Anderson Energy Ltd. Announces 2008 Third Quarter Results
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CALGARY, ALBERTA--(Marketwire - Nov. 12, 2008) - Anderson Energy Ltd. ("Anderson Energy" or the "Company") (TSX: AXL) is pleased to announce its operating and financial results for the third quarter ended September 30, 2008.
Highlights
- Funds from operations for the third quarter more than tripled to $21.2 million ($0.24 per share) compared to the third quarter of 2007. Funds from operations for the nine months ended September 30, 2008 were $66.1 million ($0.76 per share) as compared to $23.9 million ($0.39 per share) for the same nine months in 2007 and $36.4 million ($0.54 per share) for the full year ended December 31, 2007.
- Third quarter production averaged 7,671 BOED, 44% higher than the third quarter of 2007.
- The Company realized an average natural gas price of $7.86 per Mcf in the third quarter of 2008 as compared to $5.00 per Mcf in the third quarter of 2007.
- Operating expenses averaged $10.10 per BOE in the third quarter, which is 15% lower than the third quarter of 2007 and 11% lower than the second quarter of 2008. The reduction in operating expenses is primarily due to new gas plant projects that came on stream during the quarter.
- Operating netbacks improved to $34.34 per BOE for the third quarter compared to $16.76 per BOE in the third quarter of 2007.
- The Company's future drilling inventory is 1,144 gross (585 net) wells as of September 30, 2008, based on a four well per section Edmonton Sands drilling density.
- The Company has entered into letters of intent to sell six properties for a total of $18 million. The property sales are projected to reduce 2009 production by approximately 330 BOED. Closing of the transactions is subject to completion of definitive purchase and sale agreements and other normal closing conditions.
- Subsequent to the third quarter, the Company brought on production four Mannville oil and gas wells that were drilled in the third quarter in central Alberta with current production of 800 BOED. The Company made new exploration discoveries with a gas discovery in Bigoray and a light oil discovery in Willesden Green.
- The Edmonton Sands winter drilling program has commenced, with 123 wells planned for this winter, approximately 90 in the fourth quarter of 2008 and 33 in the first quarter of 2009.
Financial and Operating Highlights
Three months ended % Nine months ended %
September 30 Change September 30 Change
------------------------------------------------------------
2008 2007 2008 2007
------------------------------------------------------------
Financial (thousands of dollars, except share data) Total oil and gas revenue $39,427 $ 17,261 128% $126,143 $ 55,810 126% Funds from operations $21,212 $ 6,255 239% $ 66,124 $ 23,850 177% Per common share - basic $ 0.24 $ 0.09 167% $ 0.76 $ 0.39 95%
- diluted $ 0.24 $ 0.09 167% $ 0.76 $ 0.39 95%
Earnings (loss) $ 4,160 $ (3,018) 238% $ 14,365 $ (2,683) 635% Per common
share - basic $ 0.05 $ (0.04) 225% $ 0.16 $ (0.04) 500%
- diluted $ 0.05 $ (0.04) 225% $ 0.16 $ (0.04) 500%
Field capital
expenditures 27,050 17,924 51% 80,056 54,389 47% Acquisitions, net of dispositions 18 118,042 (100%) (857) 126,444 (101%) Debt, net of working capital 110,535 79,046 40% Shareholders' equity $350,110 $329,179 6% Average shares outstanding (thousands)
Basic 87,300 70,254 24% 87,297 61,222 43% Diluted 87,300 70,254 24% 87,400 61,222 43%
Ending shares outstanding (thousands) 87,300 87,294 0% Operating (6Mcf:1bbl conversion) Average daily sales
Natural gas (Mcfd) 38,703 26,860 44% 39,263 24,000 64%
Light/medium crude oil (bpd) 434 485 (11%) 486 520 (7%) NGL (bpd) 787 358 120% 791 213 271% Barrels of oil equivalent (BOED) 7,671 5,320 44% 7,820 4,732 65% Average sales price Natural gas ($/Mcf) 7.86 5.00 57% 8.57 6.67 28% Light/medium crude oil ($/bbl) 112.18 66.03 70% 104.70 59.03 77% NGL ($/bbl) 78.06 59.62 31% 81.67 56.44 45% Barrels of oil equivalent ($/BOE) 55.87 35.27 58% 58.87 43.20 36% Royalties ($/BOE) 11.43 6.68 71% 12.76 8.21 55% Operating costs ($/BOE) 10.10 11.83 (15%) 11.19 11.69 (4%) Operating netbacks ($/BOE) 34.34 16.76 105% 34.92 23.30 50% General and administrative ($/BOE) 2.90 3.23 (10%) 2.51 3.82 (34%) Wells drilled (gross) 39 34 15% 126 82 54% Operating Highlights Production:
In the third quarter of 2008, production averaged 7,671 BOED, an increase of 44% over the third quarter of 2007 and 3% less than the second quarter of 2008. The Company experienced plant outages at various facilities and third party production curtailments in the month of September. As well, the Company was delayed on various well tie-in projects during the quarter. As of November 11, 2008, the Company's behind pipe production capability is approximately 1,200 BOED. Approximately 90% of the behind pipe production capability relates to wells drilled prior to September 30, 2008 and not yet on stream. The remainder relates to the current fourth quarter drilling program. In addition, the Company has 300 BOED of production curtailed by third parties in its Westpem property. This production may be shut-in until the new Westpem pipeline project comes on stream, which is estimated to be in December. The Company now expects production to average approximately 7,800 BOED for fiscal 2008, which is 5% less than previously estimated due to the delay in well tie-ins and the Westpem third party production curtailment.
Financial:
The Company's funds from operations in the third quarter were $21.2 million and earnings were $4.2 million. This compares to funds from operations of $6.3 million and a loss of $3.0 million in the third quarter of 2007 and funds from operations of $27.3 million and $8.5 million in earnings during the second quarter of 2008. Natural gas prices were $7.86 per Mcf in the third quarter of 2008, compared to $5.00 per Mcf in the third quarter of 2007 and $10.26 per Mcf in the second quarter of 2008. Since the end of the quarter, natural gas prices have pulled back with October AECO spot prices being approximately $6.75 per Mcf as compared to an average of $7.34 per Mcf in the third quarter. Crude oil and natural gas liquids prices in the third quarter were $90.19 per bbl as compared to $63.31 per bbl in the third quarter of 2007. Current WTI oil prices are 50% lower than WTI oil prices experienced in the third quarter, however the Canadian dollar has also weakened relative to the U.S. dollar from 96 cents to 83 cents, which mitigates some of the oil price drop. The Company's operating netback was $34.34 per BOE in the third quarter of 2008 compared to $16.76 per BOE in the third quarter of 2007. The Company's operating expenses in the third quarter were $10.10 per BOE as compared to $11.83 per BOE in the third quarter of 2007 and $11.32 per BOE in the second quarter of 2008. This reduction in operating expenses is due to the new gas plant projects that came on stream early in the third quarter, the sale of a property with high operating expenses in the second quarter and reduced workovers in the current quarter.
Capital Program:
Capital expenditures were $27.1 million during the quarter, of which $17.8 million was spent on drilling and completions and $7.7 million on facilities.
In the third quarter, the Company drilled 39 gross (25.2 net) wells at a 92% success rate. Twenty gross (13.8 net) Edmonton Sands wells were drilled at a 95% success rate. In the deep drilling program, the Company drilled 11 gross (9.4 net) wells resulting in six deep gas wells, two oil wells, two dry holes and one potential gas well awaiting uphole completion. All of the deep gas and oil discoveries are slated to be tied in during the fourth quarter. The Company also participated in seven gross (1.3 net) outside operated CBM wells in the quarter.
As part of the deep program, the Company drilled three gross Rock Creek wells that initially tested at 2,400 Mcfd, 2,000 Mcfd and 1,200 Mcfd. A third party gas processing company is having a pipeline constructed into the Westpem area which is expected to be on stream in December. These three new wells, plus the Company's existing Westpem wells, some of which are currently shut-in, will be tied in to this pipeline when it is completed. The remainder of the Company's deep program is in the Willesden Green and Bigoray areas and the four wells that have been tied in to date are producing approximately 800 BOED. Although the wells drilled targeted infill development opportunities, we did encounter a new gas pool in Bigoray with a stabilized AOF of 13 MMcfd and a new light oil pool discovery in Willesden Green. The Willesden Green oil discovery is projected to be on stream at the end of this month.
The Company's Chedderville test is still ongoing and is expected to be completed this quarter.
The Company has commenced its Edmonton Sands winter drilling program and as of November 11, 2008, the Company has drilled 11 gross (6.3 net) wells.
Dispositions:
In the fourth quarter of 2008, the Company entered into letters of intent to sell four properties in Alberta and two in British Columbia for total proceeds of $18 million before adjustments. The property sales are projected to reduce 2009 production by approximately 330 BOED. The property sales are subject to the execution of definitive purchase and sale agreements and normal closing conditions and are expected to close in late 2008 or early 2009.
Outlook:
We have seen significant, unprecedented changes in capital, equity, commodity and currency markets in the past few months and ongoing concerns about the global credit crunch. The Company feels it is prudent to continue its fourth quarter Edmonton Sands capital program where possible to increase its exit production. To help finance the fourth quarter capital program, the Company is in the process of selling non-core, principally non-operated assets. However, commodity prices are weaker than originally forecasted and extremely volatile. The Company's original plan was to drill 200 gross (130 net) Edmonton Sands wells in the fourth quarter of 2008 and the first quarter of 2009. At this time, it appears the Company will drill approximately 123 gross (85 net) Edmonton Sands wells with most of the program deletions in the first quarter of 2009. Approximately 70% of the planned drilling for the winter program will be in the fourth quarter of 2008. The Company will evaluate the strength and direction of commodity prices at year end to determine if an upward or downward adjustment is warranted in the winter drilling program.
The Company feels it is most advantageous from an access, on stream timeliness and cost perspective to drill wells in the winter months, and to try to tie-in all wells drilled prior to spring breakup. This winter program is designed to do just that and avoid the problems that occur during wet summer months.
With the delay in well tie-ins, property dispositions and the Westpem third party production curtailment, the Company expects to produce approximately 7,800 BOED in 2008. The Company estimates that it will be producing more than 9,000 BOED by the end of the year.
The Company will be reviewing its 2009 capital and operating budgets and associated guidance in January 2009.
As of September 30, 2008, the Company has identified 1,144 gross (585 net) drilling locations, of which 88% are net Edmonton Sands locations and 7% are net Horseshoe Canyon Coal Bed Methane locations. Most of the drilling inventory consists of development locations.
The Company's Edmonton Sands drilling inventory is calculated based on four wells per section. When the Company elects to down space to six and eight wells per section, there would be a substantial increase in its drilling inventory.
Most of the Company's drilling inventory is low cost, lower productivity natural gas which at current prices attracts similar royalties under both the existing and proposed Alberta government royalty regimes. Therefore, the introduction of the new Alberta royalty framework in 2009 is not expected to have a significant impact on either the pace of the Company's activity or the intrinsic value of the drilling inventory.
The Company has grown its Edmonton Sands land position on a net section basis from 303 gross (179 net) sections at December 31, 2007 to 328 gross (198 net) sections as of November 1, 2008.
The Company is continuing to pursue Edmonton Sands farm-in opportunities and acquisition opportunities within its core area.
We encourage anyone interested in further details on our Company to visit our website at www.andersonenergy.ca.
Brian H. Dau, President and Chief Executive Officer
November 11, 2008 Anderson Energy Ltd.
Management's Discussion and Analysis
For the Three and Nine Months Ended September 30, 2008 and 2007:
The following discussion and analysis of financial results should be read in conjunction with the unaudited interim consolidated financial statements of Anderson Energy Ltd. ("Anderson Energy" or the "Company") for the three and nine months ended September 30, 2008 and 2007 and the audited consolidated financial statements and management's discussion and analysis of Anderson Energy for the years ended December 31, 2007 and 2006 and is based on information available as of November 11, 2008.
The following information is based on financial statements prepared by management in accordance with Canadian generally accepted accounting principles ("GAAP"). Production and reserves numbers are stated before deducting Crown or lessor royalties.
Included in the discussion and analysis are references to terms commonly used in the oil and gas industry such as funds from operations, finding, development and acquisition ("FD&A") costs and barrels of oil equivalent. Funds from operations as used in this report represent cash from operating activities before changes in non-cash working capital and asset retirement expenditures. See "Review of Financial Results - Funds from Operations" for details of this calculation. Funds from operations represent both an indicator of the Company's performance and a funding source for on-going operations. FD&A costs measure the cost of reserve additions and are an indicator of the efficiency of capital expended in the period. Production volumes and reserves are commonly expressed on a barrel of oil equivalent ("BOE") basis whereby natural gas volumes are converted at the ratio of six thousand cubic feet to one barrel of oil. The intention is to sum oil and natural gas measurement units into one basis for improved analysis of results and comparisons with other industry participants. These terms are not defined by Canadian GAAP and therefore are referred to as non-GAAP measures.
All references to dollar values are to Canadian dollars unless otherwise stated.
The abbreviations used in this discussion and analysis are located on the last page of this document.
Review of Financial Results Overview:
Sales volumes for the three months ended September 30, 2008 averaged 7,671 BOED, 44% higher than the same period in 2007 but slightly lower than the previous quarter due to plant outages and tie-in delays. The Company reported significantly improved operating expenses on a per barrel basis in the quarter due to the completion of construction on three gas plant projects. Funds from operations for the three months ended September 30, 2008 were $21.2 million, 3.4 times higher than 2007 but 22% lower than the previous quarter due to significantly lower commodity prices.
Capital expenditures were $27.1 million for the three months ended September 30, 2008. During the third quarter of 2008, the Company drilled 39 gross (25.2 net) wells, of which 36 gross (23.2 net) were successful. The Company spent $17.8 million on drilling and completion projects and $7.7 million on facilities in the quarter.
Debt, net of working capital, was $110.5 million at September 30, 2008, and was in line with expectations. The Company continues to plan to spend $117.0 million on its capital program in 2008, and to manage the impact of lower commodity prices on cash flows by agreeing to sell non-core properties in the fourth quarter of 2008. However, with the current uncertainty and volatility in world markets, the Company has revised its 2008-2009 winter drilling program downward from 200 gross wells to 123 gross wells, with the majority of the program deletions taking place in the first quarter of 2009.
Revenue and Production:
Gas sales comprised 84% of Anderson Energy's total oil and gas sales volumes for the three months ended September 30, 2008, consistent with the second quarter of 2008.
In the third quarter of 2008, gas sales volumes were 44% higher than the previous year. On a year to date basis, gas sales volumes were 64% higher than the previous year. The increases were due to asset acquisitions completed in 2007 and drilling successes. Gas sales volumes were 38.7 Mmcfd in the third quarter of 2008, which was slightly less than expected due to delays in well tie-ins and plant outages at various facilities in the month of September.
Oil sales for the three months ended September 30, 2008 averaged 434 bpd compared to 485 bpd in the third quarter of 2007 and 436 bpd in the second quarter of 2008. Oil sales for the nine months ended September 30, 2008 were 486 bpd, 7% lower than the first nine months of 2007 due largely to the sale of minor oil properties earlier in the year. The majority of the Company's oil production is from central and eastern Alberta.
Natural gas liquids sales for the three months ended September 30, 2008 averaged 787 bpd compared to 358 bpd for the third quarter of 2007 and 829 bpd in the second quarter of 2008. Natural gas liquids sales for the nine months ended September 30, 2008 averaged 791 bpd compared to 213 bpd for the first nine months of 2007. Development activity on the liquids rich assets acquired in the September 2007 acquisition contributed to the volume increases from 2007.
The following tables outline production revenue, volumes and average sales prices for the three and nine months ended September 30, 2008 and 2007.
Three months ended Nine months ended
September 30 September 30
------------------------------------------
Oil and Natural Gas Revenue 2008 2007 2008 2007
(thousands of dollars)
Natural gas $ 28,005 $ 12,361 $ 93,531 $ 42,557 Natural gas hedging gain (loss) - - (1,341) 1,157 Oil 4,478 2,947 13,930 8,376 NGL 5,650 1,963 17,701 3,274 Royalty and other 1,294 (10) 2,322 446
------------------------------------------
Total $ 39,427 $ 17,261 $ 126,143 $ 55,810
------------------------------------------
------------------------------------------
Production
Natural gas (Mcfd) 38,703 26,860 39,263 24,000
Oil (bpd) 434 485 486 520
NGL (bpd) 787 358 791 213
------------------------------------------
Total (BOED) 7,671 5,320 7,820 4,732
------------------------------------------
------------------------------------------
Prices Natural gas ($/Mcf) $ 7.86 $ 5.00 $ 8.57 $ 6.67 Oil ($/bbl) 112.18 66.03 104.70 59.03 NGL ($/bbl) 78.06 59.62 81.67 56.44 Total ($/BOE)(1) $ 55.87 $ 35.27 $ 58.87 $ 43.20
(1) Includes royalty and other income classified with oil and gas sales
Natural gas prices remain volatile. Anderson Energy's average gas sales price was $7.86 per Mcf for the three months ended September 30, 2008, 23% lower than the second quarter of 2008 price of $10.26 per Mcf and 57% higher than the third quarter of 2007 price of $5.00 per Mcf. Anderson Energy's average gas sales price was $8.57 per Mcf for the nine months ended September 30, 2008. In February and March of 2008, the Company had a fixed price natural gas sales contract for 25,000 GJ per day at $6.89 per GJ. This contract resulted in a $1.3 million loss in sales. The average gas price for the nine months ended September 30, 2008 was $8.69 per Mcf before this loss. Commodity prices have fallen dramatically since early summer in conjunction with the overall global economic crisis.
There were no physical or financial hedging contracts outstanding as at September 30, 2008.
Anderson Energy sells most of its gas at the daily or monthly index less associated transportation. The AECO 5A daily index was $7.34 per GJ for the three months ended September 30, 2008 compared to $9.68 per GJ in the second quarter of 2008 and $4.91 per GJ in the third quarter of 2007. Average gas prices received by the Company reflected market price changes.
The Company has classified all transportation costs as an offset to gas sales revenue as title transfers prior to transport on the applicable sales pipelines and transportation is being held by and charged by the gas purchasers. The Company has arranged firm service transportation agreements covering approximately 27.6 MMcfd of natural gas sales for various terms ranging from one to seven years.
Royalties:
Royalties were 20% of revenue for the three months ended September 30, 2008 compared to 19% for the third quarter of 2007 and 22% for the second quarter of 2008. Royalties were 22% of revenue for the nine months ended September 30, 2008 compared to 19% for the same period in 2007. Royalties in 2007 were reduced by credits related to prior period gas cost allowance assessments. In addition, royalty rates increased in the current year as a result of the higher rate gas wells and higher natural gas liquids yields associated with the wells acquired in the September 2007 acquisition and the prolific new wells that came on stream in the first quarter of 2008. Royalty expense on a BOE basis will vary with commodity prices.
On October 25, 2007, the Alberta government announced proposed significant upward revisions to the Crown royalty system. While the proposed changes are expected to have a negative impact on the oil and gas business as a whole, the impact on shallow gas programs is expected to be less than on other areas of the business. Anderson Energy believes that the proposed changes will only have a small impact on royalties at current production levels and prices. The changes do not negatively impact our long-term Edmonton Sands business strategy, as the focus is predominantly on shallow gas lower productivity wells. These changes are expected to come into effect on January 1, 2009 and are discussed further under "Business Risks".
Three months ended Nine months ended
Sept 30 Sept 30
------------------------------------------
2008 2007(1) 2008
2007(1)
------------------------------------------
Royalties (%) 20% 19% 22%
19%
Royalties ($/BOE) $ 11.43 $ 6.68 $ 12.76 $ 8.21
(1) lower than normal due to credits related to prior period gas cost
allowance assessments Operating Expenses:
Operating expenses were $10.10 per BOE for the three months ended September 30, 2008 compared to $11.83 per BOE in the third quarter of 2007 and $11.32 per BOE in the second quarter of 2008. Operating expenses were $11.19 per BOE for the nine months ended September 30, 2008 compared to $11.69 per BOE in the first nine months of 2007. The reduction in operating expenses in the third quarter of 2008 is due to the new gas plant projects that came on stream early in the quarter and started to reduce the Company's dependence on third party processing, as well as the sale of a property with high operating expenses in the second quarter and reduced workovers in the current quarter. The Company is continuing with the Chedderville Leduc A sour gas pool test in the fourth quarter, which is expected to have higher than average operating costs. The Chedderville test impacted third quarter operating expenses by approximately $0.20/BOE.
Operating Netback:
Three months ended Nine months ended
September 30 September 30
------------------------------------------
2008 2007 2008 2007
(thousands of dollars)
Revenue $ 39,427 $ 17,261 $ 126,143 $ 55,810
Royalties (8,070) (3,270) (27,344) (10,606)
Operating expenses (7,126) (5,788) (23,970) (15,098)
------------------------------------------
$ 24,231 $ 8,203 $ 74,829 $ 30,106
------------------------------------------
------------------------------------------
Sales (MBOE) 705.8 489.4 2,142.8 1,291.9
------------------------------------------
------------------------------------------
Per BOE
Revenue $ 55.87 $ 35.27 $ 58.87 $ 43.20
Royalties (11.43) (6.68) (12.76) (8.21)
Operating expenses (10.10) (11.83) (11.19) (11.69)
------------------------------------------
$ 34.34 $ 16.76 $ 34.92 $ 23.30
------------------------------------------
------------------------------------------
General and Administrative Expenses:
General and administrative expenses were $2.0 million or $2.90 per BOE for the three months ended September 30, 2008 compared to $1.6 million or $3.23 per BOE in the third quarter of 2007 and $1.8 million or $2.48 per BOE in the second quarter of 2008. General and administrative expenses were $5.4 million or $2.51 per BOE for the nine months ended September 30, 2008 compared to $4.9 million or $3.82 per BOE for the first nine months of 2007. General and administrative costs on a per BOE basis decreased from the same periods in the prior year as a result of increased production. General and administrative costs are expected to increase in the last quarter of 2008 as the Company has hired additional staff to manage its large upcoming winter drilling program.
Effective July 1, 2008, the Company initiated an Employee Stock Savings Plan ("ESSP"). Employees may contribute up to 5% of their base salaries towards the purchase of Company shares and the Company matches these contributions. Of eligible employees, over 93% are participating in the plan at an average contribution rate of 4.8% of base salary. The Company's matching expense for the three and nine months ended September 30, 2008 was $71,000 and is included in general and administrative expenses.
Three months ended Nine months ended
September 30 September 30
------------------------------------------
2008 2007 2008 2007
General and administrative (gross) $ 3,584 $ 2,565 $ 9,662 $ 8,015
Overhead recoveries (487) (326) (1,394) (1,055)
Capitalized (1,050) (656) (2,883) (2,028)
------------------------------------------
General and administrative (net) $ 2,047 $ 1,583 $ 5,385 $ 4,932
------------------------------------------
------------------------------------------
General and administrative ($/BOE) $ 2.90 $ 3.23 $ 2.51 $ 3.82
% G&A capitalized 29% 26% 30% 25%
Capitalized general and administrative costs are limited to salaries and associated office rent of staff involved in capital activities.
Stock Based Compensation:
The Company accounts for stock-based compensation plans using the fair value method of accounting. Stock-based compensation costs were $0.4 million for the third quarter of 2008 ($0.2 million net of amounts capitalized) versus $0.3 million ($0.2 million net of amounts capitalized) in the third quarter of 2007. Stock-based compensation costs were $1.3 million for the first nine months of 2008 ($0.7 million net of amounts capitalized) versus $0.8 million ($0.4 million net of amounts capitalized) in the first nine months of 2007. The increase is a result of additional stock options being granted to new and existing staff members.
Interest Expense:
Interest expense was $1.0 million for the third quarter of 2008, compared to $1.2 million in the second quarter of 2008 and $0.6 million in the third quarter of the prior year. Interest expense was $3.4 million for the first nine months of 2008, compared to $1.6 million in comparable period in 2007. The increase in interest expense is due to the higher debt levels associated with the growth of the Company. Assets acquired in the second half of 2007 were also partially financed with debt. The average effective interest rate on outstanding bank loans was 4.7% for the three months ended September 30, 2008 compared to 6.1% for the three months ended September 30, 2007 and 5.1% for the nine months ended September 30, 2008 compared to 5.9% for the nine months ended September 30, 2007.
Depletion and Depreciation:
Depletion and depreciation was $20.28 per BOE for the third quarter of 2008 compared to $20.15 per BOE in the second quarter of 2008 and $20.75 per BOE in the third quarter of 2007. Depletion and depreciation was $20.21 per BOE for the first nine months of 2008 compared to $21.06 per BOE in the first nine months of 2007. Depletion and depreciation expense is calculated based on proved reserves only.
Asset Retirement Obligation:
The Company recorded $1.2 million in asset retirement obligations in the third quarter of 2008 and $3.0 million in the first nine months of 2008. Accretion expense was $0.5 million for the third quarter of 2008 compared to $0.4 million in the third quarter of 2007, and $1.4 million for the first nine months of 2008 compared to $0.9 million in the first nine months of 2007. Accretion expense was included in depletion and depreciation expense and increased due to new drilling, facilities construction and acquisitions.
Income Taxes:
Anderson Energy is not currently taxable. The Company has approximately $288 million in tax pools at September 30, 2008 and does not expect to be currently taxable in the near future based on current capital spending and price forecasts.
Funds from Operations:
Funds from operations for the third quarter of 2008 were $21.2 million ($0.24 per share), a 167% increase on a per share basis over the $6.3 million ($0.09 per share) recorded in the same period of the prior year and 23% lower on a per share basis than the $27.3 million ($0.31 per share) recorded in the second quarter of 2008. Funds from operations for the first nine months of 2008 were $66.1 million ($0.76 per share) compared to $23.9 million ($0.39 per share) recorded in the same period of the prior year. The increase in funds from operations is a result of higher production and higher commodity prices in 2008, partially offset by higher expenses.
Cash from operating activities also increased year over year for similar reasons. The reduction in non-cash working capital in the third quarter of 2008 reflects lower revenue accruals due to lower commodity prices when compared to the previous quarter.
Three months ended Nine months ended
September 30 September 30
(thousands of dollars) 2008 2007 2008 2007
------------------------------------------
Cash from operating activities $ 26,351 $ 5,801 $ 71,427 $ 23,149 Changes in non-cash working capital (5,656) 68 (5,956) 9 Asset retirement expenditures
517 386 653 692
------------------------------------------
Funds from operations $ 21,212 $ 6,255 $ 66,124 $ 23,850
------------------------------------------
------------------------------------------
Earnings:
The Company reported earnings of $4.2 million in the third quarter of 2008 compared to a loss of $3.0 million in the third quarter of 2007 and earnings of $8.5 million in the second quarter of 2008. The Company reported earnings of $14.4 million in the first nine months of 2008 compared to a loss of $2.7 million in the first nine months of 2007. Earnings were impacted by higher production and changes in commodity prices.
The Company's funds from operations and earnings are highly sensitive to changes in factors that are beyond its control. An estimate of the Company's sensitivities to changes in commodity prices, exchange rates and interest rates is summarized below:
Funds from Operations Earnings
Sensitivities: Millions Per Share Millions Per Share
------------------------------------------
$0.50/Mcf in price of natural gas $ 6.6 $ 0.08 $ 4.6 $ 0.05 US $5.00/bbl in the WTI crude price $ 1.8 $ 0.02 $ 1.3 $ 0.01 US $0.01 in the U.S./Cdn exchange
rate $ 1.4 $ 0.02 $ 1.0 $ 0.01 1% in short-term interest rate $ 1.1 $ 0.01 $ 0.8 $ 0.01
Capital Expenditures
The Company spent $27.1 million on capital expenditures in the third quarter of 2008 and $79.2 million in the nine months ended September 30, 2008. The breakdown of expenditures is shown below:
Three months ended Nine months ended
(thousands of dollars) September 30, 2008 September 30, 2008
---------------------------------------
Land, geological & geophysical
costs $ 395 $ 1,044
Property acquisitions, net of
dispositions 18
(857)
Drilling, completion and recompletion 17,831 42,362 Facilities and well equipment 7,724 33,612 Capitalized G&A 1,050 2,883
---------------------------------------
Total oil and natural gas expenditures 27,018 79,044 Office equipment and furniture 50 155
---------------------------------------
Total capital expenditures 27,068 79,199
Non-cash asset retirement obligations
and capitalized stock based
compensation 1,451 3,621
---------------------------------------
Total cash and non-cash capital
additions $ 28,519 $ 82,820
---------------------------------------
---------------------------------------
Drilling statistics are shown below:
Three months ended Nine months ended
September 30 September 30
----------------------------------------------------------
2008 2007 2008 2007
Gross Net Gross Net Gross Net Gross Net
Gas 34.0 21.2 29.0 20.1 110.0 75.2 69.0 45.8
Oil 2.0 2.0 2.0 0.7 6.0 2.9 5.0 2.2
Dry 3.0 2.0 3.0 2.5 10.0 8.1 8.0 4.7
----------------------------------------------------------
Total 39.0 25.2 34.0 23.3 126.0 86.2 82.0 52.7
----------------------------------------------------------
----------------------------------------------------------
Success rate (%) 92% 92% 91% 89% 92% 91% 90% 91%
During the third quarter of 2008, the Company participated in the drilling of 39 gross (25.2 net) wells of which 36 gross (23.2 net) were successful. The Company spent $7.7 million on facilities, which was comprised of the completion of three plant projects that were initiated in the second quarter and some well tie-ins.
Share Information
The Company's shares have been listed on the Toronto Stock Exchange since September 7, 2005 under the symbol "AXL". As of November 11, 2008, there were 87.3 million common shares outstanding and 7.6 million stock options outstanding. The Company's market capitalization at November 11, 2008 was $154.5 million.
Three months ended Nine months ended
September 30 September 30
Share Price on TSX 2008 2007 2008 2007
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High $ 5.45 $ 4.97 $ 5.45 $ 5.40 Low $ 2.16 $ 3.67 $ 2.16 $ 3.35 Close $ 2.48 $ 3.74 $ 2.48 $ 3.74 Volume 13,233,544 10,405,724 66,274,841 27,341,078
Shares outstanding
at Sept 30 87,300,401 87,294,401 87,300,401 87,294,401
Market
capitalization at
Sept 30 $ 216,504,994 $ 326,481,060 $ 216,504,994 $ 326,481,060
Goodwill Assessment
No impairment in goodwill was assessed at September 30, 2008 based on the Company's estimate of net asset value. The assessment will be reviewed again at year end in light of more information on the longer term implications of global market conditions.
Liquidity and Capital Resources
At September 30, 2008, the Company had outstanding bank loans of $82.2 million and a working capital deficiency of $28.3 million. The large working capital deficiency is due to accruals associated with the capital program as well as operating expenses accrued but not yet billed.
The Company's 2008 capital program anticipates spending approximately $117 million in the field. This program is expected to be funded with a combination of debt, cash flow and property dispositions. To the end of the third quarter, the Company has sold $0.8 million in properties. In the fourth quarter of 2008, the Company has entered into letters of intent to sell $18 million in properties. With the significant, unprecedented changes in capital, equity, commodity and currency markets in the past few months and the ongoing concerns about the global credit crunch, the Company has reduced its originally planned 2008-2009 winter drilling program from 200 to 123 wells. The Company felt it was prudent to reduce its capital program given the uncertainty and volatility in world markets. Anderson Energy will continue to review the strength and direction of natural gas markets and the cost of services and make prudent adjustments to the winter drilling program as appropriate.
The Company's need for capital will be both short-term and long-term in nature. Short-term capital is required to finance accounts receivable and other similar short-term assets while the acquisition and development of oil and natural gas properties requires larger amounts of long-term capital. At September 30, 2008, the Company has a $110.0 million extendible revolving term credit facility, a $10.0 million working capital credit facility and a $10.0 million supplemental credit facility with a syndicate of Canadian banks. The supplemental facility will expire on June 30, 2009. Anderson Energy will prudently use its bank loan facilities to finance its operations as required. The Company expects to have adequate liquidity to fund future working capital and the remaining 2008 capital expenditure program using a combination of cash flow, debt and asset sales.
Contractual Obligations
The Company enters into various contractual obligations in the course of conducting its operations. These obligations include:
- Loan agreements - These reserves-based credit facilities have a revolving period ending July 14, 2009 extendible at the option of the lenders, followed by a term period with three equal quarterly principal repayments commencing 180 days from the term date.
- Lease for office space - This lease expires on November 30, 2012. Future minimum lease payments are expected to be $0.4 million for the remainder of 2008, $1.8 million per year in 2009 through 2011, and $1.6 million in 2012.
- Firm service transportation commitments - The Company has entered into firm service transportation agreements for approximately 27.6 Mmcfd of gas sales for various terms expiring between 2008 and 2015.
In the fourth quarter of 2008, the Company entered into letters of intent to sell four properties in Alberta and two in British Columbia for total proceeds of $18 million before adjustments. The property sales are projected to reduce 2009 production by approximately 330 BOED. The property sales are subject to the execution of definitive purchase and sale agreements and normal closing conditions and are expected to close in late 2008 or early 2009.
Changes in Accounting Policies
On January 1, 2008, the Company adopted Section 1535 "Capital Disclosures". This section requires a discussion of the Company's objectives, policies and processes for managing capital including: quantitative data about what is considered capital, whether the entity has complied with any capital requirements and the consequences of non-compliance if the entity has not complied. These disclosures are included in note 5 of the accompanying consolidated financial statements.
On January 1, 2008, the Company also adopted the new Canadian standards for financial instruments: Section 3862 "Financial Instruments - Disclosures" and Section 3863 "Financial Instruments - Presentation", which apply to both recognized and unrecognized financial instruments. These disclosures include a discussion of the nature and extent of risks arising from financial instruments and are included in note 7 of the accompanying consolidated financial statements.
International Financial Reporting Standards ("IFRS")
In February 2008, the CICA Accounting Standards Board ("AcSB") confirmed the changeover to International Financial Reporting Standards ("IFRS") from Canadian GAAP will be required for publicly accountable enterprises' interim and annual financial statements effective for fiscal years beginning on or after January 1, 2011. The AcSB issued the "omnibus" exposure draft of IFRS with comments due by July 31, 2008, wherein early adoption by Canadian entities is also permitted. The Canadian Securities Administrators have also issued Concept Paper 52-402, which requested feedback on the early adoption of IFRS as well as the continued use of US GAAP by domestic issuers. The eventual changeover to IFRS represents a change due to new accounting standards. The transition from current Canadian GAAP to IFRS is a significant undertaking that may materially affect the Company's reported financial position and results of operations.
The International Accounting Standards Board issued an exposure draft on September 25, 2008, relating to certain amendments and exemptions to IFRS 1. One such exemption relating to full cost oil and gas accounting is expected to reduce the administrative burden in the transition from the current Canadian Accounting Guideline 16 to IFRS. It is anticipated that this exposure draft will not result in an amended IFRS 1 standard until late 2009. The amendment will permit the Company to apply IFRS prospectively to their full cost pool, rather than the retrospective assessment of capitalized exploration and development expenses, with the proviso that an impairment test, under IFRS standards, be conducted at the transition date.
Although, the Company has not completed development of its IFRS changeover plan, when finalized, it will include project structure and governance, resourcing and training, an analysis of key GAAP differences and a phased plan to assess accounting policies under IFRS as well as potential IFRS 1 exemptions. The Company anticipates completing its project scoping, which will include a timetable for assessing the impact on data systems, internal controls over financial reporting, and business activities, such as financing and compensation arrangements, by the end of 2008.
Disclosure Controls and Procedures
There were no material changes in the Company's internal controls over financial reporting during the nine months ended September 30, 2008.
Effective December 31, 2008, the Company will be required to certify on the operating effectiveness of internal controls over financial reporting. The Company is currently working on testing its controls to be able to provide this certification.
Business Risks
Oil and gas exploration and production is capital intensive and involves a number of business risks including the uncertainty of finding new reserves, the instability of commodity prices, weather and various operational risks. Commodity prices are influenced by local and worldwide supply and demand, the U.S. dollar exchange rate, transportation costs, political stability and seasonal and weather related changes to demand. The industry is subject to extensive governmental regulation with respect to the environment. Operational risks include well performance, uncertainties inherent in estimating reserves, timing of/ability to obtain drilling licences and other regulatory approvals, ability to obtain equipment, expiration of licences and leases, competition from other producers, sufficiency of insurance, ability to manage growth, reliance on key personnel, third party credit risk and appropriateness of accounting estimates. These risks are described in more detail in the Company's Annual Information Form filed with Canadian securities regulatory authorities on SEDAR.
Anderson Energy manages these risks by employing competent professional staff, following sound operating practices and using capital prudently. The Company generates its exploration prospects internally and performs extensive geological, geophysical, engineering, and environmental analysis before committing to the drilling of new prospects. Anderson Energy seeks out and employs new technologies where possible. With the Company's extensive drilling inventory and advance planning, the Company can manage the slower pace of regulatory approvals and the requirements for extensive landowner consultation.
The Company has a formal emergency response plan which details the procedures employees and contractors will follow in the event of an operational emergency. The emergency response plan is designed to respond to emergencies in an organized and timely manner so that the safety of employees, contractors, residents in the vicinity of field operations, the general public and the environment are protected. A corporate safety program covers hazard identification and control on the jobsite, establishes Company policies, rules and work procedures and outlines training requirements for employees and contract personnel.
The Company currently deals with a small number of buyers and sales contracts, and ensures those buyers are an appropriate credit risk. The Company continuously evaluates the merits of entering into fixed price or financial hedge contracts for price management.
Canada is a signatory to the United Nations Framework Convention on Climate Change and has ratified the Kyoto Protocol established thereunder to set legally binding targets to reduce nation-wide emissions of carbon dioxide, methane, nitrous oxide and other "greenhouse gases". In response to the Kyoto Protocol, the Canadian federal government introduced the Regulatory Framework for Air Emissions (the "Regulatory Framework") for regulating air pollution and industrial greenhouse gas ("GHG") emissions by establishing mandatory emissions reduction requirements on a sector basis. Sector-specific regulations are expected to come into force in 2010 and targets would be based on percentages rather than absolute reductions. The Regulatory Framework also proposes a credit emissions trading system. Additionally, regulation can take place at the provincial and municipal level. For example, Alberta introduced the Climate Change and Emissions Management Act, which provides a framework for managing GHG emissions by reducing specific gas emissions relative to gross domestic product to an amount that is equal to or less than 50% of 1990 levels by December 31, 2020 and which imposes duties to report. The accompanying regulation, the Specified Gas Emitters Regulation, effective July 1, 2007, requires mandatory emissions reductions through the use of emissions intensity targets. The Canadian federal government proposes to enter into equivalency agreements with provinces that establish a regulatory regime to ensure consistency with the federal plan, but the success of any such plan is doubtful in the current political climate, leaving multiple overlapping levels of regulation. Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not possible to predict the impact of the requirements on Anderson Energy and its operations and financial condition.
On October 25, 2007, the Alberta government announced proposed changes to the Alberta Crown royalty system that are expected to come into effect on January 1, 2009. The net impact on the Company will be higher royalties paid on natural gas liquids and crude oil. With 2007 natural gas prices, the Company would expect to pay lower Crown royalties on gas, as the Company is a low productivity per well producer. At natural gas prices in excess of $7.50 per Mcf, the Company would expect to pay higher Crown royalties on gas. Approximately 50% of the Company's royalties were paid to the Alberta Crown in 2007 and as such would have been affected by the changes.
Business Prospects
The Company has an excellent future drilling inventory with over five years of development drilling locations in its core resource plays, the Sylvan Lake Edmonton Sands and Horseshoe Canyon Coal Bed Methane.
Anderson Energy currently plans to drill 233 gross (145 net) wells in 2008, with the Edmonton Sands project representing 88% of the net drilling program. The 2008 capital budget is heavily weighted to the first and fourth quarters of the year to take advantage of lower costs on frozen ground conditions. The Company has completed three natural gas plant projects and brought these facilities on stream near the end of the second quarter, which is contributing to a reduction in operating expenses in the second half of the year. In addition, the Company continuously works with its suppliers and service companies to bring the cost of services down. The Company will continue to expand its drilling inventory through acquisitions and/or farm-ins in central Alberta.
The Company's 2008 average production guidance estimate has been reduced by 5% to approximately 7,800 BOED. This revision in guidance is due to less production than anticipated in the third quarter, delays in well tie-ins and third party curtailments in the Westpem area. Estimated 2008 guidance is a 46% increase over 2007 average production. Risks associated with this guidance include gas plant capacity, regulatory issues, weather problems and access to winter services.
Quarterly Information
The following table provides financial and operating results for the last eight quarters. The $117.6 million acquisition completed in September 2007 had a significant impact on capital spent in 2007 and on operating results in the fourth quarter of 2007 and first nine months of 2008. Commodity prices have been volatile since that time, which has had a significant impact on quarterly funds from operations and earnings.
SELECTED QUARTERLY INFORMATION
($ amounts in thousands, except per share amounts and prices)
Q3 2008 Q2 2008 Q1 2008 Q4 2007
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Oil and gas revenue before
royalties $ 39,427 $ 49,021 $ 37,695 $ 27,775 Funds from operations $ 21,212 $ 27,321 $ 17,591 $ 12,564
Funds from operations per share
Basic $ 0.24 $ 0.31 $ 0.20 $ 0.14 Diluted $ 0.24 $ 0.31 $ 0.20 $ 0.14 Earnings $ 4,160 $ 8,509 $ 1,696 $ 4,867 Earning per share Basic $ 0.05 $ 0.10 $ 0.02 $ 0.06 Diluted $ 0.05 $ 0.10 $ 0.02 $ 0.06
Capital expenditures, including
acquisitions net of dispositions $ 27,068 $ 16,772 $ 35,359 $ 30,300
Cash from operating activities $ 26,351 $ 27,660 $ 17,416 $ 11,110
Daily sales
Natural gas (Mcfd) 38,703 39,881 39,210 35,672
Liquids (bpd) 1,221 1,265 1,345 1,150
BOE (bpd) 7,671 7,912 7,879 7,095
Average prices
Natural gas ($/Mcf) $ 7.86 $ 10.26 $ 7.55 $ 6.09
Liquids ($/bbl) $ 90.19 $ 97.61 $ 83.91 $ 72.28
BOE ($/BOE) $ 55.87 $ 68.08 $ 52.57 $ 42.55
Q3 2007 Q2 2007 Q1 2007 Q4 2006
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Oil and gas revenue before
royalties $ 17,261 $ 18,440 $ 20,109 $ 16,820 Funds from operations $ 6,255 $ 8,972 $ 8,623 $ 7,996
Funds from operations per share
Basic $ 0.09 $ 0.15 $ 0.16 $ 0.15 Diluted $ 0.09 $ 0.15 $ 0.16 $ 0.15 Earnings (loss) $ (3,018) $ 368 $ (33) $ 846 Earning (loss) per share Basic $ (0.04) $ 0.01 $ - $ 0.02 Diluted $ (0.04) $ 0.01 $ - $ 0.02
Capital expenditures, including
acquisitions net of dispositions $ 135,966 $ 17,586 $ 27,281 $ 20,662 Cash from operating activities $ 5,801 $ 8,943 $ 8,405 $ 8,651 Daily sales Natural gas (Mcfd) 26,860 22,928 22,162 21,075 Liquids (bpd) 843 602 750 692 BOE (bpd) 5,320 4,423 4,444 4,205 Average prices Natural gas ($/Mcf) $ 5.00 $ 7.25 $ 8.14 $ 6.82 Liquids ($/bbl) $ 63.31 $ 58.18 $ 52.59 $ 51.09 BOE ($/BOE) $ 35.27 $ 45.81 $ 50.28 $ 43.48 Advisory
Certain information regarding Anderson Energy Ltd. in this news release including, without limitation, management's assessment of future plans and operations, number of locations in drilling inventory and wells to be drilled, timing of drilling and tie-in of wells and the costs thereof, productive capacity of the wells, timing of construction of facilities, expected production rates, dates of commencement of production, capital expenditures and timing thereof, value of undeveloped land, extent of reserve additions, ability to attain cost savings, drilling program success, impact of changes to the royalty regime applicable to the Company, commodity price outlook and future share performance, may constitute forward-looking statements under applicable securities laws and necessarily involve risks and assumptions made by management of the Company including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, capital expenditure costs, including drilling, completion and facilities costs, unexpected decline rates in wells, wells not performing as expected, incorrect assessment of the value of acquisitions, failure to realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect Anderson Energy's operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), at Anderson Energy's website (www.andersonenergy.ca). Furthermore, the forward-looking statements contained in this news release are made as at the date of this news release and Anderson Energy does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.
Disclosure provided herein in respect of barrels of oil equivalent (BOE) may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf: 1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
ANDERSON ENERGY LTD. Consolidated Balance Sheets (unaudited) (stated in thousands of dollars)
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September 30, December
31,
2008 2007
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Assets
Current assets:
Cash $ 1 $ 2
Accounts receivable and accruals 28,287 31,540
Prepaid expenses and deposits 2,990 2,522
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31,278 34,064
Property, plant and equipment (note 2) 501,614 461,896
Goodwill 35,364 35,364
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$ 568,256 $ 531,324
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Liabilities and Shareholders' Equity
Current liabilities:
Accounts payable and accruals $ 59,623 $ 62,915
Bank loans (note 3) 82,190 67,981 Asset retirement obligations (note 4) 28,366 24,526 Future income taxes 47,967 41,450 ----------------------------------------------------------------------------
218,146 196,872
Shareholders' equity:
Share capital (note 5) 334,176 334,147
Contributed surplus (note 5) 3,269 2,005
Retained earnings (deficit) 12,665 (1,700)
350,110 334,452
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