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Anderson Energy Ltd. TSX: AXL 
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Aug 14, 2006 18:26 ET
Anderson Energy Ltd. Announces Second Quarter 2006 Results
CALGARY, ALBERTA--(CCNMatthews - Aug. 14, 2006) - Anderson Energy Ltd. ("Anderson Energy" or "the Company") (TSX:AXL) is pleased to announce its operating and financial results for the second quarter ended June 30, 2006.
Highlights:
- As of August 14, 2006, approximately 4.2 MMcfd of the Company's production that was shut-in due to the explosion and fire at the Sylvan Lake gas plant on July 4, 2006 has resumed production through various facilities. An additional 0.8 MMcfd is estimated to be onstream within ten days and the remaining 0.9 MMcfd is estimated to be onstream within eight weeks.
- Second quarter production averaged 4,160 BOED, an increase of 2% over the first quarter of 2006 and 152% over the comparable quarter in 2005. Current production is approximately 4,000 BOED and production behind pipe and shut-in due to facility outages is approximately 1,600 BOED.
- As of June 30, 2006, the Company's drilling inventory is approximately 1,000 gross (394 net) wells. The Edmonton Sands play represents 67% of the net inventory and Horseshoe Canyon coal bed methane projects represent 26% of the net inventory. The Company has added, through land acquisitions and farm-in deals, 34 gross (20.5 net) sections of Edmonton Sands prospective land, a 29% net increase since December 31, 2005.
- Cash flow from operations in the second quarter of 2006 is $6.7 million or $0.14 per share, a decrease of $1.9 million or $0.04 per share over the first quarter of 2006 and a $3.8 million increase over the comparable quarter in 2005.
- The average natural gas price for the second quarter was $6.05/Mcf which is $1.35/Mcf lower than the first quarter of 2006 and $1.23/Mcf lower than the comparable quarter in 2005.
- Drilling for the three months ended June 30, 2006 resulted in 16 gross (9.2 net) wells drilled with a success rate of 94%.
- The Company has completed, or is expected to close shortly, 17 property consolidation transactions in 2006. Properties were acquired for 943,791 shares worth $6.8 million and $2.6 million in cash, and properties were sold for $12.8 million in cash. The net impact of acquisition and disposition activity is net proceeds of $3.4 million and positive reserve gains with F&D&A costs (including future development capital) of $9.70/BOE proved and $8.04/BOE proved plus probable.
Financial and Operating Highlights
Three months ended %
June 30 Change
--------------------
2006 2005
--------- ---------
Financial
(thousands of dollars, except share data)
Total oil and gas revenue $ 15,452 $ 6,646 133%
Cash flow from operations $ 6,728 $ 2,942 129%
Per common share - basic $ 0.14 $ 0.09 56%
- diluted $ 0.13 $ 0.09 44%
Net earnings (loss) (1,675) (801) (109%)
Per common share - basic $ (0.03) $ (0.02) (50%)
- diluted $ (0.03) $ (0.02) (50%)
Capital expenditures 16,653 11,590 44%
Debt, net of working capital
Shareholders' equity
Average shares outstanding (thousands)
Basic 49,108 33,625 46%
Diluted 50,054 34,531 45%
Ending shares outstanding (thousands) 49,305 33,625 47%
Operating (6 Mcf:1bbl conversion)
Average daily sales
Natural gas (Mcfd) 21,664 9,623 125%
Light/medium crude oil (bpd) 379 15 2427%
NGL (bpd) 170 35 386%
Barrels of oil equivalent (BOED) 4,160 1,653 152%
Average sales price
Natural gas ($/Mcf) 6.05 7.28 (17%)
Light/medium crude oil ($/bbl) 67.91 55.95 21%
NGL ($/bbl) 68.80 54.00 27%
Barrels of oil equivalent ($/BOE) 40.50 43.98 (8%)
Royalties ($/BOE) 9.13 8.33 10%
Operating costs ($/BOE) 9.96 10.89 (9%)
Operating netbacks ($/BOE) 21.73 24.94 (13%)
General and administrative ($/BOE) 3.23 5.69 (43%)
Wells drilled (gross) 16 11 45%
Six months ended %
June 30 Change
--------------------
2006 2005
--------- ---------
Financial
(thousands of dollars, except share data)
Total oil and gas revenue $ 32,341 $ 11,912 171%
Cash flow from operations $ 15,332 $ 5,523 178%
Per common share - basic $ 0.31 $ 0.16 94%
- diluted $ 0.31 $ 0.16 94%
Net earnings (loss) (2,871) (1,574) (82%)
Per common share - basic $ (0.06) $ (0.05) (20%)
- diluted $ (0.06) $ (0.05) (20%)
Capital expenditures 50,373 32,135 57%
Debt, net of working capital 50,043 8,234 (508%)
Shareholders' equity 186,615 97,686 91%
Average shares outstanding (thousands)
Basic 48,693 33,603 45%
Diluted 49,703 34,516 44%
Ending shares outstanding (thousands) 49,305 33,625 47%
Operating (6 Mcf:1bbl conversion)
Average daily sales
Natural gas (Mcfd) 21,234 8,898 139%
Light/medium crude oil (bpd) 421 10 4110%
NGL (bpd) 161 29 455%
Barrels of oil equivalent (BOED) 4,121 1,522 171%
Average sales price
Natural gas ($/Mcf) 6.71 7.13 (6%)
Light/medium crude oil ($/bbl) 58.87 57.23 3%
NGL ($/bbl) 60.22 52.54 15%
Barrels of oil equivalent ($/BOE) 42.92 43.07 -
Royalties ($/BOE) 9.75 8.52 14%
Operating costs ($/BOE) 9.28 9.32 -
Operating netbacks ($/BOE) 24.33 25.40 (4%)
General and administrative ($/BOE) 3.19 5.93 (46%)
Wells drilled (gross) 54 37 46%
Production:
Second quarter production was less than anticipated due to significant plant outages in the quarter on various properties and pipeline breaks on two properties. Unanticipated plant turnarounds, outages and NOVA pipeline work, impacted the Company's production at Sylvan Lake, Bellshill, David North, Pembina and Prevo. In addition, the Company experienced a pipeline break at the operated Edberg oil battery which shut-in the facility for six weeks. The pipeline has since been repaired and has resumed operation. In the Sylvan Lake area, the Company's production was impacted for six weeks in the quarter with a pipeline break in a third party pipeline near the 13-32 compressor station. The pipeline operator shut-in other pipelines in the area to review pipeline integrity. This caused additional volumes to be shut-in during the quarter. The 13-32 pipeline is being repaired and should be operational in the third quarter. The pipeline integrity review is complete and that production has resumed.
In the second quarter, the Company experienced an extended spring breakup and a wet June which delayed well tie-in operations. In 2006, the Company commenced tie-in operations in late June, while in the previous year the Company was able to conduct these operations in the Sylvan Lake area earlier in the quarter.
Subsequent Event - Sylvan Lake Gas Plant Explosion and Fire:
Early in the third quarter, there was an explosion and fire at the Focus Energy Trust Sylvan Lake Gas Plant. This impacted approximately 5.9 MMcfd of the Company's production that is custom processed at this gas plant. As of August 14, 2006, the Company has managed to bring back on 71% of the shut-in volumes through an undamaged portion of the Sylvan Lake Gas plant and through other gas processing facilities in the immediate area. The Company estimates that it might take an additional two to eight weeks to return the remaining volumes to production. Shortly after the incident, the Company suspended all of its drilling, completion and well tie-in operations in the vicinity of the Sylvan Lake Gas Plant until the gas plant fully resumes operations and when the gas plant can accept more volume. Unfortunately, this had a negative impact on 2006 production guidance as the operations proximal to this plant have been delayed for two to three months, and they represent the shortest cycle time projects available to the Company. The Company was able to substitute some of its fourth quarter Edmonton Sands drilling projects that would not be custom processed by the Sylvan Lake plant into the third quarter, but these projects have inherently longer cycle times.
Current production is approximately 4,000 BOED with 1,600 BOED of production behind pipe and shut-in due to facility outages. Included in the 1,600 BOED estimate is 280 BOED of production shut-in due to the Sylvan Lake incident, and 215 BOED of behind pipe awaiting connection to the Sylvan Lake gas plant.
Operations:
In the second quarter, the Company spent $16.7 million in capital, of which $1.1 million was expended on net property acquisitions. The Company drilled 16 gross (9.2 net) wells with a success rate of 94%. Wet weather in June reduced the planned drilling program in the second quarter.
In the Sylvan Lake area, the Company drilled 12 gross (6.4 net gas wells). All of the Sylvan Lake wells were Edmonton Sands wells, except two gross (0.6 net) successful deeper exploratory tests that should be tied in for production in the third quarter. In other areas, the Company drilled a 92% working interest medium gravity oil well at Provost, a 37.5% working interest gas well at Greencourt and a 40% working interest gas well at Westlock. During the quarter, the Company evaluated different drilling technologies to drill Edmonton Sands wells and through these efforts believes that it can achieve continued cost savings in the magnitude of $20,000 per well drilled.
Acquisitions and Dispositions:
As of August 14, 2006, the Company has completed seven property acquisition transactions by issuing 943,791 common shares worth $6.8 million. Five of the transactions were producing property acquisitions where the Company acquired partner minority interests in former Aquest properties. The other two transactions were undeveloped land acquisitions in the Ghost Pine CBM project area. Two additional deals were done for cash totaling $2.6 million to acquire production and/or undeveloped land in the Sylvan Lake area.
As of August 14, 2006, the Company has completed the sale of, or is expected to close, eight transactions for a total of $12.8 million of property dispositions. Total estimated production sold is 120 BOED.
The net impact of acquisition and disposition activity was net proceeds of $3.4 million and positive reserve gains with F&D&A costs (including future development capital) of $9.70/BOE proved and $8.04/BOE proved plus probable. Through these transactions, the Company added 23 net drilling locations and increased its working interests in properties acquired as part of the Aquest Energy acquisition in 2005.
Capital Budget and Production Guidance:
The impact of second quarter plant outages, pipeline breaks and the Sylvan Lake gas plant incident has reduced the Company's 2006 average production guidance to 4,000 to 4,300 BOED. The Company's 2006 exit guidance is now 5,000 BOED and is net of dispositions of 120 BOED.
Projected capital spending for 2006 is approximately $68.0 million, including $6.8 million in property acquisitions completed by the issuance of Company shares, $2.6 million for cash acquisitions and net of $12.8 million for property dispositions. Spending for the remainder of the year is expected to be $26.1 million partially financed by $8.5 million in property dispositions that have closed or are expected to close in the third quarter.
Coal Bed Methane:
In the first half of the year, the Company drilled seven gross (2.1 net) CBM wells. These wells are expected to be tied in for production in the last half of the year. The Company forecasts that it will participate in 59 gross (11.6 net) CBM wells in the last half of the year in the Trochu/Ghost Pine Three Hills area. In the third quarter, the Company has drilled two gross (1.4 net) exploratory CBM wells in Southern Alberta and unfortunately both wells were dry and abandoned.
Outlook:
As of June 30, 2006, the Company has assembled a drilling inventory of approximately 1,000 gross (394 net) locations on its lands. Approximately 67% of the net locations are Edmonton Sands prospective, 26% are Horseshoe Canyon CBM development locations and the balance is distributed among the rest of the Company's projects. This represents a five year drilling inventory based on current plans. Since December 31, 2005, the Company has added 34 gross (20.5 net) sections of Edmonton Sands prospective lands in the Sylvan Lake area, for a total of 194 gross (90.3 net) sections as of August 14, 2006.
The warm winter conditions in January have had a negative impact on natural gas prices in 2006. The levels of natural gas storage are at historic summer highs. Natural gas prices may be soft until next winter. While the Company continues to be bullish on the long term prospects for natural gas, North American weather conditions, the geopolitics of crude oil pricing and North American production declines will determine summer gas prices. There is the potential for weaker gas prices near the end of the natural gas storage injection season, however, with the onset of winter, natural gas prices should strengthen.
The Company will continue to develop its Edmonton Sands drilling opportunities, including exploring for new Edmonton Sands prospective areas, and drilling on our CBM acreage and other prospects in North Central and Eastern Alberta. The Company expects to continue to consolidate its land holdings and conduct further dispositions.
The Company had a difficult second quarter due to production outages and pipeline breaks and expects to have less than previously forecast production in the third quarter due to the Sylvan Lake gas plant incident. One of the resolutions to the shut-in production problems related to the incident was to connect existing gas pipelines to alternative gas processing plants. This will benefit the Company longer term when its resumes drilling in the area impacted by the incident. The Company has a large production behind pipe inventory and fourth quarter drilling programs that will allow it to achieve significant production growth by year end.
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
August 14, 2006
Management's Discussion and Analysis For the Six Months Ended June 30, 2006 and 2005:
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 six months ended June 30, 2006 and 2005 and is based on information available as of August 14, 2006.
The following information is based on financial statements prepared by management in accordance with Canadian generally accepted accounting principles ("GAAP"). Production and reserve 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 cash flow from operations and barrel of oil equivalent. Cash flow from operations as used in this report represents cash from operating activities before changes in non-cash working capital and asset retirement expenditures. Anderson Energy believes that cash flow from operations represents both an indicator of the Company's performance and a funding source for on-going operations. 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.
Review of Financial Results:
Second quarter sales volumes were 4,160 BOED, which was lower than anticipated due to significant plant outages and pipeline breaks at various properties in the second quarter. This combined with an 18% decline in natural gas prices resulted in lower cash flow from operations than expected.
Revenue and Production:
Gas sales made up 77% of Anderson Energy's total oil and gas sales for the three months ended June 30, 2006 compared to 82% of total oil and gas sales for the first quarter of 2006 and 96% of total oil and gas sales for the three months ended June 30, 2005.
The Company achieved average gas sales of 21.7 MMcfd in the second quarter of 2006. This compares to 20.8 MMcfd in the first quarter of 2006 and 9.6 MMcfd in the second quarter of 2005. Sales volume increases are primarily attributable to new wells being tied-in in the quarter; however, they were also negatively impacted by unanticipated plant turnarounds, outages and pipeline work in the second quarter of 2006.
Early in the third quarter, there was an explosion and fire at the Focus Energy Trust Sylvan Lake Gas Plant. This impacted approximately 5.9 MMcfd of the Company's production that is custom processed at this gas plant. As of August 14, 2006, the Company has managed to bring back on 71% of the shut-in volumes through an undamaged portion of the Sylvan Lake Gas plant and through other gas processing facilities in the immediate area. The Company estimates that it might take an additional two to eight weeks to return the remaining volumes to production. This will have an impact on third quarter gas sales volumes.
Oil production averaged 379 bpd in the second quarter of 2006 as compared to 462 bpd in the first quarter of 2006 and 15 bpd in the second quarter of 2005. Oil production was down in the second quarter due to a pipeline break at Edberg. Natural gas liquids production averaged 170 bpd in the second quarter of 2006 as compared to 152 bpd in the first quarter of 2006 and 35 bpd in the second quarter of 2005.
The following tables outline production revenue, volumes and average sales prices for the three and six month periods.
Three months ended Six months ended
June 30 June 30
-------------------- -------------------
Oil and Natural Gas Revenue 2006 2005 2006 2005
(thousands of dollars)
Natural Gas $ 11,922 $ 6,371 $ 25,774 $ 11,485
Oil 2,344 77 4,482 107
NGL 1,066 170 1,757 271
Royalty and other 120 28 328 49
-------------------------------------------------------------
Total $ 15,452 $ 6,646 $ 32,341 $ 11,912
-------------------------------------------------------------
Production
Natural gas (Mcfd) 21,664 9,623 21,234 8,898
Oil (bpd) 379 15 421 10
NGL (bpd) 170 35 161 29
-------------------------------------------------------------
Total (BOED) 4,160 1,654 4,121 1,522
-------------------------------------------------------------
Prices
Natural gas ($/Mcf) 6.05 7.28 6.71 7.13
Oil ($/bbl) 67.91 55.95 58.87 57.23
NGL ($/bbl) 68.80 54.00 60.22 52.54
Total ($/BOE) 40.50 43.98 42.92 43.07
Anderson Energy's average gas sales price was $6.05/Mcf for the three months ended June 30, 2006. This compares to $7.40/Mcf realized in the first quarter of 2006 and $7.28/Mcf realized in the second quarter of 2005.
Anderson Energy sells most of its gas at Alberta spot market prices and has not entered into any fixed price or forward contracts for the sale of its production. 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.
Royalties:
Royalties were 22% of revenue in the second quarter of 2006, 23% of revenue in the first quarter of 2006 and 19% of revenue in the second quarter of 2005. The royalty rate in 2005 reflected a higher percentage of crown production and certain gas cost allowance adjustments. The Company expects 2006 royalties to increase overall as production increases. The average royalty rate on a percentage basis should be similar to the current quarter.
Operating Expenses:
Operating expenses were $9.96/BOE in the second quarter of 2006, $8.57/BOE for the first quarter of 2006 and $10.89/BOE for the second quarter of 2005. Workovers and prior period adjustments affected operating costs in the second quarter of 2006. Operating costs are expected to increase overall as production increases. Operating costs may increase on a BOE basis as well due to the increasing cost of doing business in western Canada.
Operating Netback:
Three months ended Six months ended
June 30 June 30
-------------------- -------------------
2006 2005 2006 2005
(thousands of dollars)
Revenue $ 15,452 $ 6,646 $ 32,341 $ 11,912
Royalties (3,456) (1,254) (7,270) (2,346)
Operating expenses (3,772) (1,640) (6,920) (2,569)
-------------------- -------------------
$ 8,224 $ 3,752 $ 18,151 $ 6,997
-------------------- -------------------
Sales (MBOE) 378.6 150.5 745.9 275.5
($/BOE)
Revenue $ 40.82 $ 44.16 $ 43.36 $ 43.24
Royalties (9.13) (8.33) (9.75) (8.52)
Operating expenses (9.96) (10.89) (9.28) (9.32)
-------------------- -------------------
$ 21.73 $ 24.94 $ 24.33 $ 25.40
-------------------- -------------------
General and Administrative Expenses:
General and administrative expenses were $3.23/BOE in the second quarter of 2006, $3.15/BOE in the first quarter of 2006 and $5.69/BOE in the second quarter of 2005. Total general and administrative expenses have increased as a result of increased staffing levels to manage the growth in drilling activity. General and administrative expenses consist largely of salaries, rent, computer and other office costs. As its production increases, general and administrative costs on a per BOE basis are expected to decline.
Three months ended Six months ended
June 30 June 30
-------------------- -------------------
2006 2005 2006 2005
General and administrative
(gross) $ 2,401 $ 1,244 $ 5,021 $ 2,335
Overhead recoveries (417) (189) (1,112) (301)
Capitalized (760) (199) (1,527) (400)
---------------------------------------------------- -------------------
General and administrative
(net) $ 1,224 $ 856 $ 2,382 $ 1,634
---------------------------------------------------- -------------------
General and administrative
($/BOE) $ 3.23 $ 5.69 $ 3.19 $ 5.93
% G&A capitalized 32% 16% 30% 17%
Capitalized general and administrative costs are limited to salaries and associated office rent of staff involved in capital activities.
Interest Expense:
Interest expense was $0.5 million in the second quarter and $0.3 million in the first quarter of 2006. Interest expense is expected to increase in future quarters as a result of higher debt levels associated with the Company's capital program and higher interest rates.
Depletion, Depreciation and Amortization:
Depletion and depreciation was $27.59/BOE in the second quarter of 2006, $26.98/BOE for the first quarter of 2006 and $27.38/BOE in the second quarter of 2005. Depletion and depreciation expense is calculated based on proved reserves only and is significantly impacted by the fact that only 53% of the Company's total reserves as of June 30, 2006 are proved reserves. The ratio reflects the newness of the wells that make up the reserve evaluation. The Company expects depletion and depreciation expense to remain high for the remainder of the year and until it can convert more of its probable reserves to proved reserves.
Asset Retirement Obligation:
As a result of new drilling, the Company incurred $0.7 million in asset retirement obligations in the second quarter of 2006. Accretion expense was $0.2 million for the second quarter of the year and was included in depletion and depreciation expense.
Income Taxes:
The Company is not currently taxable. The Company has approximately $179 million in available tax pools as of June 30, 2006.
The effect of enacted federal and provincial income tax rate reductions resulted in a $1.2 million reduction in the future tax provision in the second quarter. The provision for large corporations tax set up in the first quarter of 2006 was reversed in the second quarter with the federal government's elimination of the tax. Part XII.6 tax related to flow through shares issued is included in financing costs.
Cash Flow from Operations:
Cash flow from operations for the three months ended June 30, 2006 was $6.7 million, $8.6 million in the first quarter of 2006 and $2.9 million during the second quarter of 2005. The decrease in cash flow from the previous quarter was primarily due to the decrease in natural gas prices.
Earnings:
The Company reported a $2.9 million loss in the first half of 2006 largely due to high depletion and depreciation expense. The Company does not expect to be able to report significant earnings until it can convert more of its probable reserves to proved reserves. A large portion of the Company's capital spending is directed at developing probable undeveloped reserves in 2006.
Capital Expenditures:
The Company spent $50.4 million in capital additions for the first half of 2006. The breakdown of expenditures is shown below:
Six months ended
(thousands of dollars) June 30, 2006
------------------
Land, geological & geophysical costs $ 3,261
Property acquisitions, net of dispositions 4,809
Drilling, completion and recompletion 25,182
Facilities and well equipment 14,162
Office equipment and furniture 61
Capitalized G&A 1,527
Asset retirement costs 1,371
------------------
Total $ 50,373
------------------
In addition, a gross-up of capital costs and an associated future income tax liability of $3.1 million were recorded to reflect the fact that the property acquisitions for shares had minimal tax bases.
Drilling statistics are shown below:
Three months ended June 30 Six months ended June 30
---------------------------- ---------------------------
2006 2005 2006 2005
Gross Net Gross Net Gross Net Gross Net
Gas 14.0 7.3 9.0 4.3 44.0 20.3 33.0 20.0
Oil 1.0 0.9 - - 6.0 4.0 1.0 0.5
Dry 1.0 1.0 2.0 1.5 4.0 3.2 3.0 2.5
--------------------------------------------------------
Total 16.0 9.2 11.0 5.8 54.0 27.5 37.0 23.0
--------------------------------------------------------
Success rate (%) 94% 89% 82% 74% 93% 88% 92% 89%
For the second quarter of 2006, 81% of the gross wells drilled were in Sylvan Lake.
Liquidity and Capital Resources:
The Company expects to spend $17.6 million net of dispositions in capital in the rest of 2006. The Company's cash flow and bank lines are adequate to fund the program.
In May 2006, the Company renewed its revolving credit facility increasing the borrowing base to $55 million. The reserve-based credit facility has a revolving period ending July 15, 2007, extendible at the option of the lender, followed by a term period with three equal quarterly principle repayments commencing 180 days from the term date. The facility bears interest at the bank's prime lending rate, bankers' acceptance or LIBOR rates plus applicable margins. Loans are secured by a floating charge debenture over all assets and guarantees by material subsidiaries.
As of August 14, 2006, there are 49.3 million common shares outstanding and 4.2 million stock options outstanding.
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 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.
The Company 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. The Company seeks out and employs new technologies where possible.
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.
Business Prospects:
The Company has an excellent drilling inventory with over five years of development drilling locations. As a result of production outages and lower natural gas prices, capital spending has been cut back until prices improve.
Timing of AEUB regulatory applications continues to be slower than expected. Anderson Energy has incorporated these regulatory timing issues into its planning cycle. Competition for industry services has been more intense than previous years and that, combined with more landholder consultations, requires more lead time and more planning. Given the Company's extensive drilling inventory, we have been able to meet this challenge through advance planning of larger scale drilling programs and securing the services of drilling rigs and sourcing people for larger projects.
The Company's estimate for 2006 average production has been reduced to 4,100 to 4,300 BOED due to the impact of second quarter plant outages, pipeline breaks and the Sylvan Lake gas plant fire and explosion. Risks associated with this estimate include gas plant capacity, regulatory issues, weather problems and access to industry services.
The Company will continue to develop its Edmonton Sands drilling opportunities, including exploring for new Edmonton Sands prospective areas, drilling on its CBM acreage and other prospects in North Central and Eastern Alberta. The Company will likely continue to consolidate its land holdings and conduct further dispositions.
Quarterly Information:
(in thousands, except per share amounts)
Q2 2006 Q1 2006 Q4 2005 Q3 2005
---------- --------- --------- ---------
Oil & gas revenue before
royalties $ 15,452 $ 16,889 $ 22,894 $ 12,147
Cash flow from operations $ 6,728 $ 8,604 $ 13,187 $ 6,745
Cash flow from operations per
share
Basic $ 0.14 $ 0.18 $ 0.28 $ 0.18
Diluted $ 0.13 $ 0.17 $ 0.27 $ 0.17
Earnings (loss) $ (1,675) $ (1,196) $ 1,762 $ 543
Earnings (loss) per share
Basic $ (0.03) $ (0.02) $ 0.04 $ 0.01
Diluted $ (0.03) $ (0.02) $ 0.04 $ 0.01
Capital expenditures $ 16,653 $ 33,720 $ 25,634 $ 14,960
Daily sales
Natural gas (Mcfd) 21,664 20,799 18,785 11,991
Liquids (bpd) 549 614 577 250
BOE (bpd) 4,160 4,081 3,708 2,249
Average prices
Natural gas ($/Mcf) $ 6.05 $ 7.40 $ 11.39 $ 9.68
Liquids ($/bbl) $ 68.19 $ 51.15 $ 53.56 $ 61.97
BOE ($/BOE) $ 40.50 $ 45.41 $ 66.05 $ 58.49
Q2 2005 Q1 2005 Q4 2004 Q3 2004
---------- --------- --------- ---------
Oil & gas revenue before
royalties $ 6,646 $ 5,266 $ 4,170 $ 3,147
Cash flow from operations $ 2,942 $ 2,581 $ 2,132 $ 1,369
Cash flow from operations per
share
Basic $ 0.09 $ 0.08 $ 0.07 $ 0.05
Diluted $ 0.09 $ 0.07 $ 0.07 $ 0.05
Earnings (loss) $ (801) $ (773) $ (766) $ (323)
Earnings (loss) per share
Basic $ (0.02) $ (0.02) $ (0.03) $ (0.01)
Diluted $ (0.02) $ (0.02) $ (0.03) $ (0.01)
Capital expenditures $ 11,589 $ 20,545 $ 16,063 $ 14,035
Daily sales
Natural gas (Mcfd) 9,623 8,165 6,799 5,450
Liquids (bpd) 50 28 25 21
BOE (bpd) 1,653 1,389 1,159 929
Average prices
Natural gas ($/Mcf) $ 7.28 $ 6.96 $ 6.47 $ 6.08
Liquids ($/bbl) $ 54.59 $ 52.34 $ 51.19 $ 50.87
BOE ($/BOE) $ 43.98 $ 41.96 $ 39.08 $ 36.80
ADVISORY:
Certain information regarding Anderson Energy Ltd. in this new release including 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, productive capacity of the wells, timing of drilling, completion and construction of facilities, expected production rates, dates of commencement of production and capital expenditures and timing thereof, may constitute forward-looking statements under applicable securities laws and necessarily involve risks 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 effect Anderson'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'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 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)
------------------------------------------------------------------------
------------------------------------------------------------------------
June 30, December 31,
2006 2005
------------------------------------------------------------------------
Assets
Current assets:
Cash and short term investments $ 86 $ 510
Accounts receivable and accruals 20,722 31,303
Prepaid expenses and deposits 2,027 1,562
------------------------------------------------------------------------
22,835 33,375
Property, plant and equipment (note 1) 254,791 221,717
Goodwill 14,320 14,320
------------------------------------------------------------------------
$ 291,946 $ 269,412
------------------------------------------------------------------------
------------------------------------------------------------------------
Liabilities and Shareholders' Equity
Current liabilities:
Accounts payable and accruals $ 35,679 $ 46,420
Capital taxes payable - 184
------------------------------------------------------------------------
35,679 46,604
Bank loan (note 3) 37,199 11,368
Asset retirement obligations (note 2) 12,842 11,299
Future income taxes (note 5) 19,611 16,073
------------------------------------------------------------------------
105,331 85,344
Shareholders' equity:
Share capital (note 4) 189,431 184,315
Contributed surplus (note 4) 405 103
Deficit (3,221) (350)
------------------------------------------------------------------------
186,615 184,068
------------------------------------------------------------------------
$ 291,946 $ 269,412
------------------------------------------------------------------------
------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
ANDERSON ENERGY LTD.
Consolidated Statements of Operations and Deficit
(unaudited)
(stated in thousands of dollars, except per share amounts)
------------------------------------------------------------------------
------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
2006 2005 2006 2005
------------------------------------------------------------------------
Revenues
Oil and gas sales $ 15,452 $ 6,646 $ 32,341 $ 11,912
Royalties (net of ARTC of
$250, $205 in 2005) (3,456) (1,254) (7,270) (2,346)
Interest income 26 87 35 227
------------------------------------------------------------------------
12,022 5,479 25,106 9,793
Expenses
Operating 3,772 1,640 6,920 2,569
General and administrative 1,224 856 2,382 1,634
Interest and other financing
charges 547 16 775 21
Depletion, depreciation and
accretion 10,674 4,193 20,800 7,856
------------------------------------------------------------------------
16,217 6,705 30,877 12,080
------------------------------------------------------------------------
Loss before income taxes (4,195) (1,226) (5,771) (2,287)
Taxes
Capital taxes (90) 30 - 52
Future income taxes
(reduction) (note 5) (2,430) (455) (2,900) (765)
------------------------------------------------------------------------
(2,520) (425) (2,900) (713)
------------------------------------------------------------------------
Loss for the period (1,675) (801) (2,871) (1,574)
Deficit, beginning of period (1,546) (1,854) (350) (1,081)
------------------------------------------------------------------------
Deficit, end of period $ (3,221) $ (2,655) $ (3,221) $ (2,655)
------------------------------------------------------------------------
------------------------------------------------------------------------
Loss per share
Basic $ (0.03) $ (0.02) $ (0.06) $ (0.05)
Diluted $ (0.03) $ (0.02) $ (0.06) $ (0.05)
See accompanying notes to the consolidated financial statements.
ANDERSON ENERGY LTD.
Consolidated Statements of Cash Flows
(unaudited)
(stated in thousands of dollars)
------------------------------------------------------------------------
------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
2006 2005 2006 2005
------------------------------------------------------------------------
Cash provided by (used in):
Operations
Loss for the period $ (1,675) $ (801) $ (2,871) $ (1,574)
Items not involving cash
Depletion, depreciation
and accretion 10,674 4,193 20,800 7,856
Future income taxes
(reduction) (2,430) (455) (2,900) (765)
Stock based compensation 159 4 303 5
Asset retirement
expenditures (188) (27) (273) (187)
Changes in non-cash working
capital
Accounts receivable and
accruals 4,318 (409) 5,800 (385)
Prepaid expenses and
deposits (655) 10 (707) (44)
Accounts payable and
accruals (859) 1,386 (1,960) 1,657
Capital taxes payable (288) (16) (184) (14)
------------------------------------------------------------------------
9,056 3,885 18,008 6,549
Financing
Increase in bank loan 11,821 - 25,831 -
Issue of common shares 148 - 1,729 240
------------------------------------------------------------------------
11,969 - 27,560 240
Investments
Additions to property, plant
and equipment (15,010) (11,712) (46,693) (31,528)
Proceeds on sale of
properties 1,321 1,000 4,459 1,000
Changes in non-cash working
capital
Accounts receivable and
accruals 5,876 (3,558) 4,781 (3,547)
Prepaid expenses and
deposits 449 81 242 59
Accounts payable and
accruals (13,984) (4,503) (8,781) 2,179
------------------------------------------------------------------------
(21,348) (18,692) (45,992) (31,837)
------------------------------------------------------------------------
Decrease in cash (323) (14,807) (424) (25,048)
Cash and short-term
investments, beginning
of period 409 19,001 510 29,242
------------------------------------------------------------------------
Cash and short-term
investments,
end of period $ 86 $ 4,194 $ 86 $ 4,194
------------------------------------------------------------------------
------------------------------------------------------------------------
See accompanying notes to consolidated financial statements.
ANDERSON ENERGY LTD.
Notes to the Unaudited Interim Consolidated Financial Statements
For the six month period ended June 30, 2006 and 2005
(tabular amounts in thousands of dollars, unless otherwise stated)
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------------------------------------------------------------------------
Anderson Energy Ltd. ("Anderson Energy" or "the Company") is engaged in the acquisition, exploration and development of oil and gas properties in western Canada. These interim consolidated financial statements have been prepared following the same accounting policies and methods of computation as the consolidated financial statements for the year ended December 31, 2005. The disclosures included below are incremental to those included with the annual consolidated financial statements. These interim consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto for the year ended December 31, 2005.
1. Property, plant and equipment:
------------------------------------------------------------------------
------------------------------------------------------------------------
June 30, December 31,
2006 2005
------------------------------------------------------------------------
Cost $ 308,718 $ 255,289
Less accumulated depletion and depreciation (53,927) (33,572)
------------------------------------------------------------------------
Net book value $ 254,791 $ 221,717
------------------------------------------------------------------------
------------------------------------------------------------------------
At June 30, 2006, unproved property costs of $23.2 million (December 31, 2005 - $22.6 million) have been excluded from the full cost pool for depletion and depreciation calculations. Future development costs of proved, undeveloped reserves of $69.6 million (December 31, 2005 - $73.5 million) have been included for depletion, depreciation and impairment test calculations.
For the six months ended June 30, 2006, $1.5 million (June 30, 2005 - $400,000) of general and administrative costs were capitalized. Capitalized general and administrative costs consist of salaries and associated office rent of staff involved in capital activities.
No impairment was recognized under the ceiling test at June 30, 2006. The future commodity prices used in the ceiling test were based on commodity price forecasts adjusted for differentials specific to the reserves.
2. Asset retirement obligations:
The Company estimates the total undiscounted cash flows required to settle its asset retirement obligations is approximately $23.3 million, including expected inflation of 2% per annum. The majority of the costs will be incurred between 2006 and 2016. A credit adjusted risk-free rate of 8% was used to calculate the fair value of the asset retirement obligations.
A reconciliation of the asset retirement obligations is provided below:
------------------------------------------------------------------------
------------------------------------------------------------------------
June 30, December 31,
2006 2005
------------------------------------------------------------------------
Balance, beginning of period $ 11,299 $ 2,094
Liabilities incurred during period 1,371 3,338
Liabilities assumed on Aquest Energy
acquisition - 5,822
Liabilities settled in period (273) (310)
Accretion expense 445 355
------------------------------------------------------------------------
$ 12,842 $ 11,299
------------------------------------------------------------------------
------------------------------------------------------------------------
3. Bank loan:
In May 2006, the Company renewed its revolving credit facility with a Canadian bank, increasing the borrowing base to $55 million. The reserve-based credit facility has a revolving period ending July 15, 2007, extendible at the option of the lender, followed by a term period with three equal quarterly principle repayments commencing 180 days from the term date. Advances under the facility can be drawn in either Canadian or U.S. funds. The facility bears interest at the bank's prime lending rate, bankers' acceptance or LIBOR loan rates plus applicable margins. The margins vary depending on the borrowing option used and the Company's financial ratios. Loans are secured by a floating charge debenture over all assets and guarantees by material subsidiaries.
4. Share capital and contributed surplus:
Issued share capital
------------------------------------------------------------------------
------------------------------------------------------------------------
Number of
Common Amount
shares (thousands)
------------------------------------------------------------------------
Balance at December 31, 2005 47,967,708 $ 184,315
Stock options exercised 393,224 1,729
Transferred from contributed surplus on
stock option exercise - 1
Tax effect of flow-through share
renouncements - (3,382)
Issued on property acquisitions 943,791 6,768
------------------------------------------------------------------------
Balance at June 30, 2006 49,304,723 $ 189,431
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------------------------------------------------------------------------
Flow-through shares
Under flow-through share agreements entered into in 2005, the Company committed to incur $10,000,000 of qualifying expenditures by December 31, 2006. The renouncements were made February 28, 2006 with an effective date of December 31, 2005. At June 30, 2006, all of the qualifying expenditures had been made.
Stock options
The Company has an employee stock option plan under which employees, directors and consultants are eligible to receive grants. Changes in the number of options outstanding during the six month period ended June 30, 2006 are as follows:
------------------------------------------------------------------------
------------------------------------------------------------------------
Balance at December 31, 2005 4,179,355
Granted 714,000
Exercised (393,224)
Expirations and cancellations (266,040)
------------------------------------------------------------------------
Balance at June 30, 2006 4,234,091
------------------------------------------------------------------------
------------------------------------------------------------------------
The outstanding options at June 30, 2006 had an average exercise price of $5.14 per share and a weighted average remaining contractual life of 5.6 years; 2,693,791 of the options were exercisable at that date.
The fair value of the options issued in 2006 ranged between $1.56 to $2.07 per option. The weighted average assumptions used in arriving at these values were: a risk-free interest rate of between 4.0% to 4.5%, expected option life of 4 years, expected volatility of between 25% to 30% and a dividend yield of 0%.
Per share amounts
During the period ended June 30, 2006 there were 48,693,130 weighted average shares outstanding (June 30, 2005 - 33,603,120). On a diluted basis, there were 49,702,632 weighted average shares outstanding (June 30, 2005 - 34,516,451) after giving effect to dilutive stock options.
Contributed surplus
------------------------------------------------------------------------
------------------------------------------------------------------------
Amount
------------------------------------------------------------------------
Balance at December 31, 2005 $ 103
Stock based compensation 303
Transferred from contributed surplus on stock option exercise (1)
------------------------------------------------------------------------
Balance at June 30, 2006 $ 405
------------------------------------------------------------------------
------------------------------------------------------------------------
5. Taxes
In May 2006, the Company recorded a $1.2 million future tax benefit
related to enacted federal and provincial income tax rate reductions.
6. Cash payments
The following cash payments were made (received):
------------------------------------------------------------------------
------------------------------------------------------------------------
June 30, June 30,
2006 2005
------------------------------------------------------------------------
Interest paid $ 1,016 $ 2
Interest received (35) (246)
Taxes paid 304 110
------------------------------------------------------------------------
------------------------------------------------------------------------
7. Related party transactions:
At June 30, 2006, accounts receivable include $153,000 due from companies controlled by a director of the Company and accounts payable include $63,000 due to a company controlled by a director of the Company. The director was previously a director of Aquest Energy Ltd. (a company purchased by Anderson Energy in 2005) and the amounts arise as a result of common joint venture interests held by the director and Aquest Energy. The transactions have been recorded under the same terms and conditions as transactions with unrelated parties.
During the period ended June 30, 2006, the Company issued 943,791 common shares at an average price of $7.17 per share as consideration for the purchase of seven property acquisitions. Five of the transactions were producing property acquisitions where the Company acquired partner minority interests in former Aquest Energy properties. Three of the transactions were with companies controlled by a director of Anderson Energy, for a total consideration of 558,102 shares at an average purchase price of $6.82 per share or $3.8 million. The three transactions were completed under the same terms and conditions as the other transactions and were approved by the TSX prior to completion.
Corporate Information
Head Office
700 Canterra Tower
400 3rd Avenue S.W.
Calgary, Alberta
Canada T2P 4H2
Phone (403) 262-6207
Fax (403) 261-2792
Directors Officers
J.C. Anderson J.C. Anderson
Calgary, Alberta Chairman of the Board
Brian H. Dau Brian H. Dau
Calgary, Alberta President & Chief Executive Officer
Vincent L. Chahley (1) (2) (3) M. Darlene Wong
Calgary, Alberta Vice President Finance, Chief Financial
Officer & Secretary
Glenn D. Hockley (3)
Calgary, Alberta Blaine M. Chicoine
Vice President, Operations
David G. Scobie (1) (2) (3)
Calgary, Alberta Philip A. Harvey
Vice President, Exploitation
R.T. (Tim) Swinton (1) (2)
Calgary, Alberta Daniel F. Kell
Vice President, Land
David M. Spyker
Vice President, Business Development
Member of
(1) Audit Committee
(2) Compensation and Corporate Governance Committee
(3) Reserves Committee
Auditors
KPMG LLP
Calgary, Alberta
Independent Engineers
AJM Petroleum Consultants
Legal Counsel
Bennett Jones LLP
Registrar & Transfer Agent
Valiant Trust Company
Stock Exchange
The Toronto Stock Exchange
Symbol AXL
Abbreviations used:
bbls - barrels
bpd - barrels per day
Mbbls - thousand barrels
BOE - barrels of oil equivalent
BOED - barrels of oil equivalent per day
MBOE - thousand barrels of oil equivalent
MMBOE - millions of barrels of oil equivalent
Mcf - thousand cubic feet
Mcfd - thousand cubic feet per day
Mcfe - thousand cubic feet equivalent
MMcf - million cubic feet
MMcfd - million cubic feet per day
GJ - gigajoule
For more information, please contact
Anderson Energy Ltd.Brian H. Dau
President and Chief Executive Officer
(403) 206-6000