Exhibit 99.34
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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 2011 Second Quarter Results
Calgary, Alberta, August 15, 2011—Anderson Energy Ltd. (“Anderson Energy” or the “Company”) (TSX:AXL) is pleased to announce its operating and financial results for the three and six months ended June 30, 2011.
HIGHLIGHTS:
| | • | | Funds from operations in the second quarter were $13.9 million, up 56% from the second quarter of 2010 and 28% from the first quarter of 2011. |
| | • | | Total production was 7,758 BOED in the second quarter of 2011 compared to 7,732 BOED in the second quarter of 2010. Oil and NGL production in the second quarter averaged 2,426 bpd, up 97% from the second quarter of 2010 and 17% from the 2,071 bpd reported in the first quarter of 2011. Oil represented 1,759 bpd of total production in the second quarter and was 258% higher than the second quarter of 2010 and 28% higher than the first quarter of 2011. |
| | • | | Oil and NGL revenue made up 65% of total oil and gas sales in the second quarter of 2011. |
| | • | | Earnings were $5.9 million in the second quarter of 2011. |
| | • | | The operating netback improved to $25.47 per BOE in the second quarter of 2011 from $16.58 per BOE in the second quarter of 2010, due to increased oil volumes and higher oil and NGL prices. |
| | • | | The capital program for 2011 is estimated to be $115 million. Production guidance associated with this capital program is 7,500 to 8,000 BOED. In 2011, the Company estimates it could drill up to 44 gross (28.6 net) Cardium horizontal oil wells, of which 19 gross (13.8 net) were drilled in the first half of 2011 and nine gross (7.0 net) Cardium horizontal oil wells have been drilled in the third quarter to date. The Company currently has five drilling rigs working in the field drilling Cardium horizontal oil wells. |
| | • | | On June 8, 2011, the Company closed a $46 million convertible debenture bought deal offering. |
| | • | | On May 13, 2011, the Company entered into an agreement with its lenders to renew its credit facilities and increased the total amount of its facilities from $125 million to $135 million. |
| | • | | Drill ready Cardium horizontal oil location inventory stands at 213 gross (128.6 net) locations, a 51% increase since December 31, 2010 and an 11% increase since the May 16, 2011 press release. The Company has increased the Cardium prospective land that it owns or controls by 23% since December 31, 2010 to 124.5 gross (73.7 net) sections (85% in the oil fairway). Using an industry standard disclosure of three wells per section drilling density, the drilling inventory would be 221 net locations. |
FINANCIAL AND OPERATING HIGHLIGHTS
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| | | Three months ended June 30 | | | Six months ended June 30 | |
(thousands of dollars, unless otherwise stated) | | 2011 | | | 2010* | | | % Change | | | 2011 | | | 2010* | | | % Change | |
Oil and gas sales** | | $ | 31,566 | | | $ | 20,318 | | | | 55 | % | | $ | 57,152 | | | $ | 43,583 | | | | 31 | % |
Revenue, net of royalties** | | $ | 27,776 | | | $ | 18,622 | | | | 49 | % | | $ | 51,059 | | | $ | 38,493 | | | | 33 | % |
Funds from operations | | $ | 13,944 | | | $ | 8,923 | | | | 56 | % | | $ | 24,812 | | | $ | 19,358 | | | | 28 | % |
Funds from operations per share | | | | | | | | | | | | | | | | | | | | | | | | |
Basic and diluted | | $ | 0.08 | | | $ | 0.05 | | | | 60 | % | | $ | 0.14 | | | $ | 0.12 | | | | 17 | % |
Earnings (loss) before effect of impairment | | $ | 5,932 | | | $ | (2,450 | ) | | | 342 | % | | $ | 2,251 | | | $ | (2,194 | ) | | | 203 | % |
Earnings (loss) per share before effect of impairment | | | | | | | | | | | | | | | | | | | | | | | | |
Basic and diluted | | $ | 0.03 | | | $ | (0.01 | ) | | | 400 | % | | $ | 0.01 | | | $ | (0.01 | ) | | | 200 | % |
Earnings (loss) | | $ | 5,932 | | | $ | (4,769 | ) | | | 224 | % | | $ | 2,251 | | | $ | (49,213 | ) | | | 105 | % |
Earnings (loss) per share | | | | | | | | | | | | | | | | | | | | | | | | |
Basic and diluted | | $ | 0.03 | | | $ | (0.03 | ) | | | 200 | % | | $ | 0.01 | | | $ | (0.29 | ) | | | 103 | % |
Capital expenditures, including acquisitions net of dispositions | | $ | 26,284 | | | $ | 12,664 | | | | 108 | % | | $ | 68,638 | | | $ | 45,891 | | | | 50 | % |
Bank loans plus cash working capital deficiency | | | | | | | | | | | | | | $ | 71,464 | | | $ | 70,284 | | | | 2 | % |
Convertible debentures | | | | | | | | | | | | | | $ | 83,872 | | | $ | — | | | | 100 | % |
Shareholders’ equity | | | | | | | | | | | | | | $ | 187,401 | | | $ | 253,903 | | | | (26 | %) |
Average shares outstanding (thousands) | | | | | | | | | | | | | | | | | | | | | | | | |
Basic | | | 172,548 | | | | 172,400 | | | | — | | | | 172,526 | | | | 168,129 | | | | 3 | % |
Diluted | | | 172,935 | | | | 172,400 | | | | — | | | | 173,163 | | | | 168,129 | | | | 3 | % |
Ending shares outstanding (thousands) | | | | | | | | | | | | | | | 172,550 | | | | 172,400 | | | | — | |
Average daily sales: | | | | | | | | | | | | | | | | | | | | | | | | |
Natural gas (Mcfd) | | | 31,990 | | | | 38,998 | | | | (18 | %) | | | 32,955 | | | | 37,120 | | | | (11 | %) |
Oil (bpd) | | | 1,759 | | | | 491 | | | | 258 | % | | | 1,567 | | | | 419 | | | | 274 | % |
NGL (bpd) | | | 667 | | | | 741 | | | | (10 | %) | | | 683 | | | | 763 | | | | (10 | %) |
Barrels of oil equivalent (BOED) | | | 7,758 | | | | 7,732 | | | | — | | | | 7,742 | | | | 7,368 | | | | 5 | % |
Average prices: | | | | | | | | | | | | | | | | | | | | | | | | |
Natural gas ($/Mcf) | | $ | 3.79 | | | $ | 3.78 | | | | — | | | $ | 3.68 | | | $ | 4.46 | | | | (17 | %) |
Oil ($/bbl) | | $ | 99.39 | | | $ | 70.45 | | | | 41 | % | | $ | 93.00 | | | $ | 72.51 | | | | 28 | % |
NGL ($/bbl) | | $ | 74.24 | | | $ | 53.55 | | | | 39 | % | | $ | 70.03 | | | $ | 55.15 | | | | 27 | % |
Barrels of oil equivalent ($/BOE)** | | $ | 44.71 | | | $ | 28.88 | | | | 55 | % | | $ | 40.78 | | | $ | 32.68 | | | | 25 | % |
Realized loss on derivative contracts ($/BOE) | | $ | 1.17 | | | $ | — | | | | (100 | %) | | $ | 0.87 | | | $ | — | | | | (100 | %) |
Royalties ($/BOE) | | $ | 5.37 | | | $ | 2.41 | | | | 123 | % | | $ | 4.35 | | | $ | 3.82 | | | | 14 | % |
Operating costs ($/BOE) | | $ | 12.04 | | | $ | 9.71 | | | | 24 | % | | $ | 11.34 | | | $ | 10.21 | | | | 11 | % |
Transportation costs ($/BOE) | | $ | 0.66 | | | $ | 0.18 | | | | 267 | % | | $ | 0.50 | | | $ | 0.16 | | | | 213 | % |
Operating netback ($/BOE) | | $ | 25.47 | | | $ | 16.58 | | | | 54 | % | | $ | 23.72 | | | $ | 18.49 | | | | 28 | % |
Wells drilled (gross) | | | 5 | | | | 3 | | | | 67 | % | | | 20 | | | | 29 | | | | (31 | %) |
* 2010 results have been restated to conform with International Financial Reporting Standards.
** Includes royalty and other income classified with oil and gas sales, but excludes realized and unrealized losses on derivative contracts.
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| ANDERSON ENERGY LTD. PRESS RELEASE AUGUST 15, 2011 | | | 2 | |
OPERATIONS:
Cardium Horizontal Oil. In the second quarter of 2011, four gross (2.5 net revenue) Cardium horizontal oil wells were drilled. From May 1, 2010 to June 30, 2011, the Company has placed 41 gross (29.2 net) Cardium oil wells on production. Oil and NGL production for the three months ended June 30, 2011 was 2,426 bpd, up substantially from 1,232 bpd in the second quarter of 2010. Of this number, 1,759 bpd or 73% is crude oil production, compared to 491 bpd or 40% in the second quarter of 2010. The Company plans to drill 44 gross (32.7 net capital, 28.6 net revenue) Cardium horizontal oil wells in 2011. A summary of Cardium horizontal well activity since the first quarter of 2010 is shown below:
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| Cardium Cumulative Drilling Program | | Wells Drilled | | | Wells On Production | |
| | | Gross | | | Net | | | Gross | | | Net | |
Up to August 15, 2011 | | | 50 | | | | 36.2 | | | | 42 | | | | 30.2 | |
Estimated up to December 31, 2011 | | | 66 | | | | 44.0 | | | | 66 | | | | 44.0 | |
“Net” is net revenue interest earned.
The Company currently has five drilling rigs working in the field drilling horizontal oil wells. As of August 15, 2011, nine gross (7.0 net) Cardium horizontal oil wells have been drilled in the third quarter and six of them have been completed.
The Company’s Cardium prospective land inventory is 124.5 gross (73.7 net) sections, an increase of 8% since the last update on May 16, 2011 and 23% since December 31, 2010. Approximately 85% of the Company’s Cardium lands are in the oil prone fairway and the balance is in the gas prone fairway. Using geological mapping and offset production information, the Company has high-graded a location list to drill in the oil prone fairway. The list includes 213 gross (128.6 net) horizontal locations to be drilled in the next few years (including wells drilled to date). Each location is a development location that is technically feasible and not contingent upon the drilling of other wells. Successful drilling of these wells, drilling by third parties offsetting Company lands and new land deals have increased the count by 11% since the May 16, 2011 press release. The Company has not included prospective locations from the gas prone fairway as natural gas prices are low. The Company continues to explore opportunities to increase its land position in the play through acquisitions and farm-ins in its existing areas of focus, and to improve operating efficiencies in the drilling and completion of wells. A more detailed discussion and review of the Cardium drilling program and go forward plans is shown in the investor presentation at www.andersonenergy.ca.
In February 2011, the Company switched from oil-based fracture stimulations to water-based fracture stimulations of the Cardium. Well performance has been encouraging and the Company now conducts fracture stimulations with water. The capital cost savings of this change has been approximately $500,000 per well. The Company estimates its go forward drill, complete, equip and tie-in costs for the Cardium horizontal program to be approximately $2.6 million per well in the Garrington field and $3.0 to $3.2 million per well in other properties.
The Garrington battery consolidation project was completed in early August with all of the Company’s single well batteries connected to the central 15-34 tank battery. This project is expected to reduce operating and capital costs in this area. The 100% owned facility will ultimately be connected by Plains Midstream Canada to the Rangeland Pipeline system later this year. This facility is processing third party volumes and so also represents an attractive source of processing fee income for the Company.
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The Company is conducting a reservoir simulation study to plan its waterflood for the Garrington field. The Company is planning to conduct a water injectivity test in the fourth quarter of 2011 and be in a position to inject water in 2012.
The Company has identified five non-Cardium zones on its lands in central Alberta, with potential for horizontal oil drilling. These zones are Second White Specs, Belly River, Viking, Glauconite and Mannville. The first Belly River horizontal oil well is scheduled to be drilled in the fourth quarter of 2011 and the Company is evaluating the timeline to drill the other four horizons later in 2011 or in 2012.
PRODUCTION
For the second quarter of 2011, the Company averaged 7,758 BOED, with oil and NGL volumes representing 31% of total volumes. Oil and NGL production is 17% higher than the first quarter of 2011 due to increasing Cardium oil volumes. The Company experienced very wet weather in the latter part of the second quarter of 2011, which negatively impacted production volumes, drilling and completion activity and operating costs.
In the third quarter of 2011, the Company’s production will be negatively impacted by a planned major one month plant turnaround at Buck Lake, which represents 500 BOED of production, for the duration of the turnaround.
FINANCIAL RESULTS
Capital expenditures, net of proceeds on dispositions, were $26.3 million in the second quarter of 2011 with $12.7 million spent on drilling and completions and $9.5 million spent on facilities. This compares to capital expenditures of $12.7 million in the second quarter of 2010. As of August 15, 2011, the Company has disposed of $12.6 million in property sales and sales of excess drilling royalty credits as compared to its original budget of $10 million.
The Company’s funds from operations were $13.9 million in the second quarter of 2011 compared to $8.9 million in the second quarter of 2010. The Company’s average crude oil and natural gas liquids sales price in the second quarter of 2011 was $92.48 per barrel compared to $60.28 per barrel in the second quarter of 2010. The Company realized a loss of $0.8 million on WTI Canadian fixed price oil contracts in the second quarter of 2011, which negatively impacted funds from operations. The Company has entered into fixed price oil swaps for 2011 and 2012. The WTI Canadian prices on these contracts range between $88.45 per bbl to $107.00 per bbl. The Company’s mark to market valuation of its oil hedge gain at June 30, 2011 is $2.9 million. The Company’s average natural gas sales price was $3.79 per Mcf in the second quarter of 2011 compared to $3.78 per Mcf in second quarter of 2010. The Company entered into physical contracts to sell 15,000 GJ per day of natural gas at an average AECO gas price of $4.06 per GJ for the period July 1 to October 31, 2011. This equates to approximately 13.9 MMcfd at an average plant gate price of approximately $4.15 per Mcf. The Company recorded earnings of $5.9 million in the second quarter of 2011 primarily due to the hedging gain and a stronger contribution to total revenue by additional oil volumes and higher oil and NGL prices. The Company’s operating netback was $25.47 per BOE in the second quarter of 2011 compared to $16.58 per BOE in the second quarter of 2010. The increase in the operating netback was primarily due to the increase in oil and NGL prices and oil volumes.
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| | | Average wellhead natural gas price ($/Mcf) | | | Revenue ($/BOE) | | | Operating netback ($/BOE) | | | Funds from operations ($/BOE) | |
2009 * | | | 3.95 | | | | 27.74 | | | | 15.07 | | | | 11.26 | |
2010 * | | | 3.96 | | | | 31.31 | | | | 17.44 | | | | 13.22 | |
First quarter of 2011 | | | 3.58 | | | | 36.80 | | | | 21.96 | | | | 15.63 | |
Second quarter of 2011 | | | 3.79 | | | | 44.71 | | | | 25.47 | | | | 19.75 | |
First quarter of 2012 estimate
($90 to $100 WTI Canadian** plus oil hedge program) | | | 4.00 | ** | | | 48.00 to 50.00 | | | | 33.00 to 36.00 | | | | 25.00 to 28.00 | |
* 2009 results have not been restated to conform with International Financial Reporting Standards. 2010 results have been restated to conform with International Financial Reporting Standards.
** Estimate
As the Company increases its oil production, its revenue per BOE, operating netback per BOE and funds from operations per BOE should increase and as a consequence, the Company expects to reposition itself to achieve sustained profitability by 2012. Royalties were $5.37 per BOE in the second quarter of 2011 compared to $3.31 per BOE in the first quarter of 2011 due to annual gas cost allowance adjustments recorded in the second quarter. Operating expenses in the second quarter of 2011 were $12.04 per BOE, which was 13% higher than the first quarter of 2011 due to costs associated with temporary production facilities being utilized for longer periods of time as a result of spring breakup and extremely wet weather. These costs negatively impacted operating expenses in the second quarter by $0.78 per BOE. After adjusting for temporary production facility costs in the second quarter, operating costs were 6% higher than in the first quarter of 2011. These facilities are now permanently connected to the new Garrington battery consolidation project and to a permanent battery installation in Willesden Green.
FINANCING
On June 8, 2011, the Company completed a $46 million convertible subordinated debenture financing. The debentures have a six year term with a 7.25% coupon and a conversion price of $1.70 per share. Proceeds were initially used to reduce the Company’s bank indebtedness and provide financial flexibility for its 2011 capital program. As of June 30, 2011, 65% of the Company’s debt is long term convertible debenture financing and the remainder is extendible revolving term bank debt.
In the second quarter of 2011, the Company sold $626,000 in properties and surplus drilling royalty credits. As of August 15, 2011, the Company has sold a total of $12.6 million in properties and surplus drilling royalty credits in 2011, which is higher than the budget plan of $10 million. The Company is financing its drilling program with bank loans, convertible debentures, cash flow and dispositions in 2011. On May 13, 2011, the Company entered into an agreement with a syndicate of three Canadian banks to renew its credit facilities and increase the total facilities to $135 million. As of June 30, 2011, the Company had drawn down 34% of these facilities.
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2011 CAPITAL PROGRAM
During the second quarter of 2011, the Company’s Board of Directors approved an increase in the capital program from $75 million to $115 million. The increase in 2011 capital spending is back-end weighted. Associated production guidance with this capital program is 7,500 to 8,000 BOED (33% oil and NGL). In 2011, the Company estimates it could drill up to 44 gross (28.6 net) Cardium horizontal oil wells, of which 19 gross (13.8 net) had been drilled to June 30, 2011. The Company is planning to drill one Belly River well in the fourth quarter of 2011, and is evaluating the other four non-Cardium zones for horizontal oil drilling in the latter part of 2011 or in 2012.
COMMODITY CONTRACTS
Crude Oil. As part of its price management strategy, the Company has entered into fixed price swap contracts based on the NYMEX crude oil price in Canadian dollars. The average for volumes and prices for these contracts is summarized below:
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| Period | | Weighted average volume (bbls) | | | Weighted average WTI Canadian ($/bbl) | |
July 1, 2011 to September 30, 2011 | | | 1,500 | | | | 94.16 | |
October 1, 2011 to December 31, 2011 | | | 1,500 | | | | 94.18 | |
January 1, 2012 to March 31, 2012 | | | 1,500 | | | | 104.63 | |
April 1, 2012 to December 31, 2012 | | | 1,000 | | | | 103.93 | |
The Company entered into the hedging contracts to protect its capital program and support its bank borrowing base. As the Company continues to grow its oil production, it will evaluate the merits of additional commodity hedging as part of a price management strategy.
The mark to market hedge gain as of June 30, 2011 was $2.9 million for the crude oil contracts.
Natural Gas. The Company has physically contracted to sell 15,000 GJ per day of natural gas at an average Canadian dollar AECO price of $4.06 per GJ, form July 1, 2011 to October 31, 2011. This equates to approximately 13.9 MMcfd at an average plant gate price of approximately $4.15 per Mcf.
STRATEGY
At WTI Canadian oil prices of $85 per bbl, operating netbacks in the Cardium program are approximately $62 per BOE as compared to operating netbacks in the Edmonton Sands shallow gas program of $15 per BOE. A change in WTI Canadian oil price of $5 per bbl, would impact the Cardium operating netback by $4.36 per BOE. The Company estimates it could grow its oil and NGL production from 18% of total production in 2010 to 33% in 2011 and estimates that it will have balanced its gas production with oil and NGL production by sometime in 2012. Independent analysts currently estimate that funds from operations (or “cash flow”) will range from $47 million to $62 million in 2011 and $73 million to $98 million in 2012, which is significant growth when compared to $36.5 million in funds from operations in 2010. Management believes that a strategy of cash flow growth through light oil horizontal drilling is the best solution in this period of anemic natural gas prices. As part of this transition from natural gas to oil, the Company completed two convertible debenture financings with five to six year terms and conversion prices of $1.55 and $1.70 per share. This provides the Company with better financial flexibility to make the transformation to a balanced oil and gas producer. Debt leverage is higher than some of its peers in 2011, however, with improving revenue from oil production in 2011 and 2012, leverage is
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| ANDERSON ENERGY LTD. PRESS RELEASE AUGUST 15, 2011 | | | 6 | |
expected to return to more typical levels for junior oil producers by 2012. The Company believes it has the depth of prospects to stay the oil course and still bring forward natural gas prospects for drilling when economic conditions dictate.
With oil prices at or near present levels, we expect to be able to finance our foreseeable drilling programs out of cash flow and currently available credit facilities without the need for external financing.
In the last year, we were able to move up the learning curve in the Cardium play with drilling, completion and production initiatives. The Company is very focused on increasing its land position in the Cardium and utilizing new technologies to lower costs and enhance well performance. The addition of water-based fracture stimulation in February 2011 is one example of new initiatives.
OUTLOOK
Oil prices continue to be strong, but volatile, and are expected to remain so in the near term. Natural gas prices are weak and the timing of natural gas price recovery to economic levels is uncertain. The Company will continue to dedicate its capital program to light oil horizontal oil drilling as these prospects represent the best economics.
By the end of 2011, the Company estimates it will have 44 net revenue Cardium horizontal wells on production, up 50% from the end of the second quarter 2011. The Company has increased its Cardium development drilling inventory by 51% since December 31, 2010 and is becoming one of the industry leaders in lowering Cardium capital costs. The Company believes it is well positioned in the Cardium horizontal oil play and the results from the Cardium program will help to peel the natural gas label off the stock price and reward shareholders with more of an oil company valuation. As oil production grows in 2011, the impact that this currently higher priced commodity will have on its cash flow and earnings could be significant.
We have five drilling rigs currently active in the field, drilling Cardium horizontal oil wells. Additional horizontal oil prospectivity have been identified in the Second White Specs, Viking, Belly River, Glauconite and Mannville formations. Some of these zones are expected to be advanced for drilling in the fourth quarter of 2011.
In the second quarter of 2011, the Company achieved significant increases in operating netback and funds from operations per BOE and recorded positive earnings as a result of hedging gains and the doubling its oil and NGL production compared to the second quarter of 2010. This is the first quarter that we have started to see the benefits of the strategy change to light oil horizontal drilling. With the emphasis on oil drilling, the Company could potentially see its oil and natural gas production becoming balanced sometime in 2012. For more information, we encourage investors to review our website at www.andersonenergy.ca.
Brian H. Dau
President & Chief Executive Officer
August 15, 2011
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This page has been left blank intentionally. The Company’s Management’s Discussion and Analysis for the three and six months ended June 30, 2011 and the Company’s Interim Consolidated Financial Statements as at June 30, 2011 have been filed under separate cover.
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| ANDERSON ENERGY LTD. PRESS RELEASE AUGUST 15, 2011 | | | 8 | |
FORWARD-LOOKING STATEMENTS
Certain statements 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; percentage of production from oil and natural gas liquids; dates of commencement of production; amount of capital expenditures and the timing and method of financing thereof; value of undeveloped land; extent of reserves additions; ability to attain cost savings; drilling program success; impact of changes in commodity prices on operating results; impact of changes in the royalty regime applicable to the Company; estimates of future revenues, costs, netbacks, funds from operations and debt levels; 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; adequate weather to conduct operations; sufficiency of budgeted capital, operating and other costs to carry out planned activities; 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; changes to government regulation; ability to access sufficient capital from internal and external sources; and other factors, many of which are beyond the Company’s control. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as the factors are interdependent, and management’s future course of action would depend on its assessment of all information at the time. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements and readers should not place undue reliance on the assumptions and 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) or at Anderson Energy’s website (www.andersonenergy.ca).
Estimates of future revenues, costs, netbacks, funds from operations and debt levels may constitute future oriented financial information or a financial outlook under applicable securities laws, and are presented to provide readers with a comparison to levels in 2009 and 2010 based on the various assumptions described or inherent in the estimates. Readers are cautioned that the information may not be appropriate for other purposes.
This news release contains information regarding forecasts that were obtained from reports prepared by third parties. None of the authors of such reports have provided any form of consultation, advice or counsel regarding any aspect of this news release. Actual outcomes may vary materially from the forecast in such reports, and the prospect for material variation can be expected to increase as the length of the forecast period increases.
The forward-looking statements contained in this news release are made as at the date of this news release and the Company 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.
CONVERSION
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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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
Calgary, Alberta
Brian H. Dau
Calgary, Alberta
Christopher L. Fong (1)(2)(3)
Calgary, Alberta
Glenn D. Hockley (1)(3)
Calgary, Alberta
David J. Sandmeyer (2)(3)
Calgary, Alberta
David G. Scobie (1)(2)
Calgary, Alberta
Member of:
| (2) | Compensation & Corporate |
Governance 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, AXL.DB
Contact Information
Anderson Energy Ltd.
Brian H. Dau
President & Chief Executive Officer
(403) 262-6307
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
Sandra M. Drinnan
Vice President, Land
Philip A. Harvey
Vice President, Exploitation
Jamie A. Marshall
Vice President, Exploration
Patrick M. O’Rourke
Vice President, Production
Abbreviations used
AECO – intra-Alberta Nova inventory transfer price
bbl – barrel
bpd – barrels per day
Mstb – thousand stock tank barrels
BOE – barrels of oil equivalent
BOED – barrels of oil equivalent per day
BOPD – barrels of oil per day
MBOE – thousand barrels of oil equivalent
GJ – gigajoule
Mcf – thousand cubic feet
Mcfd – thousand cubic feet per day
MMcf – million cubic feet
MMcfd – million cubic feet per day
NGL – natural gas liquids
WTI – West Texas Intermediate
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