CALGARY, ALBERTA–(Marketwired – Feb. 11, 2015) – Anderson Energy Inc. (the “Company”) (TSX:AXL) provides the following operations update.
The Company has completed its 2014/2015 winter drilling program with 10 gross (9.1 net capital, 8.0 net revenue) wells drilled. Due to weak commodity prices, the drilling of the remaining 3 gross (2.2 net) wells in the planned program has been deferred. Seven of the nine Cardium wells drilled have more than 30 days of initial production (“IP 30”). The average production results from the 7 gross (5.3 net) Cardium wells were excellent and have on average exceeded the Company’s expectations with an average IP 30 of 398 BOED (82% oil, condensate and NGL).
Included in the most recent seven Cardium well completions was the Company’s first long-reach well which had an IP 30 of 648 BOED (92% oil, condensate and NGL) with 32 frac stages over a 1.5 mile horizontal well section. According to an industry publication reviewed by the Company, the Cardium long-reach well was one of the top three new oil wells in Alberta in November 2014. The Cardium long-reach well was the Company’s second-best IP 30 BOED well drilled in the 2014/2015 winter drilling program. In addition to the long-reach well, according to another industry publication, two of the Company’s other Cardium oil wells were in the top ten new Cardium oil wells in Alberta in December 2014.
One of the remaining two Cardium wells has been completed and has been production tested. The last Cardium well is awaiting completion this week. Due to TransCanada PipeLines Limited (“TCPL”) maintenance outages and the current commodity pricing environment, continuous production from these two wells will be deferred until the TCPL outages have been rectified and/or better commodity prices are realized in the field. Based on production testing, the initial production performance of the completed Cardium well is expected to be similar to the average of the seven previous wells that were brought on production.
The IP 30 and product mix results of the Cardium wells from the 2014/2015 winter drilling program as noted above compares favourably with the 2013/2014 winter drilling program which had an average IP 30 of 511 BOED (53% oil, condensate and NGL). A comparison of the oil, condensate and NGL components of the BOED production for the two drilling programs shows an average IP 30 of 327 barrels per day for the 2014/2015 winter drilling program and 272 barrels per day for the 2013/2014 winter drilling program. Notwithstanding the market perception of the current oil price environment, oil, condensate and NGL remain more valuable than solution gas, and a higher percentage of oil, condensate and NGL in the Company’s product mix can be more important to overall revenue and profitability than the overall BOED production rate.
All of the Company’s Cardium wells drilled during the 2014/2015 winter drilling program have been, or will be, completed with slick water fracture stimulation technology and have benefitted from the Company’s selective positioning of the horizontal well trajectory. Of the nine Cardium wells drilled in the 2014/2015 winter drilling program, five are in the Central land block, two are in the Northern land block and one is in the Southern land block of the greater Willesden Green area.
The average IP 30 for the Company’s 15 Cardium well completions in the greater Willesden Green area on Company lands since December 2012 is 458 BOED (65% oil, condensate and NGL). A recent industry publication indicated an industry average IP 30 of 322 BOED (60% oil, condensate and NGL) for the greater Willesden Green area since 2012.
The Company drilled one Glauconite well in this program and suffered a mechanical wellbore failure during completion. The Company does have workover options with respect to this well but, given the current commodity price environment, has elected to defer these operations.
At the end of December 2014, exit production volumes were 3,400 BOED (41% oil, condensate and NGL). Production in the fourth quarter was impacted by maintenance outages on the TCPL system. These TCPL outages are significant and are expected to continue throughout the first quarter of 2015.
The Company will provide a further update on its 2015 plans with the release of its year-end results, scheduled for mid-March. The Company plans to commence a marketing program to rationalize its remaining shallow gas assets in the second quarter of 2015.
With the drilling program being terminated earlier than planned, management and staff are focused on netback optimization in both the field and the office. The Company has shut-in or is proceeding to abandon 74 gross (42.7 net) shallow gas wells and suspend 10 compressor stations due to weak natural gas prices. These wells produced approximately 172 BOED.
Last year’s winter drilling program was completed in April and drilling commenced again in August. For 2015, with the current weak commodity pricing environment, the Company stopped drilling in late January and will re-evaluate commodity pricing in July with a view to potentially resuming drilling in August. Notwithstanding the weak commodity price environment, management and employees are encouraged with the Company’s recent stellar well results and the improved liquidity as a result of the reorganization and disposition that was completed on January 23, 2015.
Additional information about Anderson Energy Inc. can be found on the Company’s website and in its most recent investor presentation at www.andersonenergy.ca.
[expand title=”Advisories & Contact”]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; drilling program success; timing and location of drilling and tie-in of wells and the costs thereof; timing of shut-in and abandonment of wells and impact thereof; productive capacity of the wells; expected production rates; percentage of production from oil and natural gas liquids; dates of commencement of production; ability to attain cost savings and improve operating netbacks; programs to optimize, rationalize, consolidate and improve profitability of assets; benefits of recently completed transactions including the result on the Company’s liquidity; commodity price outlook; and general economic outlook may constitute “forward-looking information” within the meaning of 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; 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; 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 securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com) or at Anderson’s website (www.andersonenergy.ca).
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 MEASURES AND SHORT-TERM PRODUCTION RATES
Production volumes and reserves are commonly expressed on a BOE basis whereby natural gas volumes are converted at the ratio of six thousand cubic feet to one barrel of oil. Although the intention is to sum oil and natural gas measurement units into one basis for improved analysis of results and comparisons with other industry participants, BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of six Mcf to one 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. In recent years, the value ratio based on the price of crude oil as compared to natural gas has been significantly higher than the energy equivalency of 6:1, and utilizing a conversion of natural gas volumes on a 6:1 basis may be misleading as an indication of value.
This news release contains production information obtained from reports prepared by certain third parties. None of the authors of such reports has provided any form of consultation, advice or counsel regarding any aspect of this news release and the Company does not warrant the accuracy or completeness of the third party information. Industry data is subject to variations and cannot be verified due to limits on the availability and reliability of data inputs, the voluntary nature of the data gathering process and other limitations and uncertainties inherent in any market or other survey.
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 may vary.
Anderson Energy Inc.
Brian H. Dau
President & Chief Executive Officer
(403) 262-6307
(403) 261-2792 (FAX)
info@andersonenergy.ca
www.andersonenergy.ca
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