortization of derivative premiums and (ix) non-cash expenses relating to share-based payments under FAS 123R. We present Adjusted EBITDA because we consider it to be an important supplemental measure of our performance. 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.
Adjusted EBITDA is not a measurement of our financial performance under GAAP and should not 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 EBITDA amounts shown are comparable to Adjusted EBITDA or similarly named measures disclosed by other companies. In evaluating Adjusted EBITDA, you should be aware that it excludes expenses that we will incur in the future on a recurring basis. We compensate for these limitations by relying primarily on our GAAP results and using Adjusted EBITDA only on a supplemental basis.
UNAUDITED ($ in thousands)
Quarter Quarter Quarter Nine Months
Ended Ended Ended Ended
9/30/06 6/30/07 9/30/07 9/30/07
Adjusted EBITDA Reconciliations:
Net income $16,239 $(3,123) $481 $(13,007)
Plus: Financing costs 17,770 29,060 24,792 68,424
Income taxes 10,500 (2,100) (1,700) (10,400)
and amortization 18,350 23,556 25,379 69,534
Plus: Pre-tax share-based
payments 536 1,460 1,280 3,880
Amortization of derivative
premiums 1,547 2,419 3,200 7,517
Pre-tax unrealized commodity
derivative losses (28,390) 5,861 8,620 31,471
Adjusted EBITDA $36,552 $57,133 $62,052 $157,419