VENTURA, Calif., Feb. 27 /PRNewswire/ -- The Ventura Film Festival, which
was started in 2004 by Jordan Older and his father, has recently concluded its
first event of 2009 at the Majestic Ventura Theater in Ventura, California
with the Ventura Film Festival "Fun Day" on February 16, 2009 at 2pm.
The Ventura Film Festival "Fun Day" featured Ventura hometown hero and
independent film maker Dylan O'Neil and his controversial and sometimes
horrific film "Otis N'Dwayne" as well as Dylan O'Neil's Star Wars short titled
"Trip To The Darkside" and Ric Rew with his video documentary of the stage
play "Quadrophenia" about the rock band "The Who." Also present was Ventura
Film Festival board member, Ventura High School graduate, and Hollywood heavy-
hitter and Fox Film/DVD executive, Dustin Dean.
The Ventura Film Festival is a combination online and traditional film
festival requiring all submissions to be uploaded online and submitted via
traditional means. The Ventura Film Festival is in progress to becoming a non-
profit organization and is a "green" organization that has maintained that one
of its main goals is to give a large part of any proceeds to forest and ocean
preservation efforts. The Ventura Film Festival features independent films
from around the world and from local film makers focusing on environmental
issues such as forest and ocean preservation, humanitarian issues, surf,
skate, extreme sports, martial arts, and music films.
The long standing Ventura Film Festival has received threats of legal
action from attorney Sandy Lipkin and the Bell Arts Factory/Lorenzo DeStefano,
claiming "tortious interference" and outlining plans to take over the rights
to the Ventura Film Festival name and trademark despite having registered
their name 5 years after the start of the Ventura Film Festival and have not
yet put on a film festival event.
Ventura Film Festival founder met with Ventura County Assistant Clerk and
Recorder, James Becker and his staff on February 25th 2009 and was shown legal
code and told that the Bell Arts Factory and Hawaiian film maker Lorenzo
DeStefano have acted unlawfully by attempting to register a knowingly
similar and confusing fictitious business name from the Ventura Film Festival,
and that, unfortunately, the only way to proceed will be via a law suit. The
Ventura Film Festival sent a cease and desist letter to the conflicting group,
who uses the domain "venturafilmfest.com," in December 2008.
HOUSTON, Feb. 27 /PRNewswire-FirstCall/ -- Mariner Energy, Inc. (NYSE: ME) today reported full-year 2008 results, which included the following:
Year-over-year net production increased 18% to 118.4 billion cubic feet equivalent (Bcfe)
217% reserve replacement rate from all sources
Year-end estimated proved reserves up 17% to 973.9 Bcfe
Net loss for the year of $388.7 million ($4.44 per share). Adjusted net income, which excludes a non-recurring, non-cash gain and non-cash charges, was $284.1 million or $3.25 per share (see reconciliation of this non-GAAP measure below).
Operating cash flow was $885.9 million for the full 2008 fiscal year, an increase of 42% from 2007 (see reconciliation of this non-GAAP measure below).
Commenting on Mariner's 2008 results, Scott D. Josey, Mariner's Chairman, Chief Executive Officer and President, said: "Despite plummeting commodity prices, hurricanes, and the turmoil in the financial markets, Mariner posted another record year. Our capital program was very successful in 2008, with quality acquisitions, an 80% success rate offshore, and 100% success onshore. While non-cash impairments necessitated by low year-end commodity and stock prices negatively affected our earnings, our fundamentals are good.
"Economic circumstances continue to present challenges in the year ahead, but we are off to a good start in 2009. Our capital program should not only allow us to live within our cash flows, but also to increase production and pay down debt while exposing our shareholders to upside potential. We intend to carefully monitor changing industry and general economic conditions and can quickly adjust our capital program as circumstances warrant."
NON-CASH GAIN AND CHARGES
The company's results for 2008 reflect a non-recurring, non-cash gain of $46.5 million for the release as of year-end of suspended revenue associated with a disputed MMS royalty liability. Based on low commodity prices at year-end, Mariner recorded a full cost ceiling test impairment of its proved oil and gas properties in the amount of $575.6 million. The company also recorded other impairments, including goodwill, of $310.9 million for the year. Additionally, Mariner recognized a non-cash charge of $36.0 million for a contingent insurance premium. These items are detailed below in the reconciliation of adjusted net income, a non-GAAP measure.
FOURTH QUARTER 2008 RESULTS
For the three-month period ended December 31, 2008, Mariner reported a net loss of $648.9 million, or $7.41 per basic and fully-diluted share, which reflects the non-cash gain and charges cited above. This compares with net income of $50.2 million and basic and fully-diluted earnings per share of $0.59 and $0.58, respectively, for the same three-month period in the prior year. Adjusted net income, which excludes the non-cash gain and charges, was $14.5 million for fourth quarter 2008, or $0.17 per basic and fully-diluted share (see reconciliation of this non-GAAP measure below). The lower year-over-year results are due primarily to decreased production volumes as a result of Hurricanes Ike and Gustav and lower commodity prices.
Net production for fourth quarter 2008 was 23.5 Bcfe, compared with 27.1 Bcfe for fourth quarter 2007. Total natural gas net production for fourth quarter 2008 was 16.1 billion cubic feet (Bcf), compared with 18.4 Bcf for the same period in the prior year. Total net oil production for fourth quarter 2008 was 1.0 million barrels (MMBbls), compared with 1.1 MMBbls for the same period in 2007. Natural gas liquids (NGL) net production for fourth quarter 2008 was 0.3 MMBbls, compared with 0.3 MMBbls for fourth quarter 2007.
For fourth quarter 2008, Mariner's average realized natural gas price was $7.44 per thousand cubic feet (Mcf) compared with $8.07 per Mcf for the same period in 2007. Mariner's average realized oil price was $65.29 per barrel (Bbl) for fourth quarter 2008, compared with $79.64 per Bbl for fourth quarter 2007. The average realized NGL price was $26.63 per Bbl for fourth quarter 2008, compared with $55.32 per Bbl for the same period in 2007. Average realized prices reflect settlements during the period under Mariner's hedging program.
FULL-YEAR 2008 RESULTS
For the 12-month period ended December 31, 2008, Mariner reported a net loss of $388.7 million, which equates to a loss of $4.44 per basic and fully-diluted share. For the same period in the prior year, Mariner reported net income of $143.9 million, or $1.68 per basic share/$1.67 per fully-diluted share. Adjusted net income, which excludes the non-cash gain and charges noted above, was $284.1 million or $3.25 per share (see reconciliation of this non-GAAP measure below).
For the full-year 2008, Mariner reported net production of 118.4 Bcfe, up from 100.3 Bcfe reported in 2007. Total natural gas net production during 2008 was 79.8 Bcf at an averaged realized price of $9.31 per Mcf, compared with 67.8 Bcf for 2007 at an average realized price of $7.88 per Mcf. Total net oil production for 2008 was 4.9 MMBbls at an average realized price of $86.02 per Bbl, compared to 4.2 MMBbls during 2007 at an average realized price of $67.50 per Bbl. Total NGL net production during 2008 was 1.6 MMBbls at an average realized price of $55.02, compared to 1.2 MMBbls at an average realized price of $45.16 per Bbl for the prior year. Average realized prices reflect settlements during the period under Mariner's hedging program.
Operating cash flow was $885.9 million for the full 2008 fiscal year, an increase of 42% from $622.6 million in 2007. (See reconciliation of this non-GAAP measure below.)
Mariner's capital expenditures for the fourth quarter and full-year 2008 are summarized in the table below.
Fourth Full-
Quarter Year
2008 2008
---- ----
(In Millions)
Exploration $43.8 $423.3
Development
Gulf of Mexico - Deepwater $97.5 $280.8
Gulf of Mexico - Shelf 42.6 198.8
Permian Basin 30.3 108.8
---- -----
Acquisitions $48.2 $302.6
Corporate expenditures and other $14.7 $66.7
Total Capital Expenditures $277.1 $1,381.0
YEAR-END 2008 ESTIMATED RESERVES
Mariner today also announced results of an independent, fully-engineered analysis of the company's proved and probable reserves prepared by the Ryder Scott Company, L.P. The report utilizes hydrocarbon prices in effect at December 31, 2008 of $44.61 per barrel for oil and $5.71 per million British Thermal Units for gas in accordance with Securities & Exchange Commission (SEC) requirements.
Highlights from the report and year-end operations review include:
Estimated proved reserves increased 17% to a record 973.9 Bcfe.
Mariner achieved a reserve replacement rate of 217% from all sources at an all-in reserve replacement cost, net of hurricane expenditures, of $4.96 per thousand cubic feet equivalent (Mcfe), excluding probable and possible reserves.
Including probable reserves estimated by Ryder Scott at 285 Bcfe, Mariner's estimated proved and probable reserve base exceeds 1.25 trillion cubic feet of natural gas equivalent.
70% of Mariner's estimated proved reserves are proved developed.
Commenting on Mariner's year-end reserves, Mr. Josey said: "Mariner's proved reserves increased across each of its core areas during 2008. Although we achieved significant reserve growth, delays in the completion of several offshore projects due to the effects of Hurricanes Ike and Gustav reduced our reserve growth. As a result, we booked a relatively small amount of proved reserves on these projects despite substantial capital outlays for them. In 2009, we expect to add significant incremental proved reserves attributable to these projects when they are completed or come online. The company wrote down 29 Bcfe of proved reserves due to low year-end commodity prices, but we expect these reserves to be restored if drilling and completion costs adjust to the current commodity price environment."
The following table sets forth certain information with respect to our estimated proved reserves by geographic area as of December 31, 2008. Reserve volumes and values were determined under the method prescribed by the SEC, which requires the application of period-end prices and costs held constant throughout the projected reserve life. Proved reserve estimates do not include any value for probable or possible reserves, nor do they include any value for undeveloped acreage. The proved reserve estimates represent Mariner's net revenue interest in its properties.
Estimated Proved Reserve
Quantities
Natural Oil NGLs Total % of Total
Gas (MMBbls) (MMBbls) (Bcfe) Estimated
(Bcf) Proved
Reserves
Geographic Area
---------------
Permian Basin 136.2 27.3 22.7 436.6 44.8
Gulf of Mexico - Deepwater * 165.9 5.4 0.1 198.7 20.4
Gulf of Mexico - Shelf 255.9 11.1 2.7 338.6 34.8
Total 558.0 43.8 25.5 973.9 100.0
Proved developed reserves 420.9 25.9 16.9 677.7 69.6
* Depths greater than 1,300 feet (the approximate depth of deepwater
designation by the Minerals Management Service of the United States
Department of the Interior)
OPERATIONAL UPDATE
Offshore
Mariner was successful in 20 of its 25 offshore wells drilled in 2008. Mariner drilled eight offshore wells in the fourth quarter 2008, seven of which were successful:
Water
Working Depth
Well Name Operator Interest (Ft) Location
--------- -------- --------- ---- --------
De Soto Canyon 48#1
(Dalmatian) Murphy 12.5% 5876 Deepwater
Eugene Island 342 C5ST1 Mariner 50.0% 266 Conventional
Shelf
Main Pass 301 A6 Walter 6.3% 230 Conventional
Oil Shelf
Main Pass 301 A4ST Walter 10.45% 230 Conventional
Oil Shelf
South Timbalier 49#2
(Smoothie) Mariner 100.0% 60 Deep Shelf
Garden Banks 463#1
(Bushwood) Mariner 30.0% 2700 Deepwater
South Marsh Island 150 D1 Mariner 100.0% 230 Conventional
Shelf
Subsequent to the end of 2008, two additional wells were drilled and successful:
Water
Working Depth
Well Name Operator Interest (Ft) Location
--------- -------- --------- ---- --------
Green Canyon 859#1
(Heidelberg) Anadarko 12.5% 5000 Deepwater
South Marsh Island 150 D2 Mariner 100.0% 230 Conventional
Shelf
Onshore
In the fourth quarter of 2008, Mariner drilled 23 wells in the Permian Basin, all of which were successful. As of December 31, 2008, four rigs were drilling on Mariner's Permian Basin properties. The company participated in 122 onshore wells in 2008, all of which were successful.
CONFERENCE CALL TO DISCUSS RESULTS
A conference call has been scheduled for 10:00 a.m. Eastern Time (9:00 a.m. Central Time) on Friday, February 27, 2009, to discuss fiscal 2008 financial and operating results. To participate in the call, please dial (866) 953-6858 at least 10 minutes prior to the scheduled start time. International callers can dial (617) 399-3482. The conference pass code for both numbers is 8750 3087. The call also will be webcast live over the internet and can be accessed through the Investor Relations' Webcasts and Presentations section of Mariner's website at http://www.mariner-energy.com.
A telephonic replay of the call will be available through March 9, 2009 by dialing (888) 286-8010 or (617) 801-6888, pass code 8230 2373. An archive of the webcast will be available shortly after the call on Mariner's website through March 31, 2009.
About Mariner Energy, Inc.
Mariner Energy, Inc. is an independent oil and gas exploration, development and production company headquartered in Houston, Texas, with principal operations in the Permian Basin and the Gulf of Mexico. For more information about Mariner, please visit its website at www.mariner-energy.com.
MARINER ENERGY, INC.
SELECTED OPERATIONAL RESULTS (1)
(Unaudited)
Net Production, Realized Pricing and Operating Costs
Three Months Twelve Months
Ended Ended
December 31, December 31,
2008 2007 2008 2007
---- ---- ---- ----
Net production:
Natural gas (Bcf) 16.1 18.4 79.8 67.8
Oil (MMBbls) 1.0 1.1 4.9 4.2
Natural gas liquids
(MMBbls) 0.3 0.3 1.6 1.2
Total production
(Bcfe) 23.5 27.1 118.4 100.3
Realized prices (net
of hedging):
Natural gas ($/Mcf) $7.44 $8.07 $9.31 $7.88
Oil ($/Bbl) 65.29 79.64 86.02 67.50
Natural gas liquids
($/Bbl) 26.63 55.32 55.02 45.16
Operating costs per
Mcfe:
Lease operating
expense $2.73 $1.42 $1.96 $1.52
Severance and ad
valorem taxes 0.15 0.15 0.15 0.13
Transportation
expense 0.16 0.12 0.13 0.09
General and
administrative
expense 1.03 0.57 0.51 0.42
Depreciation,
depletion and
amortization 3.91 3.71 3.95 3.83
Other expense 0.09 0.02 0.03 0.05
(1) Certain prior year amounts have been reclassified to conform to current year presentation.
Estimated Proved Reserves
As of the As of the
Year Ended Year Ended
December 31, December 31,
2008 2007
Estimated proved natural gas, oil and natural
gas liquids reserves:
Natural gas (Bcf) 558.0 448.4
Oil (MMBbls) 43.8 41.9
Natural gas liquids (MMBbls) 25.5 22.6
Total estimated proved reserves (Bcfe) 973.9 835.8
Total proved developed reserves (Bcfe) 677.7 563.9
MARINER ENERGY, INC.
COMPARATIVE CONSOLIDATED FINANCIAL STATEMENTS OF OPERATIONS (1)
(In thousands, except per share data)
(Unaudited)
Three Months Ended Twelve Months Ended
December 31, December 31,
2008 2007 2008 2007
---- ---- ---- ----
Revenues:
Natural gas sales $119,665 $148,468 $742,370 $534,537
Oil sales 63,721 87,434 419,878 284,405
Natural gas liquids sales 7,136 19,313 85,715 54,192
Other revenues 46,746 (1,620) 52,544 1,631
Total revenues 237,268 253,595 1,300,507 874,765
Cost and Expenses:
Lease operating expense 64,304 38,387 231,645 152,627
Severance and ad valorem
taxes 3,505 4,138 18,191 13,101
Transportation expense 3,708 3,270 14,996 8,794
General and
administrative expense 24,333 15,540 60,613 42,151
Depreciation, depletion
and amortization 92,095 100,530 467,265 384,321
Full cost ceiling test
impairment 575,607 ? 575,607 ?
Goodwill impairment 295,598 ? 295,598 ?
Other property impairment 15,252 ? 15,252 ?
Other miscellaneous
expense 2,087 476 3,052 5,061
Total costs and
expenses 1,076,489 162,341 1,682,219 606,055
OPERATING (LOSS) INCOME (839,221) 91,254 (381,712) 268,710
Interest:
Income 386 406 1,362 1,403
Expense, net of
capitalized amounts (2,757) (14,442) (56,398) (54,665)
Other income/(expense) ? 753 ? 5,811
Income before taxes and
Minority Interest (841,592) 77,971 (436,748) 221,259
Minority Interest Expense ? (1) (188) (1)
Provision for income
taxes 192,672 (27,729) 48,223 (77,324)
NET (LOSS) INCOME $(648,920) $50,241 $(388,713) $143,934
Earnings per share:
Net (loss) income per
share?basic $(7.41) $0.59 $(4.44) $1.68
Net (loss) income per
share?diluted $(7.41) $0.58 $(4.44) $1.67
Weighted average shares
outstanding?basic 87,623 85,745 87,491 85,645
Weighted average shares
outstanding?diluted 87,623 86,277 87,491 86,126
(1) Certain prior year amounts have been reclassified to conform to current year presentation.
MARINER ENERGY, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
(Unaudited)
December 31, December 31,
2008 2007
Current Assets
Cash and cash equivalents $3,251 $18,589
Receivables, net of allowances 219,920 157,774
Insurance receivables 13,123 26,683
Derivative financial instruments 121,929 11,863
Intangible assets 2,353 17,209
Prepaid expenses and other 14,377 10,630
Deferred tax asset ? 6,232
Total current assets 374,953 248,980
Property and equipment, net 2,929,877 2,420,194
Restricted cash ? 5,000
Goodwill ? 295,598
Insurance receivables 22,132 56,924
Derivative financial instruments ? 691
Other Assets, net of amortization 65,831 56,248
TOTAL ASSETS $3,392,793 $3,083,635
Current Liabilities
Accounts payable $3,837 $1,064
Accrued liabilities 107,815 96,936
Accrued capital costs 195,833 159,010
Deferred income tax 23,148 ?
Abandonment liability 82,364 30,985
Accrued interest 12,567 7,726
Derivative financial instruments ? 19,468
Total current liabilities 425,564 315,189
Long-Term Liabilities
Abandonment liability 325,880 191,021
Deferred income tax 319,766 343,948
Derivative financial instruments ? 25,343
Long-term debt 1,170,000 779,000
Other long-term liabilities 31,263 38,115
Total long-term liabilities 1,846,909 1,377,427
Minority Interest ? 1
Stockholders' Equity
Common stock, $.0001 par value;
180,000,000 shares authorized;
88,846,073 shares issued and
outstanding at December 31, 2008;
180,000,000 shares authorized,
87,229,312 shares issued and
outstanding at December 31, 2007 9 9
Additional paid-in capital 1,071,347 1,054,089
Accumulated other comprehensive
income/(loss) 78,181 (22,576)
Accumulated retained (loss) earnings (29,217) 359,496
Total stockholders' equity 1,120,320 1,391,018
TOTAL LIABILITIES AND STOCKHOLDERS'
EQUITY $3,392,793 $3,083,635
MARINER ENERGY, INC.
SELECTED CASH FLOW INFORMATION (1)
(In Thousands)
(Unaudited)
12 Months Ended December 31,
2008 2007
Operating cash flow (2) $885,887 $622,610
Changes in operating assets and
liabilities (23,870) (86,497)
Net cash provided by operating
activities $862,017 $536,113
Net cash used in investing
activities $(1,264,784) $(643,779)
Net cash provided by financing
activities $387,429 $116,676
(Decrease) Increase in cash and
cash equivalents $(15,338) $9,010
(1) Certain prior year amounts have been reclassified to conform to current year presentation.
(2) See below for reconciliation of this non-GAAP measure.
IMPORTANT INFORMATION CONCERNING FORWARD-LOOKING STATEMENTS
AND CERTAIN STATISTICS
This press release includes 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. All statements, other than statements of historical facts, that address activities that Mariner assumes, plans, expects, believes, projects, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. Our forward-looking statements generally are accompanied by words such as "may", "will", "estimate", "project", "predict", "believe", "expect", "anticipate", "potential", "plan", "goal", or other words that convey the uncertainty of future events or outcomes. Forward-looking statements provided in this press release are based on Mariner's current belief based on currently available information as to the outcome and timing of future events and assumptions that Mariner believes are reasonable. Mariner does not undertake to update its guidance, estimates or other forward-looking statements as conditions change or as additional information becomes available. Estimated reserves are related to hydrocarbon prices. Hydrocarbon prices in effect at December 31, 2008 were used in preparation of the reserve estimates provided above as required by SEC guidelines. Actual future prices may vary significantly from the December 31, 2008 prices. Therefore, volumes of reserves actually recovered may differ significantly from such estimates. Mariner cautions that its forward-looking statements are subject to all of the risks and uncertainties normally incident to the exploration for and development, production and sale of oil and natural gas. These risks include, but are not limited to, price volatility or inflation, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating future oil and gas production or reserves, and other risks described in the Annual Report on Form 10-K for the fiscal year ended December 31, 2007, and other documents filed by Mariner with the SEC. Any of these factors could cause Mariner's actual results and plans of Mariner to differ materially from those in the forward-looking statements. Investors are urged to read the Annual Report on Form 10-K for the year ended December 31, 2007 and other documents filed by Mariner with the SEC.
The SEC generally has permitted oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. Mariner uses the terms "probable," "possible" and "non-proved" reserves, reserve "potential" or "upside" or other descriptions of volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC's guidelines may prohibit it from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of actually being realized by Mariner.
This press release does not constitute an offer to sell or a solicitation of an offer to buy any securities of Mariner.
Note on reserve replacement rate: For a calculation of reserve replacement rate, please refer to Mariner's website at www.mariner-energy.com under Investor Information, Financial Reports. Mariner's reserve replacement rates reported above were calculated by dividing total estimated proved reserve changes for the period from all sources, including acquisitions and divestitures, by production for the same period. The method Mariner uses to calculate its reserve replacement rate may differ from methods used by other companies to compute similar measures. As a result, its reserve replacement rate may not be comparable to similar measures provided by other companies.
Note on reserve replacement cost: For a calculation of reserve replacement cost, please refer to Mariner's website at www.mariner-energy.com under Investor Information, Financial Reports. Reserve replacement cost is calculated by dividing development, exploitation, exploration and acquisition capital expenditures, reduced by proceeds of divestitures, for the period by net estimated proved reserve additions for the period from all sources, including acquisitions and divestitures. Our calculation of reserve replacement cost includes costs and reserve additions related to the purchase of proved reserves. The methods we use to calculate our reserve replacement cost may differ significantly from methods used by other companies to compute similar measures. As a result, our reserve replacement cost may not be comparable to similar measures provided by other companies. We believe that providing a measure of reserve replacement cost is useful in evaluating the cost, on a per-Mcfe basis, to add proved reserves. However, this measure is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with generally accepted accounting principles. Due to various factors, including timing differences in the addition of proved reserves and the related costs to develop those reserves, reserve replacement costs do not necessarily reflect precisely the costs associated with particular reserves. As a result of various factors that could materially affect the timing and amounts of future increases in reserves and the timing and amounts of future costs, we cannot assure you that our future reserve replacement costs will not differ materially from those presented.
Reconciliation of Non-GAAP Measure: Adjusted Net Income
Mariner Energy's reported net income and earnings per share for the 2008 fiscal year and fourth quarter include a non-recurring, non-cash gain and non-cash charges. Mariner's management believes that it is common among investment analysts to consider earnings excluding the effects of these items when evaluating the company's operating results. These items and their effects on reported earnings for the full year and fourth quarter 2008 are listed below.
A non-recurring release of suspended revenue of $46.5 million associated with a disputed MMS royalty liability was recorded at December 31, 2008. This resulted in a $30.2 million after-tax gain, which equates to a $0.35 contribution to basic and fully-diluted earnings per share (EPS).
Ceiling test, goodwill and other non-recurring impairments recorded at December 31, 2008 negatively impacted net income for the year by $886.5 million, or $679.6 million after-tax for a $7.77 loss per basic and fully-diluted share.
A non-cash charge of $21.6 million and $36.0 million for a contingent withdrawal premium related to Mariner's participation in the OIL insurance mutual was taken for the fourth quarter 2008 and full-year 2008, respectively, resulting in a $14.0 million and a $23.4 million after-tax charge or a loss per basic and fully-diluted share of $0.16 and $0.27, respectively, for the fourth quarter and full-year 2008.
Excluding the items above, Mariner would have reported earnings for the fourth quarter 2008 of $14.5 million or $0.17 per basic and fully-diluted share. Fiscal 2008's full year net income and basic and diluted EPS would have been $284.1 million and $3.25, respectively. Adjusted net income should not be considered in isolation or as a substitute for net income or another measure of financial performance presented in accordance with GAAP. This is further outlined in the table below with after-tax impact calculated using the statutory rate (which excludes 2007 because there were no material impairments, nonrecurring events or other items in respect of which to adjust net income for the year ended December 31, 2007).
MARINER ENERGY, INC.
RECONCILIATION OF ADJUSTED NET INCOME
(In millions, except per share data)
(Unaudited)
Three Months Ended Twelve Months Ended
December 31, 2008 December 31, 2008
After-Tax EPS (2) After-Tax EPS (2)
Impact (1) Impact (1)
Net loss $(648.9) $(7.41) $(388.7) $(4.44)
Reversal of MMS royalty
liability (30.2) (0.35) (30.2) (0.35)
Impairment charges 679.6 7.76 679.6 7.77
Contingent OIL premium
charges 14.0 0.16 23.4 0.27
Adjusted net income (non-GAAP) $14.5 $0.17 $284.1 $3.25
(1) Calculated using the statutory rate
(2) Denotes basic and fully-diluted earnings per share
Reconciliation of Non-GAAP Measure: Operating Cash Flow
Operating cash flow (OCF) is not a financial or operating measure under generally accepted accounting principles in the United States of America (GAAP). The table below reconciles OCF to related GAAP information. Mariner believes that OCF is a widely accepted financial indicator that provides additional information about its ability to meet its future requirements for debt service, capital expenditures and working capital, but OCF should not be considered in isolation or as a substitute for net income, operating income, net cash provided by operating activities or any other measure of financial performance presented in accordance with GAAP or as a measure of a company's profitability or liquidity.
12 Months Ended
December 31,
2008 2007
---- ----
(In thousands)
(Unaudited)
Net cash provided by operating activities $862,017 $536,113
Less: Changes in operating assets and liabilities 23,870 86,497
Operating cash flow (non-GAAP) $885,887 $622,610
PHOENIX, Feb. 26 /PRNewswire-FirstCall/ -- Republic Services, Inc. (NYSE:
RSG) today reported a net loss for the three months ended December 31, 2008,
of $131.7 million, or $.55 per diluted share, compared to net income of $82.1
million, or $.44 per diluted share, for the same period in 2007. Our 2008
financial results include Allied Waste Industries, Inc. (Allied) from the
effective date of the merger which was December 5, 2008. Revenue for the
three months ended December 31, 2008 was $1,244.4 million compared to $796.0
million for the same period in 2007.
Operating loss for the three months ended December 31, 2008 was $111.6
million compared to operating income of $139.9 million for the same period
last year. During the three months ended December 31, 2008, we recorded
charges totaling $315.5 million for remediation and related costs, asset
impairments, restructuring, landfill and intangible asset amortization
expense, bad debt expense, legal settlement reserves and the synergy incentive
plan.
For the year ended December 31, 2008, net income was $73.8 million, or
$.37 per diluted share, compared to $290.2 million, or $1.51 per diluted
share, for 2007. Revenue for the year ended December 31, 2008 was $3,685.1
million compared to $3,176.2 million during 2007.
Operating income for the year ended December 31, 2008 was $283.2 million
compared to $536.0 million for 2007. During the year ended December 31, 2008,
we recorded charges totaling $383.5 million for remediation and related costs,
asset impairments, restructuring, landfill and intangible asset amortization
expense, bad debt expense, legal settlement reserves and the synergy incentive
plan.
"I am very pleased with our progress to date concerning the integration of
Republic and Allied following the merger that took place on December 5, 2008,"
said James E. O'Connor, Chairman and Chief Executive Officer of Republic
Services. "We have already completed initiatives that provide an annual
benefit of more than $50.0 million in synergies. I remain confident that we
will achieve the estimated $150.0 million in annual run-rate savings by the
end of 2010."
Quarterly Dividend Declared
We also announced that our Board of Directors declared a regular quarterly
dividend of $.19 per share for stockholders of record on April 1, 2009. The
dividend will be paid on April 15, 2009.
Fiscal Year 2009 Outlook
"Despite a weaker economy, we expect 2009 free cash flow, excluding
merger-related payments, to be approximately $650.0 million, which compares
favorably to 2008," said Donald W. Slager, President and Chief Operating
Officer. "Our field organization is adjusting the business for changing
economic conditions while remaining focused on the basic aspects of our
business including safety, customer service, pricing, and achieving strong and
predictable free cash flow."
Our objectives for 2009 remain consistent with previous years and once
again focus on enhancing shareholder value through the generation and
efficient use of free cash flow. We remain committed to implementing a broad-
based pricing initiative across all lines of business to recover increasing
costs and provide an adequate return on invested capital. We anticipate using
free cash flow to pay regular quarterly dividends and reduce debt.
Additionally, we expect to use proceeds from sales of asset divestitures to
reduce debt.
Our guidance is based on current economic conditions and does not assume
any improvement or deterioration in the overall economy in 2009 from that
experienced at the end of 2008.
Specific guidance is as follows:
-- Free Cash Flow: We anticipate 2009 free cash flow, excluding merger-
related payments, of approximately $650.0 million. We define free cash
flow as cash provided by operating activities less purchases of
property and equipment plus proceeds from sales of property and
equipment as presented in our consolidated statement of cash flows.
Additionally, we expect to realize proceeds from sales of asset
divestitures which are not included in free cash flow.
-- Earnings Per Share: We anticipate reported 2009 earnings per diluted
share before the accounting impact of our merger with Allied and
restructuring charges to be in the range of $1.70 to $1.75 per share.
Reported earnings per diluted share are expected to be in the range of
$1.10 to $1.15 per share. As of the effective date of the merger,
Republic recorded significant changes in the carrying values of
Allied's assets, liabilities and debt, as a result of assigning fair
values in purchase accounting. Republic also conformed Allied's
accounting policies to Republic's. Taken together, we estimate that
the impact of these changes will have the effect of lowering 2009
earnings by approximately $.60 per diluted share. This decrease in
2009 earnings consists of the following (approximately):
-- $.17 per diluted share is attributable to higher depreciation,
depletion and amortization,
-- $.18 per diluted share is attributable to non-cash interest expense
for amortizing the discount to fair value on Allied's debt,
-- $.05 per diluted share is for conforming Allied's accounting
policies with ours, and
-- $.20 per diluted share is related to the
integration of our businesses.
-- Revenue: We expect 2009 revenue to increase by approximately 129
percent. This reflects increases of approximately 139 percent
resulting from our merger with Allied and approximately 4 percent for
price increases, which are partially offset by a decline of
approximately 14 percent due to weaker economic conditions (but not a
loss of market share) and divestitures, as shown below:
Increase
(Decrease)
Price 4.0 %
Volume (8.0)
Divestitures (1.5)
Fuel fees (2.5)
Commodities (2.0)
Total change (10.0)%
-- Capital Spending: We anticipate 2009 net capital spending of
approximately $845.0 million.
-- Margins: EBITDA margins for 2009 are anticipated to be approximately
28%, or approximately 29.5% before costs related to integrating our
businesses.
-- Merger Synergies: In 2009, we anticipate realizing $100.0 million in
year-end, run-rate synergies as a result of the merger of Republic
Services and Allied. Our goal for the merger is $150.0 million in
annual run-rate synergies by the end of 2010. The cost to merge our
systems and business units, and thus achieve the $150.0 million
synergies, is projected to be approximately $135.0 million, or $.20 per
diluted share, in 2009, and $55.0 million, or $.08 per diluted share,
in 2010.
About Republic Services, Inc.
Republic Services, Inc. is a leading provider of services in the domestic,
non-hazardous solid waste industry. We provide solid waste collection,
transfer, disposal and recycling services for commercial, industrial,
municipal and residential customers through 400 collection companies in 40
states and Puerto Rico. We also own or operate 242 transfer stations, 213
solid waste landfills and 78 recycling facilities. Republic serves millions of
residential customers under contracts with more than 3,000 municipalities for
waste collection and residential services. For more information, visit the
Republic Services web site at www.republicservices.com.
REPUBLIC SERVICES, INC.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions, except per share amounts)
December 31, December 31,
2008 2007
Assets
Current Assets -
Cash and cash equivalents $68.7 $21.8
Accounts receivable, net of allowance
for doubtful accounts of $65.7
and $14.7, respectively 945.5 298.2
Prepaid expenses and other current assets 174.7 68.5
Deferred tax assets 136.8 25.3
Total Current Assets 1,325.7 413.8
Restricted cash 281.9 165.0
Property and equipment, net 6,738.2 2,164.3
Goodwill and other intangible assets, net 11,085.6 1,582.2
Other assets 490.0 142.5
Total Assets $19,921.4 $4,467.8
Liabilities and Stockholders' Equity
Current Liabilities -
Accounts payable, deferred revenue
and other current liabilities $2,061.8 $626.4
Notes payable and current maturities
of long-term debt 504.0 2.3
Total Current Liabilities 2,565.8 628.7
Long-term debt, net of current maturities 7,198.5 1,565.5
Accrued landfill and environmental
costs, net of current portion 1,197.1 279.2
Other long-term liabilities 1,678.6 690.6
Commitments and Contingencies
Stockholders' Equity -
Preferred stock, par value $.01 per
share; 50.0 shares authorized;
none issued - -
Common stock, par value $.01 per
share; 750.0 shares authorized;
393.4 and 195.7 shares
issued, including shares
held in treasury, respectively 3.9 2.0
Additional paid-in capital 6,260.1 38.7
Retained earnings 1,477.2 1,572.3
Treasury stock, at cost (14.9 and
10.3 shares, respectively) (456.7) (318.3)
Accumulated other comprehensive
income (loss), net of tax (3.1) 9.1
Total Stockholders' Equity 7,281.4 1,303.8
Total Liabilities and Stockholders'
Equity $19,921.4 $4,467.8
REPUBLIC SERVICES, INC.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(in millions, except per share amounts)
Three Months Ended Twelve Months Ended
December 31, December 31,
2008 2007 2008 2007
Revenue $1,244.4 $796.0 $3,685.1 $3,176.2
Expenses:
Cost of operations 863.2 497.2 2,416.7 2,003.9
Depreciation, amortization and
depletion 127.2 71.6 354.1 305.5
Accretion 10.4 4.5 23.9 17.1
Selling, general and administrative 182.7 82.8 434.7 313.7
Asset impairments 89.8 - 89.8 -
Restructuring charges 82.7 - 82.7 -
Operating income (loss) (111.6) 139.9 283.2 536.0
Interest expense (66.8) (23.7) (131.9) (94.8)
Interest income 1.7 3.3 9.6 12.8
Other income (expense), net (0.9) 11.5 (1.6) 14.1
Income (loss) before income taxes (177.6) 131.0 159.3 468.1
Provision (benefit) for income taxes (46.0) 48.9 85.4 177.9
Minority interests 0.1 - 0.1 -
Net income (loss) $(131.7) $82.1 73.8 $290.2
Basic Earnings Per Share:
Basic earnings per share $(0.55) $0.44 $0.38 $1.53
Weighted average common shares
outstanding 239.1 186.2 196.7 190.1
Diluted Earnings Per Share:
Diluted earnings per share $(0.55) $0.44 $0.37 $1.51
Weighted average common and common
equivalent shares outstanding 239.1 188.2 198.4 192.0
Cash dividends per common share $0.19 $0.17 $0.72 $0.55
REPUBLIC SERVICES, INC.
UNAUDITED SUMMARY DATA SHEET - STATEMENT OF OPERATIONS DATA
(in millions, except percentages)
The following information should be read in conjunction with our audited
consolidated financial statements and notes thereto appearing in our Form
10-K as of and for the year ended December 31, 2007. It should also be
read in conjunction with our unaudited condensed consolidated financial
statements and notes thereto appearing in our Form 10-Q as of and for the
nine months ended September 30, 2008.
Three Months Ended Twelve Months Ended
December 31, December 31,
2008 2007 2008 2007
Collection:
Residential $332.6 $203.4 $966.0 $802.1
Commercial 398.9 242.6 1,161.4 944.4
Industrial 235.1 157.3 711.4 645.6
Other 7.0 4.8 23.2 19.5
Total collection 973.6 608.1 2,862.0 2,411.6
Transfer and disposal 456.8 293.0 1,343.4 1,192.5
Less: Intercompany (228.3) (150.4) (683.5) (612.3)
Transfer and disposal, net 228.5 142.6 659.9 580.2
Other 42.3 45.3 163.2 184.4
Total revenue $1,244.4 $796.0 $3,685.1 $3,176.2
The following table reflects our revenue growth for the three and twelve
months ended December 31, 2008 and 2007:
Three Months Ended Twelve Months Ended
December 31, December 31,
2008 2007 2008 2007
Core price 4.1 % 4.3 % 4.0 % 4.2 %
Fuel surcharges 1.1 0.6 1.8 0.2
Environmental fees 0.7 - 0.4 0.2
Commodities (1.3) 1.1 0.1 0.9
Total price 4.6 6.0 6.3 5.5
Core volume (6.4) (1.5) (3.9) (1.5)
Non-core volume (0.2) 0.2 0.1 (0.1)
Total volume (6.6) (1.3) (3.8) (1.6)
Total internal growth (2.0) 4.7 2.5 3.9
Acquisitions, net of divestitures 58.0 (0.7) 13.4 (0.5)
Taxes 0.3 (0.1) 0.1 -
Total revenue growth 56.3 % 3.9 % 16.0 % 3.4 %
The increase in our revenue and our revenue growth for the three months
ended December 31, 2008 is primarily due to our acquisition of
Allied Waste Industries, Inc. (Allied) on December 5, 2008.
REPUBLIC SERVICES, INC.
UNAUDITED SUMMARY DATA SHEET - STATEMENT OF OPERATIONS DATA
(in millions, except as noted)
SUMMARY OF CHARGES
We incurred various charges and costs during the three and twelve months
ended December 31, 2008 and 2007 that are reported within our unaudited
consolidated statements of income and are reflected in the following
table:
Three Months Ended Twelve Months Ended
December 31, December 31,
2008 2007 2008 2007
Expenses:
Cost of operations (1) $87.8 $- $153.9 $49.1
Depreciation, amortization and
depletion (1) (2) (3) 8.4 - 8.4 3.6
Selling, general and administrative
(1) (4) (5) (6) 46.8 - 48.7 1.5
Asset impairments (7) 89.8 - 89.8 -
Restructuring charges (8) 82.7 - 82.7 -
Operating loss (315.5) - (383.5) (54.2)
Interest expense (9) (10.1) - (10.1) -
Other income (expense), net (1) - - (1.0) (0.7)
Income (Loss) before income taxes $(325.6) $- $(394.6) $(54.9)
(1) During the three months ended December 31, 2008, we recorded $65.9
million and $21.9 million of remediation and related charges
related to our Countywide disposal facility in Ohio and our closed
disposal facility in Contra Costa County, California, respectively.
During the twelve months ended December 31, 2008, we recorded $99.9
million, $21.9 million and $35.0 million of remediation and related
charges related to our Countywide facility, our Contra Costa County
facility and the Sunrise Landfill in Nevada. Of the $99.9 million
charge recognized for the Countywide facility, $98.0 million and $1.9
million were recorded in cost of operations and selling, general and
administrative expenses, respectively. The $21.9 million charge for
our Contra Costa County facility was recorded to cost of operations.
Of the $35.0 million charge recognized for the Sunrise landfill, $34.0
million and $1.0 million were recorded in cost of operations and other
income (expense), respectively.
During the twelve months ended December 31, 2007, we recorded $45.3
million of remediation charges for our Countywide disposal facility,
of which $41.0 million was recorded in cost of operations, $2.1
million was recorded in depreciation, amortization and depletion, $1.5
million was recorded in selling, general and administrative expenses,
and $.7 million was recorded to other income (expense), net. Also
during the twelve months ended December 31, 2007, we recorded a $9.6
million charge related to our Contra Costa County disposal facility,
of which $8.1 million was recorded in cost of operations and $1.5
million was recorded in depreciation, amortization and depletion.
(2) During the three and twelve months ended December 31, 2008, we
recorded $2.8 million of incremental landfill amortization expense as
compared to the amortization expense Allied would have recorded for
the same period. The increase in the landfill amortization expense is
the result of conforming Allied's policies for estimating the costs
and timing for capping, closure and post-closure obligations to
Republic's.
(3) During the three and twelve months ended December 31, 2008, we
recorded $5.6 million of intangible asset amortization expense related
to the intangible assets we recorded in the purchase price allocation
for the acquisition of Allied.
(4) During the three and twelve months ended December 31, 2008, we
recorded $14.2 million of bad debt expense related to conforming
Allied's methodology for recording allowance for doubtful accounts
with our methodology and $5.4 million to provide for specific
bankruptcy exposures.
(5) During the three and twelve months ended December 31, 2008, we
recorded $24.3 million of settlement charges related to our estimates
of the outcome of various legal matters.
(6) During the three and twelve months ended December 31, 2008, we
recorded $2.9 million to accrue for the synergy incentive plan pro
rata over the periods earned.
(7) During the three and twelve months ended December 31, 2008, we
recorded $89.8 million of asset impairment charges, which consist
primarily of $75.9 million related to our Countywide facility, $6.0
million related to our former corporate headquarters in Florida and
$6.1 million related to losses on the expected sales of Department of
Justice required divestitures as a result of our merger with Allied.
(8) During the three and twelve months ended December 31, 2008, we
recorded $82.7 million of restructuring charges primarily related to
severance and other employee termination and relocation benefits
attributable to integrating our operations with Allied.
(9) During the three and twelve months ended December 31, 2008, we
incurred $10.1 million of non-cash interest expense primarily
associated with amortizing the discount on the debt we acquired from
Allied that was recorded at fair value in purchase accounting.
REPUBLIC SERVICES, INC.
SUPPLEMENTAL UNAUDITED FINANCIAL INFORMATION
MERGER WITH ALLIED
We completed our acquisition of Allied effective December 5, 2008. We
issued approximately 195.8 million shares of common stock to Allied
stockholders, representing 52% of the outstanding common stock of the combined
company on a diluted basis. The total purchase price paid for Allied,
including the value of common stock issued, our acquisition of Allied's debt
and other costs, totaled approximately $11.5 billion. We have allocated the
preliminary purchase price to the assets and liabilities acquired based upon
their estimated fair values as of the acquisition date and recorded the
resulting goodwill, which represents the excess of purchase price over the net
assets acquired, of $9.0 billion. Until we have completed our valuation
process for the assets and liabilities acquired, there may be adjustments,
which we believe will be relatively small compared to our preliminary
estimates of the fair values and the resulting purchase price allocation.
Our allocation of purchase price included allocating values to intangible
assets other than goodwill. The purchase price assigned to each of these
intangible assets and the life over which these assets will be amortized is as
follows:
Other Intangibles: Amount Estimated Life
(years)
Customer relationships $420.0 10.0
Franchise agreements 60.0 9.0
Other municipal agreements 30.0 3.0
Non-compete agreements 1.0 2.0
Tradename 30.0 5.0
Total $541.0
Amortization expense for 2009 arising from the $541.0 million of other
intangible assets recorded is expected to be approximately $65.0 million.
The debt we acquired from Allied was recorded at fair value. At the date
of the merger, the fair value of Allied's variable rate debt approximated its
book value. However, because of the tightening of the credit markets, the
fair value of Allied's fixed rate debt was significantly below its book value,
which resulted in the recognition of a $624.3 million discount. Non-cash
interest expense for 2009 arising from amortizing the discount of Allied's
debt is expected to be approximately $90.7 million. This discount will
generally be amortized into interest expense over the terms of the related
debt instruments. The estimated fair value and discount for each fixed rate
debt instrument acquired from Allied is as follows:
Fixed-Rate Debt:
Estimated Discount
Fair Value
$350.0 million senior notes due 2010 $332.5 $17.5
$400.0 million senior notes due 2011 370.0 30.0
$275.0 million senior notes due 2011 257.1 17.9
$450.0 million senior notes due 2013 421.9 28.1
$425.0 million senior notes due 2014 369.8 55.2
$400.0 million senior notes due 2014 363.0 37.0
$600.0 million senior notes due 2015 531.0 69.0
$600.0 million senior notes due 2016 518.0 82.0
$750.0 million senior notes due 2017 645.0 105.0
$99.5 million debentures due 2021 92.8 6.7
$360.0 million debentures due 2035 265.9 94.1
$230.0 million convertible debentures due 2034 201.2 28.8
Other, maturing 2014 through 2027 215.3 53.0
Total $4,583.5 $624.3
In accordance with U.S. generally accepted accounting principles (GAAP),
various liabilities acquired from Allied were recorded at their fair values
using present value techniques to account for changes in the related
liabilities due to the passage of time. The differences between the estimated
fair values and the undiscounted values for these liabilities will be
amortized into either accretion expense or interest expense, depending on the
type of liability recorded, over the expected term of the applicable
liability. The estimated fair values, undiscounted values and estimated lives
for these liabilities are as follows:
Estimated Undiscounted Estimated
Fair Value Amount Average Life
(years)
Accrued Capping, Closure, and
Post-Closure Costs $813.1 $3,726.0 38.5
Accrued Environmental
Remediation $208.1 $325.9 5.9
Self-Insurance Reserves $172.6 $216.3 3.2
RECONCILIATION OF CERTAIN NON-GAAP MEASURES
Operating Income before Depreciation, Amortization, Depletion and
Accretion
Operating income before depreciation, amortization, depletion and
accretion, which is not a measure determined in accordance with GAAP, for the
three and twelve months ended December 31, 2008 and 2007 is calculated as
follows:
Three Months Ended Twelve Months Ended
December 31, December 31,
2008 2007 2008 2007
Net income (loss) $(131.7) $82.1 $73.8 $290.2
Provision (benefit) for
income taxes (46.0) 48.9 85.4 177.9
Minority interests .1 - .1 -
Other (income) expense,
net .9 (11.5) 1.6 (14.1)
Interest income (1.7) (3.3) (9.6) (12.8)
Interest expense 66.8 23.7 131.9 94.8
Depreciation, amortization
and depletion 127.2 71.6 354.1 305.5
Accretion 10.4 4.5 23.9 17.1
Operating income before
depreciation, amortization,
depletion and accretion $26.0 $216.0 $661.2 $858.6
We believe that the presentation of operating income before depreciation,
amortization, depletion and accretion is useful to investors because it
provides important information concerning our operating performance exclusive
of certain non-cash costs. Operating income before depreciation,
amortization, depletion and accretion demonstrates our ability to execute our
financial strategy which includes reinvesting in existing capital assets to
ensure a high level of customer service, investing in capital assets to
facilitate growth in our customer base and services provided, maintaining our
investment grade rating and minimizing debt, paying cash dividends, and
maintaining and improving our market position through business optimization.
This measure has limitations. Although depreciation, amortization, depletion
and accretion are considered operating costs in accordance with GAAP, they
represent the allocation of non-cash costs generally associated with long-
lived assets acquired or constructed in prior years.
For a discussion of significant items impacting our operating income
before depreciation, amortization, depletion and accretion for the periods
presented above, see Summary of Charges.
Diluted Earnings per Share
Following is a summary of adjusted diluted earnings per share for the
three and twelve months ended December 31, 2008 and 2007:
Three Months Ended Twelve Months Ended
December 31, December 31,
2008 2007 2008 2007
Diluted earnings per share $(.55) $.44 $.37 $1.51
Remediation and related
charges (1) .22 - .48 .18
Asset impairments (2) .23 - .27 -
Restructuring charges (3) .21 - .25 -
Landfill amortization
expense (4) .01 - .01 -
Intangible amortization
expense (5) .01 - .02 -
Bad debt expense (6) .05 - .06 -
Legal settlement reserves (7) .06 - .07 -
Synergy incentive plan (8) .01 - .01 -
Non-cash interest expense (9) .02 - .03 -
Tax impact of non-deductible
items (10) .14 - .16 -
Adjusted diluted earnings
per share $.41 $.44 $1.73 $1.69
(1) Remediation and related charges of $87.8 million during the three
months ended December 31, 2008 consist primarily of changes to our
estimates of costs incurred at our Countywide facility in Ohio and our
closed disposal facility in Contra Costa County, California.
Remediation and related charges of $156.8 million during the twelve
months ended December 31, 2008 were attributable to the aforementioned
disposal facilities as well as the Sunrise Landfill in Nevada.
(2) During the three and twelve months ended December 31, 2008, asset
impairments of $89.8 million primarily relate to our Countywide
facility, our former corporate headquarters in Florida and losses on
expected sales of Department of Justice required divestitures as a
result of our merger with Allied.
(3) During the three and twelve months ended December 31, 2008, we
incurred restructuring charges of $82.7 million, consisting primarily
of severance and other employee termination and relocation benefits
attributable to integrating our operations with Allied.
(4) During the three and twelve months ended December 31, 2008, we
recorded $2.8 million of incremental landfill amortization expense as
compared to the amortization expense Allied would have recorded for
the same period. The increase in the landfill amortization expense is
the result of conforming Allied's policies for estimating the costs
and timing for capping, closure and post-closure obligations to
Republic's.
(5) During the three and twelve months ended December 31, 2008, we
recorded $5.6 million of intangible asset amortization expense related
to the intangible assets we recorded in the purchase price allocation
for the acquisition of Allied.
(6) During the three and twelve months ended December 31, 2008, we
recorded bad debt expense of $14.2 million related to conforming
Allied's methodology for recording the allowance for doubtful accounts
with our methodology and $5.4 million to provide for specific
bankruptcy exposures.
(7) During the three and twelve months ended December 31, 2008, we
incurred $24.3 million of settlement charges related to our estimates
of the outcome of various legal matters.
(8) During the three and twelve months ended December 31, 2008, we
recorded $2.9 million to accrue for the synergy incentive plan pro
rata over the periods earned.
(9) During the three and twelve months ended December 31, 2008, we
incurred $10.1 million of non-cash interest expense primarily
with amortizing the discount on the debt we acquired from Allied that
was recorded at fair value in purchase accounting.
(10)During the three and twelve months ended December 31, 2008, our
effective tax rate was impacted by several expenses associated with
the merger that are not tax deductible.
We believe that the presentation of adjusted diluted earnings per share,
which excludes charges for remediation and related costs, asset impairments,
restructuring, landfill and intangible asset amortization expense, bad debt
expense, legal settlement reserves, the synergy incentive plan, non-cash
interest expense and the tax impact of non-deductible items, provides an
understanding of operational activities before the financial impact of certain
non-operational items and strategic and other decisions made for the long-term
benefit of the company. We use this measure, and believe investors will find
it helpful, in understanding the ongoing performance of our operations
separate from items that have a disproportionate impact on our results for a
particular period. Comparable costs have been incurred in prior periods, and
similar types of adjustments can reasonably be expected to be recorded in
future periods.
Cash Flow
We define free cash flow, which is not a measure determined in accordance
with GAAP, as cash provided by operating activities less purchases of property
and equipment plus proceeds from sales of property and equipment as presented
in our unaudited condensed consolidated statements of cash flows. Our free
cash flow for the three and twelve months ended December 31, 2008 and 2007 is
calculated as follows (in millions):
Three Months Ended Twelve Months Ended
December 31, December 31,
2008 2007 2008 2007
Cash provided by operating
activities $38.0 $190.7 $512.2 $661.3
Purchases of property and
equipment (122.8) (76.5) (386.9) (292.5)
Proceeds from sales of
property and equipment 2.4 1.4 8.2 6.1
Free cash flow $(82.4) $115.6 $133.5 $374.9
Purchases of property and equipment as reflected on our unaudited
condensed consolidated statements of cash flows and the free cash flow
presented above represent amounts paid during the period for such
expenditures. A reconciliation of property and equipment reflected on the
unaudited condensed consolidated statements of cash flows to property and
equipment received during the period is as follows (in millions):
Three Months Ended Twelve Months Ended
December 31, December 31,
2008 2007 2008 2007
Purchases of property and
equipment per the unaudited
condensed consolidated
statements of cash flows $122.8 $76.5 $386.9 $292.5
Adjustments for property and
equipment received during the
prior period but paid for
in the following period, net 11.5 35.5 (14.9) 3.2
Property and equipment received
during the current period $134.3 $112.0 $372.0 $295.7
The adjustments noted above do not affect either our net change in cash
and cash equivalents as reflected in our unaudited condensed consolidated
statements of cash flows or our free cash flow.
A reconciliation of our projected cash provided by operating activities to
the 2009 free cash flow outlook is as follows (in millions):
2009 Outlook
Cash provided by operating activities $1,395.0
Purchases of property and equipment (860.0)
Proceeds from sales of property and equipment 15.0
Free cash flow $550.0
Free cash flow for 2009 includes approximately $100.0 million of merger-
related payments. Excluding these payments, free cash flow for 2009 would be
$650.0 million.
We believe that the presentation of free cash flow provides useful
information regarding our recurring cash provided by operating activities
after expenditures for property and equipment, net of proceeds from sales of
property and equipment. It also demonstrates our ability to execute our
financial strategy as previously discussed and is a key metric we use to
determine compensation. The presentation of free cash flow has material
limitations. Free cash flow does not represent our cash flow available for
discretionary expenditures because it excludes certain expenditures that are
required or that we have committed to such as debt service requirements and
dividend payments. Our definition of free cash flow may not be comparable to
similarly titled measures presented by other companies.
Capital expenditures include $.6 million and $2.6 million of capitalized
interest for the three and twelve months ended December 31, 2008, and $.9
million and $3.0 million of capitalized interest for the three and twelve
months ended December 31, 2007.
As of December 31, 2008, accounts receivable was $945.5 million, net of
allowance for doubtful accounts of $65.7 million, resulting in days sales
outstanding of approximately 40 (or 25 net of deferred revenue).
SHARE REPURCHASE PROGRAM AND DEBT REPAYMENT
During 2008, we repurchased a total of 4.6 million shares of our common
stock for $138.4 million. As of December 31, 2008, we were authorized to
repurchase up to an additional $248.0 million of common stock under our
existing stock repurchase program. We suspended the share repurchase program
due to the merger with Allied. During 2009, we intend to use free cash flow
to repay debt and to continue paying dividends.
CASH DIVIDENDS
In October 2008, we paid a cash dividend of $34.7 million to stockholders
of record as of October 1, 2008. As of December 31, 2008, we recorded a
dividend payable of $72.0 million to stockholders of record at the close of
business on January 2, 2009, which has been paid. In February 2009, our Board
of Directors declared a regular quarterly dividend of $.19 per share payable
to stockholders of record as of April 1, 2009, which will be paid on April 15,
2009.
Information Regarding Forward-Looking Statements
Certain statements and information included herein constitute "forward-
looking statements" within the meaning of the Federal Private Securities
Litigation Reform Act of 1995, including statements with respect to the
expected results of the integration of our merger with Allied and our
anticipated 2009 financial results. Words such as "will", "expect,"
"anticipate" and similar words and phrases are used in this press release to
identify the forward-looking statements. These forward-looking statements,
although based on assumptions that we consider reasonable, are subject to
risks and uncertainties which could cause actual results, events or conditions
to differ materially from those expressed or implied by the forward-looking
statements. Although we believe that the expectations reflected in the
forward-looking statements are reasonable, we can give no assurance that the
expectations will prove to be correct. Among the factors that could cause
actual results to differ materially from the expectations expressed in the
forward-looking statements are:
-- whether our estimates and assumptions concerning our selected balance
sheet accounts, income tax accounts, final capping, closure, post-
closure and remediation costs, available airspace, and projected costs
and expenses related to our landfills and property and equipment
(including our estimates of the fair values of the assets and
liabilities acquired in our acquisition of Allied), and labor, fuel
rates, and economic and inflationary trends, turn out to be correct or
appropriate;
-- various factors that will impact our actual business and financial
performance such as competition and demand for services in the solid
waste industry;
-- our ability to manage growth;
-- our ability to successfully integrate Allied's and Republic's
operations and to achieve synergies or create long-term value for
stockholders as expected;
-- our compliance with, and future changes in, environmental regulations;
-- our ability to obtain approvals from regulatory agencies in connection
with operating and expanding our landfills;
-- our ability to obtain financing on acceptable terms to finance our
operations and growth strategy and to operate within the limitations
imposed by financing arrangements;
-- our dependence on key personnel;
-- general economic and market conditions including, but not limited to,
the current global economic crisis, inflation and changes in commodity
pricing, fuel, labor, risk and health insurance, and other variable
costs that are generally not within our control;
-- our dependence on large, long-term collection, transfer and disposal
contracts;
-- our dependence on acquisitions for growth;
-- risks associated with undisclosed liabilities of acquired businesses;
-- risks associated with pending and any future legal proceedings;
-- severe weather conditions, which could impair our financial results by
causing increased costs, loss of revenue, reduced operational
efficiency or disruptions to our operations;
-- compliance with existing and future legal and regulatory requirements,
including limitations or bans on disposal of certain types of wastes or
on the transportation of waste, which could limit our ability to
conduct or grow our business, increase our costs to operate or require
additional capital expenditures;
-- any litigation, audits or investigations brought by or before any
governmental body;
-- workforce factors, including potential increases in our costs if we are
required to provide additional funding to any multi-employer pension
plan to which we contribute and the negative impact on our operations
of union organizing campaigns, work stoppages or labor shortages;
-- the negative effect that trends toward requiring recycling, waste
reduction at the source and prohibiting the disposal of certain types
of wastes could have on volumes of waste going to landfills and waste-
to-energy facilities;
-- changes by the Financial Accounting Standards Board or other accounting
regulatory bodies to generally accepted accounting principles or
policies;
-- acts of war, riots or terrorism, including the events taking place in
the Middle East, the current military action in Iraq and the continuing
war on terrorism, as well as actions taken or to be taken by the United
States or other governments as a result of further acts or threats of
terrorism, and the impact of these acts on economic, financial and
social conditions in the United States; and
-- the timing and occurrence (or non-occurrence) of transactions and
events which may be subject to circumstances beyond our control.
Other factors which could materially affect our forward-looking statements
can be found in our periodic reports filed with the Securities and Exchange
Commission. Stockholders, potential investors and other readers are urged to
consider these factors carefully in evaluating our forward-looking statements
and are cautioned not to place undue reliance on forward-looking statements.
The forward-looking statements made herein are only made as of the date of
this press release, and we undertake no obligation to publicly update these
forward-looking statements to reflect subsequent events or circumstances.
WELLINGTON, New Zealand, Feb. 26 /PRNewswire-FirstCall/ -- Austral Pacific Energy Ltd. (TSX-V: APX; NZSX: APX)
Austral Pacific Energy Ltd. announces that it has agreed with its loan facility provider, Investec Bank (Australia) Ltd, to further extend the maturity date for the current facility to enable the Bank and Austral to finalise the details of a fundamental restructure of the company and further restructuring of the loan facility.
Web site: www.austral-pacific.com
Email: ir@austral-pacific.com
Phone: Thom Jewell, CEO +64 (4) 495 0880
None of the Exchanges upon which Austral Pacific's securities trade have approved or disapproved the contents hereof. This release includes certain statements that may be deemed to be "forward-looking statements" within the meaning of applicable legislation. Other than statements of historical fact, all statements in this release addressing future production, reserve potential, exploration and development activities and other contingencies are forward-looking statements. Although management believes the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance, and actual results or developments may differ materially from those in the forward-looking statements, due to factors such as market prices, exploration and development successes, continued availability of capital and financing, and general economic, market, political or business conditions. See our public filings at www.sedar.com and www.sec.gov/edgar/searchedgar/webusers.htm for further information.
VANCOUVER, Feb. 26 /PRNewswire-FirstCall/ - CanAlaska Uranium Ltd. (TSX.V - CVV) ("CanAlaska" or the "Company") has received additional assay results for holes FCL 004-FCL 006 and for infill sampling on holes FCL 001-003. These results for the uranium-mineralized sections of the first six drill holes from CanAlaska's work are detailed in the following table, and indicate good widths and grades of uranium mineralization.
The Fond du Lac project is located on the northern portion of the Athabasca Basin, Saskatchewan, where the Athabasca sandstone units have minimal thicknesses of 20-75 metres overlying the unconformity. This area was explored by AMOK in the 1960's and AMOK and Eldorado Nuclear in the 1970's and early 1980's. The property is part of the Fond Du Lac Denesuline First Nation Reserve Lands, and CanAlaska is working with the community under an Option to earn a 49% interest in the project.
A small uranium resource (non 43-101compliant) was previously discovered in the sandstone units, immediately above the unconformity, but no significant effort was made to explore for structurally hosted uranium mineralization in the basement rock at that time. However there is historical evidence for basement hosted mineralization in hematised fault zones.
The 2008 drilling and detailed ground geophysics by CanAlaska in January and February 2009 have highlighted a number of strong structural events in the basement rocks. There are patterns of sulphide mineralization and gravity anomalies. The company is preparing for a summer drill program on the property, following the completion of the Company's current four-rig winter drill program.
The uranium mineralization at Fond du Lac is principally within the Manitou Falls Formation of the Athabasca Sandstone sequence, and is characterized by strong fracturing, intense silicification, zones of hematisation and minor clay alteration. In the current area of 2008 drilling, zoning is apparent, with a central highly mineralized-core. The mineralization is evident as disseminations and replacement, both in the sandstone and near the surface (see following plan and drill section).
Across the project, there are multiple other zones, currently only loosely-defined by mineralized boulder trains (see attached figure 1 for mineralized boulder trains and geophysical responses).
In the current drilling, a very significant zone of hematite alteration was intersected in basement rocks at the unconformity, under the better-mineralized uranium zone in the drill holes FCL 001-003. This style of iron oxide mineralization is generally caused by oxidization from geothermal activity along fracture zones, and is a common indicator for most basement-hosted uranium deposits. Drill hole FCL 001 intercepted anomalous uranium mineralization in sandstone. Drill hole FCL 004 intercepted two zones of replacement mineralization on the southern edge of the main zone. Holes FCL 005 and FCL 006 intercepted uranium mineralization in the sandstone and strong clay hematite and chlorite alteration, in the basement rocks. Further drilling along strike will be required to define the extent and orientation of the present zone.
The Company received a work permit for the drilling at Fond du Lac from INAC (Indian and Northern Affairs Canada), with consent from the band and council of the Fond du Lac Denesuline First Nation. This permit allowed the Company to commence exploration on the Reserve lands. By agreement dated October 18th, 2006, the Company acquired from the Fond du Lac Denesuline First Nation an option to earn a 49% economic interest in the minerals resident on Fond du Lac reserve lands. CanAlaska may exercise this option following the incurrence of $2 million in exploration expenditures and the payment of $130,000 and 300,000 Company shares.
Elsewhere in the Athabasca Basin, CanAlaska has two drill crews working at the Cree East Project, located in the southwestern part of the Athabasca basin. A third drill crew is operating at the West McArthur project, on a new geophysical target located north west of Denison's Wheeler River project, and south west of the McArthur River mine.
The Company has just mobilized a fourth crew for a month-long drill program on the Black Lake Project, on the Black Lake Denesuline First Nation Reserve. This drill program will replace the proposed winter program at Fond du Lac, but will test higher priority strong airborne and ground truthed geophysical conductors on the splays of the Black Lake-Platt Lake Faults, on the northern end of the Virgin River mineralized trend. There are multiple targets at shallow depths in this area. These targets have been confirmed by summer boulder sampling and historical mineralized drill core from the vicinity. Drill holes will target both sandstone hosted alteration and basement mineralization in this program.
The Company is very pleased with current operations, and is fully-funded for the summer-fall work programs through its joint venture partnerships and from current treasury.
All of the drill core samples from the Fond du Lac project were submitted to Acme Laboratories Vancouver, an ISO 9001:2000 accredited and qualified Canadian Laboratory, for their Group 4B analysis. These samples were analysed for uranium and multi-element geochemistry by tri-acid digestion and ICP-MS. The samples were collected by CanAlaska field geologists under the supervision of Dr. Karl Schimann, and were shipped in secure containment to the laboratories noted above. Peter Dasler, M.Sc. P Geo. is the qualified technical person responsible for this news release.
About CanAlaska Uranium Ltd. -- www.canalaska.com
CANALASKA URANIUM LTD. (CVV -- TSX.V, CVVUF -- OTCBB, DH7 -- Frankfurt) is undertaking uranium exploration in nineteen 100%-owned and two optioned uranium projects in Canada'sAthabasca Basin. Since September 2004, the Company has aggressively acquired one of the largest land positions in the region, comprising over 2,500,000 acres (10,117 sq. km or 3,906 sq. miles). To-date, CanAlaska has expended over Cdn$45 million exploring its properties and has delineated multiple uranium targets. The Company's geological expertise and high exploration profile has attracted the attention of major international strategic partners. Among others, Mitsubishi Development Pty., a subsidiary of Japanese conglomerate Mitsubishi Corporation, has undertaken to provide CanAlaska C$11 mil. in exploration funding for its West McArthur Project. Exploration of CanAlaska's Cree East Project is also progressing under a C$19 mil. joint venture with a consortium of Korean companies led by Hanwha Corporation, and comprising Korea Electric Power Corp., Korea Resources Corp. and SK Energy Co, Ltd.
On behalf of the Board of Directors
(signed)
Peter Dasler, M.Sc., P.Geo.
President & CEO, CanAlaska Uranium Ltd.
The TSX Venture has not reviewed and does not accept responsibility for the adequacy or accuracy of this release: CUSIP # 13708P 10 2. This news release contains certain "Forward-Looking Statements" within the meaning of Section 21E of the United States Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact, included herein are forward-looking statements that involve various risks and uncertainties. There can be no assurance that such statements will prove to be accurate, and actual results and future events could differ materially from those anticipated in such statements. Important factors that could cause actual results to differ materially from the Company's expectations are disclosed in the Company's documents filed from time to time with the British Columbia Securities Commission and the United States Securities & Exchange Commission.
2009 Capital Expenditure Budget Reduced in Line with Cash Flow Outlook
ENID, Okla., Feb. 26 /PRNewswire-FirstCall/ -- Continental Resources, Inc. (NYSE: CLR) today reported continued strong growth in production in the fourth quarter ended December 31, 2008, compared with the third quarter of 2008 and the fourth quarter last year. In addition, the Company reported year-end 2008 proved reserves of 159.3 MMboe, an 18 percent increase over the 134.6 MMboe reported at year-end 2007. Combined drilling and proved undeveloped (PUDs) additions of 47.6 MMboe were almost 400 percent of Continental's total production of 12.0 MMboe for 2008.
Despite challenging economics in the final quarter of 2008, Continental completed a record year for net income and cash flow growth. Net income increased 74 percent to $321.0 million and EBITDAX increased 61 percent to $757.7 million, compared with full-year 2007 results. For the Company's definition and reconciliation of EBITDAX to Generally Accepted Accounting Principles, see "Non-GAAP Financial Measures" at the end of this press release. Net income for 2007 is pro forma for income taxes as if the Company had been a subchapter C corporation prior to its initial public offering in May 2007.
For the fourth quarter ended December 31, 2008, the Company reported net income of $416,000, or $0.00 per diluted share, compared with net income of $60.9 million, or $0.36 per diluted share, for the fourth quarter of 2007. Falling commodity prices reduced fourth quarter revenue and earnings compared to the fourth quarter of 2007.
For the fourth quarter of 2008, Continental achieved total production of 36,018 boepd, an eight percent increase over the third quarter of 2008 and a 19 percent increase over the fourth quarter last year. The Company exited the fourth quarter with average production of 37,954 boepd for December 2008, an increase of 27 percent over December 2007. Production growth strengthened despite the Company significantly scaling back its drilling program as commodity prices declined in the fourth quarter of 2008. Continental has reduced its operated drilling rig count from 32 in early October to seven rigs currently and plans to drop additional rigs as drilling contracts expire later in 2009.
With energy prices remaining low, Continental plans to reduce capital expenditures to preserve capital and the value of its assets. "Our first priority is the integrity of our balance sheet," said Harold Hamm, Chairman and Chief Executive Officer. "We plan to restrain spending until we see commodity prices begin to recover. We remain committed to financing our growth with cash flow and will not use debt to fund a high level of drilling activity, especially in an environment of low energy prices."
"I'm proud that we achieved our operating goals for 2008, finishing the year with strong fourth quarter production growth and increased reserves," he said. "The Company's accomplishments are a strong indicator of the value of our assets and our ability to accelerate growth when the economy and industry conditions rebound."
The Company has revised its 2009 capital expenditures budget to $275 million, which includes $211 million for drilling and related activities and $58 million for land and seismic, and $6 million for other capital needs. Based on the new budget, 2009 production is expected to be in a range of 12.5 MMboe to 13.0 MMboe, which would constitute growth of up to eight percent over 2008. Under this revised capex budget, Continental expects to average approximately five operated drilling rigs during the year.
Oil and natural gas sales were $130.7 million for the fourth quarter of 2008, compared with oil and gas sales of $183.8 million for the fourth quarter of 2007. The Company's average sales price per barrel of crude oil equivalent was $38.80 for the fourth quarter of 2008, compared with $68.84 for the fourth quarter of 2007.
Crude oil price differentials averaged $14.45 per barrel for the fourth quarter of 2008 and $9.50 for 2008 as a whole. This compares with $13.05 per barrel in the fourth quarter of 2007 and $8.85 per barrel for the full year. Continental noted that the differential has been improving in the first quarter of 2009.
EBITDAX for the fourth quarter of 2008 was $92.7 million, compared with EBITDAX of $137.4 million for the fourth quarter of 2007.
At December 31, 2008, the Company's balance sheet included $5.2 million in cash and $376.4 million in long-term debt. Commitments under the Company's revolving credit facility were recently increased to $672.5 million, compared with $552.5 million at December 31, 2008 and $400.0 million at September 30, 2008. With debt outstanding currently of $474.4 million, the Company has $198.1 million in availability under its revolving credit facility.
Increased Reserves
Continental's 2008 reserves growth was primarily the result of increased drilling activity in the North Dakota Bakken and in Oklahoma's Arkoma Woodford in the first nine months of the year.
The Company increased its proved reserves by 24.6 MMboe to a total of 159.3 MMboe. Total proved reserve additions were comprised of 12.7 MMboe in drilling additions, 35.0 MMboe of PUD reserve additions, and 2.2 MMboe in acquisitions. Additions were offset by 13.3 MMboe in downward revisions, of which 64 percent were related to low energy prices at year-end 2008.
Future net cash flows from the year-end 2008 proved reserves, before income taxes, were $3.1 billion, with a present value discounted at 10 percent (PV10) of $1.5 billion. In terms of crude oil/natural gas mix, crude oil reserves were 106.2 million barrels, or 67 percent, of total proved reserves at year-end 2008. Proved developed reserves represented 67 percent of total reserves at year-end 2008.
Operations Update
The following table contains financial and operating highlights for the three months and year ended December 31, 2008 compared to the same periods in 2007.
Three months ended Year ended
------------------ ----------
December 31, December 31,
------------ ------------
2008 2007 2008 2007
------ ------ ------ ------
Average daily production:
Oil (Bopd) 26,857 24,309 24,993 23,832
Natural gas (Mcfd) 54,963 36,362 46,861 31,599
Oil equivalents (Boepd) 36,018 30,369 32,803 29,099
Average prices: (1)
Oil ($/Bbl) $43.89 $77.53 $88.87 $63.55
Natural gas ($/Mcf) 3.93 5.99 6.90 5.87
Oil equivalents ($/Boe) 38.80 68.84 77.66 58.31
Production expense ($/Boe) (1) 7.83 6.85 8.40 7.35
EBITDAX (in thousands) 92,680 137,412 757,708 469,885
Net income (in thousands) (2) 416 60,892 320,950 184,002
Diluted net income per share 0.00 0.36 1.89 1.11
(1) Average prices and per-unit production expense are calculated
based on sales volumes. Crude oil sales volumes exceeded production in
the fourth quarter and full-year 2008 by 54 MBbls and 97 MBbls,
respectively. Crude oil production volumes exceeded oil sales in the
fourth quarter and full year 2007 by 125 MBbls and 221 MBbls,
respectively.
(2) Net income and diluted net income per share for full-year 2007
are after pro forma adjustments (i) to provide for income taxes as if
the Company had been a subchapter C corporation prior to the completion
of its initial public offering, and (ii) to eliminate the $198.4 million
charge recorded to recognize deferred taxes upon its conversion from a
nontaxable subchapter S corporation to a taxable subchapter C
corporation in conjunction with the Company's May 2007 initial public
offering.
The following table presents average daily production for the Company's
principal operating areas for the quarters ended December 31, 2008,
September 30, 2008 and December 31, 2007.
(boe per day) Q4 2008 Q3 2008 Q4 2007
------- ------- -------
Red River Units 14,058 13,375 14,374
Montana Bakken 6,410 6,187 7,244
North Dakota Bakken 4,401 3,444 1,382
Other Rockies 2,507 2,275 1,600
Arkoma Woodford 3,276 2,627 1,338
Other Mid-Continent 4,751 4,895 3,767
Gulf Coast 615 494 664
------- ------- -------
Total 36,018 33,297 30,369
Production growth continued to accelerate in the North Dakota Bakken and the Arkoma Woodford plays in the fourth quarter of 2008. Based on capital expenditure re-allocations and its revised 2009 budget, production in the Red River Units is expected to be flat or to decline slightly through the first nine months of 2009, then resume growing in the fourth quarter. Continental expects to generate most of its 2009 production growth in the North Dakota Bakken and the Arkoma Woodford plays.
Red River Units
Production in the Red River Units was 14,058 boepd in the fourth quarter of 2008, accounting for 39 percent of Continental's production in the quarter. This was a five percent increase over the third quarter of 2008, but down slightly from the fourth quarter last year.
The Units accounted for 37 percent of year-end 2008 proved reserves, compared with 50 percent of reserves at the end of 2007.
During fourth quarter 2008, the Company continued to convert producer wells to injectors and to expand its secondary recovery program, but the pace of the secondary recovery program was considerably reduced in November and December.
The Company currently has one operated rig drilling in the Units. Under the revised 2009 capital expenditures budget, Continental has allocated $46 million to the Units, with plans to drill four producer wells, two disposal wells, a sixth water supply well, and converting producer and air injector wells to water injectors.
As noted above, production is expected to resume growing in the Red River Units in late 2009. The Company does not expect changes in the timing of capex funding to reduce total production or ultimate reserve recovery in the Units. The Company expects production to peak at just over 17,000 boepd in the Units in 2010.
Bakken Shale
Production in the Bakken Shale of North Dakota and Montana was 10,811 boepd in the fourth quarter of 2008, or 30 percent of Continental's production in the quarter. This was a 12 percent increase over the third quarter of 2008 and a 25 percent increase over production for the fourth quarter last year.
Total proved reserves in the Bakken were 45.7 MMboe at December 31, 2008, or 29 percent of the Company's year-end 2008 reserves. This constituted an increase of 38 percent over proved reserves of 33.2 MMboe in the Bakken Shale at December 31, 2007.
In the North Dakota part of the Bakken play, total proved reserves were 17.5 MMboe at December 31, 2008, or 11 percent of the Company's total year-end 2008 reserves. This represented growth of 187 percent over reserves of 6.1 MMboe in the North Dakota Bakken at December 31, 2007.
The Company currently has four operated rigs drilling in North Dakota and none in Montana, compared with 10 rigs in North Dakota and three in Montana at the beginning of the fourth quarter of 2008.
During the fourth quarter, Continental participated in the completion of 33 gross wells (8.9 net) in North Dakota. These wells had an average rate of 546 boepd during their seven-day production period tests. All initial production period test results in this press release are seven consecutive day averages.
Since the beginning of the fourth quarter of 2008, notable completions of Company-operated wells targeting the Three Forks/Sanish (TFS) formation in North Dakota are shown below with average production period test results in gross barrels:
-- Morris 1-23H (29% WI) in Dunn Co. - 1,185 boepd;
-- Blegen 1-13H (26% WI) in McKenzie Co. - 1,028 boepd;
-- Mittelstadt 1-20H (44% WI) in Dunn Co. - 998 boepd;
-- Skachenko 1-31H (34% WI) in Dunn Co. - 809 boepd;
-- Hamlet 1-11H (39% WI) in Williams Co. - 450 boepd;
-- Glasoe 1-18H (45% WI) in Divide Co. - 441 boepd;
-- Arvid 1-34H (42% WI) in Divide Co. - 340 boepd;
-- Elveida 1-33H (46% WI) in Divide Co. - 302 boepd.
Notable recent well completions in North Dakota targeting the Middle Bakken formation include:
-- Malcolm 1-29H (45% WI) in Williams Co. - 693 boepd;
-- Shonna 1-15H (44% WI) in Divide Co. - 436 boepd;
-- Marlene 1-10H (53% WI) in Williams Co. - 427 boepd;
-- Viola 1-7H (54% WI) in Divide Co. - 391 boepd.
In the Montana Bakken, the Company continued to implement its 320-acre infield and field-extension program in the fourth quarter of 2008.
Notable completions in Richland County, MT in the fourth quarter of 2008 included the Prevost 3-16H (83% WI), which had a production period test rate of 507 boepd, and the Rita 3-19H (79% WI), which had production period test rate of 412 boepd. Production results have continued to improve in Richland County as the Company implemented multi-stage fracture stimulation technology that it developed in North Dakota.
Continental recently completed its first Montana TFS test well, the Joann 1-32H (89% WI), in Richland County. The well exhibited poor oil shows and reservoir rock quality during drilling, and in its initial production test period yielded an average 60 boepd.
The Company has commenced a pilot carbon dioxide injection project to evaluate the potential for enhanced recovery of oil in the Elm Coulee field. Utilizing the huff-and-puff technique, carbon dioxide was injected in January and will continue to be injected through March. After letting the carbon dioxide soak in for approximately 30 days, the carbon dioxide and associated fluids will be flowed back and analyzed for performance and economics.
Under its revised 2009 capital expenditures budget, Continental has allocated $72 million to drilling-related activity in North Dakota and $7 million to Montana. Another $36 million in land and seismic capex was allocated for the Bakken play in the two states, primarily to extend leases in the play.
Continental plans to participate in 86 gross wells (20.2 net) in North Dakota and no new wells in Montana in 2009. Drilling activity in North Dakota will focus on the Three Forks/Sanish formation.
Arkoma Woodford
Production in the Arkoma Woodford shale play in southeast Oklahoma was 3,276 boepd in the fourth quarter of 2008, accounting for 9 percent of Continental's production in the period. This was a 25 percent increase over the third quarter of 2008, and was more than double production for the fourth quarter last year.
Total proved reserves in the Arkoma Woodford were 30.7 MMboe at December 31, 2008, or 19 percent of the Company's year-end 2008 reserves. This represented growth of 245 percent over reserves of 8.9 MMboe in the Arkoma Woodford at December 31, 2007.
During the fourth quarter of 2008, Continental continued to develop its simultaneous fracture stimulation technology in the Arkoma Woodford, most notably with the Pasquali, Luna-Pratt and Wilson simul-fracs in the Ashland development section of the play.
After the simul-frac, the seven Pasquali wells flowed at an average 2,440 Mcfpd during their production period test, with the most prolific well flowing at 3,599 Mcfpd. The six Luna-Pratt wells flowed at an average 3,761 Mcfpd, with the most prolific flowing at 4,576 Mcfpd. The two wells in the Wilson simul-frac flowed at 8,569 Mcfpd and 5,982 Mcfpd, for an average rate of 7,276 Mcfpd.
The Company currently has one operated rig drilling in the Arkoma Woodford, compared to six rigs at the beginning of the fourth quarter of 2008. Under its revised 2009 capital expenditures budget, Continental has allocated $56 million to drilling-related activity in the play, as well as $7 million in land and seismic capex. In 2009, the Company plans to participate in 63 gross wells (8.0 net) in the Arkoma Woodford.
Emerging Plays
In the Anadarko Woodford shale of western Oklahoma, Continental is currently completing two test wells, the Brown 1-2H (100% WI) in Dewey Co. and the McCalla 1-11H (90% WI) in Grady Co.
In Ellis County, OK, the Company completed its initial test well in the Atoka shale play, the Shrewder 1-22H (100% WI), which flowed at 1.3 MMcfpd from a short, 1,300-foot lateral. The Jones-Trust 1-168H (100% WI), completed in Lipscomb Co., TX in the western part of the play, flowed at 700 Mcf per day in its initial production period test.
The Company currently has no operated rig drillings in the Anadarko Woodford or the Atoka, compared to one in each play at the beginning of the fourth quarter of 2008. Under its revised 2009 capital expenditures budget, Continental has allocated $12 million to drilling-related activity in its emerging plays, as well as $6 million in land and seismic. In 2009, the Company plans to participate in six gross wells (1.8 net) in its emerging plays.
Capital Budget and Guidance
Continental's regional allocations of capital expenditures in 2009 are listed below. Operational capex includes drilling, work-over and facilities capital expenditures.
2009 Capex Budget
-----------------
(in millions) Net Wells
----------------- ---------
North Dakota Bakken $72 20.2
Arkoma Woodford 56 8.0
Red River Units 46 3.8
Emerging plays 12 1.8
Montana Bakken 7 0.0
Other 18 3.9
----------------- ---------
Operational capex 211 37.7
Land and seismic 58
Other capital expenditures 6
----------------- ---------
Total capex $275
Continental announced its previously issued operating and financial guidance for 2009 has been revised and is as follows. As forward-looking information, this guidance is subject to a variety of risks and uncertainties, including adjustments related to fluctuations in commodity prices. Risk factors are discussed further at the end of this press release and in the Company's filings with the Securities and Exchange Commission.
Year Ended
December 31, 2009
-----------------
Production volumes:
Oil (MMbls) 8.8 - 9.1
Gas (MMcf) 22.5 - 23.4
Oil equivalent (MMboe) 12.5 - 13.0
Price differentials(1) :
Oil (Bbl) $8.00 - $10.00
Gas (Mcf) $1.50 - $2.25
Operating expenses:
Production expense (per boe) $7.75 - $8.50
Production tax (percent of sales) 6.25% - 6.75%
Depreciation, depletion, amortization and
accretion (per boe) $15.00 - $18.00
General and administrative expense (per boe)(2) $1.75 - $2.25
Non-cash stock-based compensation (per boe) $0.70 - $1.00
Income tax rate (percent of pre-tax income) 38%
Percent of income tax deferred 90%
(1) Differential to calendar month average NYMEX futures price for oil
and to average of last three trading days of prompt NYMEX futures
contract for gas.
(2) Excludes non-cash stock-based compensation.
Conference Call Information
Continental Resources will host a conference call on Thursday, Feb. 26, 2009, at 10:00 a.m. ET (9 a.m. CT) to discuss its fourth quarter 2008 results. Interested parties may listen to the conference call via the Company's website at http://www.contres.com or by phone:
Continental management is currently scheduled to present at the Raymond James & Associates 30th Annual Institutional Investors Conference in Orlando (March 8-11, 2009) and at the Howard Weil 37th Annual Energy Conference in New Orleans (March 22-26, 2009).
Continental Resources is a crude-oil concentrated, independent oil and natural gas exploration and production company with operations in the Rocky Mountain, Mid-Continent and Gulf Coast regions of the United States. The Company focuses its operations in large new and developing resource plays where horizontal drilling, advanced fracture stimulation and enhanced recovery technologies provide the means to economically develop and produce oil and natural gas reserves from unconventional formations.
This press release includes forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond the Company's control. All information, other than historical facts included in this press release, regarding strategy, future operations, drilling plans, estimated reserves, future production, estimated capital expenditures, projected costs, the potential of drilling prospects and other plans and objectives of management are forward-looking information. All forward-looking statements speak only as of the date of this press release. Although the Company believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Actual results may differ materially from those anticipated due to many factors, including oil and natural gas prices, industry conditions, drilling results, uncertainties in estimating reserves, uncertainties in estimating future production from enhanced recovery operations, availability of drilling rigs and other services, availability of crude oil and natural gas transportation capacity, availability of capital resources and other factors listed in reports we have filed or may file with the Securities and Exchange Commission.
CONTACT: Continental Resources, Inc.
J. Warren Henry Brian Engel
Investors Media
(580) 548-5127 (580) 249-4731
Condensed Consolidated Statements of Income
(in thousands, except Three months ended Year ended
share data) ------------------ -----------
December 31, December 31,
------------ ------------
2008 2007 2008 2007
---- ---- ---- ----
Revenues:
Oil and natural gas sales $130,668 $183,780 $939,906 $606,514
Loss on mark-to-market
derivatives - (30,476) (7,966) (44,869)
Oil and natural gas
service operations 5,128 5,690 28,550 20,570
----------------------------------------
Total revenues 135,796 158,994 960,490 582,215
Operating costs and expenses:
Production expense 26,362 18,288 101,635 76,489
Production tax 10,199 10,251 58,610 32,562
Exploration expense 13,882 2,499 40,160 9,163
Oil and gas service operations 2,391 3,942 18,188 12,709
Depreciation, depletion,
amortization and accretion 53,074 26,326 148,902 93,632
Property impairments 11,227 4,887 28,847 17,879
General and administrative (1) 7,907 5,148 35,719 32,802
Gain on sale of assets (488) (650) (894) (988)
----------------------------------------
Total operating costs and
expenses 124,554 70,691 431,167 274,248
Income from operations 11,242 88,303 529,323 307,967
Interest expense and other (2,743) (2,543) (10,793) (11,190)
----------------------------------------
Net income before income
tax expense 8,499 85,760 518,530 296,777
Income tax expense 8,083 24,868 197,580 268,197
----------------------------------------
Net income $416 $60,892 $320,950 $28,580
Basic net income per share $0.00 $0.36 $1.91 $0.17
Diluted net income per share 0.00 0.36 1.89 0.17
Basic weighted average
shares outstanding 168,335 167,590 168,087 164,059
Diluted weighted average
shares outstanding 169,231 169,255 169,392 165,422
(1) Includes non-cash charges for stock-based compensation of
$2.6 million and $0.7 million for the three months ended December 31,
2008 and 2007, respectively, and $9.1 million and $12.8 million for
the years ended December 31, 2008 and 2007, respectively.
Condensed Consolidated Balance Sheets December 31, December 31,
(in thousands) ----------- -----------
2008 2007
---- ----
Assets:
Cash and cash equivalents $5,229 $8,761
Receivables 229,079 163,090
Inventories and other 43,387 33,713
Net property and equipment 1,935,143 1,157,926
Other assets 3,041 1,683
----------------------
Total assets $2,215,879 $1,365,173
----------------------
Liabilities and shareholders' equity:
Current liabilities $403,594 $266,106
Long-term debt 376,400 165,000
Other noncurrent liabilities 487,177 310,935
Shareholders' equity 948,708 623,132
----------------------
Total liabilities and shareholders' equity $2,215,879 $1,365,173
----------------------
Year ended
Condensed Consolidated Statements of Cash Flows ----------
(in thousands) December 31,
------------
2008 2007
---- ----
Net income $320,950 $28,580
Adjustments to reconcile net income to net cash
provided by operating activities:
Non-cash expenses 363,801 416,977
Changes in assets and liabilities 35,164 (54,909)
-------------------
Net cash provided by operating activities 719,915 390,648
Net cash used in investing activities (927,617) (483,498)
Net cash provided by financing activities 204,170 94,568
Effect of exchange rate on change in cash and cash
equivalents - 25
-------------------
Net change in cash and cash equivalents (3,532) 1,743
Cash and cash equivalents at beginning of period 8,761 7,018
-------------------
Cash and cash equivalents at end of period $5,229 $8,761
Non-GAAP Financial Measures
EBITDAX represents earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expense, unrealized derivative gains and losses, and non-cash compensation expense. EBITDAX is not a measure of net income or cash flow as determined by generally accepted accounting principles (GAAP). EBITDAX should not be considered as an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP or as an indicator of a Company's operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. The Company's computations of EBITDAX may not be comparable to other similarly titled measures of other companies. The Company believes that EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure its ability to meet future debt service requirements, if any. The Company's credit facility requires that it maintain a total funded debt to EBITDAX ratio, as defined therein, of no greater than 3.75 to 1 on a rolling four-quarter basis. The credit facility defines EBITDAX consistently with the definition of EBITDAX utilized and presented by the Company. The following table represents a reconciliation of the Company's net income to EBITDAX.
Three months ended Year ended
(in thousands) December 31, December 31,
-------------- ---------------
2008 2007 2008 2007
---- ---- ---- ----
(unaudited)
Net income $416 $60,892 $320,950 $28,580
Loss on mark-to-market
derivatives - 14,160 - 26,703
Income tax expense 8,083 24,868 197,580 268,197
Interest expense 3,406 3,085 12,188 12,939
Depreciation, depletion,
amortization and accretion 53,074 26,326 148,902 93,632
Property impairments 11,227 4,887 28,847 17,879
Exploration expense 13,882 2,499 40,160 9,163
Equity compensation 2,592 695 9,081 12,792
-----------------------------------------
EBITDAX $92,680 $137,412 $757,708 $469,885
