EXHIBIT 99.1
Anderson Energy Announces Strong 2011 Third Quarter Results, a 76% Increase in Oil and NGL Production and Doubled Cardium Proved Plus Probable Reserves
Calgary, Alberta, November 15, 2011 - Anderson Energy Ltd. (“Anderson” or the “Company”) (TSX:AXL) is pleased to announce its operating and financial results for the three and nine months ended September 30, 2011.
HIGHLIGHTS
| – | Funds from operations in the third quarter were $12.7 million, up 61% from the third quarter of 2010. Earnings were $7.5 million in the third quarter of 2011. |
| – | Total production was 7,351 BOED in the third quarter of 2011 compared to 7,292 BOED in the third quarter of 2010. |
| – | Oil and NGL production averaged 2,345 bpd in the third quarter, up 76% from the prior year. Oil represented 1,709 bpd of total production and was 201% higher than last year. |
| – | GLJ Petroleum Consultants (“GLJ”) have completed an interim reserves report of all of the Company’s oil and natural gas properties effective October 1, 2011. Proved plus probable (“P&P”) BOE reserves have increased 13% from December 31, 2010 to 35.8 MMBOE. |
| – | P&P reserves replacement was 650% for oil and 571% for oil and NGL. On a BOE basis, Anderson replaced 297% of production with P&P reserves in the first nine months of 2011. |
| – | In the last nine months, Anderson increased proved developed producing (“PDP”), total proved (“TP”) and P&P oil reserves by 72%, 28% and 62% respectively through Cardium drilling. |
| – | Cardium P&P reserves more than doubled to 9.9 MMBOE representing 28% of total P&P reserves volumes and 46% of total P&P reserves value on a pre-tax 10% net present value (“NPV 10”) basis. The Company's net asset value is estimated to be $1.56 per share. |
| – | Anderson achieved a 23% reduction in drilling and completion costs in the Garrington and Willesden Green operating areas in the third quarter, making the average cost to drill and complete a well $2.3 million. To date in the fourth quarter of 2011, Anderson’s drilling and completion costs in the Garrington field have been $2.1 million per well. |
| – | Anderson announced a new Cardium light oil discovery in Ferrier on October 26, 2011, confirming an extension to the Ferrier Cardium G Oil Pool. By year end, a total of four wells are expected to be drilled in Ferrier. |
| – | Capitalizing on the oil drilling success in the third quarter, the 2011 capital program has been increased to $145 million allowing for acceleration of capital spending that was originally planned for the first quarter of 2012. Anderson now expects to drill 36% more net wells than previously planned in 2011 and the net benefit is expected to be more oil production and cash flow from operations in 2012. |
FINANCIAL AND OPERATING HIGHLIGHTS
| Three months ended September 30 | Nine months ended September 30 | |||||||||||||||||||||||
(thousands of dollars, unless otherwise stated) | 2011 | 2010 | * | % Change | 2011 | 2010 | * | % Change | ||||||||||||||||
Oil and gas sales** | $ | 28,513 | $ | 18,928 | 51 | % | $ | 85,665 | $ | 62,511 | 37 | % | ||||||||||||
Revenue, net of royalties** | $ | 24,970 | $ | 17,263 | 45 | % | $ | 76,029 | $ | 55,756 | 36 | % | ||||||||||||
| Funds from operations | $ | 12,655 | $ | 7,876 | 61 | % | $ | 37,467 | $ | 27,234 | 38 | % | ||||||||||||
| Funds from operations per share | ||||||||||||||||||||||||
| Basic and diluted | $ | 0.07 | $ | 0.05 | 40 | % | $ | 0.22 | $ | 0.16 | 38 | % | ||||||||||||
Earnings (loss) before effect of impairment or reversals thereof | $ | 6,667 | $ | (3,057 | ) | 318 | % | $ | 8,918 | $ | (5,251 | ) | 270 | % | ||||||||||
| Earnings (loss) per share before effect of impairment or reversals thereof | ||||||||||||||||||||||||
| Basic and diluted | $ | 0.04 | $ | (0.02 | ) | 300 | % | $ | 0.05 | $ | (0.03 | ) | 267 | % | ||||||||||
| Earnings (loss) | $ | 7,472 | $ | (39,029 | ) | 119 | % | $ | 9,723 | $ | (88,242 | ) | 111 | % | ||||||||||
| Earnings (loss) per share | ||||||||||||||||||||||||
| Basic and diluted | $ | 0.04 | $ | (0.23 | ) | 117 | % | $ | 0.06 | $ | (0.52 | ) | 112 | % | ||||||||||
Capital expenditures, including acquisitions net of dispositions | $ | 49,713 | $ | 39,378 | 26 | % | $ | 118,351 | $ | 85,269 | 39 | % | ||||||||||||
| Bank loans plus cash working capital deficiency | $ | 108,583 | $ | 102,198 | 6 | % | ||||||||||||||||||
| Convertible debentures | $ | 84,334 | $ | - | 100 | % | ||||||||||||||||||
| Shareholders’ equity | $ | 195,251 | $ | 215,389 | (9 | % ) | ||||||||||||||||||
Average shares outstanding (thousands): | ||||||||||||||||||||||||
| Basic | 172,550 | 172,400 | - | 172,534 | 169,569 | 2 | % | |||||||||||||||||
| Diluted | 172,550 | 172,400 | - | 173,040 | 169,569 | 2 | % | |||||||||||||||||
Ending shares outstanding (thousands) | 172,550 | 172,400 | - | |||||||||||||||||||||
| Average daily sales: | ||||||||||||||||||||||||
Natural gas (Mcfd) | 30,038 | 35,778 | (16 | % ) | 31,972 | 36,668 | (13 | % ) | ||||||||||||||||
Oil (bpd) | 1,709 | 568 | 201 | % | 1,615 | 469 | 244 | % | ||||||||||||||||
NGL (bpd) | 636 | 761 | (16 | % ) | 667 | 762 | (12 | % ) | ||||||||||||||||
Barrels of oil equivalent (BOED) | 7,351 | 7,292 | 1 | % | 7,610 | 7,342 | 4 | % | ||||||||||||||||
| Average prices: | ||||||||||||||||||||||||
Natural gas ($/Mcf) | $ | 3.85 | $ | 3.43 | 12 | % | $ | 3.74 | $ | 4.12 | (9 | % ) | ||||||||||||
Oil ($/bbl) | $ | 89.05 | $ | 68.24 | 30 | % | $ | 91.59 | $ | 70.77 | 29 | % | ||||||||||||
NGL ($/bbl) | $ | 66.07 | $ | 51.41 | 29 | % | $ | 68.76 | $ | 53.89 | 28 | % | ||||||||||||
Barrels of oil equivalent ($/BOE)** | $ | 42.16 | $ | 28.21 | 49 | % | $ | 41.23 | $ | 31.19 | 32 | % | ||||||||||||
Realized gain (loss) on derivative contracts ($/BOE) | $ | 1.29 | $ | - | 100 | % | $ | (0.17 | ) | $ | - | (100 | % ) | |||||||||||
Royalties ($/BOE) | $ | 5.24 | $ | 2.48 | 111 | % | $ | 4.64 | $ | 3.37 | 38 | % | ||||||||||||
Operating costs ($/BOE) | $ | 11.22 | $ | 9.45 | 19 | % | $ | 11.30 | $ | 9.96 | 13 | % | ||||||||||||
Transportation costs ($/BOE) | $ | 0.89 | $ | 0.26 | 242 | % | $ | 0.63 | $ | 0.19 | 232 | % | ||||||||||||
Operating netback ($/BOE) | $ | 26.10 | $ | 16.02 | 63 | % | $ | 24.49 | $ | 17.67 | 39 | % | ||||||||||||
Wells drilled (gross) | 21 | 14 | 50 | % | 41 | 43 | (5 | % ) | ||||||||||||||||
* 2010 results have been restated to conform to International Financial Reporting Standards.
** Includes royalty and other income classified with oil and gas sales, but excludes realized and unrealized gains or losses on derivative contracts.
ANDERSON ENERGY LTD. PRESS RELEASE NOVEMBER 15, 2011 | 2 |
OPERATIONS
Cardium Horizontal Oil Drilling. In the third quarter of 2011, Anderson drilled 21 gross (18.0 net capital, 16.4 net revenue) Cardium horizontal oil wells. From May 1, 2010 to September 30, 2011, the Company has drilled 62 gross (50.4 net capital, 45.6 net revenue) wells and placed 58 gross (42.6 net revenue) Cardium oil wells on production. The Company plans to drill 51 gross (44.3 net capital, 39.1 net revenue) Cardium horizontal oil wells in 2011, which is 36% higher than previous estimates on a net revenue basis.
Cardium Horizontal Oil Capital Costs. Anderson has been diligently reducing its drilling and completion costs with the application of new technology and other cost savings measures. Third quarter 2011 drilling and completion costs in the Garrington and Willesden Green areas are approximately 23% lower than those encountered in the first half of the year even with longer horizontal well lengths and additional fracture stimulation (“frac”) stages.
Garrington/Willesden Green Capital Costs:
| Period | Average Drilling Costs ($MM) | Average Completion Costs ($MM) | Average Drilling and Completion Costs ($MM) | Number of Frac Stages per Well |
| 2010 | 1.6 | 1.4 | 3.0 | 13 |
| First half of 2011 | 1.8 | 1.2 | 3.0 | 17 |
| Third quarter 2011 | 1.4 | 0.9 | 2.3 | 19 |
To date in the fourth quarter of 2011, Anderson’s drilling and completion costs in the Garrington field have been $2.1 million per well.
In the third quarter of 2011, the Company experimented with alternative completion technology to the commonly used open hole casing packer multi-stage fracture stimulation technology. The Company sees considerable benefits in addition to lower costs from the application of this technology. Anderson plans to utilize this technology in the Willesden Green, Garrington and Ferrier fields for its future Cardium horizontal oil wells.
Ferrier Horizontal Cardium Oil Discovery. On October 26, 2011, Anderson announced a new Cardium light oil discovery in Ferrier with an extension to the Ferrier Cardium G oil pool. To date, one operated horizontal oil well and one outside operated horizontal oil well have been drilled. The Company owns or controls 13.8 gross (6.8 net) sections of land in the Ferrier area, with most of the land being a contiguous land block in Twp 37, Ranges 7 and 8 W5M. Based on in-house mapping, the Company estimates it has 30 gross (15.9 net) locations remaining to be drilled in Ferrier. A production tank battery and solution gas compressor have been built to handle the initial production from its operated lands. Two additional appraisal wells are planned to be drilled during the fourth quarter.
Garrington Cardium Oil Pool Update. Anderson has identified a northern extension to its core Garrington field. Recent performance of wells drilled in the northern portion of the Garrington area have been above the average Garrington type curve. 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 was connected by Plains Midstream Canada to the Rangeland Pipeline system on October 24, 2011. This facility is expected to process third party volumes and could represent an attractive source of processing fee income for Anderson.
Garrington represented 59% of the Company’s oil production in the third quarter of 2011. The Company is completing is reservoir computer simulation study to design a waterflood in the Garrington field.
ANDERSON ENERGY LTD. PRESS RELEASE NOVEMBER 15, 2011 | 3 |
Cardium Land and Drilling Inventory. Anderson’s Cardium prospective land inventory is 124.5 gross (74.0 net) sections, an increase of 23% over December 31, 2010. Approximately 85% of the Company’s Cardium lands are located 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 204 gross (129.8 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.
Other Horizontal Oil Opportunities. The Company has identified five non-Cardium zones on its lands in central Alberta, with potential for horizontal oil drilling with multi-stage fracture stimulation, which is similar technology as used in Cardium horizontal drilling. These zones are Second White Specs, Belly River, Viking, Glauconite and Mannville. Anderson has 50.8 gross (29.1 net) sections of land in the emerging Second White Specs horizontal oil play. The Company is currently evaluating the timeline and level of participation to drill these horizons in 2012.
Edmonton Sands Farm-In. Anderson announced a 200 well Edmonton Sands farm-in commitment on January 29, 2009 and drilled 126 wells in the winter of 2009/2010. The Company was planning to drill the remaining 74 wells during the upcoming winter. The terms of the farm-in agreement have been modified to extend the commitment date to March 31, 2013. With weak natural gas prices, it has been decided to defer drilling the remaining 74 wells until after 2012.
RESERVES
GLJ, an independent reserves evaluator, has completed an interim reserves report of all of the Company’s oil and natural gas properties effective October 1, 2011, prepared in accordance with procedures and standards contained in the Canadian Oil and Gas Evaluation (“COGE”) Handbook. The reserves definitions used in preparing the interim report are those contained in the COGE Handbook and the Canadian Securities Administrators National Instrument 51-101. This is not a year end reserves report. The October 1, 2011 report is the first step in the process and will be updated by GLJ for year end reserves reporting. As of October 1, 2011, the Company has 12.4 MMBOE PDP (30% oil and NGL), 19.5 MMBOE TP (23% oil and NGL) and 35.8 MMBOE P&P (27% oil and NGL) reserves. The price forecast used in the evaluation is shown in Management’s Discussion and Analysis for the three and nine months ended September 30, 2011.
P&P reserves replacement was 650% for oil and 571% for oil and NGL. On a BOE basis, Anderson replaced 297% of production with P&P reserves in the first nine months of 2011. The Company's P&P BOE reserves increased 13% since December 31, 2010.
P&P reserves from the Cardium drilling program are 9.9 MMBOE at October 1, 2011, more than double the 4.7 MMBOE at December 31, 2010. Cardium reserves represent 28% of total P&P reserves volumes and 46% of total P&P reserves value on a pre-tax NPV 10 basis.
Since the inception of the Cardium play 18 months ago and including production, the Company has added 10.5 MMBOE of P&P reserves with its Cardium drilling program.
ANDERSON ENERGY LTD. PRESS RELEASE NOVEMBER 15, 2011 | 4 |
SUMMARY OF OIL AND GAS RESERVES
| October 1, 2011 | December 31, 2010 | ||||||||||
Oil (Mbbls) | NGL (Mbbls) | Gas (MMcf) | Total (MBOE) | Pre-tax NPV 10 ($M) | Oil (Mbbls) | NGL (Mbbls) | Gas (MMcf) | Total (MBOE) | Pre-tax NPV 10 ($M) | ||
Proved developed producing | 2,242 | 1,460 | 52,069 | 12,379 | 207,113 | 1,303 | 1,376 | 52,498 | 11,428 | 166,058 | |
| Proved developed producing and proved developed non-producing | 2,375 | 1,512 | 59,213 | 13,755 | 219,933 | 1,471 | 1,426 | 59,955 | 12,889 | 175,619 | |
| Total proved | 2,840 | 1,703 | 89,842 | 19,517 | 227,772 | 2,226 | 1,673 | 97,313 | 20,117 | 184,248 | |
| Proved plus probable | 6,334 | 3,185 | 157,525 | 35,773 | 349,575 | 3,908 | 2,676 | 150,621 | 31,687 | 271,469 | |
Oil now represents 18% of the Company's PDP, 15% of TP and 18% of P&P reserves as compared to 11%, 11% and 12% respectively at December 31, 2010. Anderson increased PDP, TP and P&P oil reserves by 72%, 28% and 62%, respectively, in the previous nine months.
NET ASSET VALUATION 1
As at September 30, 2011
($ millions, unless otherwise stated) | ||||
| P&P reserves (pre-tax NPV 10) | $ | 350 | ||
| Undeveloped land (excluding Cardium horizontal prospective lands) | 5 | |||
Cardium horizontal prospective lands 2 | 118 | |||
| Unrealized hedging gains and stock option proceeds | 18 | |||
| Bank loans plus cash working capital deficiency | (109 | ) | ||
| Series B convertible debentures | (46 | ) | ||
Net asset value estimate, September 30, 2011 1 | $ | 336 | ||
Net asset value estimate per fully diluted share, September 30, 2011 3,4 | $ | 1.56 | ||
| 1 | The net asset valuation (“NAV”) shows what the Company’s reserves would be produced at using GLJ’s October 1, 2011 price forecast and costs. The value is a snapshot in time and based on various assumptions including commodity prices that vary over time. It should not be assumed that NAV represents the fair market value of Anderson shares. GLJ’s price forecast at October 1, 2011 for the period 2012 to 2017 is an average of $0.57 per Mcf lower than at January 1, 2011, which negatively impacted NPV 10 by approximately $30 million. |
| 2 | Cardium undeveloped land valued at $2.5 million per net section not booked in the interim GLJ reserves report assuming $2.4 million NPV 10 per net location drilled over a three year time span (49.4 net unbooked locations). |
| 3 | For the purposes of this calculation at September 30, 2011, it was assumed that the Series B convertible debentures (convertible at $1.70 per share) would remain as debt and the Series A convertible debentures would be converted at $1.55 per share and the outstanding shares were adjusted accordingly. |
| 4 | Based on 215.1 million outstanding shares on a fully diluted basis. |
The NAV per share calculation discussed above does not include any upside associated with the Company's extensive land holdings prospective for horizontal oil in the Second White Specs, Viking, Belly River, Mannville and Glauconite zones. It also does not include any incremental value associated with the Company's shallow gas drilling inventory in a more supportive natural gas price environment.
PRODUCTION
During the third quarter of 2011, the Company averaged 7,351 BOED, with oil and NGL volumes representing 32% of total volumes. Oil and NGL production for the three months ended September 30, 2011 was 2,345 bpd, up substantially from 1,329 bpd in the third quarter of 2010. Of this, 1,709 bpd or 73% is crude oil production, compared to 568 bpd or 43% in the third quarter of 2010. The Company’s
ANDERSON ENERGY LTD. PRESS RELEASE NOVEMBER 15, 2011 | 5 |
production in the third quarter of 2011 was negatively impacted by plant outages and a slow start to the third quarter drilling program caused by wet ground conditions. The Company also sold non-core heavy oil properties in the third quarter of 2011. Anderson estimates that production in the fourth quarter of 2011 could reach 8,200 BOED with oil and NGL production representing approximately 43% of total production. The Company estimates that 2011 total production will be at the mid point of its previously stated guidance of 7,500 to 8,000 BOED.
Anderson estimates that oil and NGL production will average approximately 45% of total production in 2012 and that the Company will likely achieve the significant milestone of a balanced production profile sometime during the next twelve months.
FINANCIAL RESULTS
Capital expenditures were $49.7 million (net of proceeds on dispositions of $6.2 million) in the third quarter of 2011 with $43.7 million spent on drilling and completions and $11.4 million spent on facilities. This compares to capital expenditures of $39.4 million in the third quarter of 2010.
Anderson’s funds from operations were $12.7 million in the third quarter of 2011 compared to $7.9 million in the third quarter of 2010. The Company’s average crude oil and natural gas liquids sales prices in the third quarter of 2011 were $89.05 and $66.07 per barrel compared to $68.24 and $51.41 respectively per barrel in the third quarter of 2010. The Company has entered into fixed price oil swaps for 2011 and 2012. The Company’s unrealized gain on its oil hedge was $11.2 million for the nine months ended September 30, 2011. The Company’s average natural gas sales price was $3.85 per Mcf in the third quarter of 2011 compared to $3.43 per Mcf in third quarter of 2010 and included a $0.8 million gain relation to physical fixed price sales contracts. The Company recorded earnings of $7.5 million in the third quarter of 2011 primarily due to the oil hedging gains, a stronger contribution to total revenue by additional oil volumes and higher oil and NGL prices. The Company’s operating netback was $26.10 per BOE in the third quarter of 2011 compared to $16.02 per BOE in the third quarter of 2010. The increase in the operating netback was primarily due to the increase in oil and NGL prices and oil volumes. Anderson’s field net operating income for its Cardium horizontal properties in the first nine months of 2011 was $63.78 per BOE as compared to $14.01 per BOE for the remainder of its properties (exclusive of hedging).
Average wellhead natural gas price ($/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 | |||||||||||||
| Third quarter of 2011 | 3.85 | 42.16 | 26.10 | 18.71 | |||||||||||||
First quarter of 2012 estimate ($90 to $100 WTI Canadian** plus oil hedge program) | 3.75 to 4.00** | 53.00 to 56.00 | 36.00 to 39.00 | 27.00 to 30.00 | |||||||||||||
| * | 2009 results have not been restated to conform to International Financial Reporting Standards. 2010 results have been restated to conform to International Financial Reporting Standards. |
** Estimate
As Anderson increases its oil production, its revenue per BOE, operating netback per BOE and funds from operations per BOE should increase and contribute to profitability in 2012. Royalties were $5.24 per BOE in the third quarter of 2011 compared to $5.37 per BOE in the second quarter of 2011. Operating expenses in the third quarter of 2011 were $11.22 per BOE, which was 7% lower than the second quarter of 2011. The second quarter of 2011 was affected by costs associated with temporary production facilities and wet weather.
ANDERSON ENERGY LTD. PRESS RELEASE NOVEMBER 15, 2011 | 6 |
2011 CAPITAL PROGRAM
During the third quarter of 2011, the Company’s Board of Directors approved an increase in the capital program to $145 million, net of dispositions, to focus on the development of new Cardium oil discoveries and required facility infrastructure for new discoveries in Ferrier, Willesden Green and Garrington North. In addition, the Company will be evaluating with the drill-bit a potentially new core area for Cardium oil development in the Northwest Pembina/Carrot Creek areas. A portion of the capital budget increase is an acceleration of planned 2012 capital spending into 2011. The benefit of the acceleration is expected to be increased oil production and funds from operations in 2012. In 2011, the Company estimates it could drill up to 51 gross (44.3 net capital, 39.1 net revenue) Cardium horizontal oil wells, which is 36% higher on a net revenue basis than previous estimates.
COMMODITY CONTRACTS
Crude Oil. As part of its price management strategy, Anderson has entered into fixed price swap contracts based on the NYMEX crude oil price in Canadian dollars. The average for volumes and prices for these contracts is summarized below:
| Period | Weighted average volume (bpd) | Weighted average WTI Canadian ($/bbl) ) | ||||||
| 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 value of the hedging contracts at September 30, 2011 was $9.2 million.
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, from 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. The Company recorded a $0.8 million gain, included in oil and gas sales in relation to these physical contracts.
STRATEGY
With oil prices at or near present levels, the Company expects to be able to finance the foreseeable drilling program out of cash flow and currently available credit facilities, without the need for external financing. Anderson estimates its oil and NGL production will grow from 18% of total production in 2010 to 34% in 2011 to potentially 45% in 2012. Independent analysts currently estimate that funds from operations could range from $48 million to $59 million in 2011 and $72 million to $95 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, Anderson completed two convertible debenture financings with five to six year terms and conversion prices of $1.55 and $1.70 per common 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 expected to return to more typical levels for junior oil producers by the end of 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. In a stronger
ANDERSON ENERGY LTD. PRESS RELEASE NOVEMBER 15, 2011 | 7 |
natural gas market, the Company has a significant shallow gas inventory of over 850 gross locations that can be drilled. This asset is strategic and valuable to the Company longer term.
Anderson will closely monitor commodity prices and adjust its capital spending plans appropriately to stay within bank lines. The Company is planning to divest of various non-core oil and natural gas properties outside of its Central Alberta core area and use the proceeds from the disposition to reduce bank debt and/or expand its Cardium oil drilling program.
Over the last year, the Company has been able to move up the learning curve in the Cardium play with drilling, completion and production initiatives. Anderson is very focused on increasing its land position in the Cardium and utilizing new technologies to lower costs and enhance well performance.
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. Anderson 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, Anderson estimates it will have 54.5 net revenue Cardium horizontal wells on production, up 28% from the end of the third quarter 2011. The Company has increased its Cardium development drilling inventory by 52% since December 31, 2010 and is becoming an industry leader in lowering Cardium per well capital costs, including a 23% reduction in the third quarter of 2011. Anderson believes it is well positioned in the 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 and 2012, the impact that this higher priced commodity will have on its cash flow and earnings could be significant.
Anderson’s strategy of diversification into light oil drilling is now showing the benefits. Edmonton benchmark light oil prices continue to remain strong despite recent volatility in WTI Canadian oil prices. Anderson estimates that oil and NGL production could average 45% of total production in 2012 and that sometime in 2012, the Company could have a balanced production portfolio of oil and natural gas.
For more information, we encourage investors to review our website at www.andersonenergy.ca.
Brian H. Dau
President & Chief Executive Officer
November 15, 2011
ANDERSON ENERGY LTD. PRESS RELEASE NOVEMBER 15, 2011 | 8 |
This page has been left blank intentionally. The Company’s Management’s Discussion and Analysis for the three and nine months ended September 30, 2011 and the Company’s Interim Consolidated Financial Statements as at September 30, 2011 have been filed under separate cover.
ANDERSON ENERGY LTD. PRESS RELEASE NOVEMBER 15, 2011 | 9 |
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 information” (within the meaning of applicable Canadian securities legislation) or “forward-looking statements” (within the meaning of the United States Private Securities Litigation Reform Act of 1995, as amended) 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’s operations and financial results are included in reports on file with Canadian and U.S. securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), the EDGAR website (www.sec.gov/edgar) or at Anderson’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.
ANDERSON ENERGY LTD. PRESS RELEASE NOVEMBER 15, 2011 | 10 |
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: (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, AXL.DB, AXL.DB.B | Contact Information Anderson Energy Ltd. Brian H. Dau President & Chief Executive Officer (403) 262-6307 info@andersonenergy.ca 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, Drilling and Completions 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 Mbbls – thousand 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 MMBOE – million 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 |
ANDERSON ENERGY LTD. PRESS RELEASE NOVEMBER 15, 2011 | 11 |