Anderson Energy Ltd. ("Anderson Energy" or the "Company") (TSX:AXL) is pleased
to announce its operating and financial results for the fourth quarter and year
ended December 31, 2010.
Repositioning for oil production growth continues to be the primary focus of the
Company in light of the current and projected weakness in natural gas pricing.
As detailed in the following discussion, production from the Cardium horizontal
oil drilling program initiated in the summer of 2010 started to come on-stream
in the fourth quarter of 2010. The Company is making progress in its efforts to
acquire additional Cardium acreage and implement drilling and completion
initiatives to lower costs and improve well productivity and reserves.
HIGHLIGHTS:
- As of March 25, 2011, the Company has 31 gross (22.5 net) producing Cardium
horizontal oil wells. Current Cardium production is approximately 1,800 to 1,900
BOED (85% oil and NGL), with an additional 10 gross (7.3 net) Cardium horizontal
wells expected to be on production in the second quarter of 2011.
- Current oil and NGL production is approximately 2,450 bpd, up from 1,130 bpd
in the first quarter of 2010. Of this number, 1,780 bpd or 73% is crude oil
production, compared to 345 bpd or 31% in the first quarter of 2010.
- Year end reserves were 31.7 MMBOE on a proved plus probable ("P&P") basis, of
which 21% were oil and NGL. The reserve life index was 11.5 years. The Company
replaced 224% of its production with new P&P reserves and replaced 697% of its
oil and NGL production with new oil and NGL P&P reserves.
- Oil & NGL reserves increased from 3.7 MMBOE at the end of 2009 to 6.6 MMBOE on
a P&P basis at December 31, 2010. After drilling 22 gross (15.4 net) wells in
our first year in the play, Cardium reserves were 2.37 MMBOE of total proved
("TP") and 4.7 MMBOE of P&P reserves and represent 14.8% of total P&P reserves.
The Company expects that the Cardium reserves will continue to grow and become a
larger percentage of TP and P&P reserves in future years.
- Finding, development and acquisition costs in 2010, including future
development capital, additions and technical revisions but excluding natural gas
related economic factors, were $22.30 per BOE TP and $22.35 per BOE P&P.
- The Company estimates its net asset value per share to be approximately $1.78
per share.
- Since the inception of the Cardium horizontal oil program, 37 gross (26.7 net)
wells have been drilled with a 100% success rate. In the first quarter of 2011,
15 gross (11.3 net) Cardium horizontal oil wells have been drilled to date, with
four drilling rigs still working in the field.
- The Company has increased its Cardium horizontal well prospective lands from
its January 17, 2011 update by 10% to 112.5 gross (65.8 net) sections. Based on
a drilling density of three wells per section, the Company estimates it could
potentially drill 338 gross (197.4 net) Cardium horizontal wells. The Company's
drill ready non-contingent development drilling inventory has increased by 30%
since January 17, 2011 to 183 gross (111.2 net) locations.
- The Company has a $75 million capital budget in 2011 to be spent almost
exclusively on the Cardium horizontal oil drilling program. The Company
continues to review the commodity price outlook and could potentially expand its
2011 drilling program in the last half of the year with additional Cardium
horizontal drilling.
FINANCIAL AND OPERATING HIGHLIGHTS
Three months ended % Year ended %
(thousands of December 31, Change December 31, Change
dollars) 2010 2009 2010 2009
Oil and gas
revenue before
royalties(1) $ 23,946 $ 20,439 17% $ 86,457 $ 76,993 12%
Funds from
operations $ 9,515 $ 9,151 4% $ 37,180 $ 31,258 19%
Funds from
operations per
share
Basic $ 0.06 $ 0.06 - $ 0.22 $ 0.25 (12%)
Diluted $ 0.06 $ 0.06 - $ 0.22 $ 0.25 (12%)
Net loss $(11,741) $ (6,457) (82%) $(35,631) $(36,458) 2%
Net loss per share
Basic $ (0.07) $ (0.04) (75%) $ (0.21) $ (0.29) 28%
Diluted $ (0.07) $ (0.04) (75%) $ (0.21) $ (0.29) 28%
Capital
expenditures,
including
acquisitions net
of dispositions $ 26,473 $ 11,312 134% $112,173 $ 33,558 234%
Bank loans plus
cash working
capital
deficiency $ 71,507 $ 72,524 (1%)
Convertible
debentures $ 43,460 $ - 100%
Shareholders'
equity $333,791 $332,719 -
Average shares
outstanding
(thousands)
Basic 172,464 150,500 15% 170,298 125,047 36%
Diluted 172,464 150,500 15% 170,298 125,047 36%
Ending shares
outstanding
(thousands) 172,485 150,500 15%
Average daily
sales
Natural gas
(Mcfd) 38,479 34,938 10% 37,124 38,489 (4%)
Liquids (bpd) 1,815 1,257 44% 1,379 1,189 16%
Barrels of oil
equivalent
(BOED) 8,228 7,080 16% 7,566 7,603 -
Average prices
Natural gas
($/Mcf) $ 3.48 $ 4.28 (19%) $ 3.96 $ 3.95 -
Liquids
($/bbl)(1) $ 69.11 $ 53.79 28% $ 63.24 $ 48.22 31%
Barrels of oil
equivalent
($/BOE)(1) $ 31.63 $ 31.38 1% $ 31.31 $ 27.74 13%
Realized loss on
derivative
contracts ($/BOE) $ (0.17) $ - (100%) $ (0.05) $ - (100%)
Royalties ($/BOE) $ 2.98 $ 2.66 12% $ 3.26 $ 2.97 10%
Operating costs
($/BOE) $ 11.62 $ 10.49 11% $ 10.56 $ 9.70 9%
Operating netback
($/BOE) $ 16.86 $ 18.23 (8%) $ 17.44 $ 15.07 16%
General and
administrative
($/BOE) $ 2.87 $ 2.94 (2%) $ 2.80 $ 2.52 11%
Reserves (MBOE)
Total proved 20,117 23,615 (15%)
Total proved plus
probable 31,687 34,896 (9%)
Wells drilled
(gross) 6 107 (94%) 49 118 (58%)
Undeveloped land
(thousands of
acres)
Gross 99 123 (20%)
Net 47 62 (24%)
(1) Excludes realized loss on derivative contracts of $0.1 million and
unrealized loss on derivative contracts of $1.9 million pertaining to
fixed price crude oil swaps recorded in the fourth quarter of 2010.
OPERATIONS:
Cardium Horizontal Oil. In 2010, 22 gross (15.4 net revenue) Cardium horizontal
oil wells were drilled. In the fourth quarter of 2010, 6 gross (4.6 net revenue)
Cardium horizontal oil wells were drilled. To date in the first quarter of 2011,
the Company has drilled 15 gross (11.3 net revenue) Cardium horizontal oil
wells, and currently has four drilling rigs still working in the field finishing
the remainder of the winter program (4 gross (3.1 net) wells). As of December
31, 2010, the Company had 13.4 net wells producing. Today, 22.5 net Cardium
horizontal wells are producing with 7.3 net new Cardium horizontal oil wells
expected to be on-stream in the second quarter of 2011. Cardium production was
approximately 1,800 to 1,900 BOED (85% oil and NGL) as of March 25, 2011. Oil
and NGL production is approximately 2,450 bpd, up substantially from 1,130 bpd
in the first quarter of 2010. Of this number, 1,780 bpd or 73% is crude oil
production, compared to 345 bpd or 31% in the first quarter of 2010. The Company
plans to drill 32 gross (22.0 net capital, 20.0 net revenue) Cardium horizontal
oil wells in 2011. A summary of Cardium horizontal well activity since the first
quarter of 2010 is shown below:
Cardium Cumulative Drilling Program Wells Drilled Wells On Production
Gross Net Gross Net
Up to March 25, 2011 37 26.7 31 22.5
Estimated up to June 30, 2011 41 29.8 41 29.8
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"Net" is net revenue interest earned.
The Company's Cardium prospective land inventory is 112.5 gross (65.8 net)
sections, which has appreciated 10% since the update provided in our January 17,
2011 press release. Based on a development drilling density of three wells per
section, the Company estimates it could potentially drill 338 gross (197.4 net)
Cardium horizontal wells. From this location list, the Company has advanced 183
gross (111.2 net) horizontal locations to be drilled in the next few years
(including wells drilled to date). Each location is a development location that
is technically feasible and not contingent upon the drilling of other wells.
Successful drilling of these wells and wells being drilled by third parties
offsetting Company lands and new land deals have increased the count by 30%
since the January 17, 2011 press release. The Company continues to explore
opportunities to increase its land position in the play through acquisitions and
farm-ins in its existing areas of focus and to improve operating efficiencies in
the drilling and completion of wells. A more detailed discussion and review of
the Cardium drilling program and go forward plans is shown in the investor
presentation at www.andersonenergy.ca.
In February 2011, the Company switched from oil based fracture stimulations to
water based fracture stimulations of the Cardium. Well performance has been
encouraging and the Company is planning to conduct future fracture stimulations
with water. The capital cost savings of this change has been approximately
$500,000 per well. The Company estimates its full cycle drill, complete, equip
and tie-in costs for the Cardium horizontal program with water based fracture
stimulation to be approximately $2.8 to $3.0 million per well.
In 2010, $6.6 million was spent on the installation of multi-well Cardium oil
tank batteries and associated pipelines, some of which will be of use for
production from drilling in 2011 and beyond.
PRODUCTION
For the year ended December 31, 2010, production averaged 7,566 BOED. Production
for the fourth quarter of 2010 was 8,228 BOED, up 16% from the same period last
year. Oil and NGL production in the fourth quarter of 2010 was 1,815 bpd, up 44%
from the same period last year.
Production from the winter drilling program is being brought on-stream in the
second half of March and throughout the second quarter of 2011. The production
guidance estimate for the 2011 fiscal year is approximately 7,500 BOED. The
Company estimates oil and NGL production will be approximately one third of that
estimate.
The following graph illustrates the growth in Cardium production since inception
of the play in the first quarter of 2010. The graph shows the contribution to
production since October 2010 from net wells completed and brought on production
in 2010 and to date in 2011. The graph illustrates how the Company has been able
to ramp up its Cardium production in the past few months and also illustrates
how quickly the production curve stabilizes.
To view the Cardium Production Growth chart, please visit the following link:
http://media3.marketwire.com/docs/328axl_chart.pdf
The numbers in brackets in the legend are the net number of wells included in
the data above.
FINANCIAL RESULTS
Capital expenditures were $112.2 million in 2010 with $72.9 million spent on
drilling and completions and $40.1 million spent on facilities. This compares to
capital expenditures of $33.6 million in 2009.
Funds from operations were $37.2 million in 2010 as compared to $31.3 million in
2009. The average natural gas sales price was $3.96 per Mcf in 2010 as compared
to $3.95 per Mcf in 2009. Natural gas sales prices in 2010 were $5.22 per Mcf in
the first quarter, $3.78 per Mcf in the second quarter, $3.43 per Mcf in the
third quarter and $3.48 per Mcf in the fourth quarter. Natural gas prices
continue to be low in the first quarter of 2011. The Company's average crude oil
and natural gas liquids sales price in 2010 was $63.24 per bbl as compared to
$48.22 per bbl in 2009. Operating expenses in 2010 were $10.56 per BOE, which
was 9% higher than $9.70 per BOE in 2009. Start up costs associated with new
Cardium production, various production optimization initiatives,
reclassification of co-gen power credits and a large one time compressor repair
cost at Buck Lake offset some of the cost savings associated with the Edmonton
Sands lower operating cost gas production during 2010. The largest part of these
adjustments was recorded in the fourth quarter of the year. The operating
netback was $17.44 per BOE in 2010 as compared to $15.07 per BOE in 2009. The
increase in the operating netback was primarily due to the impact of Cardium
horizontal oil production in the fourth quarter of 2010.
In 2011, the Company will be adopting International Financial Reporting
Standards. The adoption date of January 1, 2011 requires restatement, for
comparative purposes, of amounts reported by the Company for the year ended
December 31, 2010, including the opening balance sheet as at January 1, 2010.
The changeover will have a significant effect on reported results. The impacts
are discussed in more detail in Management's Discussion and Analysis for the
year ended December 31, 2010 and we encourage shareholders to look there for
more information.
FINANCING
On December 31, 2010, the Company completed a $50.0 million convertible
subordinated debenture financing. The debentures have a five year term with a
7.5% coupon and a conversion price of $1.55 per share. Proceeds were initially
used to reduce the Company's bank indebtedness and provide financial flexibility
for its 2011 capital program. The Company closed the sale of $5.1 million in
properties on February 9, 2011. During the first quarter of 2011, the Company
also signed agreements to sell surplus drilling incentive credits and other
properties for expected proceeds of $0.4 million. The Company intends to sell a
total of $10 million in assets in 2011. The Company is financing its drilling
program with bank loans, convertible debentures, cash flow and dispositions in
2011. The Company has credit facilities of $125 million with a syndicate of
three Canadian banks.
2011 CAPITAL PROGRAM
The Company has a capital budget of $75 million, net of $10 million of planned
dispositions in 2011, which will be spent almost exclusively on the Cardium oil
horizontal drilling program. The Company is planning to drill 32 gross (22 net
capital, 20 net revenue) Cardium horizontal oil wells in Central Alberta. At the
May 16, 2011 annual shareholder's meeting, the Company will update its
shareholders on timing of any potential expansion of the drilling program.
COMMODITY CONTRACTS
The Company has fixed price swaps for 1,000 barrels per day of crude oil for
calendar 2011 at a NYMEX crude oil price of Canadian $88.45 per barrel and for
250 barrels per day of crude oil for calendar 2012 at a NYMEX crude oil price of
Canadian $103.20 per barrel. The Company reviews commodity contracts as part of
its price management strategy on an ongoing basis.
RESERVES
GLJ Petroleum Consultants ("GLJ") was engaged to prepare an evaluation of the
Company's reserves as of December 31, 2010 in accordance with NI51-101.
A summary of the Company's reserves evaluation is shown below as of December 31,
2010.
Barrels of
Natural Gas Oil
Natural Gas Oil Liquids equivalent
Reserves Category (Bcf) (Mbbls) (Mbbls) (MBOE)
Proved Developed Producing 52.5 1,303 1,376 11,428
Proved Developed Non
Producing 7.5 168 50 1,461
Proved Undeveloped 37.3 755 247 7,228
Total Proved 97.3 2,226 1,673 20,117
Total Proved plus Probable 150.6 3,908 2,676 31,687
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At the end of 2009, the Company had 0.14 MMBOE of TP and 0.47 MMBOE of P&P
reserves associated with the Cardium horizontal oil play, representing
approximately 1.4% of the total P&P reserves. At the end of 2010, the Company
had 2.37 MMBOE of TP and 4.7 MMBOE of P&P reserves associated with the Cardium
horizontal oil play, after producing approximately 124.3 MBOE of production in
2010. Today the Cardium represents 14.8% of the Company's P&P reserves. Oil and
NGL have grown from 10% of TP and P&P reserves in 2009 to 19% of TP and 21% of
P&P reserves in 2010. The Company expects that the Cardium reserves will
continue to grow and become a larger percentage of the Company's TP and P&P
reserves in future years as the play is developed. In management's opinion, the
GLJ report is conservative on Cardium oil reserves as this is the first year an
independent evaluation has been prepared on this new and emerging play for the
Company.
The Company's reserve life indices are 7.3 years TP and 11.5 years P&P, based on
2010 annual production. In 2010, the Company replaced 224% of production with
new P&P reserves additions, net of technical revisions. The Company replaced
697% of its oil and NGL production with new P&P oil and NGL reserves.
Proved developed producing ("PDP") reserves grew 24% in 2010. The PDP net
present value at a 10% pre-tax discount rate ("NPV 10")increased 6% in 2010.
Reserve volumes grew due to positive additions and revisions in both natural gas
and oil. The percentage of PDP reserves relating to oil and NGL was 23% in 2010
compared to 18% in 2009. PDP NPV 10 values were negatively impacted by
reductions in forecast natural gas prices.
In 2010, the Company experienced positive technical revisions of 3.3 MMBOE TP
and 0.3 MMBOE P&P. These were offset by negative economic factors of 7.1 MMBOE
TP and 6.6 MMBOE P&P. Almost the entire economic factor related to the
undeveloped gas and NGL reserves in the Edmonton Sands. The economic factor was
due to a 25% reduction in GLJ's natural gas price outlook for the years 2011 to
2015, and 16% thereafter. This was partially offset by the fact that there was
improved performance in the proved developed producing category for the Edmonton
Sands resulting in positive additions and revisions of 2.2 MMBOE.
The Company's 2010 finding, development and acquisition costs ("FD&A") for
additions only were $17.56 per BOE TP and $15.81 per BOE P&P. FD&A, including
future development capital and additions and technical revisions but excluding
economic factors, were $22.30 per BOE TP and $22.35 per BOE P&P. The Company's
2010 FD&A costs were higher than in 2009, as the Company's capital investments
were geared to starting up the more capital intensive Cardium horizontal oil
drilling program, building Cardium multi-well batteries and completing its
2009/2010 winter shallow gas drilling program. With a WTI oil price of $100 US,
the Cardium wellhead operating netback is approximately $75 per BOE and the
$22.35 per BOE FD&A is very acceptable, providing a recycle ratio of 3.3 times.
Management's Discussion and Analysis contains more details on the calculation of
FD&A costs.
Total Proved
Developed Total Proved Total Proved
Producing (MBOE) plus Probable
Opening Balance,
December 31, 2009 9,223 23,615 34,896
Additions 3,270 3,023 5,913
Technical revisions 2,124 3,318 269
Production (2,761) (2,761) (2,761)
Economic factors (428) (7,078) (6,630)
--------------------------------------------
Closing Balance,
December 31, 2010 11,428 20,117 31,687
----------------------------------------------------------------------------
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NET ASSET VALUATION (1)
As at December 31, 2010
($ millions, unless otherwise stated)
P&P reserves (pretax 10% discount rate) $ 271
Undeveloped land (excluding Cardium horizontal
prospective lands) 5
Cardium horizontal prospective lands 166
Stock option proceeds 6
Bank loans plus cash working capital
deficiency (71)
--------
Net asset value estimate, December 31, 2010 $ 377
Net asset value estimate per fully diluted
share, December 31, 2010(i) $ 1.78
----------------------------------------------------------------------------
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(i) based on 211.3 million outstanding shares on a fully diluted basis
(1) The net asset valuation shows what the Corporation's reserves would be
produced at using forecast prices 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 Energy shares.
It was assumed in the NAV calculation that the convertible debenture would be
converted at $1.55 per share and the outstanding shares were adjusted
accordingly.
The GLJ price forecast as of December 31, 2010 is shown in Management's
Discussion and Analysis for the year ended December 31, 2010. Complete reserves
disclosure as required under NI 51-101 will be contained in the Company's 2010
Annual Information Form, to be filed on SEDAR by March 31, 2011.
The Company has 98,813 gross (47,300 net) undeveloped acres of land excluding
Cardium horizontal prospective land as of December 31, 2010 and has assigned a
value of $5.0 million to this acreage position. The Company used a $3.0 million
per net section valuation for Cardium lands that were not assigned drilling
locations in the GLJ reserves report. The Company believes that these locations
were not assigned reserves as there was insufficient production or horizontal
well control to book reserves under the criteria of NI51-101, and/or the
locations were picked based on land deals done after December 31, 2010. The
Company's engineers have estimated the potential net present value of an average
unbooked Cardium location to be approximately $2.2 million per location, using
GLJ's price forecast, a 10% pretax discount rate, farm-in and straight up
economics over a four year time span of drilling activity. The Company has an
inventory of 74.7 net Cardium locations not booked in the GLJ reserves report.
As of March 25, 2011, the Company's drill ready non-contingent development
Cardium horizontal drilling inventory is as follows:
Cardium Locations Gross Net
Inventory at March 25, 2011 183 111.2
Drilled to March 25, 2011 (37) (26.7)
--------------------------
Remaining 146 84.5
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OUTLOOK
The last two years have been very difficult in the natural gas business, and
2011 does not currently look like it will be much better. Oil prices continue to
remain strong due increasing demand and ongoing geopolitical events in the
world. The Company's response to a very weak and uncertain gas price environment
was to switch its capital program to light oil horizontal drilling. The Company
was able to position itself and make the switch in the last half of 2010. The
Company was able to move up the learning curve in the Cardium play in 2010 and
in the first quarter of 2011 with its drilling, completion and production
initiatives. The Company is very focused on increasing its land position in the
Cardium and utilizing new technologies to lower costs and enhance well
performance. The addition of water based fracture stimulation in February 2011
is one example of new initiatives. At WTI oil prices of $100 U.S. per bbl,
operating netbacks in the Cardium program are approximately $75.00 per BOE as
compared to operating netbacks in the Edmonton Sands shallow gas program of
$15.00 per BOE.
Current oil & NGL production is approximately 2,450 bpd and the Company's goal
is grow its oil production to achieve 50% of total production being oil and NGL
production by early 2012. By the second quarter of this year, the Company will
have drilled and brought on production 41 gross (29.8 net) Cardium oil
horizontal wells. The Company has increased its Cardium development drilling
inventory by 30% in the past few months and is becoming one of the industry
leaders in lower capital costs. The Company believes it is well positioned in
the Cardium horizontal oil play and the results from the winter drilling program
will help in peeling the natural gas label off the Company's stock price and
reward the shareholders with more of an oil company evaluation.
The Company will be assessing the potential to increase its 2011 capital program
in the second quarter.
PEOPLE
On February 28, 2011, Patrick O'Rourke joined the Company as Vice President of
Production. Patrick is a professional engineer with 22 years of experience in
both technical and managerial positions in facilities and production
engineering. Patrick will be focused on optimizing our new Cardium oil
production and reducing overall operating expenses in 2011. We welcome Patrick
to the management team.
2010 was a year of repositioning. The Company would like to thank its
shareholders and its employees for their support throughout this year of
transition. The Company invites its shareholders to attend the annual meeting on
May 16, 2011 at the Metropolitan Centre in Calgary, Alberta at 2:00 pm MDT and
encourages anyone interested in further details to visit the Company's website
at www.andersonenergy.ca.
Brian H. Dau
President & Chief Executive Officer
March 28, 2011
Management's Discussion and Analysis
FOR THE YEARS ENDED DECEMBER 31, 2010 AND 2009
The following discussion and analysis of financial results should be read in
conjunction with the audited consolidated financial statements of Anderson
Energy Ltd. ("Anderson Energy" or the "Company") for the years ended December
31, 2010 and 2009 and is based on information available as of March 25, 2011.
The following information is based on financial statements prepared by
management in accordance with Canadian generally accepted accounting principles
("GAAP"). Production and reserves numbers are stated before deducting Crown or
lessor royalties.
Included in the discussion and analysis are references to terms commonly used in
the oil and gas industry such as funds from operations, finding, development and
acquisition ("FD&A") costs, operating netback and barrels of oil equivalent
("BOE"). Funds from operations as used in this report represent cash from
operating activities before changes in non-cash working capital and asset
retirement expenditures. See "Review of Financial Results - Funds from
Operations" for details of this calculation. Funds from operations represent
both an indicator of the Company's performance and a funding source for on-going
operations. FD&A costs measure the cost of reserves additions and are an
indicator of the efficiency of capital expended in the period. Operating netback
is calculated as oil and gas revenues less royalties and operating expenses and
is a measure of the profitability of operations before administrative and
financing expenditures. 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. 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. These terms are not defined by
Canadian GAAP and therefore are referred to as non-GAAP measures.
All references to dollar values are to Canadian dollars unless otherwise stated.
Definitions of the abbreviations used in this discussion and analysis are
located on the last page of this document.
REVIEW OF FINANCIAL RESULTS
Overview. For the year ended December 31, 2010, funds from operations were $37.2
million ($0.22 per share), up 19% from 2009 as a result of the Company's refocus
on Cardium light oil drilling. Sales volumes averaged 7,566 BOED, similar to the
previous year.
Capital additions, net of dispositions were $112.2 million for the year ended
December 31, 2010. During the year, the Company drilled 22 gross (16.3 net
capital) Cardium horizontal light oil wells, four gross (4.0 net) Rock Creek
deep gas wells, two gross (1.1 net) Ellerslie deep gas wells and two gross (2.0
net) Whitemud horizontal wells with a 100% success rate. In the first quarter of
2010, the Company drilled 19 gross (14.7 net) Edmonton Sands wells with a 79%
success rate. The Company tied in 13 gross (10.0 net) Cardium horizontal light
oil wells and seven gross (4.5 net) Edmonton Sands shallow gas wells in the
fourth quarter of 2010. The Company has deferred the drilling of the remaining
74 Edmonton Sands gas wells under its farm-in agreement until the first quarter
of 2012. The Company's finding, development and acquisition costs, net of the
change in future development capital and before economic factors was $22.35 per
BOE on a proved plus probable basis for 2010.
Bank loans plus the working capital deficiency before the unrealized loss on
derivative contracts and future income tax asset was $71.5 million at December
31, 2010. Total bank facilities are currently $125 million. On December 31,
2010, the Company completed a convertible subordinated debenture financing for
proceeds, net of commission and expenses, of $47.7 million. Proceeds were
initially used to pay down bank debt. The availability created in the credit
facilities, along with cash flows, will be used to help finance the Company's
2011 capital program.
Revenue and Production. In 2010, the Company changed its focus to oil prospects
in light of the depressed natural gas market. Oil and natural gas liquids
revenue went from 27% of total revenue in the first quarter of 2010 to 48% of
total revenue in the fourth quarter of 2010.
Gas sales volumes for the year ended December 31, 2010 decreased to an average
of 37.1 MMcfd from 38.5 MMcfd last year due to the suspension of shallow gas
drilling after the first quarter. The central Alberta area, centered around the
Sylvan Lake area and northwest to Pembina, remains the Company's largest area of
production, with gas sales averaging 35.6 MMcfd (36.7 MMcfd during 2009).
Gas sales volumes averaged 38.5 MMcfd in the fourth quarter of 2010 compared to
35.8 MMcfd in the third quarter of 2010 and 34.9 MMcfd in the fourth quarter of
2009. The increase in the gas volumes from the third quarter of 2010 resulted
from the tie-in of natural gas wells drilled earlier in the year, as well as the
shallow gas fit for purpose processing facilities in the Medicine River area
being fully operational throughout the fourth quarter of 2010.
Oil sales for the year ended December 31, 2010 averaged 601 bpd compared to 395
bpd for the year ended December 31, 2009. Oil production averaged 992 bpd in the
fourth quarter of 2010 compared to 568 bpd in the third quarter of 2010 and 351
bpd in the fourth quarter of 2009. The increase in volumes is due to new oil
production from 17 gross (11.0 net) Cardium horizontal light oil wells which
were brought on production during the fourth quarter of 2010. There were no oil
wells drilled in 2009.
Natural gas liquids sales for the year ended December 31, 2010 averaged 778 bpd
compared to 794 bpd for the year ended December 31, 2009. Natural gas liquids
sales averaged 823 bpd in the fourth quarter of 2010 compared to 761 bpd in the
third quarter of 2010 and 906 bpd in the fourth quarter of 2009. The increase in
sales volumes in the fourth quarter of 2010 is due to well tie-ins occurring
late in the third quarter of 2010 at Westpem.
The following tables outline production revenue, volumes and average sales
prices for the three and twelve months ended December 31, 2010 and 2009.
OIL AND NATURAL GAS REVENUE
Three months ended Year ended
December 31 December 31
(thousands of dollars) 2010 2009 2010 2009
Natural gas $ 12,320 $ 13,754 $ 52,304 $ 55,426
Gain on fixed price natural gas
contracts - - 1,302 -
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Total natural gas 12,320 13,754 53,606 55,426
Oil(1) 7,081 2,247 16,142 8,540
NGL 4,459 3,973 15,672 12,375
Royalty and other 86 465 1,037 652
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Total revenue(1) $ 23,946 $ 20,439 $ 86,457 $ 76,993
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excludes realized loss on derivative contracts of $0.1 million and
unrealized loss on derivative contracts of $1.9 million pertaining to
fixed price crude oil swaps recorded in the fourth quarter of 2010.
PRODUCTION
Three months ended Year ended
December 31 December 31
2010 2009 2010 2009
Natural gas (Mcfd) 38,479 34,938 37,124 38,489
Oil (bpd) 992 351 601 395
NGL (bpd) 823 906 778 794
----------------------------------------
Total (BOED) 8,228 7,080 7,566 7,603
----------------------------------------------------------------------------
----------------------------------------------------------------------------
PRICES
Three months ended Year ended
December 31 December 31
2010 2009 2010 2009
Natural gas ($/Mcf)(1) $ 3.48 $ 4.28 $ 3.96 $ 3.95
Oil ($/bbl)(2) 77.62 69.60 73.62 59.26
NGL ($/bbl) 58.87 47.67 55.22 42.73
----------------------------------------
Total ($/BOE)(2)(3) $ 31.63 $ 31.38 $ 31.31 $ 27.74
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes gain on fixed price natural gas contracts of $1.3 million from
the first quarter of 2010.
(2) Excludes realized loss on derivative contracts of $0.1 million and
unrealized loss on derivative contracts of $1.9 million pertaining to
fixed price crude oil swaps recorded in the fourth quarter of 2010.
(3) Includes royalty and other income classified with oil and gas sales.
Anderson Energy's average gas sales price was $3.96 per Mcf for the year ended
December 31, 2010 compared to $3.95 per Mcf for the year ended December 31,
2009. For the three months ended December 31, 2010, the gas sales price was
$3.48 per Mcf compared to $3.43 per Mcf realized in the third quarter of 2010
and $4.28 per Mcf in the fourth quarter of 2009. Gas prices were significantly
affected by increased supply and lower industrial consumption of natural gas in
the United States. Prices were higher in the last quarter of 2009 and first
quarter of 2010, but remained low for the remainder of 2010. The natural gas
price in 2010 includes a gain on fixed price natural gas contracts of $1.3
million. The 2010 natural gas price before the gain was $3.86 per Mcf. The oil
price in 2010 does not include a realized loss on derivative contracts of $0.1
million. The realized oil price including this loss was $76.18 per barrel for
the fourth quarter of 2010 and $73.02 per barrel for the year ended December 31,
2010.
The Company is currently selling all of its gas production at the average daily
index price. The Company has classified all transportation costs as an offset to
gas sales revenue as title transfers prior to transport on the applicable sales
pipelines and transportation is being held by and charged by the gas purchasers.
The Company has arranged firm service transportation agreements covering
approximately 29 MMcfd of natural gas sales for various terms ranging from one
to ten years.
Commodity Contracts. In October 2010, as part of its risk management program,
the Company entered into fixed price swap contracts for 1,000 barrels per day of
crude oil for December 2010 at a NYMEX crude oil price of Canadian $85.70 per
barrel and for calendar 2011 at a NYMEX crude oil price of Canadian $88.45 per
barrel. In 2010, these contracts had the following impact on the consolidated
statements of operations:
Three months ended Year ended
December 31 December 31
(thousands of dollars) 2010 2009 2010 2009
Realized loss on derivative
contracts $ (131) $ - $ (131) $ -
Unrealized loss on derivative
contracts (1,918) - (1,918) -
----------------------------------------
$ (2,049) $ - $ (2,049) $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In March 2011, the Company entered into a fixed price swap contract for 250
barrels per day of crude oil for calendar 2012 at a NYMEX crude oil price of
Canadian $103.20 per barrel.
The Company had no fixed price natural gas contracts in place at December 31, 2010.
Royalties. Royalties were 10.4% of revenue for the year ended December 31, 2010
compared to 10.7% of revenue for the year ended December 31, 2009. Royalties
were 9.4% of revenue in the fourth quarter of 2010 compared to 8.8% of revenue
in the third quarter of 2010 and 8.5% of revenue in the fourth quarter of 2009.
The increase in the royalty rate in the fourth quarter of 2010 is due to an
estimated reduction in gas cost allowance for 2010 as a result of lower crown
royalties and lower facility effective royalty rates expected to be used in the
annual assessment. This increase was partially offset by the decline in the
gross crown royalty rate due to a larger percentage of royalties calculated at
the 5% royalty rate for new production.
Royalties as a percentage of revenue are highly sensitive to prices and
adjustments to gas cost allowance and so royalty rates can fluctuate from
quarter to quarter. In addition, when prices and corresponding revenues are
lower, fixed monthly gas cost allowance becomes more significant to the overall
royalty rate. On January 1, 2009, the Alberta government's New Royalty Framework
came into effect. The Alberta government revised the royalty regime in March
2009, and again in March 2010, for new wells tied in on Crown lands. Producers
will pay a reduced Crown royalty rate of 5% for the first year on up to 500 MMcf
of gas production or up to 50 Mstb of oil production. In addition, the Alberta
government changed the maximum royalty payable on oil from 50% to 40% and on
natural gas from 50% to 36%. Other important changes positively impact the
Company's refocused horizontal oil program, where based on the measured depth of
the well, the Company will pay the Crown a 5% royalty for 24 to 30 months for up
to 60 to 70 Mstb of oil production. The majority of the Company's horizontal
program on Crown lands would qualify for the 30 months of 5% royalty for up to
70 Mstb of oil production.
Three months ended Year ended
December 31 December 31
2010 2009 2010 2009
Gross crown royalties 10.9% 15.3% 12.5% 15.4%
Gas cost allowance (3.7%) (10.8%) (7.2%) (11.1%)
Other royalties 2.2% 4.0% 5.1% 6.4%
-----------------------------------------
Total royalties 9.4% 8.5% 10.4% 10.7%
Total royalties ($/BOE) $ 2.98 $ 2.66 $ 3.26 $ 2.97
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operating Expenses. Operating expenses were $10.56 per BOE for the year ended
December 31, 2010 compared to $9.70 per BOE for the year ended December 31,
2009. Operating expenses were $11.62 per BOE in the fourth quarter of 2010
compared to $9.71 per BOE in the third quarter of 2010 and $10.49 per BOE in the
fourth quarter of 2009. Start up costs associated with new Cardium production,
various production optimization initiatives, reclassification of co-gen power
credits and a large one time compressor repair cost at Buck Lake offset some of
the cost savings associated with the Edmonton Sands lower operating cost gas
production during 2010.
OPERATING NETBACK
Three months ended Year ended
December 31 December 31
(thousands of dollars) 2010 2009 2010 2009
Revenue(1) $ 23,946 $ 20,439 $ 86,457 $ 76,993
Realized loss on derivative
contracts (131) - (131) -
Royalties (2,256) (1,731) (9,011) (8,253)
Operating expenses (8,799) (6,831) (29,148) (26,906)
----------------------------------------
$ 12,760 $ 11,877 $ 48,167 $ 41,834
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Sales (MBOE) 757.0 651.4 2,761.5 2,775.2
Per BOE
Revenue(1) $ 31.63 $ 31.38 $ 31.31 $ 27.74
Realized loss on derivative
contracts (0.17) - (0.05) -
Royalties (2.98) (2.66) (3.26) (2.97)
Operating expenses (11.62) (10.49) (10.56) (9.70)
----------------------------------------
$ 16.86 $ 18.23 $ 17.44 $ 15.07
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes royalty and other income classified with oil and gas sales.
Excludes unrealized loss on derivative contracts of $1.9 million
pertaining to fixed price crude oil swaps recorded in the fourth quarter
of 2010.
General and Administrative Expenses. General and administrative expenses were
$7.7 million or $2.80 per BOE for the year ended December 31, 2010 compared to
$7.0 million or $2.52 per BOE for the year ended December 31, 2009. General and
administrative expenses were $2.87 per BOE in the fourth quarter of 2010
compared to $2.82 per BOE in the third quarter of 2010 and $2.94 per BOE in the
fourth quarter of 2009. In light of a more competitive labour market in 2010,
the Company reversed the salary cutbacks taken in 2009 and reinstated its
employee stock savings plan effective April 1, 2010. The Company also accrued
additional bonuses for employees in the fourth quarter of 2010 in
acknowledgement of employee efforts in refocusing the Company in 2010.
Three months ended Year ended
December 31 December 31
(thousands of dollars) 2010 2009 2010 2009
General and administrative (gross) $ 4,082 $ 3,276 $ 13,742 $ 12,284
Overhead recoveries (570) (437) (1,751) (1,721)
Capitalized (1,339) (924) (4,258) (3,565)
----------------------------------------
General and administrative (net) $ 2,173 $ 1,915 $ 7,733 $ 6,998
----------------------------------------------------------------------------
----------------------------------------------------------------------------
General and administrative ($/BOE) $ 2.87 $ 2.94 $ 2.80 $ 2.52
% Capitalized 33% 28% 31% 29%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capitalized general and administrative costs are limited to salaries and
associated office rent of staff involved in capital activities.
Stock-Based Compensation. The Company accounts for stock-based compensation
plans using the fair value method of accounting. Stock-based compensation
expense was $2.1 million in 2010 ($1.2 million net of amounts capitalized)
versus $2.1 million ($1.1 million net of amounts capitalized) in 2009.
Stock-based compensation costs were $0.4 million for the fourth quarter of 2010
($0.3 million net of amounts capitalized) versus $0.4 million ($0.2 million net
of amounts capitalized) in the fourth quarter of 2009.
Interest Expense. In the fourth quarter of 2010, interest expense was $1.1
million compared to $0.8 million in the third quarter of 2010 and $0.8 million
in the fourth quarter of 2009. The increase in interest expense from the third
quarter of 2010 is due to the higher average debt levels. Interest expense was
$3.4 million for the year ended December 31, 2010 compared to $3.7 million in
2009. The decrease in interest expense from the comparable 2009 period is due to
lower average debt levels in 2010 partially offset by increases in interest
rates. The average effective interest rate on outstanding bank loans was 4.9% in
2010 compared to 4.2% in 2009.
Depletion and Depreciation. Depletion and depreciation was $78.7 million ($28.51
per BOE) for the year ended December 31, 2010 compared to $78.6 million ($28.33
per BOE) in 2009. Depletion and depreciation was $22.2 million ($29.38 per BOE)
in the fourth quarter of 2010 compared to $18.9 million ($28.23 per BOE) in the
third quarter of 2010 and $17.2 million ($26.39 per BOE) in the fourth quarter
of 2009. Depletion and depreciation expense is calculated based on proved
reserves only. Fourth quarter depletion and depreciation is calculated using the
new reserves evaluation and incorporates a decrease in total proved natural gas
reserves.
Asset Retirement Obligation. The Company recorded a $1.4 million increase in
asset retirement obligations in 2010 ($0.3 million the fourth quarter of 2010)
related to current activity and changes in estimates. Accretion expense was $2.5
million for 2010 compared with $2.3 million for 2009. Accretion expense was
included in depletion and depreciation expense and increased due to the higher
obligations.
Income Taxes. Anderson Energy is not currently taxable. The Company does not
anticipate paying current income tax in 2011. The estimated tax pool balances at
December 31, 2010 are summarized below. Non-capital losses are estimated
assuming full claims for CDE, COGPE and UCC are made in the current year. Tax
pool classifications are estimates as some new wells have not yet had their
status as exploratory or development confirmed. The balances below have been
reduced for the effect of income recorded in 2010 that will not be taxed until
2011.
Canadian Exploration Expenses (CEE) $ 66 million
Canadian Development Expenses (CDE) 126 million
Undepreciated Capital Cost (UCC) 108 million
Canadian Oil and Gas Property Expenses (COGPE) 12 million
Non-Capital Losses and Other 78 million
---------------
Total $ 390 million
----------------------------------------------------------------------------
Funds from Operations. Funds from operations increased by 19% to $37.2 million
in 2010 compared to $31.3 million in 2009. On a per share basis, funds from
operations were $0.22 per share in 2010 compared to $0.25 per share in 2009. For
the three months ended December 31, 2010, funds from operations were $9.5
million or $0.06 per share, an increase of 19% over the previous quarter of $8.0
million or $0.05 per share, and an increase of 4% from the fourth quarter of
2009 of $9.2 million or $0.06 per share. Funds from operations increased as the
Company refocused its capital initiatives on oil prospects, which are brought on
production at significantly higher expected operating margins. In the fourth
quarter of 2010, oil and NGLs accounted for $11.5 million or 48% of revenue
compared to $7.2 million or 38% in the third quarter of 2010 and $6.2 million or
30% in the fourth quarter of 2009.
Three months ended Year ended
December 31 December 31
(thousands of dollars) 2010 2009 2010 2009
Cash from operating activities $ 10,721 $ 5,361 $ 40,996 $ 23,820
Changes in non-cash working
capital (1,324) 3,246 (5,365) 5,956
Asset retirement expenditures 118 544 1,549 1,482
----------------------------------------
Funds from operations $ 9,515 $ 9,151 $ 37,180 $ 31,258
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Earnings. The Company reported an $11.7 million net loss in the fourth quarter
of 2010 compared to a net loss $9.0 million in the third quarter of 2010 and
$6.5 million in the fourth quarter of 2009. Earnings were lower in the fourth
quarter of 2010 compared to the previous quarter as a result of higher depletion
due to a reduction in proved natural gas reserves. The Company reported a net
loss of $35.6 million in 2010 compared to a net loss of $36.5 million in 2009.
As with funds from operations, earnings continue to be impacted by low natural
gas prices. The change in the Company's focus to crude oil, with its currently
higher operating margins, is expected to improve future earnings.
The Company's funds from operations and earnings are highly sensitive to changes
in factors that are beyond its control. An estimate of the Company's
sensitivities to changes in commodity prices, exchange rates and interest rates
is summarized below:
SENSITIVITIES
Funds from
Operations Earnings
Per Per
Millions Share Millions Share
$0.50/Mcf in price of natural gas $ 6.4 $ 0.04 $ 4.8 $ 0.03
US $5.00/bbl in the WTI crude
price $ 1.8 $ 0.01 $ 1.4 $ 0.01
US $0.01 in the US/Cdn exchange
rate $ 0.8 $ 0.00 $ 0.6 $ 0.00
1% in short-term interest rate $ 0.4 $ 0.00 $ 0.3 $ 0.00
----------------------------------------------------------------------------
----------------------------------------------------------------------------
This sensitivity analysis was calculated by applying different pricing, interest
rate and exchange rate assumptions to the 2010 actual results related to
production, prices, royalty rates, operating costs and capital spending. As the
Company changes its focus to crude oil development, the impact of oil prices is
expected to become more significant and the impact of natural gas prices is
expected to become less significant to funds from operations and earnings than
is shown in the table above.
CAPITAL EXPENDITURES
The Company spent $26.5 million in capital expenditures, net of dispositions and
drilling incentive credits, in the fourth quarter of 2010 and $112.2 million for
the year ended December 31, 2010. The breakdown of expenditures is shown below:
Three months ended Year ended
December 31 December 31
(thousands of dollars) 2010 2009 2010 2009
Land, geological and geophysical
costs $ (11) $ (15) $ 416 $ 173
Acquisitions, net of dispositions 299 - (464) (54)
Drilling, completion and
recompletion 19,336 15,492 72,873 23,952
Drilling incentive credits 162 (6,000) (3,455) (6,000)
Facilities and well equipment 6,297 3,642 40,079 11,349
Capitalized G&A 1,339 924 4,258 3,565
----------------------------------------
Total finding, development &
acquisition expenditures 27,422 14,043 113,707 32,985
Change in compressor and other
equipment inventory (957) (2,736) (1,601) 542
Office equipment and furniture 8 5 67 31
----------------------------------------
Total capital expenditures 26,473 11,312 112,173 33,558
Non-cash asset retirement
obligations and capitalized
stock-based compensation 504 2,003 2,369 3,220
----------------------------------------
Total cash and non-cash capital
additions $ 26,977 $ 13,315 $114,542 $ 36,778
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Drilling statistics are shown below:
Three months ended Year ended
December 31 December 31
2010 2009 2010 2009
Gross Net Gross Net Gross Net Gross Net
Gas - - 98 73.6 23 19.0 109 81.9
Oil 6 5.1 - - 22 16.3 - -
Dry - - 9 7.6 4 2.8 9 7.6
--------------------------------------------------------
Total 6 5.1 107 81.2 49 38.1 118 89.5
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Success rate (%) 100% 100% 92% 91% 92% 93% 92% 92%
----------------------------------------------------------------------------
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For the year ended December 31, 2010, the Company drilled 22 gross (16.3 net
capital) Cardium horizontal light oil wells. Of the 22 gross well drilled, the
Company drilled six gross (5.1 net capital) Cardium horizontal light oil wells
in the fourth quarter of 2010. The Company has not drilled any vertical Edmonton
Sands shallow gas wells since the first quarter of 2010. In 2010, the Company
tied in 97 gross (65.7 net) Edmonton Sands shallow gas wells, of which seven
gross (4.5 net) were tied-in in the fourth quarter of 2010. The Company also
brought 20 gross (14.3 net capital) Cardium horizontal light oil wells on-stream
during 2010, of which 13 gross (10.0 net) well were brought on-stream in the
fourth quarter. In addition, the Company tied in four gross (4.0 net) Rock Creek
wells during 2010. In 2009, the Company drilled 118 gross (89.5 net) Edmonton
Sands wells of which 107 gross (81.2 net) wells were drilled in the fourth
quarter under a large scale farm-in.
In the fourth quarter of 2009, the Company accrued $6.0 million for drilling
incentive credits. Drilling credits earned are capped at 50% of crown royalties
paid between April 1, 2009 and March 31, 2011 and the Company estimates that it
will earn more drilling credits than it will be able to claim. These credits are
expected to be paid out between 2009 and 2011 as crown royalties are paid. The
estimate is highly dependent on commodity prices, production levels, crown
royalty rates and gas cost allowance earned over this period. To the extent that
crown royalties paid are lower or higher, drilling credits will be lower or
higher as well. As a result of the cap, the Company reduced its accrual by $1.0
million in the fourth quarter of 2010 and did not accrue any additional drilling
credits related to drilling in 2010. The Company received $4.5 million in
proceeds on the sale of some of these surplus credits in 2010.
CEILING TEST
At December 31, 2010, the ceiling test resulted in the discounted cash flows
from proved plus probable reserves being in excess of the carrying value of the
underlying petroleum and natural gas assets and as such no ceiling test
write-down was required. See "Reserves - Summary of Pricing and Inflation Rate
Assumptions" for the prices used in the 2010 ceiling test.
RESERVES
The Company's reserves were evaluated by GLJ Petroleum Consultants ("GLJ") in
accordance with National Instrument 51-101 ("NI 51-101") as of December 31,
2010. The tables in this section are an excerpt from what will be contained in
the Company's Annual Information Form for the year ended December 31, 2010
("AIF") as the Company's NI 51-101 annual required filings.
SUMMARY OF GROSS OIL AND GAS RESERVES
As at December 31, 2010
Natural
Natural Gas Total
Gas (1) Oil (1) Liquids BOE
(MMcf) (Mbbls) (Mbbls) (MBOE)
Proved developed producing 52,498 1,303 1,376 11,428
Proved developed non-producing 7,457 168 50 1,461
Proved undeveloped 37,358 755 247 7,228
----------------------------------------
Total proved 97,313 2,226 1,673 20,117
Probable 53,308 1,682 1,003 11,570
----------------------------------------
Total proved plus probable 150,621 3,908 2,676 31,687
----------------------------------------------------------------------------
(1) Coal Bed Methane is not material to report separately and is included
in the Natural Gas category. Heavy Oil is not material to report
separately and is included in the Oil category.
NET PRESENT VALUE BEFORE INCOME TAXES
As at December 31, 2010
GLJ December 31, 2010 Price Forecast, Escalated Prices
(thousands of dollars) 0% 5% 10% 15% 20%
Proved developed producing 252,854 196,268 166,058 145,193 129,562
Proved developed non-producing 19,167 13,331 9,561 6,988 5,154
Proved undeveloped 52,833 24,954 8,629 (1,310) (7,520)
---------------------------------------------
Total proved 324,854 234,553 184,248 150,870 127,197
Probable 231,850 136,742 87,221 58,520 40,543
---------------------------------------------
Total proved plus probable 556,704 371,295 271,469 209,391 167,739
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The estimated net present value of future net revenues presented in the
table above does not necessarily represent the fair market value of the
Company's reserves.
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
As at December 31, 2010
GLJ Forecast Prices and Costs
Natural
Oil Gas Edmonton Liquids Prices
Light,
Sweet
WTI Crude AECO Gas Pentanes
Cushing Edmonton Price Propane Butane Plus
Year ($US/bbl) ($Cdn/bbl) ($Cdn/Mcf) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl)
2011 88.00 86.22 4.16 54.32 67.26 90.54
2012 89.00 89.29 4.74 56.25 68.75 91.96
2013 90.00 90.92 5.31 57.28 70.01 92.74
2014 92.00 92.96 5.77 58.56 71.58 94.82
2015 95.17 96.19 6.22 60.60 74.07 98.12
2016 97.55 98.62 6.53 62.13 75.94 100.59
2017 100.26 101.39 6.76 63.87 78.07 103.42
2018 102.74 103.92 6.90 65.47 80.02 106.00
2019 105.45 106.68 7.06 67.21 82.15 108.82
2020 107.56 108.84 7.21 68.57 83.80 111.01
Thereafter 2%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Exchange
Inflation rate
Year Rate % (US$/Cdn)
2011 2.0 0.98
2012 2.0 0.98
2013 2.0 0.98
2014 2.0 0.98
2015 2.0 0.98
2016 2.0 0.98
2017 2.0 0.98
2018 2.0 0.98
2019 2.0 0.98
2020 2.0 0.98
Thereafter 2%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total future development costs included in the reserves evaluation were $137.0
million for total proved reserves and $239.9 million for proved plus probable
reserves. Further details related to future development costs, including
assumptions regarding the timing of the expenditures, will be included in the
Company's AIF for the 2010 fiscal year. Future development costs are associated
with the reserves as disclosed in the GLJ report and do not necessarily
represent the Company's current exploration and development budget.
CONTINUITY OF GROSS RESERVES
Oil & Natural Gas
Natural Gas (Bcf) (1) Liquids (Mbbls)
Proved Probable Total Proved Probable Total
Opening balance
December 31, 2009 128.0 59.0 187.0 2,287 1,443 3,730
Extensions and
improved recovery 7.6 9.0 16.6 1,766 1,432 3,198
Technical revisions 17.1 (17.6) (0.5) 472 (114) 358
Economic factors (41.8) 2.9 (38.9) (120) (30) (150)
Dispositions - - - (3) (46) (49)
Production (13.6) - (13.6) (503) - (503)
-----------------------------------------------------
Closing balance
December 31, 2010(1) 97.3 53.3 150.6 3,899 2,685 6,584
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The closing balance for natural gas includes 4.4 Bcf of proved and 3.9
Bcf of probable Coal Bed Methane reserves. The closing balance for oil
and natural gas liquids includes 251 Mbbls of proved and 140 Mbbls of
probable Heavy Oil reserves.
The Company's reserves life indices are 7.3 years total proved and 11.5 years
proved plus probable, based on 2010 annual production. With the 25% reduction in
GLJ's natural gas price outlook in the years 2011 to 2015, and 16% thereafter,
the Company experienced a negative revision for economic factors of 7.1 MMBOE
for total proved and 6.6 MMBOE for proved plus probable reserves. The economic
factors negative revision was almost entirely related to the Company's
undeveloped gas reserves in the Edmonton Sands. Offsetting the economic factors
were positive technical revisions of 3.3 MMBOE total proved and 0.3 MMBOE proved
plus probable reserves. In addition, the Company experienced positive proved
developed producing additions and revisions of 2.2 MMBOE in the Edmonton Sands,
indicative of improved performance. Reserves additions before revisions were 3.0
MMBOE total proved and 5.9 MMBOE proved plus probable, predominantly from
Cardium oil horizontal drilling. The Company replaced 224% of its production
with new proved plus probable reserves additions and technical revisions in
2010. The Company replaced 697% of its 2010 oil and NGL production with new P&P
oil and NGL reserves.
FINDING, DEVELOPMENT AND ACQUISITION COSTS
Year Ended December 31, 2010
Proved plus
(in thousands of dollars) Proved Probable
Finding, development & acquisition
expenditures $ 113,707 $ 113,707
Change in future development costs (60,613) (20,200)
-------------------------
$ 53,094 $ 93,507
Adjustment to change in future development
costs for natural gas economic factors 88,290 44.642
-------------------------
$ 141,384 $ 138,149
Reserve additions (MBOE) 3,023 5,913
Technical revisions (MBOE) 3,318 269
-------------------------
6,341 6,182
Economic factors (MBOE) (7,078) (6,630)
-------------------------
(737) (448)
2010 finding, development & acquisition costs
- additions only, including change in future
development costs ($/BOE) $ 17.56 $ 15.81
2010 finding, development & acquisition costs
- additions and technical revisions, including
change in future development costs, excluding
economic factors and the change in future
development costs related to economic factors
($/BOE) $ 22.30 $ 22.35
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's FD&A costs in 2010 were $17.56 per BOE on a proved basis and
$15.81 per BOE on a proved plus probable basis for additions only, including
changes in future development costs. The Company experienced a significant
revision for economic factors in 2010 which not only reduced reserves but also
reduced future development capital. To measure FD&A costs excluding the impact
of economic factors, the future development capital was also adjusted upwards to
exclude the effect of removing these reserves. FD&A costs including future
development costs for additions and technical revisions, but excluding economic
factors were $22.30 per BOE total proved and $22.35 per BOE for proved plus
probable. FD&A costs are presented before economic factors as the amount would
be negative or indeterminate after consideration of those revisions. Economic
factors are influenced by consultant price forecasts and an uplift in natural
gas price forecasts may cause economic factors to be positive in future years.
Calculated on a similar basis, the Company's FD&A costs in 2009 were $8.64 per
BOE on a proved basis and $8.46 per BOE on a proved plus probable basis and FD&A
costs in 2008 were indeterminate. The three year average FD&A costs was also
indeterminate as a result of the negative revisions in 2010 and 2008. There were
no property acquisitions in the year and dispositions were negligible, so a
separate calculation of finding and development costs excluding acquisitions has
not been presented. The aggregate of the exploration, development and
acquisition costs incurred in the most recent financial year and the change
during the year in estimated future development costs generally will not reflect
total finding, development and acquisition costs related to reserves additions
for that year.
SHARE INFORMATION
The Company's shares have been listed on the Toronto Stock Exchange since
September 7, 2005 under the symbol "AXL". As of March 25, 2011, there were 172.5
million common shares outstanding, 11.4 million stock options outstanding and
$50.0 million principal amount of convertible debentures which are convertible
into common shares at a conversion price of $1.55 per common share. During 2010,
84,900 common shares (2009 - Nil) were issued under the employee stock option
plan.
SHARE PRICE ON TSX
2010 2009
High $ 1.57 $ 1.48
Low $ 0.95 $ 0.65
Close $ 1.05 $ 1.16
Volume 120,489,236 125,408,442
Shares outstanding at December 31 172,485,301 150,500,401
Market capitalization at December 31 $ 181,109,566 $ 174,580,465
----------------------------------------------------------------------------
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The statistics above include trading on the Toronto Stock Exchange only. Shares
also trade on alternative platforms like Alpha, Chi-X, Pure and Omega.
Approximately 65.0 million common shares traded on these alternative exchanges
in 2010. Including these exchanges, an average of 736,212 common shares traded
per day in 2010 (2009 - 584,790), representing a turnover ratio of 109% (2009 -
117%).
In February 2010, the Company issued 21.9 million common shares at a price of
$1.45 per share pursuant to a short form prospectus.
RELATED PARTY TRANSACTIONS
On December 31, 2010, the Company issued 1,000 convertible debentures to
directors at a price of $1,000 per convertible debenture for total gross
proceeds of $1.0 million as part of a $50.0 million bought share offering of
convertible debentures.
In February 2010, the Company issued 352,466 common shares to directors at a
price of $1.45 per share for total gross proceeds of $0.5 million as part of a
$31.8 million bought deal offering of common shares.
On May 28 2009, the Company issued 4,992,034 common shares to management and
directors and 3,377,966 common shares to family of management and directors of
the Company at a price of $0.95 per share for total gross proceeds of $8.0
million as part of a $60.0 million bought deal offering of common shares.
LIQUIDITY AND CAPITAL RESOURCES
At December 31, 2010, the Company had outstanding bank loans of $52.7 million,
convertible debentures of $50.0 million (principal) and a working capital
deficiency of $18.8 million, excluding the unrealized loss on derivative
contracts and future income tax assets. The working capital deficiency is due to
accruals associated with the capital program in the last quarter of the year.
The Company's current capital budget for 2011 is $75 million, which is almost
entirely directed at oil horizontal drilling, primarily in the Cardium. The
Company is committed to drill 74 gross Edmonton Sands gas wells under its
farm-in agreement by March 31, 2012. The Company does not plan to drill any
additional Edmonton Sands gas wells until the first quarter of 2012. The Company
plans to drill 15 gross (11.3 net revenue) Cardium oil wells in the first
quarter of 2011.
The Company's need for capital will be both short-term and long-term in nature.
Short-term capital is required to finance accounts receivable and other similar
short-term assets while the acquisition and development of oil and natural gas
properties requires larger amounts of long-term capital. At December 31, 2010,
the Company had total credit facilities of $125 million, consisting of an $80
million extendible revolving term credit facility, a $10 million working capital
credit facility and a $35 million supplemental credit facility with a syndicate
of Canadian banks. The Company had $72.2 million of credit available at December
31, 2010. Draws over $30 million under the supplemental facility will be subject
to the consent of the syndicate at the time of the drawdown. On December 31,
2010, the Company completed a convertible subordinated debenture financing for
proceeds, net of commission and expenses, of $47.7 million. The net proceeds
were initially used to pay down bank debt. Anderson Energy will prudently use
its bank loan facilities to finance its operations as required. The available
lending limits under the bank facilities are reviewed twice a year and are based
on the bank syndicate's interpretation of the Company's reserves and future
commodity prices. The last review was conducted in November 2010. There can be
no assurance that the amount of the available bank lines will not be adjusted at
the next scheduled review to be completed prior to July 12, 2011. The Company
will continue to fund its ongoing operations from a combination of cash flow,
debt, asset dispositions and equity financing as needed.
CONTRACTUAL OBLIGATIONS
The Company enters into various contractual obligations in the course of
conducting its operations. These obligations include:
- Loan agreements - The reserves-based extendible, revolving term credit
facility and working capital credit facility have a revolving period ending on
July 12, 2011, extendible at the option of the lenders. If not extended, the
facilities cease to revolve and all outstanding advances thereunder become
repayable one year from the term date of July 12, 2011. The supplemental
facility is available on a revolving basis and expires on July 1, 2011 with any
amounts outstanding due in full at that time. No amounts were drawn under the
supplemental facility at December 31, 2010.
- Convertible debentures - The Company issued $50.0 million in convertible
debentures on December 31, 2010. The convertible debentures have a face value of
$1,000, bear interest at the rate of 7.5% per annum payable semi-annually in
arrears on the last day of January and July of each year, commencing on July 31,
2011 and mature on January 31, 2016. The convertible debentures are convertible
at the holder's option at a conversion price of $1.55 per common share, subject
to adjustment in certain events. The Debentures are not redeemable by the
Corporation before January 31, 2014.
- Lease for office space - This lease expires on November 30, 2012. Future
minimum lease payments are expected to be $1.8 million per year in 2011, and
$1.6 million in 2012.
- Firm service transportation commitments - The Company has entered into firm
service transportation agreements for approximately 29 million cubic feet per
day of gas sales for various terms expiring between 2011 and 2020. Based on rate
schedules announced to date, the payments in each of the next five years and
thereafter are estimated to be $1.6 million in 2011, $1.3 million in 2012, $0.8
million in 2013, $0.7 million in 2014, $0.6 million in 2015 and $0.4 million
thereafter.
- Oil transportation contract - In 2010, the Company entered into a facilities
construction and operation agreement pursuant to which it is committed to ship a
minimum volume of gross crude oil through new facilities and pipelines being
constructed in Garrington. The total financial commitment is $2.6 million to be
incurred over a minimum of five years. The contract contains a minimum volume
requirement per year for the first five years following completion of
construction which is expected to be in the second quarter of 2011. In the event
that the volume shipped is less than the minimum volume, the Company will be
subject to a fee per cubic metre of oil on the difference between actual volumes
shipped and the minimum volume required. Conversely, if the Company exceeds the
minimum volume requirement in a single year, the excess is carried forward as a
credit to the minimum volume requirement in the subsequent year. If no volumes
were shipped, a minimum of $0.26 million would be payable each year. After the
total contracted volumes have been shipped, the contract will automatically
renew for one year periods unless terminated.
- Farm-in - On January 30, 2009, the Company announced a farm-in agreement with
a large international oil and gas company on lands near its existing core
operations. Under the farm-in agreement, the Company has access to 388 gross
(205 net) sections of land. During the commitment phase of the transaction, the
Company is committed to drill, complete and equip 200 wells to earn an interest
in up to 120 sections. The Company has drilled 126 wells under the commitment to
December 31, 2010. The Company is obligated to complete the drilling of the
remaining wells on or before March 31, 2012. The commitment is subject to
certain guarantees. The Company estimates that its minimum commitment to drill
the remaining 74 wells is $10 million. The Company currently plans to defer its
spending on the farm-in project until the first quarter of 2012.
CRITICAL ACCOUNTING ESTIMATES
The Company's significant accounting policies are disclosed in note 1 to the
consolidated financial statements. Certain accounting policies require that
management make appropriate decisions with respect to the formulation of
estimates and assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses. These accounting policies are discussed
below and are included to aid the reader in assessing the critical accounting
policies and practices of the Company and the likelihood of materially different
results than reported. The Company's management reviews its estimates regularly.
The emergence of new information and changed circumstances may result in actual
results that differ materially from current estimates.
Proved Oil and Gas Reserves. Proved oil and gas reserves, as defined by the
Canadian Securities Administrators in NI 51-101 with reference to the Canadian
Oil and Gas Evaluation Handbook, are those reserves that can be estimated with a
high degree of certainty to be recoverable. Determination of reserves is a
complex process involving judgments, estimates and decisions based on available
geological, engineering, production and any other relevant data. These estimates
are subject to material change as economic conditions change and ongoing
production and development activities provide new information.
Independent reserves evaluators have prepared the Company's oil and gas reserves
estimate. Estimates are reviewed and revised as appropriate. Revisions occur as
a result of changes in prices, costs, fiscal regimes, reservoir performance,
methodology of booking undeveloped reserves, or a change in the Company's
development plans. The effect of changes in proved oil and gas reserves on the
financial results and financial position of the Company is described below under
the heading "Full Cost Accounting" and "Full Cost Accounting Ceiling Test".
Full Cost Accounting. The Company follows the full cost method of accounting for
petroleum and natural gas properties, whereby all costs of exploring for and
developing petroleum and natural gas properties and related reserves are
capitalized. The capitalized costs are depleted and depreciated using the
unit-of-production method based on estimated proved reserves. Reserves estimates
can have a significant impact on earnings, as they are a key component in the
calculation of depletion and depreciation. Downward revisions in reserves
estimates or upward revisions in future development cost estimates could result
in a higher depletion and depreciation charge to earnings. In addition, if net
capitalized costs are determined to be in excess of the calculated ceiling,
which is based largely on reserves estimates (see "Full Cost Accounting Ceiling
Test"), the excess must be written off as an expense charged against earnings.
In the event of property dispositions, proceeds are normally deducted from the
full cost pool without recognition of gain or loss unless there is a change in
the depletion rate of 20% or greater.
Unproved Properties. Certain costs related to unproved properties are excluded
from costs subject to depletion until proved reserves have been determined or
their value is impaired. These properties are reviewed quarterly and any
impairment is transferred to the costs being depleted. The costs relating to
unproved properties are also excluded from the book value subject to the ceiling
test measurement.
Full Cost Accounting Ceiling Test. Petroleum and natural gas assets are
evaluated in each reporting period to determine that the carrying amount in a
cost centre is recoverable and does not exceed the fair value of the properties
in the cost centre.
Impairment is indicated if the carrying value of the oil and gas cost centre is
not recoverable by the future undiscounted cash flows. If impairment is
indicated, the amount by which the carrying value exceeds the estimated fair
value of the oil and gas assets is charged to earnings. The ceiling test is
based on estimates of reserves, production rates, petroleum and natural gas
prices, future costs and other relevant assumptions. By their nature, these
estimates are subject to measurement uncertainty and the impact on the financial
statements could be material.
Asset Retirement Obligations. The Company is required to provide for future
removal and site restoration costs. The Company must estimate these costs in
accordance with existing laws, contracts or other policies. These estimated
costs are charged to property, plant & equipment and the appropriate liability
account over the expected service life of the asset. The estimate of future
removal and site restoration costs involves a number of estimates related to
timing of abandonment, determination of the economic life of the asset, costs
associated with abandonment and site restoration, review of potential
abandonment methods and salvage/usage of tangible equipment.
Income Taxes. The determination of the Company's income and other tax
liabilities requires interpretation of complex laws and regulations often
involving multiple jurisdictions. All tax filings are subject to audit and
potential reassessment after the lapse of considerable time. Accordingly, the
actual income tax liability may differ from that estimated and recorded by
management. The Company estimates its future income tax rate in calculating its
future income tax liability. Various assumptions are made in assessing when
temporary differences will reverse and this will impact the rate used.
Stock-Based Compensation. In order to recognize stock-based compensation costs,
the Company estimates the fair value of stock options granted using assumptions
related to interest rates, expected life of the option, forfeitures, volatility
of the underlying security and expected dividend yields. These assumptions may
vary over time.
INTERNATIONAL FINANCIAL REPORTING STANDARDS ("IFRS")
In October 2009, the Accounting Standards Board issued a third and final IFRS
Omnibus Exposure Draft confirming that publicly accountable enterprises will be
required to apply IFRS, in full and without modification, for all financial
periods beginning January 1, 2011. The adoption date of January 1, 2011 requires
the restatement, for comparative purposes, of amounts reported by the Company
for the year ended December 31, 2010, including the opening balance sheet as at
January 1, 2010.
In response, the Company has completed its high-level IFRS changeover plan and
established a timeline for the execution and completion of the conversion
project. The changeover plan was determined following a preliminary assessment
of the differences between Canadian GAAP and IFRS and the potential effects of
IFRS to accounting and reporting processes, information systems, business
processes and external disclosures. This assessment has provided insight into
what are anticipated to be the most significant areas of difference applicable
to the Company.
The Company has performed an in-depth review of the significant areas of
difference identified during the preliminary assessment, in order to identify
all specific Canadian GAAP and IFRS differences and select ongoing IFRS
policies. Key areas addressed were also reviewed to determine any information
technology issues, the impact on internal controls over financial reporting and
the impact on business activities including the effect, if any, on covenants and
compensation arrangements. External advisors have been retained to assist
management with the project on an as needed basis to ensure IFRS readiness for
the filing of the Company's first quarterly IFRS financial statements of 2011.
The Audit Committee has approved the IFRS accounting policy selections presented
by management to date and disclosed herein. Below is a summary of the Company's
accounting policies that are expected to have a significant impact on the
Company's consolidated financial statements. The list and comments below should
not be regarded as a complete list of changes that will result from the
transition to IFRS. The amounts quantified are based on the Company's internal
calculations and have not been audited by the Company's external auditors.
Note that most adjustments required on transition to IFRS will be made
retrospectively, against opening retained earnings in the first comparative
balance sheet. Transitional adjustments relating to those standards where
comparative figures are not required to be restated because they are applied
prospectively will only be made as of the first day of the year of transition.
IFRS 1 "First-Time Adoption of International Financial Reporting Standards"
provides entities adopting IFRS for the first time with a number of optional
exemptions and mandatory exceptions, in certain areas, to the general
requirement for full retrospective application of IFRS. The Company has
finalized the various accounting policy choices available with the significant
IFRS 1 exemptions taken described below.
Property, Plant and Equipment. International Accounting Standard (IAS) 16
"Property, Plant & Equipment" and Canadian GAAP contain the same basic
principles, however there are some differences. IFRS requires that significant
parts of an asset be depreciated separately and depreciation commences when the
asset is available for use. There will be more depreciable components than the
current single full cost pool as depletion and depreciation cannot be calculated
at a level more aggregated than a cash generating unit. At transition, the
Company did not identify any significant components that needed to be
depreciated on a basis other than unit-of-production.
IFRS also permits property, plant equipment to be measured using the fair value
model or the historical cost model. The Company is not planning on adopting the
fair value measurement model for property, plant and equipment.
IFRS 1 contains an exemption where by a company may apply IFRS prospectively by
utilizing its current reserves (volumes or values) at the transition date to
allocate the Company's full cost pool, with the provision that an impairment
test, under IFRS standards, be conducted at the transition date. The Company
intends to use this exemption and allocate the net book values based on reserve
volumes.
The Company has the option to calculate depletion using a reserve base of proved
reserves or both proved plus probable reserves, as compared to the Canadian GAAP
method of calculating depletion using proved reserves only. The Company plans to
deplete its property, plant and equipment using proved plus probable reserves.
As a result of this policy choice, the Company expects that its quarterly
depletion under IFRS will be lower than it was under Canadian GAAP.
Provisions. Under IFRS, similar to Canadian GAAP, the Company is required to
record obligations relating to the retirement of its wells and facilities where
a legal or contractual obligation currently exists. Upon the adoption of IFRS,
the Company will also need to evaluate if there are any constructive obligations
where the decommissioning liability would also need to be recognized. Currently,
the Company has not identified any constructive obligations.
The Company intends to apply the IFRS 1 exemption whereby the decommissioning
liability provision is recalculated at January 1, 2010 using the IFRS
methodology and any adjustments would be offset against opening retained
earnings. As a result of applying this IFRS 1 exemption, at transition, the
Company expects to increase its provision by $12 to $15 million. The increase in
the provision is a result of the Company applying a risk free rate to the future
cash flows. The use of a risk free rate will result in lower accretion expense,
which is included in finance expenses, and higher depletion expense subsequent
to transition.
Impairment of Assets. IAS 36 "Impairment of Assets" requires that impairments be
determined based on discounted cash flows. This differs from the current two
step practice where the asset's carrying value is initially compared to the
estimated undiscounted future cash flows, and only if the carrying value exceeds
the undiscounted future cash flows is a discounted analysis, step two, required.
There is no undiscounted test under IFRS. This may result is more frequent
write-downs upon transition.
In addition, under IFRS, an entity must also evaluate whether there are changes
in circumstances that would support an impairment reversal, which is not
allowable under GAAP.
Another difference arises in the level at which an impairment test is performed.
Under IFRS, impairment testing will be performed on cash generating units. The
Company has identified its cash generating units based on the reserve
characteristics. At transition, the Company has four cash generating units:
Horizontal Oil, Deep Gas, Shallow Gas and Non-Core.
As a result of applying the IFRS 1 exemption for deemed cost, the Company tested
for impairment at transition. Based on preliminary calculations, the Company
expects an impairment at transition on January 1, 2010 of between $50 and $70
million with the offset going to opening retained earnings. Throughout 2010, the
estimates of forward natural gas prices declined significantly (GLJ price
forecasts declined 25% on average for 2011 to 2015, and 16% thereafter) and year
end reserves were subject to a 6.6 MMBOE reduction for economic factors. As a
result, the Company expects to record additional significant impairments in the
natural gas weighted cash generating units for 2010.
Income taxes. Under IAS 12 "Income Taxes", current and deferred tax are normally
recognized in the income statement, except to the extent that tax arises from
(1) an item that has been recognized directly in equity, whether in the same or
a different period, (2) a business combination or (3) a share based payment
transaction. If a deferred tax asset or liability is re-measured subsequent to
initial recognition, the impact of re-measurement is recorded in earnings,
unless it relates to an item originally recognized in equity, in which case the
change would also be recorded in equity. The practice of tracking the
re-measurement of taxes back to the item which originally triggered the
recognition is commonly referred to as ''backwards tracing.'' Canadian GAAP
prohibits backwards tracing except on business combinations and financial
reorganizations. As a result of the changes to the Company's transition balance
sheet described herein, the Company estimates that its deferred tax liability
will be reduced by $18 to $22 million with the offset going to opening retained
earnings.
Share based payments. Under IFRS 2 "Share-Based Payments", graded vested options
are required to be separated into their vesting tranches and valued and
accounted for separately. This differs from Canadian GAAP, where graded vested
options are valued at grant date and expensed using the straight line method.
IFRS 1 provides an exemption on IFRS 2 for equity instruments which vested
before the transition date and does not require them to be retroactively
restated. All unvested options at transition date will be required to be
retroactively restated with the adjustment going through opening retained
earnings on transition. The Company intends to use this exemption and expects
the transition impact to be less than $0.5 million.
In addition to accounting policy differences discussed above, the Company's
transition to IFRS is expected to impact its internal controls over financial
reporting, disclosure controls and procedures, certain business activities and
IT systems.
Internal controls over financial reporting ("ICFR"). The Company is currently in
the process of reviewing its ICFR documentation and is identifying instances
where controls must be amended or added in order to address the accounting
policy changes required under IFRS. No material changes in control procedures
are expected as a result of transition to IFRS.
Disclosure controls and procedures. The Company is currently assessing the
impact of transition to IFRS on its disclosure controls and procedures and does
not expect any material changes required in its control environment. It is
expected that there will be increased note disclosure around certain financial
statement items than what is currently required under Canadian GAAP. Management
is currently drafting its IFRS note disclosure in accordance with current IFRS
standards and continues to monitor requirements put forth by the International
Accounting Standards Board ("IASB") in discussion papers and exposure drafts for
future disclosure requirements. Throughout the transition process, the Company
has carefully considered its stakeholders' information requirements and will
continue to ensure that adequate and timely information is provided to meet
these needs.
Business activities. Management has been cognizant of the upcoming transition to
IFRS, and as such, has worked with its counterparties and lenders to ensure that
any agreements that contain references to Canadian GAAP financial statements are
modified to allow for IFRS statements. Based on the changes to the Company's
accounting policies, no issues are expected to arise with the existing wording
of credit facilities and related agreements as a result of the conversion to
IFRS.
IT systems. The Company has recently completed the accounting system upgrades
required in order to prepare for IFRS reporting. The modifications were not
significant, however, they were deemed critical in order to allow for reporting
of both Canadian GAAP and IFRS statements in 2010 as well as the modifications
required to track property, plant and equipment at a more granular level of
detail for IFRS reporting.
Throughout the first half of 2011, the Company will continue calculating the
quarterly impact of its policy choices under IFRS. The Company's external
auditors have been engaged to review the 2010 adjustments in early April 2011 in
order to have sufficient time to review the Company's information for its first
IFRS financial statements.
The Company continues to monitor standards development as issued by the IASB and
the AcSB as well as regulatory developments as issued by the Canadian Securities
Administrators, which may affect the timing, nature or disclosure of its
adoption of IFRS.
CONTROLS AND PROCEDURES
The Chief Executive Officer and the Chief Financial Officer have evaluated and
tested the effectiveness of Anderson Energy's disclosure controls and procedures
as of December 31, 2010 and have concluded that such disclosure controls and
procedures were effective.
The Chief Executive Officer and the Chief Financial Officer have evaluated and
tested the design and operating effectiveness of Anderson Energy's internal
controls over financial reporting as of December 31, 2010 and have concluded
that, these internal controls are designed properly and are effective in the
preparation of financial statements for external purposes in accordance with
Canadian GAAP. There were no material changes in the Company's internal controls
over financial reporting in the last quarter of the Company's fiscal year.
Because of inherent limitations, internal controls over financial reporting may
not prevent or detect all misstatements, errors or fraud. Control systems, no
matter how well designed, only provide reasonable, not absolute, assurance that
the objectives of the controls systems are met.
BUSINESS RISKS
Oil and gas exploration and production is capital intensive and involves a
number of business risks including, without limitation, the uncertainty of
finding new reserves, the instability of commodity prices, weather and various
operational risks. Commodity prices are influenced by local and worldwide supply
and demand, OPEC actions, ongoing global economic concerns, the U.S. dollar
exchange rate, transportation costs, political stability and seasonal and
weather related changes to demand. The price of natural gas has weakened due to
increasing U.S. gas production driven primarily by the U.S. shale gas plays. The
large amount of gas in storage combined with strong U.S. gas production and
financial market fears has continued to suppress the price of natural gas. Oil
prices have increased recently as crude oil is a geopolitical commodity, and is
responding to instability in the Middle East. The industry is subject to
extensive governmental regulation with respect to the environment. Operational
risks include well performance, uncertainties inherent in estimating reserves,
timing of/ability to obtain drilling licences and other regulatory approvals,
ability to obtain equipment, expiration of licences and leases, competition from
other producers, sufficiency of insurance, ability to manage growth, reliance on
key personnel, third party credit risk and appropriateness of accounting
estimates. These risks are described in more detail in the Company's Annual
Information Form for the year ended December 31, 2010 to be filed with Canadian
securities regulatory authorities on SEDAR.
The Company anticipates making substantial capital expenditures for the
acquisition, exploration, development and production of oil and natural gas
reserves in the future. As the Company's revenues may decline as a result of
decreased commodity pricing, it may be required to reduce capital expenditures.
In addition, uncertain levels of near term industry activity coupled with the
present global economic concerns exposes the Company to additional access to
capital risk. There can be no assurance that debt or equity financing, or funds
generated by operations will be available or sufficient to meet these
requirements or for other corporate purposes or, if debt or equity financing is
available, that it will be on terms acceptable to the Company. The inability of
the Company to access sufficient capital for its operations could have a
material adverse effect on the Company's business, financial condition, results
of operations and prospects.
Anderson Energy manages these risks by employing competent professional staff,
following sound operating practices and using capital prudently. The Company
generates its exploration prospects internally and performs extensive
geological, geophysical, engineering, and environmental analysis before
committing to the drilling of new prospects. Anderson Energy seeks out and
employs new technologies where possible. With the Company's extensive drilling
inventory and advance planning, the Company can manage the slower pace of
regulatory approvals and the requirements for extensive landowner consultation.
The Company has a formal emergency response plan which details the procedures
employees and contractors will follow in the event of an operational emergency.
The emergency response plan is designed to respond to emergencies in an
organized and timely manner so that the safety of employees, contractors,
residents in the vicinity of field operations, the general public and the
environment are protected. A corporate safety program covers hazard
identification and control on the jobsite, establishes Company policies, rules
and work procedures and outlines training requirements for employees and
contract personnel.
The Company currently deals with a small number of buyers and sales contracts,
and endeavors to ensure that those buyers are an appropriate credit risk. The
Company continuously evaluates the merits of entering into fixed price or
financial hedge contracts for price management.
The oil and natural gas business is subject to regulation and intervention by
governments in such matters as the awarding of exploration and production
interests, the imposition of specific drilling obligations, environmental
protection controls, control over the development and abandonment of fields
(including restrictions on production) and possibly expropriation or
cancellation of contract rights. As well, governments may regulate or intervene
with respect to prices, taxes, royalties and the exportation of oil and natural
gas. Such regulation may be changed from time to time in response to economic or
political conditions. The implementation of new regulations or the modification
of existing regulations affecting the oil and natural gas industry could reduce
demand for oil and natural gas, increase the Company's costs or affect its
future opportunities.
The oil and natural gas industry is currently subject to environmental
regulations pursuant to a variety of provincial and federal legislation. Such
legislation provides for restrictions and prohibitions on the release or
emission of various substances produced in association with certain oil and gas
industry operations. Such legislation may also impose restrictions and
prohibitions on water use or processing in connection with certain oil and gas
operations. In addition, such legislation requires that well and facility sites
be abandoned and reclaimed to the satisfaction of provincial authorities.
Compliance with such legislation can require significant expenditures and a
breach of such requirements may result, amongst other things in suspension or
revocation of necessary licenses and authorizations, civil liability for
pollution damage, and the imposition of material fines and penalties.
Canada is a signatory to the United Nations Framework Convention on Climate
Change. The Canadian federal government previously released the Regulatory
Framework for Air Emissions, updated March 10, 2008 by Turning the Corner:
Regulatory Framework for Industrial Greenhouse Gas Emissions (collectively, the
"Regulatory Framework"), for regulating greenhouse gas ("GHG") emissions by
proposing mandatory emissions intensity reduction obligations on a sector by
sector basis. Legislation to implement the Regulatory Framework had been
expected to be put in place this year, but the federal government has delayed
the release of any such legislation and potential federal requirements in
respect of GHG emissions are unclear. On January 30, 2010, the Canadian federal
government announced its new target to reduce overall Canadian GHG emissions by
17% below 2005 levels by 2020, from the previous target of 20% from 2006 levels
by 2020, to align itself with the GHG emission reduction goals of the United
States. In 2009, the Canadian federal government announced its commitment to
work with the provincial governments to implement a North American-wide cap and
trade system for GHG emissions, in cooperation with the United States. Canada
would have its own cap-and-trade market for Canadian-specific industrial sectors
that could be integrated into a North American market for carbon permits.
Additionally, regulation can take place at the provincial and municipal level.
For example, Alberta introduced the Climate Change and Emissions Management Act,
which provides a framework for managing GHG emissions and establishes a target
of reducing specified gas emissions relative to gross domestic product to an
amount that is equal to or less than 50% of 1990 levels by December 31, 2020.
The accompanying regulations, the Specified Gas Emitters Regulation and the
Specified Gas Emitters Reporting Regulation require mandatory emissions
reductions through the use of emissions intensity targets and impose duties to
report. The Canadian federal government proposes to enter into equivalency
agreements with provinces that establish a regulatory regime to ensure
consistency with the federal plan, but the success of any such plan is doubtful
in the current political climate, leaving multiple overlapping levels of
regulation.
The Government of Alberta implemented a new oil and gas royalty framework
effective January 2009. The new framework establishes new royalties for
conventional oil, natural gas and bitumen that are linked to price and
production levels and apply to both new and existing conventional oil and gas
activities and oil sands projects. Under the framework, the formula for
conventional oil and natural gas royalties uses a sliding rate formula,
dependent on the market price and production volumes. Royalty rates for
conventional oil range from 0% to 50%. Natural gas royalty rates range from 5%
to 50%.
In November 2008, the Government of Alberta announced that companies drilling
new natural gas and conventional oil wells at depths between 1,000 and 3,500
metres, which are spudded between November 19, 2008 and December 31, 2013, will
have a one-time option of selecting new transitional royalty rates or the new
royalty framework rates. The transition option provides lower royalties in the
initial years of a well's life. For example, under the transition option,
royalty rates for natural gas wells will range from 5% to 30%. The option for
producers to elect transitional royalties in respect of qualifying deep wells
ended on December 31, 2010 and any wells spudded on or after January 1, 2011 are
subject to the royalty rates discussed below. Wells that are subject to
transitional royalty rates will automatically revert to the new royalty
framework rates on January 1, 2014.
On March 3, 2009, the Government of Alberta announced a three-point incentive
program. Amendments to the program were announced on June 11 and June 25, 2009.
This incentive program includes a drilling credit for new oil and natural gas
wells drilled between April 1, 2009 and March 31, 2011, providing a $200 per
metre drilled royalty credit to companies. The credit can be used to offset up
to 50% of Crown royalties payable after the wells have been drilled up until
March 31, 2011. There is also a new well incentive program that provides a
maximum 5% royalty rate for the first 12 months of production from new wells
that begin producing oil or natural gas between April 1, 2009 and March 31, 2011
to a maximum of 50,000 barrels of oil or 500 million cubic feet of natural gas.
The province of Alberta will also invest $30 million in a fund committed to
abandonment and reclamation projects where there is no legally responsible or
financially able party to deal with the clean-up of inactive wells.
On March 11, 2010, the Alberta government announced its intention to adjust
royalty rates effective January 1, 2011. This adjustment includes making the
incentive program royalty rate of 5% on new natural gas and conventional oil
wells a permanent feature of the royalty system with the time and volume limits
discussed above. The maximum royalty rate was reduced from the current level of
50% to 40% for conventional oil and to 36% for natural gas. The transitional
royalty framework for oil and gas will continue until December 31, 2013 as
announced but no new wells will be allowed to select transitional royalty rates
effective January 1, 2011; wells that have selected the transitional royalty
rates will be allowed to switch to the new rates effective January 1, 2011.
Royalty curves incorporating the changes announced on March 11, 2010 were
released on May 27, 2010.
The changes to the royalty regime in the Province of Alberta are subject to
certain risks and uncertainties. There may be modifications introduced to the
royalty structure and such changes may be adverse to the business of the
Company. There can be no assurance that the Government of Alberta or the
Government of Canada will not adopt new royalty regimes which may render the
Company's projects uneconomic or otherwise adversely affect the business of the
Company.
BUSINESS PROSPECTS
The Company believes it has an excellent future drilling inventory in the
Cardium light oil horizontal oil play and is focused on growing its production
and reserves with Cardium horizontal drilling. The Company has 112.5 gross (65.8
net) sections in the fairway. At a drilling density of three wells per section,
the potential drilling inventory is 338 gross (197.4 net) Cardium horizontal
locations. The Company continues to add to its land position and drilling
inventory through a combination of acquisitions, property swaps and farm-ins,
and continues to implement new technologies to control and reduce its costs in
this project.
The Company's annual production guidance for 2011 is 7,500 BOED. Risks
associated with this guidance include continued low commodity prices which may
restrict capital spending, new well performance, gas plant capacity, gas plant
turnaround duration, regulatory issues, weather problems and access to industry
services.
QUARTERLY INFORMATION
The following table provides financial and operating results for the last eight
quarters. Commodity prices have declined from the first quarter of 2009 and
remain volatile, affecting funds from operations and earnings throughout 2009
and 2010.
SELECTED QUARTERLY INFORMATION
($ amounts in thousands, except per share amounts and prices)
Q4 2010 Q3 2010 Q2 2010 Q1 2010
----------------------------------------
Oil and gas revenue before
royalties(1) $ 23,946 $ 18,928 $ 20,318 $ 23,265
Funds from operations $ 9,515 $ 8,026 $ 9,004 $ 10,635
Funds from operations per share
Basic $ 0.06 $ 0.05 $ 0.05 $ 0.06
Diluted $ 0.06 $ 0.05 $ 0.05 $ 0.06
Net loss $(11,741) $ (9,046) $ (8,891) $ (5,953)
Net loss per share
Basic $ (0.07) $ (0.05) $ (0.05) $ (0.04)
Diluted $ (0.07) $ (0.05) $ (0.05) $ (0.04)
Capital expenditures, including
acquisitions, net of dispositions $ 26,473 $ 39,528 $ 12,745 $ 33,427
Cash from operating activities $ 10,721 $ 8,437 $ 8,892 $ 12,946
Daily sales
Natural gas (Mcfd) 38,479 35,778 38,998 35,221
Liquids (bpd) 1,815 1,329 1,232 1,130
BOE (BOED) 8,228 7,292 7,732 7,000
Average prices
Natural gas ($/Mcf) $ 3.48 $ 3.43 $ 3.78 $ 5.22
Liquids ($/bbl) $ 69.11 $ 58.61 $ 60.28 $ 62.43
BOE ($/BOE)(1) $ 31.63 $ 28.21 $ 28.88 $ 36.93
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Q4 2009 Q3 2009 Q2 2009 Q1 2009
----------------------------------------
Oil and gas revenue before
Royalties (1) $ 20,439 $ 14,617 $ 17,508 $ 24,429
Funds from operations $ 9,151 $ 6,623 $ 6,692 $ 8,792
Funds from operations per share
Basic $ 0.06 $ 0.04 $ 0.06 $ 0.10
Diluted $ 0.06 $ 0.04 $ 0.06 $ 0.10
Net loss $ (6,457) $ (9,432) $(10,410) $(10,159)
Net loss per share
Basic $ (0.04) $ (0.06) $ (0.09) $ (0.12)
Diluted $ (0.04) $ (0.06) $ (0.09) $ (0.12)
Capital expenditures, including
acquisitions net of dispositions $ 11,312 $ 6,571 $ 2,130 $ 13,545
Cash from operating activities $ 5,361 $ 6,689 $ 2,472 $ 9,298
Daily sales
Natural gas (Mcfd) 34,938 36,282 40,495 42,344
Liquids (bpd) 1,257 1,013 1,040 1,448
BOE (BOED) 7,080 7,060 7,789 8,505
Average prices
Natural gas ($/Mcf) $ 4.28 $ 2.81 $ 3.43 $ 5.15
Liquids ($/bbl) $ 53.79 $ 53.84 $ 49.00 $ 38.69
BOE ($/BOE)(1) $ 31.38 $ 22.50 $ 24.70 $ 31.91
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes royalty and other income classified with oil and gas sales and
excludes the realized and unrealized losses on derivative contracts in
the fourth quarter of 2010 of $0.1 million and $1.9 million
respectively.
SELECTED ANNUAL INFORMATION
YEARS ENDED DECEMBER 31
(in thousands, except per share amounts)
2010 2009 2008
Total oil and gas revenues(1) $ 86,457 $ 76,993 $ 156,245
Total oil and gas revenues, net
of royalties(1) $ 77,446 $ 68,740 $ 122,207
Earnings (loss) before goodwill
impairment $ (35,631) $ (36,458) $ 8,500
Earnings (loss) before goodwill
impairment per share
Basic $ (0.21) $ (0.29) $ 0.10
Diluted $ (0.21) $ (0.29) $ 0.10
Net loss $ (35,631) $ (36,458) $ (26,864)
Net loss per share
Basic $ (0.21) $ (0.29) $ (0.31)
Diluted $ (0.21) $ (0.29) $ (0.31)
Total assets $ 535,115 $ 497,169 $ 543,533
Total bank loans $ 52,719 $ 62,404 $ 85,314
Total convertible debentures,
liability component $ 43.460 $ - $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes royalty and other income classified with oil and gas sales.
Excludes the realized and unrealized losses on derivative contracts in
2010 of $0.1 million and $1.9 million respectively.
ADVISORY
Certain information regarding Anderson Energy Ltd. 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, dates of commencement of production, amount of
capital expenditures and timing 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 to
the royalty regime applicable to the Company, including payment of drilling
incentive credits, commodity price outlook and general economic outlook may
constitute forward-looking statements under applicable securities laws and
necessarily involve risks and assumptions made by management of the Company
including, without limitation, risks associated with oil and gas exploration,
development, exploitation, production, marketing and transportation, loss of
markets, volatility of commodity prices, currency fluctuations, imprecision of
reserves estimates, environmental risks, competition from other producers,
inability to retain drilling rigs and other services, capital expenditure costs,
including drilling, completion and facilities costs, unexpected decline rates in
wells, 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 and ability to access
sufficient capital from internal and external sources. As a consequence, actual
results may differ materially from those anticipated in the forward-looking
statements. Readers are cautioned that the foregoing list of factors is not
exhaustive. Additional information on these and other factors that could affect
Anderson Energy's operations and financial results are included in reports on
file with Canadian securities regulatory authorities and may be accessed through
the SEDAR website (www.sedar.com) and at Anderson Energy's website
(www.andersonenergy.ca).
Furthermore, the forward-looking statements contained in this news release are
made as at the date of this news release and Anderson Energy 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.
ANDERSON ENERGY LTD.
Consolidated Balance Sheets
DECEMBER 31, 2010 AND 2009
2010 2009
(Stated in thousands of dollars)
(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents $ 4,024 $ 1
Accounts receivable and accruals (note 11) 20,998 22,990
Prepaid expenses and deposits 3,052 3,778
Future income tax asset (note 7) 508 -
---------------------------
28,582 26,769
Property, plant and equipment (note 3) 506,533 470,400
---------------------------
$ 535,115 $ 497,169
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accruals $ 46,862 $ 36,889
Unrealized loss on derivative contracts
(note 11) 1,918 -
---------------------------
48,780 36,889
Bank loans (note 4) 52,719 62,404
Convertible debentures (note 5) 43,460 -
Asset retirement obligations (note 6) 36,320 33,879
Future income taxes (note 7) 20,045 31,278
---------------------------
201,324 164,450
Shareholders' equity:
Share capital (note 8) 422,038 391,637
Equity component of convertible debentures
(note 5) 4,242 -
Contributed surplus (note 8) 8,164 6,104
Deficit (100,653) (65,022)
---------------------------
333,791 332,719
Commitments (note 13)
Subsequent event (note 14)
---------------------------
$ 535,115 $ 497,169
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
ANDERSON ENERGY LTD.
Consolidated Statements of Operations, Comprehensive Loss and Deficit
YEARS ENDED DECEMBER 31, 2010 AND 2009
2010 2009
(Stated in thousands of dollars,
except per share amounts)
(Unaudited)
REVENUES
Oil and gas sales $ 86,457 $ 76,993
Royalties (9,011) (8,253)
Realized loss on derivative contracts (131) -
Unrealized loss on derivative contracts
(note 11) (1,918) -
Interest income 96 155
---------------------------
75,493 68,895
EXPENSES
Operating 29,148 26,906
General and administrative 7,733 6,998
Stock-based compensation 1,175 1,092
Interest and other financing charges 3,352 3,733
Depletion, depreciation and accretion 81,265 80,940
---------------------------
122,673 119,669
---------------------------
---------------------------
Net loss before taxes (47,180) (50,774)
Future income tax reduction (note 7) (11,549) (14,316)
---------------------------
Net loss and comprehensive loss for the year (35,631) (36,458)
Deficit, beginning of year (65,022) (28,564)
---------------------------
Deficit, end of year $ (100,653) $ (65,022)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net loss per share (note 8)
Basic $ (0.21) $ (0.29)
Diluted $ (0.21) $ (0.29)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
ANDERSON ENERGY LTD.
Consolidated Statements of Cash Flows
YEARS ENDED DECEMBER 31, 2010 AND 2009
2010 2009
(Stated in thousands of dollars)
(Unaudited)
CASH PROVIDED BY (USED IN)
OPERATIONS
Net loss for the year $ (35,631) $ (36,458)
Items not involving cash:
Depletion, depreciation and accretion 81,265 80,940
Future income tax reduction (11,549) (14,316)
Unrealized loss on derivative contracts
(note 11) 1,918 -
Stock-based compensation 1,175 1,092
Accretion on convertible debentures (note 5) 2 -
Asset retirement expenditures (1,549) (1,482)
Changes in non-cash working capital (note 10) 5,365 (5,956)
---------------------------
40,996 23,820
FINANCING
Decrease in bank loans (9,685) (22,910)
Issue of common shares, net of issue costs 29,859 56,538
Issue of convertible debentures, net of issue
costs 47,700 -
Changes in non-cash working capital (note 10) 384 115
---------------------------
68,258 33,743
INVESTMENTS
Additions to property, plant and equipment (114,380) (33,612)
Proceeds on disposition of properties 2,207 54
Changes in non-cash working capital (note 10) 6,942 (24,005)
---------------------------
(105,231) (57,563)
---------------------------
Increase in cash 4,023 -
Cash, beginning of year 1 1
---------------------------
Cash and cash equivalents, end of year $ 4,024 $ 1
---------------------------
Cash in bank 374 1
Short-term investments 3,650 -
---------------------------
Cash and cash equivalents $ 4,024 $ 1
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See note 10 for supplemental cash flow information.
See accompanying notes to the consolidated financial statements.
ANDERSON ENERGY LTD.
Notes to the Consolidated Financial Statements
YEARS ENDED DECEMBER 31, 2010 AND 2009
(Tabular amounts in thousands of dollars, unless otherwise stated)
(Unaudited)
Anderson Energy Ltd. ("Anderson Energy" or the "Company") was incorporated under
the laws of the province of Alberta on January 30, 2002. Anderson Energy is
engaged in the acquisition, exploration and development of oil and gas
properties in western Canada.
1. SIGNIFICANT ACCOUNTING POLICIES
(a) Basis of presentation. These consolidated financial statements include the
accounts of Anderson Energy Ltd. and its wholly owned subsidiaries and a
partnership and have been prepared by management in accordance with accounting
principles generally accepted in Canada. All inter-entity transactions and
balances have been eliminated. Management is required to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amount of revenue and expenses during the reported
period. Actual results could differ from these estimates. Specifically, the
amounts recorded for depletion and depreciation of oil and gas properties and
the accretion of asset retirement obligations are based on estimates. The
ceiling test is based on estimates of reserves, production rates, oil and gas
prices, future costs and other relevant assumptions. The amounts for stock-based
compensation are based on estimates of risk-free rates, expected lives,
forfeitures and volatility. Future income taxes are based on estimates as to the
timing of the reversal of temporary differences and tax rates currently
substantively enacted. The fair value of derivative contracts are based on the
discounted value of the market for future commodity prices, interest rates and
the exchange rate between United States and Canadian dollars. By their nature,
these estimates are subject to measurement uncertainty and the effect on the
financial statements of changes in such estimates in future periods could be
significant.
(b) Cash and cash equivalents. Cash is defined as cash in the bank, less
outstanding cheques. Cash equivalents consist of term deposits with original
maturity dates of less than 30 days.
(c) Property, plant and equipment. The Company follows the full cost method of
accounting for oil and gas properties. Under this method, all costs related to
the exploration for and development of oil and gas reserves are capitalized.
Capitalized costs include lease acquisitions, geological and geophysical costs,
lease rentals on non-producing properties, costs of drilling productive and
non-productive wells, plant and production equipment costs, asset retirement
costs and that portion of general and administrative expenses directly
attributable to exploration and development activities. Proceeds received from
disposals of oil and gas properties and equipment are credited against
capitalized costs unless the disposal would alter the rate of depletion and
depreciation by more than 20%, in which case a gain or loss on disposal is
recorded.
Oil and gas capitalized costs are depleted and depreciated using the unit of
production method based on total proved reserves before royalties. Natural gas
sales and reserves are converted to equivalent units of crude oil using their
relative energy content. The costs of acquiring and evaluating unproved
properties are initially excluded from depletion calculations until it is
determined whether or not proved reserves are attributable to the property or
impairment occurs. Office equipment and furniture are being depreciated over
their useful lives using the declining balance method at rates between 20% and
30% per annum.
A detailed impairment calculation is performed when events or circumstances
indicate a potential impairment of the carrying amount of oil and gas properties
may have occurred, and at least annually in the fourth quarter. An impairment
loss is recognized when the carrying amount of a cost centre is not recoverable
and exceeds its fair value. The carrying amount is assessed to be recoverable
when the sum of the undiscounted cash flows expected from proved reserves plus
the cost of unproved properties, net of impairments, exceeds the carrying amount
of the cost centre. When the carrying amount is assessed not to be recoverable,
an impairment loss is recognized to the extent that the carrying amount of the
cost centre exceeds the sum of the discounted cash flows from proved and
probable reserves plus the cost of unproved properties, net of impairments, of
the cost centre. The cash flows are estimated using expected future product
prices and costs and are discounted using a risk-free interest rate.
(d) Asset retirement obligations. The Company records the fair value of asset
retirement obligations as a liability in the period in which it incurs a legal
obligation to restore an oil and gas property, typically when a well is drilled,
equipment is put in place or in the event of an acquisition. The fair value is
discounted using the Company's credit adjusted, risk-free rate with the
associated asset retirement costs capitalized as part of the carrying amount of
property, plant and equipment and depleted and depreciated using the unit of
production method based on total proved reserves before royalties. Subsequent to
the initial measurement of the obligations, the obligations are increased at the
end of each period to reflect the passage of time resulting in an accretion
charge to earnings. The obligations are also adjusted for changes in the
estimated future cash flows underlying the obligation. Actual costs incurred
upon settlement of the retirement obligation are charged against the obligation
to the extent of the liability recorded.
(e) Income taxes. The Company follows the asset and liability method of
accounting for income taxes. Under this method, income tax assets and
liabilities are recognized for the estimated tax consequences attributable to
differences between the amounts reported in the financial statements and their
respective tax bases, using income tax rates that are substantively enacted and
expected to apply in the periods when the temporary differences are expected to
reverse. The effect of a change in rates on future income tax assets and
liabilities is recognized in the period that the change occurs.
(f) Flow-through shares. The resource expenditure deductions for income tax
purposes related to exploratory and development activities funded by
flow-through share arrangements are renounced to investors in accordance with
income tax legislation. An estimate of the additional tax liability to be
incurred and included in the future tax provision is recognized and charged to
share capital at the time the resource expenditure deductions for income tax
purposes are renounced to investors.
(g) Stock-based compensation plans. The Company accounts for stock options
granted to employees and directors using the fair value method of accounting for
stock-based compensation plans. Under this method, the Company recognizes
compensation expense, with a corresponding increase to contributed surplus,
based on the fair value of the options over the vesting period of the grant. The
Company uses a Black-Scholes option pricing model to determine the fair value of
options at the date of grant. When exercised, the consideration paid together
with the amount previously recognized in contributed surplus is recorded as an
increase to share capital.
(h) Revenue recognition. Revenue from the sale of oil and gas is recognized when
title passes from the Company to the purchaser.
(i) Financial instruments. A financial instrument is any contract that gives
rise to a financial asset to one entity and a financial liability or equity
instrument to another entity. Upon initial recognition, all financial
instruments, including all derivatives, are recognized on the balance sheet at
fair value. Subsequent measurement is then based on the financial instruments
being classified into one of five categories: held for trading, held to
maturity, loans and receivables, available for sale and other liabilities. The
Company has designated its cash and cash equivalents as held for trading which
is measured at fair value. Accounts receivable are classified as loans and
receivables which are measured at amortized cost. Accounts payable and accrued
liabilities, bank loans and the liability component of convertible debentures
are classified as other liabilities which are measured at amortized cost
determined using the effective interest rate.
The Company is exposed to market risks resulting from fluctuations in commodity
prices, foreign exchange rates and interest rates in the normal course of
operations. A variety of derivative instruments may be used by the Company to
reduce its exposure to fluctuations in commodity prices, foreign exchange rates,
and interest rates. The Company does not use these derivative instruments for
trading or speculative purposes. The Company considers all of these transactions
to be economic hedges, however, the Company's contracts do not qualify or have
not been designated as hedges for accounting purposes. As a result, derivative
contracts are classified as held for trading and are recorded on the balance
sheet at fair value, with changes in the fair value recognized in earnings,
unless specific hedge criteria are met. If specific hedge criteria are met,
changes in the fair value are initially recognized in other comprehensive
income, and are subsequently reclassified to earnings in the same period in
which the revenues associated with the hedged transactions are recognized. The
fair values of these derivative instruments are based on an estimate of the
amounts that would have been received or paid to settle these instruments prior
to maturity given future market prices and other relevant factors.
The Company has elected to account for its physical delivery sales contracts for
the purpose of receipt or delivery of non-financial items in accordance with its
expected purchase, sale or usage requirements as executory contracts on an
accrual basis rather than as non-financial derivatives.
The Company measures and recognizes embedded derivatives separately from the
host contracts when the economic characteristics and risks of the embedded
derivative are not closely related to those of the host contract, when it meets
the definition of a derivative and when the entire contract is not measured at
fair value. Embedded derivatives are recorded at fair value.
The Company nets all transaction costs incurred, in relation to the acquisition
of a financial asset or liability, against the related financial asset or
liability. Convertible debentures are recorded net of issue costs and bank loans
are presented net of deferred interest payments, with interest recognized in
earnings on an effective interest basis.
The Company applies trade-date accounting for the recognition of a purchase or
sale of cash equivalents and derivative contracts.
(j) Convertible debentures. The Company's convertible debentures are financial
liabilities consisting of a liability with an embedded conversion feature. As
such, the debentures are segregated between liabilities and equity based on the
residual value method, where the liability is first measured using a discount
rate without the conversion feature and the remaining amount is allocated to
equity. Therefore, the debenture liabilities are presented at less than their
maturity values. The liability and equity components are further reduced for
issuance costs initially incurred. The difference between the discounted
liability component and the maturity value is accreted by the "effective
interest" method over the debenture term and expensed accordingly. As debentures
are converted to shares, an appropriate portion of the liability and equity
components are transferred to share capital.
(k) Interests in joint operations. A substantial portion of the Company's oil
and gas exploration and development activities are conducted jointly with
others, and accordingly, the consolidated financial statements reflect only the
Company's proportionate interest in such activities.
(l) Per share amounts. Basic per share amounts are calculated using the weighted
average number of common shares outstanding during the period. Diluted per share
amounts reflect the potential dilution that could occur if securities or other
contracts to issue common shares were exercised or converted to common shares.
The treasury stock method is used to determine the dilutive effect of stock
options and other dilutive instruments. Under the treasury stock method, only
options for which the exercise price is less than the market value impact the
dilution calculations.
(m) Comparative figures. Certain comparative figures have been reclassified to
conform to the current year's presentation.
2. FUTURE ACCOUNTING PRONOUCEMENTS
Convergence with International Financial Reporting Standards ("IFRS"). In
January 2006, the Canadian Accounting Standards Board ("AcSB") announced its
decision to replace Canadian GAAP with IFRS. On February 13, 2008, the AcSB
confirmed January 1, 2011 as the mandatory changeover date to IFRS for all
Canadian publicly accountable enterprises. As a result, Anderson Energy will
prepare its financial statements under IFRS for the interim periods and fiscal
year ends beginning in 2011.
3. PROPERTY, PLANT AND EQUIPMENT
2010 2009
Cost $ 838,405 $ 723,549
Less accumulated depletion and depreciation (331,872) (253,149)
---------------------------
Net book value $ 506,533 $ 470,400
----------------------------------------------------------------------------
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At December 31, 2010, unproved property costs of $5.0 million (December 31, 2009
- $6.2 million) have been excluded from the full cost pool for depletion and
depreciation calculations. Future development costs of proved, undeveloped
reserves of $137.0 million (December 31, 2009 - $197.6 million) have been
included in the depletion and depreciation calculation.
For the year ended December 31, 2010, $5.2 million (December 31, 2009 - $4.6
million) of general and administrative costs including $0.9 million (December
31, 2009 - $1.0 million) of stock-based compensation costs were capitalized. The
future tax liability of $0.3 million (December 31, 2009 - $0.3 million)
associated with the capitalized stock-based compensation has also been
capitalized. Capitalized general and administrative costs consist of salaries
and associated office rent of staff involved in capital activities.
No impairment was recognized under the ceiling test at December 31, 2010. The
future commodity prices used in the ceiling test were based on commodity price
forecasts of the Company's independent reserves engineers adjusted for
differentials specific to the Company's reserves. Factors used in the ceiling
test calculation are as follows:
AECO Gas Price WTI Cushing Exchange rate
($Cdn/Mcf) ($US/bbl) (US$/Cdn)
2011 4.16 88.00 0.98
2012 4.74 89.00 0.98
2013 5.31 90.00 0.98
2014 5.77 92.00 0.98
2015 6.22 95.17 0.98
2016 6.53 97.55 0.98
2017 6.76 100.26 0.98
2018 6.90 102.74 0.98
2019 7.06 105.45 0.98
2020 7.21 107.56 0.98
Thereafter 2%
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----------------------------------------------------------------------------
After 2020, only inflationary growth of 2% was considered. Natural gas liquids
prices were tied to crude oil prices based on historical trends and analysis.
Exchange rates were expected to remain constant beyond 2020.
4. BANK LOANS
At December 31, 2010, total bank facilities were $125 million consisting of an
$80 million extendible revolving term credit facility, a $10 million working
capital credit facility and a $35 million supplemental credit facility, with a
syndicate of Canadian banks. The extendible revolving term credit facility and
working capital credit facility have a revolving period ending on July 12, 2011,
extendible at the option of the lenders. If not extended, these facilities cease
to revolve and all outstanding advances thereunder become repayable one year
from the term date of July 12, 2011. The supplemental facility is also available
on a revolving basis and is scheduled to expire on July 1, 2011, with any
outstanding amounts due in full at that time.
At December 31, 2010 there were no amounts drawn under the supplemental
facility. The average effective interest rate on advances in 2010 was 4.9%
(December 31, 2009 - 4.2%). The Company had $133,500 in letters of credit
outstanding at December 31, 2010, which reduced the amount of credit available
to the Company.
Advances under the facilities can be drawn in either Canadian or U.S. funds and
bear interest at the bank's prime lending rate, bankers' acceptance or LIBOR
loan rates plus applicable margins. The margins vary depending on the borrowing
option used and the Company's financial ratios. At December 31, 2010 there were
no advances in U.S. funds.
Loans are secured by a floating charge debenture over all assets and guarantees
by material subsidiaries. Draws over $30 million under the supplemental facility
will be subject to the consent of the bank syndicate at the time of the
drawdown.
The available lending limits of the facilities are reviewed semi-annually and
are based on the bank syndicate's interpretations of the Company's reserves and
future commodity prices. There can be no assurance that the amount of the
available facilities or the applicable margins will not be adjusted at the next
scheduled review on or before July 12, 2011.
5. CONVERTIBLE DEBENTURES
On December 31, 2010, the Company issued $50 million of convertible unsecured
subordinated debentures (the "Debentures") on a bought deal basis. The
Debentures have a face value of $1,000, bear interest at the rate of 7.5% per
annum payable semi-annually in arrears on the last day of January and July of
each year commencing on July 31, 2011 and mature on January 31, 2016 (the
"Maturity Date"). The Debentures are convertible at the holder's option at a
conversion price of $1.55 per common share (the "Conversion Price"), subject to
adjustment in certain events. The Debentures are not redeemable by the
Corporation before January 31, 2014. On and after January 31, 2014 and prior to
the Maturity Date, the Debentures are redeemable at the Corporation's option, in
whole or in part, at a price equal to their principal amount plus accrued and
unpaid interest if the weighted average trading price of the common shares on
the Toronto Stock Exchange for the 20 consecutive trading days preceding the
date on which the notice of redemption is given is not less than 125% of the
Conversion Price. The Debentures are listed and posted for trading on the TSX
under the symbol "AXL.DB".
As the Debentures are convertible into common shares, the liability and equity
components are presented separately. The initial carrying amount of the
financial liability is determined by discounting the stream of future payments
of interest and principal. Using the residual method, the carrying amount of the
conversion feature is the difference between the principal amount and the
carrying value of the financial liability. The Debentures, net of the equity
component and issue costs are accreted using the effective interest rate method
over the term of the Debentures such that the carrying amount of the financial
liability will equal the principal balance at maturity.
There were no convertible debentures outstanding at December 31, 2009. The
following table indicates the convertible debenture activities for the year
ended December 31, 2010:
Face Debt Equity
Value Component Component
Balance, December 31, 2009 $ - $ - $ -
Issued pursuant to prospectus (1) 50,000 45,553 4,447
Issue costs (2,300) (2,095) (205)
Accretion expense - 2 -
----------------------------------------
Balance, December 31, 2010 $ 47,700 $ 43,460 $ 4,242
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes 1,000 Debentures issued to directors for total gross proceeds
of $1.0 million.
6. ASSET RETIREMENT OBLIGATIONS
The Company estimates the total undiscounted cash flows required to settle its
asset retirement obligations is approximately $73.7 million (December 31, 2009 -
$70.1 million), including expected inflation of 2% (December 31, 2009 - 2%) per
annum. The majority of the costs will be incurred between 2011 and 2030. A
credit adjusted risk-free rate of 8% to 10% (December 31, 2009 - 8% to 10%) was
used to calculate the fair value of the asset retirement obligations. A
reconciliation of the asset retirement obligations is provided below:
2010 2009
Balance, beginning of year $ 33,879 $ 30,820
Liabilities incurred 758 1,544
Liabilities settled (1,549) (1,482)
Change in estimate 690 666
Accretion expense 2,542 2,331
-------------------------
Balance, end of year $ 36,320 $ 33,879
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----------------------------------------------------------------------------
7. TAXES
The temporary differences that gave rise to the Company's future income tax
liabilities (assets) at December 31, 2010 and 2009 were as follows:
2010 2009
Future income tax liabilities (assets):
Property, plant and equipment $ 46,073 $ 50,210
Non-capital losses (18,080) (9,289)
Asset retirement obligations (9,080) (8,470)
Share issue costs (2,229) (1,985)
Current income deferred 2,853 812
-------------------------
Balance, end of year $ 19,537 $ 31,278
Future income tax asset $ (508) $ -
Future income tax liability 20,045 31,278
-------------------------
$ 19,537 $ 31,278
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The provision for income taxes differs from the result that would have been
obtained by applying the combined federal and provincial tax rates to the loss
before income taxes. The difference results from the following items:
2010 2009
Loss before taxes $ (47,180) $ (50,774)
Combined federal and provincial tax rates 28.0% 29.0%
-------------------------
-------------------------
Expected future income tax reduction (13,210) (14,724)
Increase in income taxes resulting from:
Changes in expected future tax rates 1,339 108
Non-deductible stock-based compensation and other 322 300
-------------------------
Future income tax reduction $ (11,549) $ (14,316)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
At December 31, 2010, the Company has loss carryforwards of $72 million that
will expire between 2025 and 2030. The Company expects to be able to fully
utilize these losses.
8. SHARE CAPITAL AND CONTRIBUTED SURPLUS
Authorized share capital. The Company is authorized to issue an unlimited number
of common and preferred shares. The preferred shares may be issued in one or
more series.
Issued share capital.
Number of Common
Shares Amount
Balance at December 31, 2008 87,300,401 $ 334,176
Issued pursuant to prospectus(1) 63,200,000 60,040
Share issue costs - (3,502)
Tax effect of share issue costs - 923
-------------------------
Balance at December 31, 2009 150,500,401 $ 391,637
Issued pursuant to prospectus(2) 21,900,000 31,755
Share issue costs - (1,963)
Tax effect of share issue costs - 507
Stock options exercised 84,900 67
Transferred from contributed surplus on
stock option exercise - 35
-------------------------
Balance at December 31, 2010 172,485,301 $ 422,038
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes 4,992,034 common shares issued to management and directors and
3,377,966 common shares issued to family of management and directors for
total gross proceeds of $8.0 million.
(2) Includes 352,466 common shares issued to directors for total gross
proceeds of $0.5 million.
Stock options. The Company has an employee stock option plan under which
employees, directors and consultants are eligible to receive grants. The
exercise price of stock options equals the weighted average trading price of the
Company's shares for the five trading days prior to the date of the grant.
Options have terms of either five or ten years and vest equally over a three
year period starting on the first anniversary date of the grant. Changes in the
number of options outstanding during the years ended December 31, 2010 and
December 31, 2009 are as follows:
Weighted
Number of average
options exercise price
Balance at December 31, 2008 7,594,856 $ 4.37
Granted 3,316,200 0.80
Expirations (252,300) 6.47
Forfeitures (400,000) 3.01
--------------------------------
Balance at December 31, 2009 10,258,756 $ 3.22
Granted 3,950,250 1.06
Exercised (84,900) 0.79
Expirations (1,430,124) 5.78
Forfeitures (687,750) 1.44
--------------------------------
Balance at December 31, 2010 12,006,232 $ 2.32
----------------------------------------------------------------------------
Exercisable at December 31, 2010 6,111,399 $ 3.53
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Options outstanding Options exercisable
Weighted Weighted Weighted
average average average
Number of exercise remaining Number of exercise
Range of exercise options price life (years) options price
prices
$ 0.79 to $0.99 2,706,900 $ 0.79 3.6 902,300 $ 0.79
$ 1.00 to $1.50 3,831,750 1.06 4.6 29,400 1.09
$ 2.26 to $3.35 727,950 2.68 2.7 489,300 2.68
$ 3.36 to $5.00 4,354,732 4.00 1.5 4,308,499 4.00
$ 5.01 to $7.50 320,100 5.67 0.3 317,100 5.68
$ 7.51 to $9.01 64,800 7.69 0.1 64,800 7.69
-------------------------------------------------------
Total at December
31, 2010 12,006,232 $ 2.32 3.0 6,111,399 $ 3.53
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The fair value of the options issued during the year ended December 31, 2010 was
$0.55 per option (December 31, 2009 - $0.42 per option). The weighted average
assumptions used in arriving at the values were: a risk-free interest rate of
2.3% (December 31, 2009 - 2.4%), expected option life of five years (December
31, 2009 - five years), expected volatility of 58% (December 31, 2009 - 60%) and
a dividend yield of 0% (December 31, 2009 - 0%).
Per share amounts. During the year ended December 31, 2010 there were
170,298,490 weighted average shares outstanding (December 31, 2009 -
125,047,250). On a diluted basis, there were 170,298,490 weighted average shares
outstanding (December 31, 2009 - 125,047,250) after giving effect to dilutive
stock options and dilutive convertible debentures. At December 31, 2010, there
were 12,006,232 options (December 31, 2009 - 10,258,756) and 32,258,065 common
shares reserved for convertible debentures (December 31, 2009 - Nil) that were
anti-dilutive.
Contributed surplus
Amount
Balance at December 31, 2008 $ 4,000
Stock-based compensation 2,104
----------
Balance at December 31, 2009 $ 6,104
Stock-based compensation 2,095
Transferred from contributed surplus on stock option exercise (35)
----------
Balance at December 31, 2010 $ 8,164
----------------------------------------------------------------------------
----------------------------------------------------------------------------
9. MANAGEMENT OF CAPITAL STRUCTURE
Anderson Energy's capital management policy is to maintain a strong, but
flexible capital structure that optimizes the cost of capital and maintains
investor, creditor and market confidence while sustaining the future development
of the business.
The Company manages its capital structure and makes adjustments to it in the
light of changes in economic conditions and the risk characteristics of the
underlying petroleum and natural gas assets. The Company's capital structure
includes shareholders' equity of $333.8 million, bank loans of $52.7 million,
convertible debentures with a face value of $50.0 million and the working
capital deficiency of $18.8 million, excluding the unrealized loss on derivative
contract and future income tax asset. In order to maintain or adjust the capital
structure, the Company may from time to time issue shares, seek additional debt
financing and adjust its capital spending to manage current and projected debt
levels.
Consistent with other companies in the oil and gas sector, Anderson Energy
monitors capital based on the ratio of total debt to funds from operations. This
ratio is calculated by dividing total debt at the end of the period (comprised
of the working capital deficiency, the liability component of convertible
debentures and outstanding bank loans) by the annualized current quarter funds
from operations (cash flow from operating activities before changes in non-cash
working capital and asset retirement expenditures). This ratio may increase at
certain times as a result of acquisitions, the timing of capital expenditures
and market conditions. In order to facilitate the management of this ratio, the
Company prepares annual capital expenditure budgets, which are updated as
necessary depending on varying factors including current and forecast crude oil
and natural gas prices, capital deployment and general industry conditions. The
annual and updated budgets are approved by the Board of Directors.
2010 2009
Bank loans $ 52,719 $ 62,404
Current liabilities, excluding unrealized loss on
derivative contracts 46,862 36,889
Current assets, excluding future income tax asset (28,074) (26,769)
----------------------------------------------------------------------------
Net debt before convertible debentures $ 71,507 $ 72,524
Convertible debentures (liability component) 43,460 -
----------------------------------------------------------------------------
Total net debt $ 114,967 $ 72,524
Cash from operating activities in quarter $ 10,721 $ 5,361
Changes in non-cash working capital (1,324) 3,246
Asset retirement expenditures 118 544
----------------------------------------------------------------------------
Funds from operations in quarter $ 9,515 $ 9,151
Annualized current quarter funds from operations $ 38,060 $ 36,604
Net debt before convertible debentures to funds
from operations 1.9 2.0
Total net debt to funds from operations 3.0 2.0
----------------------------------------------------------------------------
----------------------------------------------------------------------------
At December 31, 2010, the Company's total net debt to annualized funds from
operations was 3.0 and the Company's net debt before convertible debentures to
annualized funds from operations was 1.9. At December 31, 2009, the Company's
total debt to annualized funds from operations was 2.0. The increase in the
total net debt to funds from operations ratio in the fourth quarter of 2010 is
due to $26.5 million in capital expenditures and lower natural gas prices in the
quarter as well as the issuance of 50,000 convertible debentures on December 31,
2010. Net debt before convertible debentures to annualized funds from operation
in 2010 was relatively consistent with 2009. New production resulting from the
capital expenditures is not yet reflected in the reported funds from operations.
As this new crude oil production is brought on stream at higher expected
operating margins, the debt to funds from operations ratio is expected to
decrease.
The Company's share capital is not subject to external restrictions, however,
its credit facilities are petroleum and natural gas reserves based (see note 4).
Anderson Energy has not paid or declared any dividends since the date of
incorporation and does not contemplate doing so in the foreseeable future.
10. SUPPLEMENTAL CASH FLOW INFORMATION
2010 2009
Change in non-cash working capital:
Accounts receivable and accruals $ 1,992 $ 5,970
Prepaid expenses and deposits 726 (1,086)
Accounts payable and accruals 9,973 (34,730)
-------------------------
Change in non-cash working capital $ 12,691 $ (29,846)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Relating to:
Operating activities $ 5,365 $ (5,956)
Financing activities 384 115
Investing activities 6,942 (24,005)
-------------------------
Change in non-cash working capital $ 12,691 $ (29,846)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The following cash payments were made (received):
2010 2009
Interest paid $ 2,256 $ 2,835
Interest received (90) (155)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
11. FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT
The Company's financial instruments include cash and cash equivalents, accounts
receivable and accruals, deposits, accounts payable and accruals, bank loans,
convertible debentures and forward price contracts.
The Company's risk management policies are established to identify and analyze
the risks faced by the Company, to set appropriate risk limits and controls, and
to monitor risks and adherence to market conditions and the Company's
activities.
The Company has exposure to credit risk, liquidity risk and market risk as a
result of its use of financial instruments. This note presents information about
the Company's exposure to each of the above risks and the Company's objectives,
policies and processes for measuring and managing these risks. Further
quantitative disclosures are included throughout these financial statements.
The Board of Directors has overall responsibility for the establishment and
oversight of the Company's risk management framework. The Board has implemented
and monitors compliance with risk management policies.
Fair value of financial asset and financial liabilities. Financial instruments
measured at fair value on the balance sheet require classification into one of
the following levels of fair value hierarchy:
- Level 1 - observable inputs such as quoted prices in active markets;
- Level 2 - inputs, other than the quoted market prices in active markets, which
are observable, either directly and/or indirectly; and
- Level 3 - unobservable inputs for the asset or liability in which little or no
market data exists, therefore requiring an entity to develop its own
assumptions.
Cash and cash equivalents as shown in the consolidated balance sheet as at
December 31, 2010 and 2009, is measured using level 1. The commodity contracts
are classified as level 2 within the fair value hierarchy. The Company does not
have any financial instruments that are measured using level 3 inputs.
During the years ended December 31, 2010 and 2009, there were no transfers
between level 1, level 2 and level 3 classified assets and liabilities.
Cash and cash equivalents. The fair value of cash and cash equivalents
approximates its carrying value due to its short-term nature.
Accounts receivable and accruals, accounts payable and accruals. The carrying
amount of accounts receivable and accruals and accounts payable and accruals
approximate their fair values due to the short-term nature of the instruments.
Bank loans. The fair value of the Company's variable-rate bank loans
approximates its carrying value, as it is at a floating market rate of interest.
Convertible debentures. The liability component has been classified as other
liabilities and measured at amortized cost. The convertible debentures have a
fixed term and interest rate (note 5) resulting in fair values that will vary
over time as market conditions change. The fair value of the liability component
of convertible debentures was determined based on a discounted cash flow model
assuming no future conversions and continuation of current interest and
principal payments as well as taking into consideration the current public
trading activity of such debentures. The Company applied a discount rate of 10%
considering current available market information, assumed credit adjustments and
term to maturity.
Forward crude oil price swap. The Company may manage the risk associated with
changes in commodity prices by entering into derivatives, which are recorded at
fair value as derivative assets and liabilities with gains and losses recognized
through earnings. As the fair value of the contracts varies with commodity
prices, they give rise to financial assets and liabilities. The fair values of
the derivatives are determined by a Level 2 valuation model, where pricing
inputs other than quoted prices in an active market are used. These pricing
inputs include quoted forward prices for commodities, foreign exchange rates,
volatility and risk-free rate discounting, all of which can be observed or
corroborated in the marketplace. The actual gains and losses realized on
eventual cash settlement can vary materially due to subsequent fluctuations in
commodity prices and foreign exchange rates as compared to the valuation
assumptions.
Credit risk. Credit risk is the risk of financial loss to the Company if a
customer or counterparty to a financial instrument fails to meet its contractual
obligations. A substantial portion of the Company's accounts receivable are with
natural gas and liquids marketers and joint venture partners in the oil and gas
industry and are subject to normal industry credit risks. Purchasers of the
Company's natural gas and liquids are subject to credit review to minimize the
risk of non-payment. As at December 31, 2010, the maximum credit exposure is the
carrying amount of the accounts receivable and accruals of $21.0 million
(December 31, 2009 - $23.0 million). As at December 31, 2010, the Company's
receivables consisted of $11.4 million (December 31, 2009 - $14.4 million) from
joint venture partners and other trade receivables and $9.6 million (December
31, 2009 - $8.6 million) of revenue accruals and other receivables from
petroleum and natural gas marketers.
Receivables from petroleum and natural gas marketers are typically collected on
the 25th day of the month following production. The Company's policy to mitigate
credit risk associated with these balances is to establish marketing
relationships with large purchasers. The Company historically has not
experienced any significant collection issues with its petroleum and natural gas
marketers. Of the $9.6 million of revenue accruals and receivables from
petroleum and natural gas marketers, $8.5 million was received on or about
January 25, 2011. The balance is expected to be received in subsequent months
through joint venture billings from partners.
Joint venture receivables are typically collected within one to three months of
the joint venture bill being issued to the partner. The Company mitigates the
risk from joint venture receivables by obtaining partner approval of capital
expenditures prior to starting a project. However, the receivables are from
participants in the petroleum and natural gas sector, and collection is
dependent on typical industry factors such as commodity price fluctuations,
escalating costs and the risk of unsuccessful drilling. Further risks exist with
joint venture partners, as disagreements occasionally arise that increase the
potential for non-collection. For properties that are operated by Anderson
Energy, production can be withheld from joint venture partners who are in
default of amounts owing. In addition, the Company often has offsetting amounts
payable to joint venture partners from which it can net receivable balances. At
December 31, 2010, the largest amount owing from one partner is $0.8 million.
The Company is from time to time exposed to credit risk associated with possible
non-performance by counterparties to derivative financial instrument contracts.
The Company believes these risks to be minimal as the counterparties are major
financial institutions.
The Company's allowance for doubtful accounts as at December 31, 2010 is $1.0
million (December 31, 2009 - $1.6 million). This allowance was mostly created in
prior years and is associated with prior corporate acquisitions and potential
joint venture billing disputes. The Company wrote-off $0.6 million in
receivables during the year ended December 31, 2010 (December 31, 2009 - $Nil).
The Company would only choose to write-off a receivable balance (as opposed to
providing an allowance) after all reasonable avenues of collection had been
exhausted.
As at December 31, the Company considers its receivables to be aged as follows
Aging 2010 2009
Not past due $ 18,960 $ 22,402
Past due by less than 120 days 1,706 537
Past due by more than 120 days 332 51
-------------------------
Total $ 20,998 $ 22,990
----------------------------------------------------------------------------
----------------------------------------------------------------------------
These amounts are before offsetting amounts owing to joint venture partners that
are included in accounts payable and accrued liabilities.
Liquidity risk. Liquidity risk is the risk that the Company will incur
difficulties meeting its financial obligations as they are due. The Company's
approach to managing liquidity is to ensure, as far as possible, that it will
have sufficient liquidity to meet its liabilities when due, under both normal
and stressed conditions without incurring unacceptable losses or risking harm to
the Company's reputation.
The Company prepares annual capital expenditure budgets, which are regularly
monitored and updated as considered necessary. The Company uses authorizations
for expenditures on both operated and non-operated projects to further manage
capital expenditures. To facilitate the capital expenditure program, the Company
has revolving reserves based credit facilities, as outlined in note 4, which are
reviewed semi-annually by the lenders. The Company monitors its total debt
position monthly. The Company also attempts to match its payment cycle with
collection of petroleum and natural gas revenues on the 25th of each month. The
Company anticipates it will have adequate liquidity to fund its financial
liabilities through its future cash flows.
The following are the contractual maturities of financial liabilities and
associated interest payments as at December 31, 2010:
Financial Liabilities 2011 2012 2013 2014 2015 2016
Accounts payable and
accruals $ 46,862 $ - $ - $ - $ - $ -
Bank loans - principal - 52,719 - - - -
Convertible debentures -
interest 2,198 3,750 3,750 3,750 3,750 1,875
Convertible debentures -
principal - - - - - 50,000
----------------------------------------------------
Total $ 49,060 $ 56,469 $ 3,750 $ 3,750 $ 3,750 $ 51,875
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Please refer to note 13 for additional details on commitments.
Market risk. Market risk consists of currency risk, commodity price risk and
interest rate risk. The objective of market risk management is to manage and
control market risk exposures within acceptable limits, while maximizing
returns.
The Company may use both financial derivatives and physical delivery sales
contracts to manage market risks. All such transactions are conducted in
accordance with a risk management policy that has been approved by the Board of
Directors.
Currency risk. Foreign currency exchange rate risk is the risk that the fair
value or future cash flows will fluctuate as a result of changes in foreign
exchange rates. Substantially all of the Company's petroleum and natural gas
sales are denominated in Canadian dollars, however, the underlying market prices
in Canada for petroleum and natural gas are impacted by changes in the exchange
rate between the Canadian and United States dollar. The Company had no
outstanding forward exchange rate contracts in place at December 31, 2010.
Commodity price risk. Commodity price risk is the risk that the fair value or
future cash flows will fluctuate as a result of changes in commodity prices.
Commodity prices for petroleum and natural gas are impacted by world economic
events that dictate the levels of supply and demand as well as the relationship
between the Canadian and United States dollar, as outlined above. The Company
may mitigate commodity price risk through the use of financial derivatives and
physical delivery fixed price sales contracts. All such contracts require
approval of the Board of Directors.
There were no derivative contracts for the year ended December 31, 2009. As at
December 31, 2010, Anderson had a fixed price contract for 1,000 barrels per day
of crude oil for calendar 2011 at a NYMEX crude oil price of Canadian $88.45 per
barrel.
The unrealized loss on derivative contracts of $1.9 million for the year ended
December 31, 2010 has been included on the balance sheet as a current liability
with changes in the fair value included in unrealized loss on derivative
contracts on the consolidated statements of operations. As at December 31, 2010,
if the future strip prices for crude oil were $1 per barrel higher or lower with
all other variables held constant, the earnings of the year would have been $0.4
million lower for the year. An equal and opposite impact would have occurred had
future strip prices for crude oil been lower by the same amount.
In October 2010, the Company entered into fixed price swaps for 1,000 barrels
per day of crude oil for December 2010 at a NYMEX crude oil price of Canadian
$85.70 per barrel. The Company realized a loss of $0.1 million in relation to
this contract in the year ended December 31, 2010, which is included in the
realized loss on derivative contract on the consolidated statements of
operations.
In March 2011, the Company entered into a fixed price contract for 250 barrels
per day of crude oil for calendar 2012 at a NYMEX crude oil price of Canadian
$103.20 per barrel.
In December 2009, the Company entered into physical sales contracts to sell
20,000 GJ per day of natural gas for each of January, February and March 2010 at
an average AECO price of $5.41 per GJ. The Company realized a gain of $1.3
million in relation to these physical sales contracts in the year ended December
31, 2010, which is included in oil and gas sales.
Interest rate risk. Interest rate risk is the risk that future cash flows will
fluctuate as a result of changes in market interest rates. The Company is
exposed to interest rate fluctuations on its bank debt which bears interest at a
floating rate. For the year ended December 31, 2010, if interest rates had been
1% lower with all other variables held constant, earnings for the year would
have been $0.3 million (December 31, 2009 - $0.5 million) higher, due to lower
interest expense. An equal and opposite impact would have occurred had interest
rates been higher by the same amounts.
The Company had no interest rate swap or financial contracts in place at
December 31, 2009.
12. RELATED PARTY TRANSACTIONS
On December 31, 2010, the Company issued 1,000 convertible debentures to
directors at a price of $1,000 per convertible debenture for total gross
proceeds of $1.0 million as part of a $50.0 million bought share offering of
convertible debentures.
In February 2010, the Company issued 352,466 common shares to directors at a
price of $1.45 per share for total gross proceeds of $0.5 million as part of a
$27.9 million bought share offering of common shares.
In May 2009, the Company issued 4,992,034 common shares to management and
directors and 3,377,966 common shares to family of management and directors of
the Company at a price of $0.95 per share for total gross proceeds of $8.0
million as part of a $60.0 million bought share offering of common shares.
13. COMMITMENTS
The Company has entered into an agreement to lease office space until November
30, 2012. Future minimum lease payments are expected to be $1.8 million in 2011
and $1.6 million in 2012.
On December 2, 2010, the Company entered into a facilities construction and
operation agreement pursuant to which it is committed to ship a minimum volume
of gross crude oil through new facilities and pipelines being constructed in one
of its core areas. The total financial commitment is $2.6 million to be incurred
over a minimum of five years. The contract contains a minimum volume requirement
per year for the first five years following completion of construction which is
expected to be in the second quarter of 2011. In the event that the volume
shipped is less than the minimum volume, the Company will be subject to a fee
per cubic metre of oil on the difference between actual volumes shipped and the
minimum volume required. Conversely, if the Company exceeds the minimum volume
requirement in a single year, the excess is carried forward as a credit to the
minimum volume requirement in the subsequent year. If no volumes were shipped, a
minimum of $0.26 million would be payable each year. After the total contracted
volumes have been shipped, the contract will automatically renew for one year
periods unless terminated.
The Company entered into firm service transportation agreements for
approximately 29 million cubic feet per day of gas sales in central Alberta for
various terms expiring in one to ten years. Based on rate schedules announced to
date, the payments in each of the next five years and thereafter are estimated
as follows:
Committed
Committed volume (MMcfd) amount
2011 29 $ 1,633
2012 19 $ 1,337
2013 8 $ 825
2014 4 $ 674
2015 4 $ 606
Thereafter 12 $ 442
----------------------------------------------------------------------------
----------------------------------------------------------------------------
On January 29, 2009, the Company executed a farm-in agreement with a large
international oil and gas company (the "Farmor") on lands near its existing core
operations. Under the farm-in agreement, the Company has access to 388 gross
(205 net) sections of land. During the commitment phase of the transaction, the
Company is committed to drill, complete and equip 200 wells to earn an interest
in up to 120 sections. The Company is obligated to complete the drilling of the
wells on or before March 31, 2012. The Company's equipping obligation is up to,
but does not include, multi-well gathering systems downstream of field
compression and/or gas plants. The Company has an option to continue the farm-in
transaction until March 1, 2013 by committing to drill a minimum of 100
additional wells under similar terms as in the commitment phase to earn a
minimum of 50 sections of land. Following the commitment and/or option phases,
the parties to the agreement can then jointly develop the lands on denser
drilling spacing under terms of an operating agreement.
The Company commenced drilling in the fourth quarter of 2009 and currently
estimates that the average working interest of the 200 well capital commitment
will be approximately 80% to 85%, based on partner participation identified to
date. As of December 31, 2010, the Company has drilled 126 wells under the
farm-in agreement and plans to defer the drilling of the remaining 74 wells
until 2012. The Company earns its interest in each well as the well is put on
production. A $550,000 penalty is payable for each well not drilled under the
commitment as of March 31, 2012, subject to certain reductions due to
unavoidable events beyond the Company's control and rights of first refusal. The
Company estimates that its minimum commitment to drill the remaining 74 wells is
$10 million.
14. SUBSEQUENT EVENT
On February 9, 2011, the Company disposed of properties for gross proceeds of
$5.1 million.
Corporate Information Contact Information
Head Office Anderson Energy Ltd.
700 Selkirk House Brian H. Dau
555 4(th) Avenue S.W. President & Chief Executive Officer
Calgary, Alberta (403) 262-6307
Canada T2P 3E7
Phone (403) 262-6307
Fax (403) 261-2792
Website www.andersonenergy.ca
Officers
Directors
J.C. Anderson
J.C. Anderson Chairman of the Board
Calgary, Alberta
Brian H. Dau
Brian H. Dau President & Chief Executive Officer
Calgary, Alberta
David M. Spyker
Christopher L. Fong (1)(2)(3) Chief Operating Officer
Calgary, Alberta
M. Darlene Wong
Glenn D. Hockley (1)(3) Vice President Finance, Chief Financial
Calgary, Alberta Officer & Secretary
David J. Sandmeyer (2)(3) Blaine M. Chicoine
Calgary, Alberta Vice President, Operations
David G. Scobie (1)(2) Sandra M. Drinnan
Calgary, Alberta Vice President, Land
Member of: Philip A. Harvey
(1) Audit Committee Vice President, Exploitation
(2) Compensation & Corporate
Governance Committee Jamie A. Marshall
(3) Reserves Committee Vice President, Exploration
Patrick M. O'Rourke
Vice President, Production
Auditors Abbreviations used
KPMG LLP AECO - intra-Alberta Nova inventory transfer
price
bbl - barrel
Independent Engineers bpd - barrels per day
GLJ Petroleum Consultants Mbbls - thousand barrels
Mstb - thousand stock tank barrels
Legal Counsel BOE - barrels of oil equivalent
Bennett Jones LLP BOED - barrels of oil equivalent per day
MBOE - thousand barrels of oil equivalent
Registrar & Transfer Agent MMBOE - million barrels of oil equivalent
Valiant Trust Company GJ - gigajoule
Mcf - thousand cubic feet
Stock Exchange Mcfd - thousand cubic feet per day
The Toronto Stock Exchange MMcf - million cubic feet
Symbol AXL, AXL.DB MMcfd - million cubic feet per day
Bcf - billion cubic feet
NGL - natural gas liquids
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