Exhibit 99.20
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 | | 700 Selkirk House 555 – 4th Avenue S.W. Calgary, Alberta Canada T2P 3E7 Phone: (403) 262-6307 Fax: (403) 261-2792 |
Anderson Energy Announces
2009 Fourth Quarter and Year End Results
Calgary, Alberta, March 22, 2010—Anderson Energy Ltd. (“Anderson Energy” or the “Company”) (TSX:AXL) is pleased to announce its operating and financial results for the fourth quarter and year ended December 31, 2009.
HIGHLIGHTS:
| | • | | Total finding, development and acquisition costs for 2009, including changes in future development capital, revisions and drilling incentive credits, were $7.76 per BOE on a total proved (“TP”) basis and $7.97 per BOE on a proved plus probable (“P&P”) basis. The Company’s recycle ratio in 2009 was 1.9 times for both TP and P&P reserves. |
| | • | | The Company’s year end reserves were 23.6 MMBOE TP and 34.9 MMBOE P&P. Reserve life indices are 9.1 years TP and 13.5 years P&P, based on 2009 fourth quarter production. |
| | • | | The Company estimates its net asset value per share to be approximately $2.52 per share. |
| | • | | As of March 22, 2010, 126 gross (96.1 net) Edmonton Sands wells were drilled with an 89 percent success rate in this winter’s drilling program. The Company has completed the first phase of its drilling commitment on the farm-in transaction with 126 wells drilled. The remaining 74 wells will be drilled in the second half of 2010 to complete the farm-in commitment. Significant cost savings were achieved in this winter’s program, with average drilling and completion costs of $215,000 per well as compared to $313,000 per well in the fourth quarter of 2008. New production from the Edmonton Sands winter drilling program is expected to be on-stream in the second quarter at an average operating expense of $5.00 per BOE. |
| | • | | In the first quarter of 2010, three gross (2.25 net) Cardium horizontal oil wells were drilled. The Company’s 100% working interest wells are in Garrington and Pembina, and encountered 850 meters and 1,300 meters of horizontal oil pay respectively. The Garrington well was recently completed and is now tied in for production. During spring breakup, the well will be produced intermittently through a temporary single well battery. The well is currently flowing without artificial lift at 200 barrels of light oil per day. The remaining Cardium horizontal wells will be completed after spring breakup. |
| | • | | The Company has 85 gross (47 net) sections of Cardium prospective land. Based on a drilling density of three wells per section, it could potentially drill 240 gross (141 net) Cardium horizontal oil wells. The Company’s exposure in the Cardium oil horizontal play has the potential to significantly increase future production. |
| | • | | In the first quarter of 2010, two 100% working interest Whitemud Sands horizontal wells were drilled. Both wells were recently completed and flow-back operations are being conducted to determine a stabilized rate for these wells. The Company has an interest in 200 sections of Whitemud Sands prospective lands. Based on a drilling density of two wells per section, the Company could drill 400 gross (240 net) horizontal development wells. |
| | • | | In the first quarter of 2010, two 100% working interest Rock Creek wells were drilled in Westpem. The wells tested at rates of 1.1 and 1.5 MMcfd with 40 bbls per MMscf of natural gas liquids. These wells are expected to be on-stream early in the second quarter. |
| | • | | In February 2010, a net $29.8 million financing was completed by issuing 21.9 million common shares at a price of $1.45 per share. |
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| 2 | | ANDERSON ENERGY PRESS RELEASE MARCH 22, 2010 |
FINANCIAL AND OPERATING HIGHLIGHTS
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| | | Three months ended December 31, | | | % Change | | | Year ended December 31, | | | % Change | |
| (thousands of dollars) | | 2009 | | | 2008 | | | | | | 2009 | | | 2008 | | | | |
Oil and gas revenue before royalties | | $ | 20,439 | | | $ | 30,102 | | | | (32 | %) | | $ | 76,993 | | | $ | 156,245 | | | | (51 | %) |
Funds from operations | | $ | 9,151 | | | $ | 13,204 | | | | (31 | %) | | $ | 31,258 | | | $ | 79,328 | | | | (61 | %) |
Funds from operations per share | | | | | | | | | | | | | | | | | | | | | | | | |
Basic | | $ | 0.06 | | | $ | 0.15 | | | | (60 | %) | | $ | 0.25 | | | $ | 0.91 | | | | (73 | %) |
Diluted | | $ | 0.06 | | | $ | 0.15 | | | | (60 | %) | | $ | 0.25 | | | $ | 0.91 | | | | (73 | %) |
Earnings (loss) before impairment of goodwill | | $ | (6,457 | ) | | $ | (5,865 | ) | | | (10 | %) | | $ | (36,458 | ) | | $ | 8,500 | | | | (529 | %) |
Earnings (loss) before impairment of goodwill per share | | | | | | | | | | | | | | | | | | | | | | | | |
Basic | | $ | (0.04 | ) | | $ | (0.07 | ) | | | 43 | % | | $ | (0.29 | ) | | $ | 0.10 | | | | (390 | %) |
Diluted | | $ | (0.04 | ) | | $ | (0.07 | ) | | | 43 | % | | $ | (0.29 | ) | | $ | 0.10 | | | | (390 | %) |
Earnings (loss) | | $ | (6,457 | ) | | $ | (41,229 | ) | | | 84 | % | | $ | (36,458 | ) | | $ | (26,864 | ) | | | (36 | %) |
Earnings (loss) per share | | | | | | | | | | | | | | | | | | | | | | | | |
Basic | | $ | (0.04 | ) | | $ | (0.47 | ) | | | 91 | % | | $ | (0.29 | ) | | $ | (0.31 | ) | | | 6 | % |
Diluted | | $ | (0.04 | ) | | $ | (0.47 | ) | | | 91 | % | | $ | (0.29 | ) | | $ | (0.31 | ) | | | 6 | % |
Capital expenditures, including acquisitions net of dispositions | | $ | 11,312 | | | $ | 27,470 | | | | (59 | %) | | $ | 33,558 | | | $ | 106,669 | | | | (69 | %) |
Debt, net of working capital | | | | | | | | | | | | | | $ | 72,524 | | | $ | 125,280 | | | | (42 | %) |
Shareholders’ equity | | | | | | | | | | | | | | $ | 332,719 | | | $ | 309,612 | | | | 7 | % |
Average shares outstanding (thousands) | | | | | | | | | | | | | | | | | | | | | | | | |
Basic | | | 150,500 | | | | 87,300 | | | | 72 | % | | | 125,047 | | | | 87,298 | | | | 43 | % |
Diluted | | | 150,500 | | | | 87,300 | | | | 72 | % | | | 125,047 | | | | 87,298 | | | | 43 | % |
Ending shares outstanding (thousands) | | | | | | | | | | | | | | | 150,500 | | | | 87,300 | | | | 72 | % |
Average daily sales | | | | | | | | | | | | | | | | | | | | | | | | |
Natural gas (Mcfd) | | | 34,938 | | | | 38,090 | | | | (8 | %) | | | 38,489 | | | | 38,968 | | | | (1 | %) |
Liquids (bpd) | | | 1,257 | | | | 1,341 | | | | (6 | %) | | | 1,189 | | | | 1,293 | | | | (8 | %) |
Barrels of oil equivalent (BOED) | | | 7,080 | | | | 7,689 | | | | (8 | %) | | | 7,603 | | | | 7,787 | | | | (2 | %) |
Average prices | | | | | | | | | | | | | | | | | | | | | | | | |
Natural gas ($/Mcf) | | $ | 4.28 | | | $ | 6.76 | | | | (37 | %) | | $ | 3.95 | | | $ | 8.13 | | | | (51 | %) |
Liquids ($/bbl) | | $ | 53.79 | | | $ | 48.49 | | | | 11 | % | | $ | 48.22 | | | $ | 79.50 | | | | (39 | %) |
Barrels of oil equivalent ($/BOE) | | $ | 31.38 | | | $ | 42.55 | | | | (26 | %) | | $ | 27.74 | | | $ | 54.82 | | | | (49 | %) |
Royalties ($/BOE) | | $ | 2.66 | | | $ | 9.46 | | | | (72 | %) | | $ | 2.97 | | | $ | 11.94 | | | | (75 | %) |
Operating costs ($/BOE) | | $ | 10.49 | | | $ | 11.51 | | | | (9 | %) | | $ | 9.70 | | | $ | 11.27 | | | | (14 | %) |
Operating netback ($/BOE) | | $ | 18.23 | | | $ | 21.58 | | | | (16 | %) | | $ | 15.07 | | | $ | 31.61 | | | | (52 | %) |
General and administrative ($/BOE) | | $ | 2.94 | | | $ | 1.40 | | | | 110 | % | | $ | 2.52 | | | $ | 2.24 | | | | 12 | % |
Reserves (MBOE) | | | | | | | | | | | | | | | | | | | | | | | | |
Total proved | | | | | | | | | | | | | | | 23,615 | | | | 23,396 | | | | 1 | % |
Total proved plus probable | | | | | | | | | | | | | | | 34,896 | | | | 32,297 | | | | 8 | % |
Wells drilled (gross) | | | 107 | | | | 91 | | | | 18 | % | | | 118 | | | | 217 | | | | (46 | %) |
Undeveloped land (thousands of acres) | | | | | | | | | | | | | | | | | | | | | | | | |
Gross | | | | | | | | | | | | | | | 123 | | | | 153 | | | | (20 | %) |
Net | | | | | | | | | | | | | | | 62 | | | | 77 | | | | (19 | %) |
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| 3 | | ANDERSON ENERGY PRESS RELEASE MARCH 22, 2010 |
OPERATIONS:
Edmonton Sands. On January 30, 2009, the Company announced a significant farm-in transaction (the “Farm-In”) which more than doubled its land and prospective Edmonton Sands drilling inventory. The Company is committed to drill 200 wells by December 31, 2010 and has an option to drill a minimum of 100 additional wells prior to April 30, 2012 to earn additional lands. In this winter’s drilling program, the Company drilled 126 gross (96.1 net) Edmonton Sands wells. The Company achieved significant cost savings in this winter program, with average drilling and completion costs of $215,000 per well as compared to $313,000 per well in the fourth quarter of 2008. Completion test rate results averaged 40% higher than the previous winter’s drilling program. The Company will be drilling 74 additional wells in the last half of 2010 to complete its 200 well commitment. The Company has completed construction of its new Leedale compressor station and is currently constructing its new Medicine River compressor station. The Medicine River station is expected to be completed in the second quarter of 2010. Various other well tie-in projects have been completed or are nearing completion in the Gilby, Buck Lake and Sylvan Lake areas. New production from the winter drilling program is expected to be on-stream in the second quarter of 2010 at an average operating expense of $5.00 per BOE.
Cardium Horizontal Oil. In the first quarter of 2010, the Company drilled three gross (2.25 net) Cardium horizontal oil wells. The Company’s 100% working interest wells are in Garrington and Pembina, and encountered 850 meters and 1,300 meters of horizontal oil pay respectively. The Garrington well was recently completed with an eight stage frac and is now tied in for production. During spring breakup, the well will be produced intermittently through a temporary single well battery. A permanent single well battery will be operational in June 2010. The well is currently flowing without artificial lift at 200 barrels of light oil per day. The remaining Cardium horizontal wells will be completed after spring breakup. The Company has 85 gross (47 net) sections of Cardium prospective land. Based on a development drilling density of three wells per section, it could potentially drill 240 gross (141 net) Cardium horizontal wells. The Company is planning on operating the drilling of four gross (3.0 net) locations in the second and third quarters of 2010 at Garrington, Willesden Green, Pembina and Ferrier to allow the Company to further delineate areas for near term development. The Company’s exposure in the Cardium oil horizontal play has the potential to significantly increase future production.
Whitemud Horizontal Gas. The Company drilled and completed two Whitemud horizontal gas wells in the first quarter of 2010. Both wells were recently completed and the Company is currently conducting flow-back operations to determine a stabilized rate for these wells. The Whitemud Sands are at 600 meters vertical depth and the horizontal wells traverse 1,000 to 1,200 meters through the formation. The Whitemud Sands has on average 2.5 Bcf per section of initial gas in place. Currently, the Company has 200 sections of land that it owns or controls in this play.
Deeper Drilling. The Company drilled two Westpem Rock Creek liquids rich gas wells in the first quarter of 2010. The wells tested at 1.1 and 1.5 MMcfd with 40 bbls per MMscf of natural gas liquids. These wells are expected to be tied in for production early in the second quarter. The Company is planning on drilling four gross (2.9 net) deeper targets and 2 gross (1.5 net) recompletions in the second half of the year. All of these operations are liquids rich gas targets.
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| 4 | | ANDERSON ENERGY PRESS RELEASE MARCH 22, 2010 |
PRODUCTION
For the year ended December 31, 2009, the Company averaged 7,603 BOED. As expected, production was slightly lower than the prior year. Due to low commodity prices and the need to conserve funds for the farm-in drilling program in the fourth quarter, new wells were not drilled and brought on production during the year to offset natural production declines. During 2009, the Company also had approximately 200 BOED of production shut-in due to poor economics and facility issues. Property dispositions in the fourth quarter of 2008 also affected production compared to the prior year.
The Company estimates production in the first quarter of 2010 to be similar to production in the fourth quarter of 2009. Production from the winter drilling program is being brought on-stream in the second half of March and throughout April 2010. Some well tie-ins are being deferred to the summer as newly constructed gas plants will initially be full. Production guidance estimates for the 2010 fiscal year are 8,000 to 8,500 BOED.
FINANCIAL RESULTS
Capital expenditures, net of drilling incentive credits, were $33.6 million in 2009 with $24.0 million spent on drilling and completions before drilling incentive credits and $11.3 million on facilities. This compares to capital expenditures of $106.7 million in 2008.
The Company’s funds from operations were $31.3 million in 2009 as compared to $79.3 million in 2008. The Company’s average natural gas sales price was $3.95 per Mcf in 2009 as compared to $8.13 per Mcf in 2008. Natural gas sales prices in 2009 were $5.15 per Mcf in the first quarter, $3.43 per Mcf in the second quarter, $2.81 per Mcf in the third quarter and $4.28 per Mcf in the fourth quarter. The Company’s average natural gas sales price in the first quarter of 2010 is estimated to be approximately $5.20 per Mcf. The Company has hedged approximately 19 MMcfd of natural gas production in the first quarter of 2010 at an average AECO price of $5.71 per Mcf. The Company’s average crude oil and natural gas liquids sales price in 2009 was $48.22 per bbl as compared to $79.50 per bbl in 2008. The Company’s operating netback was $15.07 per BOE in 2009 as compared to $31.61 per BOE in 2008. The reduction in the operating netback was primarily due to the decline in commodity prices. Operating expenses in 2009 were $9.70 per BOE, which was 14% lower than $11.27 per BOE in 2008. Operating expenses decreased as the Company sold or shut-in higher operating expense properties, renegotiated field operating contracts and placed more production through lower cost fit for purpose Edmonton Sands gas plants. Fourth quarter 2009 operating expenses increased over the average incurred throughout the year as the Company brought back on-stream some of the higher operating expense properties and conducted workovers and compressor maintenance that was deferred throughout 2009 due to weaker natural gas prices in the previous quarters The new production from the Edmonton Sands winter drilling program is expected to come on-stream at an average operating expense of $5.00 per BOE as compared to a historical operating expense of $9.00 per BOE.
FINANCING
On May 28, 2009 the Company successfully completed a net $56.5 million financing by issuing 63.2 million shares at an issue price of $0.95 per share. This financing was put in place to finance the Farm-In transaction. In February 2010, the Company completed a net $29.8 million financing by issuing 21.9 million common shares at an issue price of $1.45 per share. This financing was put in place to expand the Company’s Cardium oil horizontal drilling program. Total outstanding common shares, after giving effect to the February 2010 equity issue, are 172.4 million. The Company has credit facilities of $100 million with three Canadian banks.
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| 5 | | ANDERSON ENERGY PRESS RELEASE MARCH 22, 2010 |
RESERVES
GLJ Petroleum Consultants (“GLJ”) was engaged to prepare an evaluation of the Company’s reserves as of December 31, 2009.
A summary of the Company’s reserves evaluation is shown below as of December 31, 2009.
| | | | | | | | | | | | | | | | |
| Reserves Category | | Natural Gas
(Bcf) | | | Oil (Mbbls) | | | Natural Gas
Liquids
(Mbbls) | | | Barrels of Oil
equivalent
(MBOE) | |
Proved Developed Producing & Proved Developed Non Producing | | | 61 | | | | 594 | | | | 1,169 | | | | 11,935 | |
Total Proved | | | 128 | | | | 813 | | | | 1,474 | | | | 23,615 | |
Total Proved plus Probable | | | 187 | | | | 1,460 | | | | 2,270 | | | | 34,896 | |
The Company’s reserves life indices are 9.1 years TP and 13.5 years P&P, based on annualized 2009 fourth quarter production. The Company replaced 194% of its production with new proved plus probable reserves additions, net of revisions, in 2009. The Company’s finding, development and acquisition (“FD&A”) costs in 2009 were $7.76 per BOE TP and $7.97 per BOE P&P. The recycle ratio in 2009 was 1.9 times for both TP and P&P reserves. Management’s Discussion and Analysis contains more details on the calculation of FD&A costs.
| | | | | | | | |
| | | Total Proved (MBOE) | | | Total Proved plus
Probable (MBOE) | |
Opening Balance, December 31, 2008 | | | 23,396 | | | | 32,297 | |
Additions | | | 6,089 | | | | 8,779 | |
Revisions | | | (3,095 | ) | | | (3,405 | ) |
Production | | | (2,775 | ) | | | (2,775 | ) |
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Closing Balance, December 31, 2009 | | | 23,615 | | | | 34,896 | |
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NET ASSET VALUATION
As at December 31, 2009
| | | | |
| ($ millions, unless otherwise stated) | | | |
P&P reserves (pretax 10% discount rate) | | $ | 364.1 | |
Undeveloped land (excluding Cardium horizontal prospective lands) | | | 6.2 | |
Cardium horizontal prospective lands (at $7,100 per hectare) | | | 85.0 | |
Stock option proceeds and drilling incentive credits | | | 5.2 | |
Debt, net of working capital | | | (72.5 | ) |
| | | | |
Net asset value estimate, December 31, 2009* | | $ | 388.0 | |
Net asset value estimate per fully diluted share, December 31, 2009* | | $ | 2.52 | |
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* Does not include changes made by the Alberta Government on March 11, 2010 making the 5% Crown royalty on the first year of production on new wells a permanent measure.
The Cardium horizontal opportunity was conservatively valued based on recent land sale activity. The net asset value calculation as presented does not include value for the development potential of the Cardium play, the Whitemud horizontal gas drilling program or the option phase on the Farm-In lands. These are all very significant projects and the Company believes that they will contribute to unlocking value in 2010.
The GLJ price forecast as of December 31, 2009 is shown in Management’s Discussion and Analysis for the year ended December 31, 2009. Complete reserves disclosure as required under NI 51-101 will be contained in the Company’s 2009 Annual Information Form, to be filed on SEDAR later this week.
The Company has 123,105 gross (61,989 net) undeveloped acres of land as of December 31, 2009 and has assigned a value of $6.2 million to this acreage position. The Company assigned $7,100 per hectare to its Cardium horizontal prospective lands in the net asset value table, which is an average of the last three Cardium Crown land sales. Company engineers have estimated the potential net present value of a Cardium well to be
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| 6 | | ANDERSON ENERGY PRESS RELEASE MARCH 22, 2010 |
$3.3 million, using a $75 per barrel Canadian oil price and a 10% pretax discount rate. The Company has an inventory of 141 net Cardium wells based on a three well per section development.
As of December 31, 2009 the Company’s vertical drilling inventory is as follows:
| | | | | | | | |
| | | Gross | | | Net | |
Edmonton Sands (with GLJ assigned P&P reserves) | | | 865 | | | | 457 | |
Edmonton Sands on Farm-In Option Lands | | | 317 | | | | 207 | |
Horseshoe Canyon CBM (with GLJ assigned P&P reserves) | | | 99 | | | | 20 | |
Deep Drilling | | | 24 | | | | 20 | |
| | | | | | | | |
Total | | | 1,305 | | | | 704 | |
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As of December 31, 2009, the Company’s horizontal drilling inventory is as follows:
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| | | Gross | | | Net | |
Cardium Light Oil (3 wells per section drilling density) | | | 240 | | | | 141 | |
Whitemud Sands Gas (2 wells per section drilling density) | | | 400 | | | | 240 | |
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Total | | | 640 | | | | 381 | |
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OUTLOOK
Although 2010 has to date been a better environment for the natural gas business than 2009, there is still is a good deal of uncertainty in the natural gas marketplace with respect to supply and consumption of natural gas. Accordingly, the Company entered into fixed price contracts to protect its capital program in the first quarter of the year. The Company hedged 20,000 GJ per day at an average AECO Canadian dollar price of $5.41 per GJ for January, February and March of 2010. This is approximately 19 MMcfd of natural gas at an AECO Canadian dollar price of $5.71 per Mcf and is approximately 50% of the Company’s estimated barrel of oil equivalent production for the first quarter of 2010. The Company reviews hedging as part of a price management strategy on an ongoing basis.
Completion test rate results from the Edmonton farm-in program averaged 40% higher than results achieved in the previous winter’s drilling program. The Company expects similar results for the next fall/winter drilling program. This winter, the locations drilled were predominantly on Crown land that did not require mineral subsurface poolings or have any surface access restrictions. Next winter, the Company will be drilling more freehold lands and lands where subsurface poolings have been completed. Many of the new locations to be drilled next winter will connect to the new plant infrastructure built this winter.
2009 was a difficult year and the Company would like to thank its shareholders and its employees for their support throughout the year. The Company had excellent FD&A costs because of the drilling on farm-in lands and the Company’s successful program to reduce capital costs. The Company believes the horizontal multistage frac opportunities represent a significant option value to its shareholder. The new year has started out with excellent drilling success that is expected to unlock significant shareholder value in 2010.
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| 7 | | ANDERSON ENERGY PRESS RELEASE MARCH 22, 2010 |
PEOPLE
In addition to the current directors, David Sandmeyer will be standing for election to the Company’s Board of Directors at the upcoming annual shareholders’ meeting. Mr. Sandmeyer is a professional engineer and is a current Director and former President and Chief Executive Officer of Freehold Royalty Trust and a former President and Chief Executive Officer of Rife Resources Ltd. He was a founding Governor of the Canadian Association of Petroleum Producers (“CAPP”), serving several terms and active on a number of CAPP committees.
The Company invites its shareholders to attend the Company’s annual meeting on May 13, 2010 at the Metropolitan Centre in Calgary at 2 pm MDT and encourages anyone interested in further details on our Company to visit the Company’s website at www.andersonenergy.ca.
Brian H. Dau
President & Chief Executive Officer
March 22, 2010
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| 8 | | ANDERSON ENERGY PRESS RELEASE MARCH 22, 2010 |
This page has been left blank intentionally. The Company’s Management’s Discussion and Analysis for the year ended December 31, 2009 and the Company’s Consolidated Financial Statements as at December 31, 2009 have been filed under separate cover.
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| 9 | | ANDERSON ENERGY PRESS RELEASE MARCH 22, 2010 |
ADVISORY
Certain information regarding Anderson Energy Ltd. in this news release including, without limitation, management’s assessment of future plans and operations, benefits and valuation of the development prospects described herein, number of locations in drilling inventory and wells to be drilled, timing and location of drilling and tie-in of wells and the costs thereof, productive capacity of the wells, timing of and construction of facilities, expected production rates, dates of commencement of production, amount of capital expenditures and timing thereof, value of undeveloped land, extent of reserves additions, ability to attain cost savings, drilling program success, impact of changes to the royalty regime applicable to the Company, including payment of drilling incentive credits, commodity price outlook and general economic outlook 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 reserves 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 and farm-ins, failure to realize the anticipated benefits of acquisitions and farm-ins, 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) and 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.
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| 10 | | ANDERSON ENERGY PRESS RELEASE MARCH 22, 2010 |
Corporate Information
Head Office
700 Selkirk House
555 4th Avenue S.W.
Calgary, Alberta
Canada T2P 3E7
Phone (403) 262-6307
Fax (403) 261-2792
Website www.andersonenergy.ca
Directors
J.C. Anderson (2)(3)
Calgary, Alberta
Brian H. Dau (3)
Calgary, Alberta
Chris L. Fong (1)(2)
Calgary, Alberta
Glenn D. Hockley (1)(3)
Calgary, Alberta
David G. Scobie (1)(2)
Calgary, Alberta
Member of:
(1) Audit Committee
(2) Compensation & Corporate
Governance Committee
(3) Reserves Committee
Auditors
KPMG LLP
Independent Engineers
GLJ Petroleum Consultants
Legal Counsel
Bennett Jones LLP
Registrar & Transfer Agent
Valiant Trust Company
Stock Exchange
The Toronto Stock Exchange
Symbol AXL
Contact Information
Anderson Energy Ltd.
Brian H. Dau
President & Chief Executive Officer
(403) 206-6000
Officers
J.C. Anderson
Chairman of the Board
Brian H. Dau
President & Chief Executive Officer
David M. Spyker
Chief Operating Officer
M. Darlene Wong
Vice President Finance, Chief Financial
Officer & Secretary
Blaine M. Chicoine
Vice President, Operations
Philip A. Harvey
Vice President, Exploitation
Daniel F. Kell
Vice President, Land
Jamie A. Marshall
Vice President, Exploration
Abbreviations used
AECO – intra-Alberta Nova inventory transfer price
bbl – barrel
bpd – barrels per day
Mbbls – thousand barrels
Mstb – thousand stock tank barrels
BOE – barrels of oil equivalent
BOED – barrels of oil equivalent per day
MBOE – thousand barrels of oil equivalent
MMBOE – million barrels of oil equivalent
CBM – Coal Bed Methane
GJ – gigajoule
Mcf – thousand cubic feet
Mcfd – thousand cubic feet per day
MMcf – million cubic feet
MMscf – million standard cubic feet
MMcfd – million cubic feet per day
Bcf – billion cubic feet
Tcf – trillion cubic feet
