Market Overview

Anderson Energy Announces 2016 First Quarter Results

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CALGARY, ALBERTA--(Marketwired - May 12, 2016) - Anderson Energy Inc. ("Anderson" or the "Company") (TSX:AXL) announces its operating and financial results for the first quarter ended March 31, 2016. The Company will be filing its unaudited condensed interim financial statements and management's discussion and analysis ("MD&A") for the three months ended March 31, 2016 on SEDAR today. Copies can be found under the Company's profile on www.sedar.com and on the Company's website at www.andersonenergy.ca.

HIGHLIGHTS



-- As of March 31, 2016, the Company had no bank debt and positive working
capital of $5.2 million (compared to a $6.7 million adjusted working
capital surplus at the end of 2015).
-- Production in the first quarter of 2016 was 1,884 BOED (42% oil,
condensate and NGL), down 30% from the first quarter of 2015 due to
natural declines and the dispositions of mostly shallow gas properties
during 2015 and the first quarter of 2016. Cardium production
represented 1,593 BOED (46% oil, condensate and NGL) of first quarter
production.
-- Funds from (used in) operations for the three months ended March 31,
2016 were ($1.2 million) compared to funds from (used in) operations of
$0.3 million in the first quarter of 2015. The convertible debentures
have been settled in 2016 and there will be no cash interest paid on the
debentures in 2016. Funds from (used in) operations before interest on
convertible debentures were ($0.1 million) for the three months ended
March 31, 2016 and $1.8 million for the fourth quarter of 2015.
-- The operating netback in the first quarter of 2016 was $7.40 per BOE
compared to $14.98 per BOE in the first quarter of 2015. The operating
netback from Cardium properties in the first quarter of 2016 was $13.19
per BOE.
-- In light of the changes in commodity prices, the Company made additional
changes to its administrative cost structure effective March 1, 2016
which are expected to reduce 2016 gross G&A expenses by $1.0 million
compared to 2015. The Company also implemented several changes in the
field during 2015 and 2016, which are expected to result in operating
costs of approximately $11.00 per BOE in 2016.
-- A new horizontal oil development project has been added to the Company's
portfolio in central Alberta in the Duvernay Carbonates. Anderson has
assembled over 12 sections of 100% working interest land in this project
area, which is prospective for light oil horizontal drilling at medium
depth.
-- On January 31, 2016, the Company exercised its right to repay both the
principal amount ($50.0 million) and the accrued and unpaid interest
($1.875 million) on the 7.50% Series A convertible unsecured
subordinated debentures that matured on January 31, 2016 (the "Series A
Debentures") in common shares of the Company. The exchange price was
$0.00565616 per common share and 9.171 billion common shares were issued
from treasury.
-- On April 1, 2016, the holders of the Series B Debentures (the "Series B
Debentureholders") passed an extraordinary resolution to exchange the
entire principal amount ($46.0 million) of the 7.25% Series B
convertible unsecured subordinated debentures maturing June 30, 2017
(the "Series B Debentures"), and the interest that would otherwise
accrue on the Series B Debentures to June 30, 2016 ($1.667 million), for
common shares of the Company using an exchange price of $0.00565616 per
common share, for 8.428 billion common shares to be issued from treasury
(the "Exchange Transaction"). The Exchange Transaction closed and the
common shares were issued on May 10, 2016.
-- The Company intends to propose a share consolidation ratio of 1,000 pre-
consolidation common shares to one (1) post-consolidation share at an
annual meeting of shareholders scheduled to be held on June 14, 2016.
-- The Company has received an indicative term sheet to renew its bank
facility at $18 million, subject to formal approval by the bank and
other closing conditions. The available lending limit of the facility is
based on the bank's interpretation of the Company's reserves and future
commodity prices. The new facility is lower than the previous $31
million, reflecting the dramatically lower commodity prices and Company
reserves in the current economic environment compared to May 2015 when
the previous limit was established. The Company has not drawn on the
facility.



FINANCIAL AND OPERATING HIGHLIGHTS



Three months ended March 31
----------------------------------------------------------------------------
(thousands of dollars, unless otherwise
stated) 2016 2015 % Change
----------------------------------------------------------------------------
Oil and gas sales(1) $ 3,454 $ 6,989 (51%)
Revenue, net of royalties(1) $ 3,164 $ 6,253 (49%)
Funds from (used in) operations $ (1,199) $ 275 (536%)
Funds from (used in) operations per share
- basic and diluted $ - $ - -
Adjusted earnings (loss) before taxes(2) $ (4,382) $ 24,300 (118%)
Adjusted earnings (loss) before taxes per
share(2) - basic and diluted $ - $ 0.14 (100%)
Earnings (loss) $ (4,382) $ 23,923 (118%)
Earnings (loss) per share
Basic and diluted $ - $ 0.14 (100%)
Capital expenditures (net of proceeds on
dispositions) $ 1,492 $ (28,158) 105%
Bank loans and adjusted working capital $ 5,158 $ 2,822 83%
Convertible debentures $ 44,416 $ 91,968 (52%)
Shareholders' equity (deficit) $ 1,759 $ (3,753) 147%
Average shares outstanding (thousands):
Basic and diluted 6,320,422 172,550 3,563%
Ending shares outstanding (thousands) 9,343,965 172,550 5,315%
Average daily sales:
Oil and condensate (bpd) 646 1,089 (41%)
NGL (bpd) 148 162 (9%)
Natural gas (Mcfd) 6,538 8,716 (25%)
Barrels of oil equivalent (BOED)(3) 1,884 2,704 (30%)
Average prices:
Oil and condensate ($/bbl) $ 39.12 $ 47.90 (18%)
NGL ($/bbl) $ 5.86 $ 13.68 (57%)
Natural gas ($/Mcf) $ 1.81 $ 2.65 (32%)
Barrels of oil equivalent ($/BOE)(3) $ 20.15 $ 28.72 (30%)
Royalties ($/BOE) $ 1.69 $ 3.02 (44%)
Operating costs ($/BOE) $ 10.78 $ 10.39 4%
Transportation costs ($/BOE) $ 0.28 $ 0.33 (15%)
Operating netback ($/BOE)(2) $ 7.40 $ 14.98 (51%)
Wells drilled (gross) - 2 (100%)
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(1) Includes royalty and other income classified with oil and gas sales.
(2) Adjusted earnings (loss) before taxes, adjusted earnings (loss) before
taxes per share and operating netback per BOE are considered non-GAAP
measures. Refer to the section entitled "Non-GAAP Measures" in the MD&A
for a more complete description of these non-GAAP terms,
reconciliations to the closest related GAAP measures, and the purposes
for which management uses the non-GAAP measures. These non-GAAP
measures may not be comparable with the calculation of similar measures
for other entities.
(3) 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.



OPERATING ENVIRONMENT

Oil and natural gas prices continue to be low in 2016. The average WTI oil price per bbl was approximately $33.52 US in the first three months of 2016, $42.17 US in the fourth quarter of 2015 and $48.76 US for the full year of 2015. The lowest average monthly oil price seen to date in 2016 was $30.62 US per bbl, realized in February 2016 and has improved to $41.12 US for April 2016 and approximately $44.44 US in May to date. Although the US/Canadian dollar exchange rate moved beneficially from an average of approximately $0.78 in 2015 to approximately $0.73 in the first quarter of 2016, it did not sufficiently compensate for the collapse in WTI pricing and it has increased again since the end of the quarter. Recent average NYMEX futures pricing for WTI for June through December 2016 is approximately $48.26 US per bbl ($62.35 Canadian per bbl).

Natural gas prices have continued to decrease since the fourth quarter of 2015 and AECO pricing in April 2016 of $1.04 per GJ is the lowest it has been in many years. US and Canadian natural gas storage levels are historically high for this time of year, therefore natural gas prices will likely be depressed until the onset of winter next year. In response to the decline in oil prices, the Company stopped its drilling program on January 28, 2015. The Company focused its efforts on reducing operating, administrative and capital costs, in both the office and in the field in order to be positioned to resume drilling when commodity prices improve.

OPERATING INITIATIVES

In 2015 and to date in 2016, significant progress has been made in focusing the Company's asset base into the core Cardium operating areas and divesting or shutting in production outside of these focus areas. 199 wellbores were sold and 48 wellbores were abandoned in 2015 resulting in a 37% reduction in the gross active well count (31% reduction in net active well count). In addition, reclamation certificate applications were submitted to the AER for 28 gross (23.7 net) abandoned wells and one reclamation certificate was received. It is expected that reclamation certificate applications will be submitted for a similar number of wells in 2016.

These initiatives have continued into 2016 with 63 gross (48.4 net) well abandonments planned; of which 16 gross (8.7 net) wells have already been abandoned to date in 2016. With this work underway, the Company is actively reducing its long-term decommissioning obligations. The Company is projecting the non-producing well count at year end 2016 will be further reduced by 25% on a gross basis and 27% on a net basis as a result of the planned 2016 well abandonment program.

The Company has recently signed a letter of intent to dispose of 12 gross (9.8 net) shallow gas wells and closing is expected to occur late in the second quarter of 2016.

Anderson has successfully completed the transition away from its shallow gas legacy and in the first quarter of 2016, the Company has only 40 gross (27.4 net) producing shallow gas wells which contribute approximately 700 Mcfd or 6% of the Company's first quarter of 2016 production.

Corporate production is now derived primarily from the Cardium formation in the greater Willesden Green operating area which represents 83% of the production in the first quarter of 2016. Of the remainder, 11% is from various deeper producing formations in the general Sylvan Lake area.

This rebalancing of the portfolio has allowed the Company to more effectively focus its resources on the core operating areas resulting in significant reductions in operating expenses, reduced staff count, and the implementation of a wellbore and facilities decommissioning program which takes advantage of the current low-cost structure from service providers.

2016 PRODUCTION AND CAPITAL PROGRAM

The Company estimates production will be approximately 1,500 to 1,600 BOED (42% oil, condensate and NGL) for the full year of 2016. Production in the first quarter of 2016 was 1,884 BOED (42% oil, condensate and NGL), slightly higher than the upper end of the first quarter estimate of 1,750 to 1,850 BOED (42% oil, condensate and NGL). The Company's 2016 capital budget of $3 million is restricted to maintenance capital, capitalized G&A and land acquisitions (net of dispositions). The price trigger to consider starting up a new drilling program is estimated to be approximately $50 WTI US per bbl. Where possible, Anderson tries to achieve a 12-month or less payout on new drilling projects and the combination of capital costs, operating costs, fiscal regime and commodity prices are the variables that need to be determined prior to undertaking a capital program. As well, due to historically wet ground conditions in the Willesden Green area in June and July, the earliest the Company could initiate a drilling program would be August or September 2016.

LIGHT OIL HORIZONTAL POTENTIAL DRILLING OPPORTUNITIES

The Company's undeveloped light oil horizontal potential drilling opportunities at May 12, 2016, are outlined below:



Prospect Area (number of potential drilling opportunities) Gross Net(i)
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Willesden Green Cardium 74 55.0
West Pembina/Buck Lake Cardium 18 7.5
Willesden Green Glauconite 6 6.0
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Total Light Oil Horizontal Potential Drilling Opportunities 98 68.5
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(i) Net is net revenue interest.

GLJ Petroleum Consultants, the Company's independent reserves evaluator, booked undeveloped reserves to 17.9 of these net potential drilling opportunities at December 31, 2015.

The Duvernay Carbonate light oil horizontal project lands acquired in the first quarter of 2016 could yield an incremental four potential horizontal drilling opportunities per section. The Company acquired over 12 sections of 100% working interest lands.

COMMODITY PRICES

A comparison of Anderson's average oil and condensate price to various market prices is presented below. The difference between Anderson's realized price and WTI Canadian is due to the price differential between Cushing, Oklahoma and Edmonton, Alberta, product transportation costs from the field to Edmonton, and adjustments for product quality. There were no financial derivative or fixed-price contracts in 2016 or 2015.

CRUDE OIL AND CONDENSATE PRICES



Three months ended
March 31
----------------------------------------------------------------------------
2016 2015
----------------------------------------------------------------------------
WTI - $US $ 33.52 $ 48.56
WTI - $Cdn $ 45.96 $ 60.28
Differential from Cushing to Edmonton - $US per bbl $ 3.68 $ 6.79
Edmonton Par - $Cdn per bbl $ 40.90 $ 51.70
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Anderson average oil price per bbl $ 39.07 $ 47.81

Anderson average oil and condensate price per bbl(i) $ 39.12 $ 47.90
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(i)Condensate includes field condensate and plant condensate.

Monthly WTI Canadian oil prices were $52.71 per bbl in April and approximately $57.04 per bbl in May 2016 month to date. Differentials from Cushing, Oklahoma to Edmonton, Alberta were approximately $2.16 US per bbl in April and $4.37 US per bbl in May 2016.

Going forward, light oil prices are expected to remain weak in the short term. Over the long term, prices will continue to be volatile and will be influenced by the balance between supply and demand, and by geopolitical events. Differentials between Cushing, Oklahoma and Edmonton, Alberta and the US/Canadian dollar exchange rate will also remain volatile.

A comparison of Anderson's average plant gate natural gas price to various market prices is presented below. The difference between the AECO price and Anderson's plant gate price is due to transportation costs and the heat content of the gas. There were no financial derivative or fixed-price contracts during 2016 or 2015.

The average heat content of the Company's natural gas has increased from 1,086 Btu/scf in the first quarter of 2015 to 1,122 Btu/scf in the first quarter of 2016 due to the new Cardium gas having higher heat content than the Company's legacy shallow gas production. Natural gas is sold on the basis of heat content; therefore, higher heat content gas will yield higher prices per unit of measured volume.

NATURAL GAS PRICES



Three months ended
March 31
----------------------------------------------------------------------------
2016 2015
----------------------------------------------------------------------------
NYMEX $US per MMBtu $ 1.99 $ 2.82
AECO $CAD per GJ $ 1.74 $ 2.61
AECO $CAD per MMBtu $ 1.83 $ 2.75
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Anderson average plant gate price per Mcf $ 1.81 $ 2.65
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AECO natural gas prices were $1.04 per GJ ($1.10 per MMBtu) in April and approximately $1.17 per GJ ($1.24 per MMBtu) month to date in May 2016.

The recent forest fires in northern Alberta have led to the temporary shut-down of various oil sands production facilities and the disruption of demand for natural gas used in those operations. As a result of the demand disruption, AECO spot prices decreased below $1.00 per GJ for some days in May 2016. The extent and duration of the impact of the fires, and how it might affect the Company's financial and operating results has not been determined. Reports in recent days have been encouraging, indicating that disruptions may be relatively short-lived.

Natural gas prices are influenced by weather and other events and are tempered by the increasing supply of new shale gas. Until meaningful exports of natural gas commence from North America through liquefied natural gas projects, the Company believes that natural gas prices will be range-bound by weather and other events. Currently, Alberta natural gas prices are very weak due to a warm Alberta winter, the recent northern Alberta fires and continued growth in Western Canadian gas supply, as operators ramped up their drilling activity in anticipation of future LNG exports from British Columbia. However, North American natural gas storage can be no more than full heading into next winter, prompting the possibility of industry production shut-ins this summer and fall. The onset and severity of the North American winter will dictate the prices of natural gas next winter.

FINANCIAL RESULTS

Oil and gas sales for the three months ended March 31, 2016 were $3.5 million compared to $5.0 million and $7.0 million in the fourth quarter and first quarter of 2015 respectively. Decreases in commodity prices reduced oil and gas sales in the first quarter of 2016 by approximately $1.0 million from the fourth quarter of 2015, and the remainder was due to lower production volumes.

On a BOE basis, oil and gas sales averaged $20.15 per BOE in the first quarter of 2016 compared to $26.53 per BOE in the fourth quarter of 2015 and $28.72 per BOE in the first quarter of 2015. During the first quarter of 2016, liquids revenue (i.e. oil, condensate and NGL) represented 69% of total oil and gas sales. The Company's operating netback was $7.40 per BOE in the first quarter of 2016 compared to $15.16 per BOE in the fourth quarter of 2015 and $14.98 per BOE in the first quarter of 2015. Anderson's operating netback for Cardium properties in the first quarter of 2016 was $13.19 per BOE, compared to $21.18 per BOE in the fourth quarter of 2015, and $22.14 per BOE in the first quarter of 2015.

Funds from (used in) operations for the three months ended March 31, 2016 were ($1.2 million) compared to funds from (used in) operations of less than $0.1 million and $0.3 million in the fourth quarter and first quarter of 2015 respectively. At low commodity prices, interest on convertible debentures had a significant impact on funds from (used in) operations. The remaining convertible debentures were settled in the second quarter of 2016 and there was no cash interest paid on the debentures in 2016. Funds from (used in) operations before interest on convertible debentures were ($0.1 million) for the three months ended March 31, 2016, $1.8 million for the fourth quarter of 2015 and $2.0 million for the first quarter of 2015. In addition, accrued and unpaid interest of $0.8 million at March 31, 2016 was subsequently paid in common shares and not cash. Funds from (used in) operations in 2016 will include interest on convertible debentures until their maturity, redemption or other settlement and all of this remaining interest was paid in common shares.

The Company reported a loss of $4.4 million in the first quarter of 2016, largely due to lower commodity prices.

Subsequent to March 31, 2016, the Company received an indicative term sheet to renew its bank facility at $18 million, subject to formal approval by the bank and other closing conditions. The available lending limit of the facility is based on the bank's interpretation of the Company's reserves and future commodity prices. The term date and maturity date are expected to be extended to May 31, 2017 and May 31, 2018, respectively.

OIL AND GAS NETBACKS



Average
Average oil and Cash Funds from
natural gas condensate Operating interest (used in)
price price Revenue netback expense operations
($/Mcf) ($/bbl) ($/BOE) ($/BOE) ($/BOE) ($/BOE)
----------------------------------------------------------------------------
Q2 2015 2.51 65.00 34.48 21.54 8.88 7.08
Q3 2015 2.73 54.56 30.18 18.92 9.11 4.17
Q4 2015 2.40 49.78 26.53 15.16 9.70 0.08
Q1 2016 1.81 39.12 20.15 7.40 6.95 (7.01)
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Capital expenditures, before dispositions were $1.6 million for the three months ended March 31, 2016, compared to $0.3 million and $6.9 million in the fourth and first quarters of 2015 respectively. Capital investments in the last three quarters of 2015 and the first quarter of 2016 were focused on maintenance activities and operating expense reduction initiatives, as well as land acquisitions net of dispositions, of $1.0 million in the first quarter of 2016.

COMMODITY HEDGING CONTRACTS

The Company has not hedged any crude oil or natural gas volumes at this time.

The Company continues to evaluate the merits of commodity hedging as part of a price management strategy and to provide a floor for funds from (used in) operations.

CONVERTIBLE DEBENTURES

On January 31, 2016, the Company exercised its right to repay both the entire principal amount of the Series A Debentures ($50.0 million) and the accrued and unpaid interest ($1.875 million) in common shares of the Company. The Company issued approximately 9.171 billion common shares from treasury at an exchange price of $0.00565616 per common share. The exchange price was based on 95% of the 20 day volume weighted average trading price of the common shares on the Toronto Stock Exchange ending five days prior to the maturity date.

On May 10, 2016, the Company exchanged the Series B Debentures ($46.0 million) and the interest that would otherwise accrue on the Series B Debentures to June 30, 2016 ($1.667 million) for common shares of the Company on the basis of an exchange price of $0.00565616 per share, for approximately 8.428 billion common shares issued from treasury.

SHARE CONSOLIDATION

As a result of the issuance of common shares on the repayment of the Series A Debentures and the issuance of common shares to settle the Series B Debentures and related accrued interest amounts, Anderson has positive working capital, no debt and approximately 17.772 billion common shares outstanding. The Company plans to propose a special resolution to approve a share consolidation at an annual and special meeting of shareholders to be held on June 14, 2016 at 9:00 a.m. (Mountain Time) at the Westwinds Conference Room, 2nd Floor Selkirk House, 555 - 4th Avenue S.W., Calgary, Alberta. The Board of Directors intends to recommend a share consolidation ratio of 1,000 to one (1). The share consolidation is subject to approval by the TSX.

The purpose of doing a share consolidation is to reduce the number of outstanding shares in order to improve the trading liquidity of the common shares.



-- More liquidity will make it easier for existing shareholders to sell and
new shareholders to buy the shares when they want to.
-- More liquidity provides better support for the overall market
capitalization of the Company, which will help the Company in
negotiations with other industry participants (e.g. potential sale,
merger or financing opportunities).
-- A share price similar to our peers will allow for better peer
comparisons.
-- A higher share price will encourage institutional investors and
investment funds to invest in the Company, who may be reluctant or
prohibited from investing in stocks trading below $1.00 per share.
-- Theoretically, a share consolidation should not change the value to a
shareholder. As the number of shares decrease, the value per share
should increase by a corresponding amount. However, there may be some
initial market volatility and there may be downward pressure as the
market settles on a value for the common shares. Ultimately, the trading
price should reflect the underlying value of the Company.



SUMMARY

In 2015, the Company shut down its drilling program in response to the collapse in commodity prices. It focused its efforts on reducing both G&A and operating expenses with initiatives undertaken in April 2015 and continuing through to March 2016. The Company also continued its efforts to transition away from shallow gas production through a variety of disposition and abandonment initiatives to allow it to focus on its horizontal oil plays. As of January 2016, 85% of Anderson's production and 88% of its proved plus probable reserves come from the Cardium formation. In 2015, the Company reduced its producing and non-producing net well count by 31% and expects to make further significant reductions in 2016. The Company continues to look for opportunities to sell non-core assets and reduce decommissioning obligations.

Strategically, in 2016, a significant new horizontal oil development project has been added to the Company's portfolio in central Alberta targeting the Duvernay Carbonates.

The Company has cash in the bank, unused bank lines and a sizable inventory of Cardium potential drilling opportunities. In the second quarter of 2016, the Company has settled all of its outstanding convertible debentures. Once a share consolidation is completed, the Company should be more attractive to both investors and industry participants. The industry and its workforce is going through a very difficult downturn. It is difficult to predict when this will turn around and what structural and political changes await the industry. Although the Company will be debt free, with cash in the bank, it still needs higher commodity prices to invest in its drilling projects.

The Company has hunkered down, waiting for an eventual improvement in oil prices. Company engineers estimate that with a $50 WTI US per bbl oil price, the Company can achieve a 12-month payout with new drilling projects. Historically, the Company has been an industry leader in Cardium well results in average initial production rates over the first 30 days ("IP 30") and in achieving low capital costs per well in the Cardium play. When drilling resumes, the Company expects to resume its position as a leader on both parameters in this play.

I appreciate the support of the Board of Directors and the financial sacrifices that staff and management had to make to reposition the Company for the future. Anderson's most recent investor presentation will be posted on the Company's website at www.andersonenergy.ca.

Thank you for your continued patience.

Brian H. Dau, President & Chief Executive Officer

May 12, 2016

FORWARD-LOOKING STATEMENTS

Certain statements in this news release including, without limitation, management's business strategy and assessment of future plans and operations; benefits and valuation of the development prospects described herein; number of potential drilling opportunities; 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 and risks to such expectations; percentage of production from oil, condensate 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; reserves and net present value of future net revenue from reserves; ability to attain cost savings and amount thereof; tax horizon; expectations related to future operating netbacks; impact of changes in commodity prices on operating results; programs to optimize, rationalize, consolidate and improve profitability of assets, including the impact from shutting-in or abandonment of wells; factors on which the continued development of the Company's oil and gas assets are dependent; benefits of recently completed transactions including the Exchange Transaction and the impact of these transactions on Anderson and its capital structure, financial position, liquidity and net asset value; growth potential of Anderson's asset base; the results of the annual review of Anderson's bank facility; Anderson's ability to implement its plans relating to the share consolidation; the timing of the annual and special meeting of shareholders; the timing and benefits of the share consolidation; the potential outcome of litigation and disputes; 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; delays resulting from or inability to obtain required regulatory approvals; changes to government regulation; availability of third-party transportation and processing facilities; ability to access sufficient capital from internal and external sources; ability of Anderson's common shares to remain listed on the TSX; the receipt in a timely manner of regulatory and shareholder approval of the share consolidation; the plans of shareholders and other counterparties with respect to the share consolidation; the expected costs of the share consolidation; 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.

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 or reserves. Individual well performance may vary.

ABBREVIATIONS



bbl - barrel AECO - intra-Alberta Nova inventory
transfer price
bpd - barrels per day Bcf - billion cubic feet
BOE - barrels of oil equivalent Btu - British thermal unit
BOED - barrels of oil equivalent per GJ - gigajoule
day
m3 - cubic meters Mcf - thousand cubic feet
Mbbls - thousand barrels Mcfd - thousand cubic feet per day
MBOE - thousand barrels of oil MMBtu - million British thermal units
equivalent
Mstb - thousand stock tank barrels MMcf - million cubic feet
NGL - natural gas liquids, excluding scf - standard cubic foot
condensate
WTI - West Texas Intermediate US - United States



FOR FURTHER INFORMATION PLEASE CONTACT:
Anderson Energy Inc.
Brian H. Dau
President & Chief Executive Officer
403-262-6307
403-261-2792 (FAX)
www.andersonenergy.ca

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