Anderson Energy Ltd.

Anderson Energy Ltd.

February 25, 2013 07:55 ET

Anderson Energy Ltd. Provides Operations and Reserves Update

CALGARY, ALBERTA--(Marketwire - Feb. 25, 2013) - Anderson Energy Ltd. ("Anderson" or the "Company") (TSX:AXL) provides the following update on its operations and key results of its year end reserves evaluation. The Company continues to focus on its Cardium light oil assets:

  • 75% of proved plus probable BOE reserves volumes are from the Cardium formation;
  • 90% of proved plus probable pre-tax NPV 10% reserves value is from the Cardium formation;
  • 55% of current BOE production is from Cardium properties;
  • 148 additional net Cardium locations (97% Company operated) have been identified; and
  • slickwater frac technology has significantly improved initial production rates for wells drilled in the Cardium formation.


Anderson has completed its winter drilling program with 6 gross (4.3 net revenue) Cardium oil wells drilled, completed and on production. The Company has completed all of its drilling commitments on third party lands. Wells were drilled in the Ferrier, Willesden Green, Garrington and Buck Lake project areas. Drilling and completion costs were approximately $2.3 million per well in this program.


In February 2012, Anderson initiated its first slick water frac completion in the Cardium formation. The Company had previously employed gelled water and gelled hydrocarbon frac techniques in this formation. Encouraged by the success of its first slick water frac completion and recent industry activity in slick water frac technology, the Company used slick water fracs on its six well Cardium horizontal winter drilling program this winter. Production information from the seven wells confirms that initial production is significantly higher when slick water frac technology is used in the Cardium formation compared to previously used gelled water and gelled hydrocarbon frac techniques. This conclusion is supported by industry activity offsetting Company interest lands. For the wells drilled by the Company that were completed using slick water frac technology, the average initial production ("IP") performance for various calendar day averages is shown below:

Average Gross Initial Production for first X days (IP X) IP 30 IP 60 IP 90 IP 180
Number of wells in average 6 3 1 1
Barrels of oil per day (BOPD) 260 201 247 155
Barrels of oil and NGL per day (BPD) 289 223 296 193
Barrels of oil equivalent per day (BOED)* 417 342 582 415

* Barrels of oil equivalent ("BOE") maybe 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.

The last well drilled in the winter program is not included in the above table as it only recently came on-stream. This well has produced at an average rate of 734 BOPD (860 BOED) over 18 days without artificial lift.

Short term production rates can be influenced by flush production effects from fracture stimulations in horizontal wellbores and may not be indicative of longer term production performance. Individual well performance can vary.


The Company's drilled and drill ready light oil horizontal drilling inventory is outlined below:

Cardium Prospect Area (number of drilling locations) Gross Net *
Garrington 115 87
Willesden Green 119 86
Ferrier 27 17
Pembina 50 17
Total Cardium inventory 311 207
Cardium oil wells drilled to February 22, 2013 79 59
Remaining Cardium inventory 232 148
Horizontal prospect inventory in other zones 108 62
Remaining Cardium and other zone inventory, February 22, 2013 340 210

* Net is net revenue interest

The Company's remaining Edmonton Sands shallow gas drilling inventory is now estimated to be 542 gross (307 net) locations.

The recently completed reserves report effective December 31, 2012, and summarized herein, includes proved plus probable reserves for 48 net Cardium horizontal oil, 0.75 net other horizontal oil and no Edmonton Sands locations. There are a further 100 net Cardium horizontal and 61 net other horizontal light oil locations that are not booked in the GLJ reserves report.


The property dispositions announced in the fourth quarter of 2012 have all been completed. Net of all of the properties sold, the Company estimates first quarter 2013 production to be approximately 3,900 to 4,200 BOED of which 55% is from high netback Cardium properties. Oil & NGL production is estimated to be 43% of the total BOED production in the quarter. The Company shut-in 900 Mcfd of natural gas production which was uneconomic to produce in the current price environment.


GLJ Petroleum Consultants, an independent evaluator, has completed a reserves report (the "GLJ Report") of all the Company's oil and natural gas properties effective December 31, 2012, prepared in accordance with procedures and standards contained in National Instrument 51-101 of the Canadian Securities Administrators ("NI 51-101") and the Canadian Oil and Gas Evaluation ("COGE") Handbook. The reserves definitions used in preparing the report are those contained in the COGE Handbook and NI 51-101. As of December 31, 2012, the Company had 6.9 MMBOE proved developed producing ("PDP") reserves (39% oil & NGL), 10.3 MMBOE total proved ("TP") reserves (43% oil & NGL) and 17.8 MMBOE total proved plus probable ('"P&P") reserves (48% oil & NGL). The reserves report reflects the disposition of $74 million in properties in 2012, the previously announced termination of the Company's shallow gas drilling commitment and the negative impact of significant reductions in natural gas price forecasts over the past year. The percentage of PDP, TP and P&P total BOE reserves volumes from the Cardium formation represent approximately 59%, 66% and 75% respectively. By product, approximately 96% of P&P oil and NGL reserves and 55% of P&P natural gas reserves (primarily solution gas) are in the Cardium formation. The Cardium P&P NPV 10% value is approximately 90% of the total Company P&P NPV 10% value. The Edmonton Sands shallow gas project represents approximately 5% of the total Company P&P NPV 10% value.

A summary of oil and gas reserves at December 31, 2012 is shown below:

Gross Working Interest Oil and Gas Reserves as at December 31, 2012 Oil
) Natural Gas Liquids
) Natural Gas
) Total BOE* (MBOE )
NPV 10% ($000
Proved developed producing 2,089 595 25,150 6,875 114,369
Total proved 3,480 964 35,118 10,297 143,960
Total proved plus probable 6,709 1,814 55,475 17,770 224,826

* Barrels of oil equivalent ("BOE") maybe 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.

The GLJ price forecast, inflation and exchange rate assumptions used in the reserves evaluation is shown below. Over the next 10 years, this price forecast is on average 11% lower for natural gas and 6% lower for oil than the price forecast used in the reserves evaluation last year.

GLJ Price Forecast as at January 1, 2013
Oil Natural Gas Edmonton Liquids Prices
Year WTI Cushing ($US/bbl ) Light, Sweet Crude Edmonton
) AECO Gas Price ($Cdn/MMBtu ) Propane ($Cdn/bbl ) Butane ($Cdn/bbl ) Pentanes Plus ($Cdn/bbl ) Inflation Rate % Exchange rate (US$/Cdn )
2013 90.00 85.00 3.38 34.06 65.45 96.63 2.0 1.00
2014 92.50 91.50 3.83 45.75 70.46 97.91 2.0 1.00
2015 95.00 94.00 4.28 56.40 72.38 97.76 2.0 1.00
2016 97.50 96.50 4.72 57.90 74.31 100.36 2.0 1.00
2017 97.50 96.50 4.95 57.90 74.31 100.36 2.0 1.00
2018 97.50 96.50 5.22 57.90 74.31 100.36 2.0 1.00
2019 98.54 97.54 5.32 58.52 75.11 101.44 2.0 1.00
2020 100.51 99.51 5.43 59.71 76.62 103.49 2.0 1.00
2021 102.52 101.52 5.54 60.91 78.17 105.58 2.0 1.00
2022 104.57 103.57 5.64 62.14 79.75 107.71 2.0 1.00
Thereafter 2%

In March 2013, the Company will provide more detailed information regarding its December 31, 2012 reserves report as part of its customary year end financial reporting and annual information form filings.


The Company is continuing its process to identify, examine and consider a range of strategic alternatives available to the Company with a view to enhancing shareholder value. The strategic alternatives may include, but are not limited to, a sale of all or a material portion of the assets of Anderson, either in one transaction, or in a series of transactions, the outright sale of the Company, or a merger or other strategic transaction involving Anderson and a third party. The Board of Directors believes that the Company's shares trade at a discount to the value of the underlying assets, especially given its high quality light oil production base, prospective horizontal light oil drilling inventory and significant tax pools. The Board of Directors has established a special committee comprised of independent directors of the Company to oversee the process and has retained BMO Capital Markets and RBC Capital Markets as its financial advisors to assist the Special Committee and the Board of Directors with the process.

Since January 1, 2012, the Company has sold approximately $74 million of oil and natural gas properties (71% natural gas) and has restructured its shallow gas and Cardium horizontal drilling commitments. All of the Company's drilling commitments have now been completed.

It is Anderson's current intention to not disclose developments with respect to its strategic alternatives process unless and until the Board of Directors has approved a specific transaction or otherwise determines that disclosure is necessary in accordance with applicable law. The Company cautions that there are no assurances or guarantees that the process will result in a transaction or, if a transaction is undertaken, the terms or timing of such a transaction. The Company has not set a definitive schedule to complete the evaluation.


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; expected production rates; percentage of production from oil and natural gas liquids; dates of commencement of production; extent of reserves additions; drilling program success; potential results of the strategic alternatives review process, including the possibility of further asset dispositions and use of proceeds therefrom, and enhancement of shareholder value; disclosure intentions with respect to the strategic alternatives review process; commodity price outlook and general economic outlook may constitute forward-looking information within the meaning of applicable securities legislation 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; inability to complete property dispositions or to complete them at anticipated values; delays resulting from or inability to obtain required regulatory approvals; changes to government regulation; inability 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 securities regulatory authorities and may be accessed through the SEDAR website ( or at Anderson's website (

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.


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.

Contact Information

  • Anderson Energy Ltd.
    Brian H. Dau
    President & Chief Executive Officer
    (403) 262-6307