Anderson Energy Ltd. ("Anderson" or the "Company") (TSX:AXL) is
pleased to announce its operating and financial results for the
three and nine months ended September 30, 2012.
HIGHLIGHTS
-- Funds from operations in the third quarter of 2012 were $5.7 million.
Funds from operations for the first nine months of 2012 were $23.9
million.
-- Production in the third quarter of 2012 was 5,770 bpd, of which oil and
NGL production averaged 1,850 bpd. Oil represented 1,274 bpd of total
production.
-- Oil and NGL revenue represented 72% of Anderson's total oil and gas
sales in the third quarter of 2012 compared to 63% in the same period of
2011.
-- The operating netback per BOE in the third quarter of 2012 was $20.54
per BOE compared to $26.10 per BOE in the third quarter of 2011. The
operating netback was primarily impacted by declining commodity prices,
partially offset by a reduction in operating costs resulting from the
Company's prior investments in low operating cost crude oil
infrastructure which has significantly lowered transportation costs.
Cardium oil netbacks averaged approximately $43.29 per BOE in the third
quarter of 2012.
-- GLJ Petroleum Consultants ("GLJ") have completed an interim reserves
report of all of the Company's oil and natural gas properties effective
October 1, 2012 including properties sold by the Company in the fourth
quarter of 2012. Proved plus probable ("P&P") BOE reserves are 25.3
MMBOE.
-- Subsequent to September 30, 2012, the Company has sold or agreed to sell
approximately 1,560 BOED of production (75% natural gas) for cash
consideration of $37.5 million subject to normal closing adjustments.
Approximately one-half of these dispositions have now closed and the
remainder is scheduled to close before the end of November 2012.
-- As previously announced, the Company's board of directors (the "Board of
Directors") is conducting a process to identify, examine and consider a
range of strategic alternatives with a view to enhancing shareholder
value. Anderson has engaged BMO Capital Markets and RBC Capital Markets
as financial advisors to assist in this process. Since January 1, 2012,
the Company has sold or has agreed to sell approximately $74 million of
oil and gas properties subject to normal closing adjustments.
FINANCIAL AND OPERATING HIGHLIGHTS
Three months ended Nine months ended
September 30 September 30
(thousands of
dollars, unless % %
otherwise stated) 2012 2011 Change 2012 2011 Change
Oil and gas
sales(i) $ 17,013 $ 28,513 (40%)$ 62,532 $ 85,665 (27%)
Revenue, net of
royalties(i) $ 15,284 $ 24,970 (39%)$ 56,019 $ 76,029 (26%)
Funds from
operations $ 5,725 $ 12,655 (55%)$ 23,947 $ 37,467 (36%)
Funds from
operations per
share
Basic and
diluted $ 0.03 $ 0.07 (57%)$ 0.14 $ 0.22 (36%)
Earnings (loss)
before effect of
impairments $ 94 $ 6,667 (99%)$ (7,598)$ 8,918 (185%)
Earnings (loss)
per share before
effect of
impairments,
basic and diluted $ - $ 0.04 (100%)$ (0.04)$ 0.05 (180%)
Earnings (loss) $ 94 $ 7,472 (99%)$ (22,598)$ 9,723 (332%)
Earnings (loss)
per share
Basic and
diluted $ - $ 0.04 (100%)$ (0.13)$ 0.06 (317%)
Capital
expenditures, net
of (proceeds) on
dispositions $ (28,986)$ 49,713 (158%)$ (12,110)$ 118,351 (110%)
Bank loans plus cash working capital
deficiency $ 96,991 $ 108,583 (11%)
Convertible
debentures $ 86,247 $ 84,334 2%
Shareholders'
equity $ 141,751 $ 195,251 (27%)
Average shares outstanding
(thousands)
Basic 172,550 172,550 - 172,550 172,534 -
Diluted 172,550 172,550 - 172,550 173,040 -
Ending shares outstanding
(thousands) 172,550 172,550 -
Average daily
sales:
Natural gas
(Mcfd) 23,519 30,038 (22%) 25,799 31,972 (19%)
Oil (bpd) 1,274 1,709 (25%) 1,632 1,615 1%
NGL (bpd) 576 636 (9%) 676 667 1%
Barrels of oil
equivalent
(BOED) 5,770 7,351 (22%) 6,607 7,610 (13%)
Average prices:
Natural gas
($/Mcf) $ 2.24 $ 3.85 (42%)$ 1.98 $ 3.74 (47%)
Oil ($/bbl) $ 80.44 $ 89.05 (10%)$ 84.03 $ 91.59 (8%)
NGL ($/bbl) $ 51.59 $ 66.07 (22%)$ 58.06 $ 68.76 (16%)
Barrels of oil
equivalent
($/BOE)(i) $ 32.05 $ 42.16 (24%)$ 34.54 $ 41.23 (16%)
Realized gain
(loss) on
derivative
contracts ($/BOE) $ 3.16 $ 1.29 145% $ 1.77 $ (0.17) 1141%
Royalties ($/BOE) $ 3.26 $ 5.24 (38%)$ 3.60 $ 4.64 (22%)
Operating costs
($/BOE) $ 11.28 $ 11.22 1% $ 10.62 $ 11.30 (6%)
Transportation
costs ($/BOE) $ 0.13 $ 0.89 (85%)$ 0.25 $ 0.63 (60%)
Operating netback
($/BOE) $ 20.54 $ 26.10 (21%)$ 21.84 $ 24.49 (11%)
Wells drilled
(gross) - 21 (100%) 3 41 (93%)
(i) Includes royalty and other income classified with oil and
gas sales, but excludes realized and unrealized gains and losses on
derivative contracts.
FINANCIAL RESULTS
Capital expenditures before dispositions were $1.7 million in
the third quarter of 2012, and proceeds on disposition were $30.7
million in the third quarter of 2012. This compares to capital
expenditures of $55.9 million before dispositions and proceeds on
dispositions of $6.2 million in the third quarter of 2011.
Anderson's funds from operations were $5.7 million in the third
quarter of 2012 compared to $12.7 million in the third quarter of
2011. Oil and gas sales were lower in the third quarter of 2012 as
compared to the third quarter of 2011 due to a 42% decrease in gas
prices, a 22% decrease in NGL prices, a 10% decrease in oil prices,
and a 22% decrease in production related to property dispositions,
natural declines in oil and gas production and lower capital
spending.
During the third quarter of 2012, oil and NGL sales represented
72% of Anderson's total oil and gas sales compared to 63% in the
third quarter of 2011. The Company has 500 bpd of fixed price oil
swaps for October 2012 and 1,000 bpd of fixed price oil swaps for
November and December 2012.
The Company's operating netback was $20.54 per BOE in the third
quarter of 2012 compared to $26.10 per BOE in the third quarter of
2011. Anderson's netback for its Cardium horizontal properties in
the third quarter of 2012 was approximately $43.29 per BOE
(exclusive of hedging).
Average
wellhead Average
natural oil and Operating Funds from
gas price NGL price Revenue netback operations
($/Mcf) ($/bbl) ($/BOE) ($/BOE) ($/BOE)
2010 3.96 63.24 31.31 17.44 13.22
2011 3.60 86.53 42.13 25.89 19.40
First quarter of 2012 2.01 82.90 38.28 23.62 16.12
Second quarter of 2012 1.72 73.15 32.70 21.04 12.25
Third quarter of 2012 2.24 71.46 32.05 20.54 10.78
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The Company recorded earnings of $0.1 million in the third
quarter of 2012 primarily due to the gain recognized on asset
dispositions.
Subsequent to September 30, 2012, Anderson sold or has agreed to
sell oil and gas properties for cash consideration of approximately
$37.5 million subject to normal closing adjustments. Approximately
one-half of the dispositions closed at the end of October 2012 with
the remainder to close before the end of November 2012. The
Company's bank lines will step down to $70 million after the
closing of the dispositions. Pro forma the dispositions,
outstanding bank loans would be $51.4 million at September 30,
2012.
COMMODITY PRICES
The Company's average crude oil and natural gas liquids sales
prices in the third quarter of 2012 were $80.44 and $51.59 per
barrel respectively compared to $89.05 and $66.07 per barrel in the
third quarter of 2011. Light, sweet oil differentials between
Cushing, Oklahoma and Edmonton, Alberta were an average $7.21 per
bbl U.S. discount in the third quarter of 2012, $10.25 per bbl U.S.
discount in the second quarter of 2012, $10.53 per bbl U.S.
discount in the first quarter of 2012, compared to an average $1.46
per bbl U.S. premium as recently as the fourth quarter of 2011. In
the fourth quarter of 2012, light sweet, oil differentials are
expected to be comparable on average to the third quarter of 2012;
however, they will remain volatile in the future depending on
supply, transportation alternatives and refining demand.
The Company's average natural gas sales price was $2.24 per Mcf
in the third quarter of 2012 compared to $3.85 per Mcf in the third
quarter of 2011. The AECO average daily spot natural gas price in
April 2012 of $1.58 per GJ reached lows not seen in western Canada
since 1996. The AECO average daily spot natural gas price has since
increased to an average of $2.94 per GJ in October 2012.
The Company's average NGL price was $51.59 per barrel in the
third quarter of 2012 as compared to $66.07 in the third quarter of
2011. Average propane and butane prices were significantly lower in
the third quarter of 2012 as compared to the third quarter of 2011.
NGL prices received as a ratio of oil prices have decreased since
2011. NGL prices as a percentage of oil prices received were 64% in
the third quarter of 2012 compared to 74% in the third quarter of
2011.
COMMODITY HEDGING CONTRACTS
Crude Oil. As part of its price management strategy, the Company
has fixed price swap contracts based on the NYMEX crude oil price
in Canadian dollars. Subsequent to September 30, 2012, Anderson
settled 500 bpd of these hedges for the last two months of the year
and realized a gain of $0.4 million which will be reflected in the
financial results for the fourth quarter of 2012. As of November
12, 2012, the average volumes and prices for the remaining
contracts are summarized below:
Weighted Weighted average
average volume WTI Canadian
Period (bpd) ($/bbl)
October 2012 1,500 $103.87
--------------------------------------------------------------------------
November to December 2012 1,000 $104.30
--------------------------------------------------------------------------
By comparison, WTI Canadian averaged $91.70 per bbl in the third
quarter and $88.36 per bbl in October 2012.
During the third quarter of 2012, the Company realized a gain of
$0.1 million on its physical sales contracts to sell 7,000 GJs per
day of natural gas for August and September 2012 at an average AECO
price of $2.45 per GJ, which is included in oil and gas sales.
The Company has entered into hedging contracts to protect its
balance sheet and will continue to evaluate the merits of
additional commodity hedging as part of a price management
strategy.
PRODUCTION
Production in the third quarter of 2012 was 5,770 BOED (68%
natural gas). Properties disposed of in the third and fourth
quarters of 2012 contributed approximately 1,700 BOED (75% natural
gas) of production to the third quarter of 2012. Oil and natural
gas liquids production averaged 1,850 bpd. Overall production was
lower in the third quarter of 2012 as compared to the same period
in 2011 due to natural declines in natural gas properties, the
shut-in of higher operating expense natural gas properties and
property dispositions. The Company has a relatively low and
continuously flattening base production decline rate of
approximately 20% per year. This oil and gas production is
relatively free of co-produced water which further attests to the
quality and stability of this production stream which originates
from tight, layered oil and gas reservoirs.
In response to the lowest natural gas prices of the last 16
years, the Company has approximately 700 Mcfd of natural gas
production with high operating costs shut-in. The Company is
monitoring natural gas prices to determine when these wells could
be returned to production. In addition, the Company has 3.1 MMcfd
of proved developed non-producing gas that could be brought
on-stream at various price points.
HORIZONTAL OIL PROSPECT INVENTORY
The Company's drilled and drill ready tight oil inventory suited
to horizontal exploitation is outlined below:
Cardium Prospect Area Gross Net (i)
Garrington 114 84
Willesden Green 78 57
Ferrier 23 15
Pembina 31 15
--------------------
Total Cardium inventory 246 171
Horizontal prospect inventory in other zones 87 46
--------------------
Total Cardium and other zone horizontal inventory 333 217
Oil wells drilled to November 12, 2012 73 54
--------------------
Remaining Cardium and other zone inventory, November 12,
2012 260 163
----------------------------------------------------------------------------
(i) Net is net revenue interest
Anderson has completed all of its Cardium facility construction
projects. Future wells drilled from the Cardium and much of the
other zone inventory outlined above could be simply connected to
the new Company-owned infrastructure.
FACILITIES UPDATE
The upgrade of the Garrington battery at 15-34-035-03 W5 to
accommodate trucked in oil from both owned and third party sources
is now complete. The Company receives processing fee income at this
facility which offsets a portion of the operating costs of the
facility. This 100% owned facility is strategic in mitigating
pipeline interruptions in other Cardium oil fields by trucking to
this facility which is connected to the Rangeland pipeline
system.
RESERVES
GLJ, an independent reserves evaluator, has completed an interim
reserves report of all of the Company's oil and natural gas
properties effective October 1, 2012, prepared in accordance with
procedures and standards contained in the Canadian Oil and Gas
Evaluation ("COGE") Handbook. This reserves report was completed
for the Company's bank syndicate and includes properties sold in
the fourth quarter of 2012. This is not a year end reserves report.
GLJ will update this report for fourth quarter activities with an
appropriate January 2013 price forecast for year end reserves
reporting. The reserves definitions used in preparing the interim
report are those contained in the COGE Handbook and the Canadian
Securities Administrators National Instrument 51-101. As of October
1, 2012, the Company has 14.5 MMBOE total proved (32% oil and NGL)
and 25.3 MMBOE proved plus probable (35% oil and NGL) reserves. The
price forecast used in the evaluation is shown in Management's
Discussion and Analysis for the three and nine months ended
September 30, 2012.
PROPERTY DISPOSITIONS
Since September 30, 2012, Anderson has sold or agreed to sell
approximately 1,560 BOED of production (75% natural gas) for cash
consideration of $37.5 million subject to normal closing
adjustments. Since January 1, 2012, the Company has sold or agreed
to sell interests in 17 properties for total consideration of $74
million (subject to normal course closing adjustments). Total
production sold or agreed to be sold was approximately 2,292 BOED
(71% natural gas) and includes 54 BOED of dry gas swapped in
exchange for additional interests in Cardium drillable lands at
Garrington. Anderson has sold almost its entire position in W4M,
exited the outside operated coal bed methane business and remains
focused exclusively on its W5M assets. Anderson has retained its
position in both the large, well established Cardium light oil play
and the emerging Second White Specs light oil play.
STRATEGY AND OUTLOOK
Subject to the outcome of the strategic alternatives process
described below, the Company continues to focus on converting its
core central Alberta asset base to be more than 50% oil and NGL
production. Since the first quarter of 2012, the Company has been
focused on the divestiture of primarily non-strategic gas-weighted
properties to help achieve this goal, as well as to reduce bank
debt. The level of capital expenditures in the fourth quarter of
2012 will be commensurate with corporate cash flow projections, the
extent of property dispositions and available bank lines. The
Company has resumed drilling in the fourth quarter with one well
drilled to date since September 30, 2012.
Anderson is encouraged that natural gas pricing has recently
strengthened in response to a reduction in North American gas
directed drilling activity, as well as a warmer than normal summer
in the United States resulting in higher electrical generation
demand. Normal winter temperatures in 2012/2013 could help to
strengthen natural gas pricing, however, this could be offset by an
increase in industry drilling activity. Oil prices continue to
fluctuate according to the level of the geopolitical premium on top
of fundamental supply and demand considerations. The Company
benefits from being almost fully hedged for crude oil for the
balance of 2012. As part of the Company's risk management policy,
both oil and gas hedging opportunities are continuously
evaluated.
The Company previously filed a Form 15 with the U.S. Securities
and Exchange Commission (the "SEC") to temporarily suspend the
Company's SEC reporting obligations, and now intends to file a Form
15F with the SEC to terminate those obligations. The Company
continues to be listed on the Toronto Stock Exchange.
STRATEGIC ALTERNATIVES
As previously announced, the Board of Directors is conducting a
process to identify, examine and consider a range of strategic
alternatives available to the Company with a view to enhancing
shareholder value. The strategic alternatives considered may
include, but are not limited to, a sale of all or a material
portion of the assets of Anderson, either in one transaction or in
a series of transactions, the outright sale of the Company, or a
merger or other strategic transaction involving Anderson and a
third party. The Board of Directors believes that the Company's
shares trade at a significant discount to the value of the
underlying assets, especially given its high quality oil production
base, prospective horizontal oil drilling inventory and significant
tax pools. The Board of Directors has established a special
committee comprised of independent directors of the Company to
oversee this process and has retained BMO Capital Markets and RBC
Capital Markets as its financial advisors to assist the Special
Committee and the Board of Directors with the process. The process
was not initiated as a result of any particular offer.
Since January 1, 2012, the Company has sold or has agreed to
sell approximately $74 million of oil and gas properties. It is
Anderson's current intention to not disclose developments with
respect to its strategic alternatives process unless and until the
Board of Directors has approved a specific transaction or otherwise
determines that disclosure is necessary in accordance with
applicable law. The Company cautions that there are no assurances
or guarantees that the process will result in a transaction or, if
a transaction is undertaken, the terms or timing of such a
transaction. The Company has not set a definitive schedule to
complete its evaluation.
CORPORATE OFFICE MOVE
The Company is moving its corporate office effective November
26, 2012 to 2200, 333 - 7th Avenue SW, Calgary, Alberta, T2P
2Z1.
Brian H. Dau, President & Chief Executive Officer
November 13, 2012
Management's Discussion and Analysis
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2012 AND
2011
The following management's discussion and analysis ("MD&A")
is dated November 12, 2012 and should be read in conjunction with
the unaudited condensed interim consolidated financial statements
of Anderson Energy Ltd. ("Anderson" or the "Company") for the three
and nine months ended September 30, 2012 and the audited
consolidated financial statements and management's discussion and
analysis of Anderson for the years ended December 31, 2011 and
2010.
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
decommissioning 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 sales plus realized gains/losses on
derivative contracts less royalties, operating expenses and
transportation expenses and is a measure of the profitability of
operations before administrative, financing, depletion and
depreciation expenses. Production volumes and reserves are commonly
expressed on a BOE basis whereby natural gas volumes are converted
at the ratio of six thousand cubic feet to one barrel of oil.
Although the intention is to sum oil and natural gas measurement
units into one basis for improved analysis of results and
comparisons with other industry participants, BOE's 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. In recent years, the
value ratio based on the price of crude oil as compared to natural
gas has been significantly higher than the energy equivalency of
6:1 and utilizing a conversion of natural gas volumes on a 6:1
basis may be misleading as an indication of value. These terms are
not defined by International Financial Reporting Standards ("IFRS")
and therefore are referred to as non-GAAP measures.
All references to dollar values are to Canadian dollars unless
otherwise stated. Production volumes are measured upon sale unless
otherwise noted. Definitions of the abbreviations used in this
discussion and analysis are located on the last page of this
document.
REVIEW OF FINANCIAL RESULTS
Overview. Anderson has made significant improvements to its
statement of financial position during 2012. Proceeds from the
disposition of properties have been used to pay down bank loans,
reduce the working capital deficiency and fund a modest level of
capital spending. However, the dispositions have contributed to
lower production volumes and related cash flows from operations.
The natural declines of oil and gas production, shut-ins of
uneconomic gas production, lower capital spending during 2012 and
comparatively lower commodity prices have also impacted operating
and financial results for the three and nine months ended September
30, 2012 compared to the same periods ended in 2011.
Bank loans plus cash working capital deficiency decreased from
$132.7 million since December 31, 2011 to $97.0 million at
September 30, 2012. As previously disclosed, Anderson has entered
into agreements to sell additional properties for cash
consideration of $37.5 million (subject to normal course closing
adjustments). Approximately one-half of these dispositions have now
closed and the remainder is scheduled to close before the end of
November 2012, at which point the Company's bank lines will step
down to $70 million from $98 million at September 30, 2012. Pro
forma the close of these transactions, outstanding bank loans at
September 30, 2012 would be $51.4 million (bank loans and working
capital deficiency - $59.5 million.)
Funds from operations of $5.7 million for the third quarter of
2012 were 55% lower than the third quarter of 2011 as a result of
the substantial drop in natural gas prices (42% decrease), declines
in oil prices (10% decrease) and overall lower production volumes
(22% decrease). Funds from operations for the third quarter of 2012
were $1.9 million lower than the second quarter of 2012 primarily
due to reduced production volumes (15% decrease).
The Company did not drill any new wells in the third
quarter.
Revenue and Production. During the nine months ended September
30, 2012, Anderson sold interests in 13 properties for total
consideration of $36.9 million. Total production sold was
approximately 678 BOED (59% natural gas), and is considered by the
Company to be non-strategic. The Company has swapped an additional
54 BOED of dry gas in exchange for additional interests in Cardium
drillable lands at Garrington. During the third quarter of 2012,
Anderson sold approximately 428 BOED (51% natural gas) for cash
consideration of $30.7 million.
Subsequent to September 30, 2012, Anderson has sold or agreed to
sell an additional 1,560 BOED of production (75% natural gas) for
cash consideration of $37.5 million (subject to normal closing
adjustments). Since January 1, 2012, the Company has sold or agreed
to sell interests in 17 properties for total consideration of $74
million (subject to normal course closing adjustments). Total
production sold or agreed to be sold was approximately 2,292 BOED
(71% natural gas) and includes 54 BOED of dry gas swapped in
exchange for additional interests in Cardium drillable lands at
Garrington.
Oil and natural gas liquids, which have higher sales prices and
operating netbacks than natural gas, continue to take a larger role
in the Company's sales mix. Oil and natural gas liquids represented
72% of oil and gas sales in the third quarter of 2012, down from
79% in the second quarter of 2012 and up 9% from the third quarter
of 2011. For the nine months ended September 30, 2012, oil and
natural gas liquids represented 77% of oil and gas sales compared
to 62% in the comparable period in 2011.
Oil production for the third quarter of 2012 averaged 1,274 bpd
compared to 1,669 bpd in the second quarter of 2012 and 1,709 bpd
for the third quarter of 2011. The decrease in volumes from the
second quarter of 2012 is due to property dispositions in the
quarter and natural production declines as no new wells have been
drilled since the first quarter of 2012. For the first nine months
of 2012, oil sales averaged 1,632 bpd compared to 1,615 bpd in the
comparable period of 2011. The higher oil production in 2012
compared to 2011 is the result of Anderson's focus on Cardium oil
development.
The Company suspended its shallow gas drilling program after the
first quarter of 2010 because of low natural gas prices.
Accordingly, natural production declines have not been replaced,
resulting in decreases in gas sales throughout 2011 and 2012. In
addition, as a result of the low prices, Anderson has shut-in
approximately 700 Mcfd of natural gas production with high
operating costs and has sold some non-strategic assets. Gas sales
volumes continued to decline in the third quarter of 2012 to 23.5
MMcfd from 26.4 MMcfd in the second quarter of 2012. Gas sales
volumes for the nine months ended September 30, 2012 were 25.8
MMcfd compared to 32.0 MMcfd for the same period of 2011.
Natural gas liquids sales for the three months ended September
30, 2012 averaged 576 bpd compared to 750 bpd in the second quarter
of 2012 and 636 bpd for the third quarter of 2011. For the nine
months ended September 30, 2012, natural gas liquids sales averaged
676 bpd compared to 667 bpd in the first nine months of 2011.
The following tables outline oil and natural gas sales, volumes
and average sales prices for the three and nine month periods ended
September 30, 2012 and 2011.
OIL AND NATURAL GAS SALES
Three months ended Nine months ended
September 30 September 30
(thousands of dollars) 2012 2011 2012 2011
Natural gas $4,707 $9,834 $13,869 $31,788
Gain on fixed price natural gas
contracts 136 818 136 818
Oil(1) 9,432 14,002 37,568 40,377
NGL 2,733 3,863 10,754 12,517
Royalty and other 5 (4) 205 165
----------------------------------------
Total oil and gas sales(1) $17,013 $28,513 $62,532 $85,665
----------------------------------------------------------------------------
(1) The three months ended September 30, 2012 excludes the realized gain and
unrealized gain (loss) on derivative contracts of $1.7 million and
($2.7) million respectively (September 30, 2011 - $0.9 million and $6.4
million respectively). The nine months ended September 30, 2012 excludes
the realized gain (loss) and unrealized gain on derivative contracts of
$3.2 million and $0.3 million respectively (September 30, 2011 - ($0.4)
million and $11.2 million respectively).
PRODUCTION
Three months ended Nine months ended
September 30 September 30
2012 2011 2012 2011
Natural gas (Mcfd) 23,519 30,038 25,799 31,972
Oil (bpd) 1,274 1,709 1,632 1,615
NGL (bpd) 576 636 676 667
----------------------------------------
Total (BOED) 5,770 7,351 6,607 7,610
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PRICES
Three months ended Nine months ended
September 30 September 30
2012 2011 2012 2011
Natural gas ($/Mcf) $2.24 $3.85 $1.98 $3.74
Oil ($/bbl)(1) 80.44 89.05 84.03 91.59
NGL ($/bbl) 51.59 66.07 58.06 68.76
----------------------------------------
Total ($/BOE)(1)(2) $32.05 $42.16 $34.54 $41.23
----------------------------------------------------------------------------
(1) Excludes realized and unrealized gains and losses on derivative
contracts.
(2) Includes royalty and other income classified with oil and gas sales.
World and North American benchmark prices for oil remain
volatile and as described below, the Company has entered into
certain derivative contracts to partially hedge oil prices.
Differentials between WTI oil prices and prices received in Alberta
are affected by factors including refining demand and pipeline
capacity. Light, sweet oil differentials between Cushing, Oklahoma
and Edmonton, Alberta were an average $7.21 per bbl U.S. discount
in the third quarter of 2012, $10.25 per bbl U.S. in the second
quarter of 2012 and $10.53 per bbl U.S. discount in the first
quarter of 2012, compared to an average $1.46 per bbl U.S. premium
as recently as the fourth quarter of 2011. In the fourth quarter of
2012, light sweet, oil differentials are expected to be comparable
on average to the third quarter of 2012 and may remain volatile in
the future depending on supply, transportation alternatives and
refining demand.
Natural gas prices were low throughout 2011. Market conditions,
including high supply and low demand due to a warm winter in North
America, resulted in another step change reduction in natural gas
prices during the first six months of 2012. However, the increased
demand for natural gas for electrical power generation during the
hot summer throughout North America has contributed to some recent
price gains.
For the three months ended September 30, 2012, the above noted
oil prices do not include a realized gain on derivative contracts
of $1.7 million (September 30, 2011 - $0.9 million). The realized
oil price including the realized gains was $94.76 per barrel for
the third quarter of 2012 compared to $94.58 per barrel for the
third quarter of 2011. For the nine months ended September 30,
2012, the above noted oil prices do not include a realized gain on
derivative contracts of $3.2 million (September 30, 2011 - $0.4
million loss). The realized oil price including realized gains
(losses) was $91.18 per barrel for the first nine months of 2012
compared to $90.79 per barrel for the first nine months of
2011.
The Company's average natural gas sales price was $2.24 per Mcf
for the three months ended September 30, 2012, 30% higher than the
second quarter of 2012 price of $1.72 per Mcf and 42% lower than
the third quarter of 2011 price of $3.85 per Mcf. For the nine
months ended September 30, 2012, the Company's average natural gas
sales price was $1.98 per Mcf compared to $3.74 per Mcf for the
first nine months of 2011. The natural gas price in the third
quarter of 2012 includes a gain of $0.1 million on the Company's
fixed price natural gas contracts, compared to a gain of $0.8
million in the third quarter of 2011. The third quarter gas price
before the gain was an average of $2.18 per Mcf compared to $3.56
per Mcf in the third quarter of 2011
Commodity Contracts. At September 30, 2012, the following
derivative contracts were outstanding and recorded at estimated
fair value:
Weighted Weighted average
average volume WTI Canadian
Period (bpd) ($/bbl)
October 1, 2012 to December 31, 2012 1,500 103.87
----------------------------------------------------------------------------
In October 2012, 500 bpd of derivative contracts for the months
of November and December 2012 were settled for a gain of $0.4
million which will be reflected in the financial results for the
fourth quarter of 2012.
By comparison, WTI Canadian averaged $103.04 per bbl in the
first quarter of 2012, $94.29 per bbl in the second quarter of
2012, $91.70 per bbl in the third quarter and $88.36 per bbl in
October 2012.
Derivative contracts had the following impact on the
consolidated statements of operations and comprehensive loss for
the three and nine months ended September 30, 2012 and 2011:
Three months ended Nine months ended
September 30 September 30
(thousands of dollars) 2012 2011 2012 2011
Realized gain (loss) on
derivative contracts $ 1,680 $ 871 $ 3,198 $ (353)
Unrealized gain (loss) on
derivative contracts (2,656) 6,350 347 11,166
------------------------------------------
$ (976) $ 7,221 $ 3,545 $ 10,813
---------------------------------------------------------------------------
Fixed Price Contracts. The Company entered into physical
contracts to sell 7,000 GJs per day of natural gas for August and
September 2012 at an average AECO price of $2.45 per GJ. The
Company realized a gain on fixed price natural gas contracts of
$0.1 million for the three and nine months ended September 30, 2012
as compared to a gain of $0.8 million for the three and nine months
ended September 30, 2011.
Royalties. For the third quarter of 2012, the average royalty
rate was 10.2% of oil and gas sales compared to 10.0% in the second
quarter of 2012 and 12.4% in the third quarter of 2011. For the
first nine months of 2012, the average royalty rate was 10.4% of
revenue compared to 11.2% in the first nine months of 2011. Royalty
rates quarter over quarter have declined slightly as a result of
lower commodity prices.
Royalties as a percentage of total oil and gas sales are highly
sensitive to prices and adjustments to gas cost allowance and so
royalty rates can fluctuate from quarter to quarter.
Three months ended Nine months ended
September 30 September 30
2012 2011 2012 2011
Gross Crown royalties 7.0% 10.3% 8.3% 9.6%
Gas cost allowance (2.5%) (5.5%) (3.9%) (5.3%)
Other royalties 5.7% 7.6% 6.0% 6.9%
--------------------------------------------
Total royalties 10.2% 12.4% 10.4% 11.2%
Royalties ($/BOE) $ 3.26 $ 5.24 $ 3.60 $ 4.64
----------------------------------------------------------------------------
Operating Expenses. Operating expenses were $11.28 per BOE for
the three months ended September 30, 2012 compared to $10.06 per
BOE in the second quarter of 2012 and $11.22 per BOE in the third
quarter of 2011. Operating expenses were $10.62 per BOE for the
nine months ended September 30, 2012 compared to $11.30 per BOE in
same period in 2011. The decrease in operating expenses for the
nine months ended September 30, 2012 relative to the comparable
periods in 2011 is due to the completion of infrastructure built
for new wells drilled throughout 2011 and early 2012, resulting in
more efficient operations and lower costs. The impact of the lower
costs from this infrastructure was partially offset during the
third quarter of 2012 with the sale of assets and related
processing revenues that were netted from operating expenses.
Transportation Expenses. For the three months ended September
30, 2012, transportation expenses were $0.13 per BOE compared $0.89
per BOE in the third quarter of 2011. For the nine months ended
September 30, 2012, transportation expenses were $0.25 per BOE
compared to $0.63 per BOE for the same period in 2011. The decrease
in transportation expenses in 2012 relative to 2011 is due to the
direct tie-in of the Garrington battery to a newly constructed
lateral pipeline in late October 2011, thereby replacing clean oil
trucking charges with a pipeline tariff, which is netted from the
Company's oil sales price.
OPERATING NETBACK
Three months ended Nine months ended
September 30 September 30
(thousands of dollars) 2012 2011 2012 2011
Revenue (1) $ 17,013 $ 28,513 $ 62,532 $ 85,665
Realized gain (loss) on
derivative contracts 1,680 871 3,198 (353)
Royalties (1,729) (3,543) (6,513) (9,636)
Operating expenses (5,985) (7,590) (19,223) (23,473)
Transportation expenses (69) (602) (459) (1,304)
-------------------------------------------
Operating netback $ 10,910 $ 17,649 $ 39,535 $ 50,899
-------------------------------------------------------------------------
Sales (MBOE) 530.9 676.3 1,810.4 2,077.6
Per BOE
Revenue (1) $ 32.05 $ 42.16 $ 34.54 $ 41.23
Realized gain (loss) on
derivative contracts 3.16 1.29 1.77 (0.17)
Royalties (3.26) (5.24) (3.60) (4.64)
Operating expenses (11.28) (11.22) (10.62) (11.30)
Transportation expenses (0.13) (0.89) (0.25) (0.63)
-------------------------------------------
Operating netback per BOE $ 20.54 $ 26.10 $ 21.84 $ 24.49
-------------------------------------------------------------------------
(1) Includes royalty and other income classified with oil and gas sales. The
three months ended September 30, 2012 excludes the unrealized gain
(loss) on derivative contracts of ($2.7) million (September 30, 2011 -
$6.4 million). The nine months ended September 30, 2012 excludes the
unrealized gain on derivative contracts of $0.3 million (September 30,
2011 - $11.2 million).
Depletion and Depreciation. Depletion and depreciation was $10.1
million ($19.01 per BOE) for the third quarter of 2012 compared to
$12.3 million ($19.77 per BOE) in the second quarter of 2012 and
$12.3 million ($18.16 per BOE) in the third quarter of 2011.
Depletion and depreciation expense for the third quarter of 2012 is
lower compared to the same period of 2011 due to lower overall
production volumes, whereas the depletion and depreciation rate per
BOE is higher in 2012 due to the higher capital costs associated
with the 2011 and 2012 capital programs.
Impairment Loss (Reversal). In the third quarter of 2012, an
impairment test was performed on the Company's CGU's and management
concluded that no impairment existed at September 30, 2012.
In the second quarter of 2012, declines in forecasted natural
gas commodity prices and the ongoing strategic alternatives process
were indicators of impairment for certain CGUs. Forecasted natural
gas commodity prices at June 30, 2012 declined between eight and 18
per cent when compared to December 31, 2011. Accordingly, the
Company tested its gas-weighted CGUs for impairment and determined
that the aggregate carrying value of these CGUs was $20 million
higher than the recoverable amount and impairments were
recorded.
At September 30, 2011, there were significant changes in the
future commodity price forecasts used by the Company's independent
qualified reserves evaluators when compared to December 31, 2010.
The Company considered the downward price adjustments on natural
gas to be an indicator of impairment for the Company's Shallow Gas
and Non-Core CGUs. Similarly, the Company considered the upward
price adjustments on natural gas liquids to be an indicator of
impairment reversal for its Deep Gas CGU as a result of this CGU
having a significant amount of natural gas liquids. All of the
Company's oil and gas reserves were evaluated and reported on by
independent qualified reserves evaluators at October 1, 2011. Based
on this assessment, the Company determined that $9.7 million of
previous impairments were reversed from its Deep Gas CGU and its
Shallow Gas and Non-Core CGUs were impaired by $3.2 million and
$5.4 million respectively.
General and Administrative Expenses. General and administrative
expenses excluding stock-based compensation were $2.1 million
($3.88 per BOE) for the third quarter of 2012 compared to $2.4
million ($3.94 per BOE) in the second quarter of 2012 and $2.6
million ($3.81 per BOE) for the third quarter of 2011. For the nine
months ended September 30, 2012, general and administrative
expenses excluding stock-based compensation were $6.7 million
($3.68 per BOE) compared to $7.2 million ($3.48 per BOE) for the
same period in 2011. The decrease in cash general and
administrative expenses is the result of lower employee
compensation associated with reduced staff and decreased audit and
tax fees as the comparative period in 2011 had higher fees
associated with the adoption of IFRS. In the fourth quarter of
2012, the Company laid off some of its staff. One time severance
costs of approximately $0.5 million will be recorded in the fourth
quarter. Beginning in December 2012, office rent is expected to
decrease by $0.1 million per month as a result of the corporate
office move.
Three months ended Nine months ended
September 30 September 30
(thousands of dollars) 2012 2011 2012 2011
General and administrative (gross) $ 3,152 $ 3,747 $ 10,110 $ 11,440
Overhead recoveries (265) (502) (973) (1,312)
Capitalized (825) (671) (2,484) (2,895)
--------------------------------------
General and administrative (cash) $ 2,062 $ 2,574 $ 6,653 $ 7,233
Net stock-based compensation 143 239 573 730
--------------------------------------
General and administrative $ 2,205 $ 2,813 $ 7,226 $ 7,963
---------------------------------------------------------------------------
General and administrative (cash)
($/BOE) $ 3.88 $ 3.81 $ 3.68 $ 3.48
% Capitalized 26% 18% 25% 25%
---------------------------------------------------------------------------
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 costs were $0.2 million in the third
quarter of 2012 ($0.1 million net of amounts capitalized) compared
to $0.4 million for the third quarter of 2011 ($0.2 million net of
amounts capitalized). For the nine months ended September 30, 2012,
stock-based compensation costs were $0.9 million ($0.6 million net
of amounts capitalized) compared to $1.2 million ($0.7 million net
of amounts capitalized) in the same period of 2011.
Finance Expenses. Finance expenses were $3.9 million in the
third quarter of 2012, compared to $3.8 million for the second
quarter of 2012 and $3.3 million in the third quarter of 2011. For
the nine months ended September 30, 2012, finance expenses were
$11.3 million compared to $8.5 million in the same period of 2011.
While the average effective interest rate on outstanding bank loans
was 4.5% for the nine months ended September 30, 2012 compared to
5.7% for the comparable period in 2011, the Company had higher
levels of bank loans outstanding during 2012, leading to the higher
finance expenses.
Three months ended Nine months ended
September 30 September 30
(thousands of dollars) 2012 2011 2012 2011
Interest and accretion on
convertible debentures $ 2,269 $ 2,233 $ 6,765 $ 4,831
Interest expense on credit
facilities and other 1,352 670 3,645 2,394
Accretion on decommissioning
obligations 242 439 879 1,295
------------------------------------------
Finance expenses $ 3,863 $ 3,342 $ 11,289 $ 8,520
---------------------------------------------------------------------------
Decommissioning Obligations. In the third quarter of 2012, the
Company disposed of $6.1 million in decommissioning obligations
related to property dispositions, and increased the decommissioning
obligations by $2.6 million primarily relating to changes in
estimates. Accretion expense was $0.2 million for the third quarter
of 2012 compared to $0.4 million in the third quarter of 2011 and
was included in finance expenses. For the nine months ended
September 30, 2012, the Company disposed of $11.1 million in
decommissioning obligations related to property dispositions, and
increased the decommissioning obligations by $3.6 million primarily
relating to changes in estimates.
The risk-free discount rates used by the Company to measure the
obligations at September 30, 2012 were between 1.0% and 2.5%
depending on the timelines to reclamation compared to 0.9% and 3.1%
at December 31, 2011.
Income Taxes. Anderson is not currently taxable. The Company
estimates that it has approximately $461 million in tax pools at
September 30, 2012.
Funds from Operations. Funds from operations for the third
quarter of 2012 were $5.7 million ($0.03 per share), down 25% from
the $7.6 million ($0.04 per share) recorded in the second quarter
of 2012 and down 55% from the $12.7 million ($0.07 per share)
recorded in the third quarter of 2011. The decrease in funds from
operations in the third quarter of 2012 compared to the second
quarter of 2012 was largely due to 15% lower production volumes
associated with property dispositions and natural production
declines. Funds from operations for the nine months ended September
30, 2012 decreased compared to 2011 for due to lower commodity
prices for natural gas (47%), oil (8%) and NGL's (16%) in the nine
months ended September 30, 2012 versus the nine months ended
September 30, 2011. Production declines in natural gas of 19% in
the nine months ended September 30, 2012 compared to September 30,
2011 due to natural production declines also contributed to lower
funds from operations in 2012.
Three months ended Nine months ended
September 30 September 30
(thousands of dollars) 2012 2011 2012 2011
Cash from operating activities $ 5,845 $ 11,893 $ 22,863 $ 37,847
Changes in non-cash working
capital (147) 701 692 (483)
Decommissioning expenditures 27 61 392 103
----------------------------------------
Funds from operations $ 5,725 $ 12,655 $ 23,947 $ 37,467
---------------------------------------------------------------------------
Earnings. The Company reported earnings of $0.1 million in the
third quarter of 2012 compared to a loss of $16.8 million for the
second quarter of 2012 and earnings of $7.5 million for the third
quarter of 2011. In the third quarter of 2012, earnings were
impacted by gains recognized on the Company asset dispositions.
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
Annual
Funds from Annual
Operations Earnings
Millions Per Share Millions Per Share
$0.50/Mcf in price of natural
gas $ 4.7 $ 0.03 $ 3.5 $ 0.02
U.S. $5.00/bbl in the WTI crude
price $ 3.3 $ 0.02 $ 2.5 $ 0.01
U.S. $0.01 in the U.S./Cdn
exchange rate $ 1.0 $ 0.01 $ 0.7 $ 0.00
1% in short-term interest rate $ 0.6 $ 0.00 $ 0.4 $ 0.00
----------------------------------------------------------------------------
This sensitivity analysis was calculated by applying different
pricing, interest rate and exchange rate assumptions to the 2011
actual results related to production, prices, royalty rates,
operating costs and capital spending. As the contribution of oil
production continues to increase as a percentage of total
production, the impact of oil prices will be more significant and
the impact of natural gas prices will be less significant to funds
from operations and earnings than is shown in the table above.
CAPITAL EXPENDITURES
Capital expenditures before dispositions were $1.7 million in
the third quarter of 2012, and proceeds on disposition were $30.7
million in the third quarter of 2012. The breakdown of expenditures
is shown below:
Three months ended Nine months ended
September 30 September 30
(thousands of dollars) 2012 2011 2012 2011
Land, geological and geophysical
costs $ 50 $ 201 $ 410 $ 3,967
Proceeds on disposition (30,710) (6,203) (36,909) (11,570)
Drilling, completion and
recompletion 262 43,700 14,350 95,260
Drilling incentive credits - (262) - (400)
Facilities and well equipment 457 11,436 7,584 28,001
Capitalized general and
administrative expenses 825 671 2,484 2,895
------------------------------------------
Total finding, development &
acquisition expenditures (29,116) 49,543 (12,081) 118,153
Change in compressor and other
inventory and equipment 131 128 (54) 128
Office equipment and furniture (1) 42 25 70
------------------------------------------
Total net cash capital
expenditures (28,986) 49,713 $ (12,110) $ 118,351
---------------------------------------------------------------------------
Drilling statistics are shown below:
Three months ended Nine months ended
September 30 September 30
2012 2011 2012 2011
Gross Net Gross Net Gross Net Gross Net
Gas - - - - - - - -
Oil - - 21 18.0 3 2.5 41 34.2
Dry - - - - - - - -
-------------------------------------------------
Total - - 21 18.0 3 2.5 41 34.2
----------------------------------------------------------------------------
Success rate (%) - - 100% 100% 100% 100% 100% 100%
----------------------------------------------------------------------------
Subsequent to September 30, 2012, Anderson entered into
agreements to sell or closed the sale of approximately 1,560 BOED
of production (75% natural gas) for cash consideration of $37.5
million (subject to normal course closing adjustments).
Approximately one-half of these dispositions have now closed and
the remainder is scheduled to close before the end of November
2012.
RESERVES
GLJ Petroleum Consultants ("GLJ"), an independent reserves
evaluator, has completed an interim reserves report of all of the
Company's oil & natural gas properties effective October 1,
2012, prepared in accordance with procedures and standards
contained in the Canadian Oil and Gas Evaluation ("COGE") Handbook.
This reserves report was completed for the Company's bank syndicate
and includes properties sold in the fourth quarter of 2012. This is
not a year end reserves report. GLJ will update this report for
fourth quarter activities with an appropriate January 2013 price
forecast for year end reserves reporting. The reserves definitions
used in preparing the interim report are those contained in the
COGE Handbook and the Canadian Securities Administrators National
Instrument 51-101. As of October 1, 2012, the Company has 14.5
MMBOE total proved ("TP") and 25.3 MMBOE total proved plus probable
("P&P") reserves.
Oil and NGL reserves represent 32% of TP and 35% of the P&P
reserves as compared to 29% and 31% respectively at December 31,
2011.
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
As at October 1, 2012
GLJ Forecast Prices and Costs
Oil Natural Gas
Light, Sweet
WTI Cushing Crude Edmonton AECO Gas Price
Year ($US/bbl) ($Cdn/bbl) ($Cdn/Mcf)
2012 Q4 92.50 90.50 2.92
2013 92.50 92.35 3.44
2014 95.00 95.92 3.90
2015 97.50 98.47 4.36
2016 100.00 101.02 4.82
2017 100.00 101.02 5.05
2018 101.35 102.40 5.43
2019 103.38 104.47 5.54
2020 105.45 106.58 5.65
2021 107.56 108.73 5.76
Thereafter 2%
----------------------------------------------------------------------------
Edmonton Liquids Prices
Pentanes Exchange
Propane Butane Plus Inflation rate
Year ($Cdn/bbl)($Cdn/bbl)($Cdn/bbl) Rate % (US$/Cdn)
2012 Q4 27.15 70.59 99.55 2.0 1.00
2013 46.17 72.03 98.81 2.0 0.98
2014 57.55 74.82 99.76 2.0 0.98
2015 59.08 76.81 102.41 2.0 0.98
2016 60.61 78.80 105.06 2.0 0.98
2017 60.61 78.80 105.06 2.0 0.98
2018 61.44 79.87 106.49 2.0 0.98
2019 62.68 81.49 108.65 2.0 0.98
2020 63.95 83.13 110.84 2.0 0.98
2021 65.24 84.81 113.08 2.0 0.98
Thereafter 2%
----------------------------------------------------------------------------
SHARE INFORMATION
The Company's shares have been listed on the Toronto Stock
Exchange since September 7, 2005 under the symbol "AXL". As of
November 12, 2012, there were 172.5 million common shares
outstanding, 15.2 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 and $46.0 million principal amount of convertible
debentures which are convertible into common shares at a conversion
price of $1.70 per common share. Approximately 0.6 million stock
options are scheduled to expire by the end of November 2012. During
the third quarter of 2012 and 2011, there were no common shares
issued under the employee stock option plan.
Three months ended Nine months ended
September 30 September 30
2012 2011 2012 2011
High $ 0.35 $ 0.87 $ 0.68 $ 1.36
Low $ 0.21 $ 0.42 $ 0.21 $ 0.42
Close $ 0.23 $ 0.43 $ 0.23 $ 0.43
Volume 8,042,349 23,739,995 32,883,171 108,708,081
Shares outstanding
at September 30 172,549,701 172,549,701 172,549,701 172,549,701
Market
capitalization at
September 30 $ 39,686,431 $ 74,196,371 $ 39,686,431 $ 74,196,371
----------------------------------------------------------------------------
The statistics above include trading on the Toronto Stock
Exchange only. Shares also trade on alternative platforms like
Alpha, Chi-X, Pure and Omega. During the three months and nine
months ended September 30, 2012 approximately 4.8 million and 15.3
million common shares traded on these alternative exchanges
respectively. Including these exchanges, an average of 0.2 million
common shares traded per day in the third quarter of 2012
(September 30, 2011 - 0.6 million), representing a quarterly
turnover ratio of 7% (September 30, 2011 - 20%).
The Company previously filed a Form 15 with the U.S. Securities
and Exchange Commission (the "SEC") to temporarily suspend the
Company's SEC reporting obligations, and now intends to file a Form
15F with the SEC to terminate those obligations. The Company
continues to be listed on the Toronto Stock Exchange.
LIQUIDITY AND CAPITAL RESOURCES
At September 30, 2012, the Company had outstanding bank loans of
$88.9 million, convertible debentures of $96.0 million (principal)
and a cash working capital deficiency (excluding unrealized gain on
derivative contracts) of $8.1 million. The working capital
deficiency includes $1.5 million of interest on convertible
debentures which is paid semi-annually, with the next payment due
at the end of December 2012. The following table shows the changes
in bank loans plus cash working capital deficiency:
Three months ended Nine months ended
September 30 September 30
(thousands of dollars) 2012 2011 2012 2011
Bank loans plus cash working
capital deficiency,
beginning of period $ (131,675) $ (71,464) $ (132,656) $ (71,507)
Funds from operations 5,725 12,655 23,947 37,467
Net cash capital
(expenditures) proceeds 28,986 (49,713) 12,110 (118,351)
Proceeds from issue of
convertible debentures, net
of issue costs - - - 43,860
Proceeds from exercise of
stock options - - - 51
Decommissioning expenditures (27) (61) (392) (103)
---------------------------------------------
Bank loans plus cash working
capital deficiency, end of
period $ (96,991) $ (108,583) $ (96,991) $ (108,583)
---------------------------------------------------------------------------
Successful future operations of the Company are dependent on the
ability of the Company to secure sufficient funds through
operations, the proceeds from the disposition of non-strategic
assets or other sources from the strategic alternatives process.
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. The Company is funding its 2012
capital program from a combination of cash flow and the proceeds
from the sale of non-strategic assets. The Company has actively
pursued the sale of its non-strategic assets. The extent of the
capital program in the fourth quarter will be dependent on the
property disposition program, oil and natural gas prices and
available credit facilities.
Subsequent to September 30, 2012, Anderson sold or agreed to
sell oil and gas properties for cash consideration of $37.5
million, subject to normal course closing adjustments. Pro forma
the dispositions, bank loans would be $51.4 million and bank loan
plus working capital deficiency would be $59.5 million at September
30, 2012.
At September 30, 2012, the Company had total credit facilities
of $98 million, consisting of an $88 million revolving term credit
facility and a $10 million working capital credit facility with a
syndicate of Canadian banks. Upon completion of the previously
disclosed disposition transactions that are scheduled to close by
the end of November 2012, the Company's bank lines will step down
to $70 million. If not extended, the revolving term credit facility
and working capital credit facility cease to revolve and all
outstanding advances become repayable on July 10, 2013. Advances
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. These margins vary from 3% to 4%
depending on the borrowing option used. At September 30, 2012, no
amounts were drawn in U.S. funds.
The available lending limits of the facilities are scheduled to
be reviewed on or before December 15, 2012 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 as a result of future dispositions, changes in reserve
values, future commodity prices or at the next scheduled
review.
OFF BALANCE SHEET ARRANGEMENTS
The Company had no guarantees or off balance sheet arrangements
other than as described below under "Contractual Obligations".
CONTRACTUAL OBLIGATIONS
The Company enters into various contractual obligations in the
course of conducting its operations. The obligations noted below
are updates as at September 30, 2012 to the obligations disclosed
in the management's discussion and analysis of Anderson for the
years ended December 31, 2011 and 2010 and should be read in
conjunction with that document:
-- Loan agreements - The reserves-based revolving term credit facility and
working capital credit facility have a maturity date of July 10, 2013.
If not renewed, all outstanding advances thereunder become repayable on
July 10, 2013.
-- Firm service transportation commitments - The Company has entered into
firm service transportation agreements for approximately 15 million
cubic feet per day of gas sales for various terms expiring between 2012
and 2020.
-- Cardium Horizontal Well Program (Oil) - The Company has farm-in
obligations to drill four gross (3.9 net capital) horizontal wells in
the Cardium geological formation prior to the end of 2012. One agreement
has a $100,000 non-performance fee clause should the Company fail to
drill the well. Another agreement pertains to two wells; there is a
$35,000 non-performance fee should the Company fail to drill both wells,
and if only one well is drilled, the Company would also forfeit fifty
per cent of the interest in the first well drilled under the agreement;
in a second agreement pertaining to one of these wells, there is also a
$25,000 non-performance fee should the Company fail to drill the well.
In a third agreement, there is a $200,000 non-performance fee should the
Company fail to drill the well. One gross (1 net capital) well has been
drilled subsequent to September 30, 2012.
-- New head office lease - Subsequent to September 30, 2012, the Company
entered into an agreement to lease office space at a rate of
approximately $560,000 per year starting December 1, 2012 and ending
June 30, 2014.
There are no material changes to other commitments and
contingencies from those disclosed in the Company's annual
Management's Discussion and Analysis for the years ended December
31, 2011 and 2010.
CONTROLS AND PROCEDURES
The Chief Executive Officer ("CEO") and the Chief Financial
Officer ("CFO") have designed, or caused to be designed under their
supervision, disclosure controls and procedures ("DC&P") and
internal controls over financial reporting ("ICOFR") as defined in
National Instrument 52-109 Certification of Disclosure in Issuer's
Annual and Interim Filings in order to provide reasonable assurance
regarding the reliability of financial reporting and the
preparation of the financial statements for external purposes in
accordance with IFRS.
The DC&P have been designed to provide reasonable assurance
that material information relating to the Company is made known to
the CEO and CFO by others and that information required to be
disclosed by the Company in its annual filings, interim filings or
other reports filed or submitted by the Company under securities
legislation is recorded, processed, summarized and reported within
the time periods specified in securities legislation. The Company's
CEO and CFO have concluded, based on their evaluation as of the end
of the period covered by the interim filings, that the Company's
disclosure controls and procedures are effective to provide
reasonable assurance that material information related to the
issuer is made known to them by others within the Company.
The CEO and CFO are required to cause the Company to disclose
any change in the Company's ICOFR that occurred during the most
recent interim period that has materially affected, or is
reasonably likely to materially affect, the Company's ICOFR. No
changes in ICOFR were identified during such period that have
materially affected or are reasonably likely to materially affect
the Company's ICOFR.
It should be noted a control system, including the Company's
DC&P and ICOFR, no matter how well conceived or operated, can
provide only reasonable, not absolute, assurance that the objective
of the control system will be met and it should not be expected
that DC&P and ICOFR will prevent all errors or fraud.
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 continue to remain volatile as they are a
geopolitical commodity, affected by concerns about economic markets
in the U.S. and Europe and continued instability in oil producing
countries. Differentials between WTI oil prices and prices received
in Alberta have widened and also remain volatile. 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 most recent Annual Information Form
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 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 seeks out and employs new
technologies where possible. With the Company's extensive drilling
inventory and advance planning, the Company believes it 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.
BUSINESS PROSPECTS
The Company believes it has an excellent future drilling
inventory in the Cardium horizontal light oil play and is focused
on growing its production and reserves with Cardium horizontal
drilling. The Company has identified an inventory of 333 gross (217
net revenue) drill-ready Cardium and other horizontal zone oil
locations, of which 73 gross (54 net revenue) have been drilled to
November 12, 2012. Historically, the Company has added 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.
STRATEGY
Subject to the outcome of the strategic alternatives process
described below, the Company continues to focus on converting its
asset base to be more than 50% oil and NGL production.
Anderson has a substantial Cardium drilling inventory and with
the completion of infrastructure projects in the last year, newly
drilled Cardium horizontal wells can be easily connected to these
gathering systems.
In response to low natural gas prices, the Company has
approximately 700 Mcfd of natural gas production with high
operating costs shut-in. In a higher price environment, these
natural gas wells could easily be returned to production. In
addition, the Company has 3.1 MMcfd of proved developed
non-producing gas that could be brought on-stream at various price
points.
Commodity prices are volatile and Anderson continues to look at
hedging opportunities to help protect its capital program and its
shareholders from volatile markets.
STRATEGIC ALTERNATIVES
As previously announced, in response to the lack of market
recognition of the inherent value in the Company's asset base, the
Company's board of directors (the "Board of Directors") is
conducting a process to identify, examine and consider a range of
strategic alternatives with a view to enhancing shareholder value.
The strategic alternatives considered may include, but are not
limited to, a sale of all or a material portion of the assets of
Anderson, either in one transaction or in a series of transactions,
the outright sale of the Company, or a merger or other strategic
transaction involving Anderson and a third party. The Board of
Directors believes that the Company's shares trade at a significant
discount to the value of the underlying assets, especially given
its high quality Cardium oil production base, prospective Cardium
horizontal oil drilling inventory and significant tax pools. The
Board of Directors has established a special committee comprised of
independent directors of the Company to oversee this process and
has retained financial advisors to assist the Special Committee and
the Board of Directors with the process. This process has not been
initiated as a result of any particular offer.
Since January 1, 2012, Anderson has sold or agreed to sell
interests in 17 properties for total consideration of approximately
$74 million (subject to normal closing adjustments). Total
production sold or agreed to be sold was 2,292 BOED (71% natural
gas), including 54 BOED of dry gas swapped in exchange for
additional interests in Cardium drillable lands at Garrington, and
is considered by the Company to be non-strategic. Anderson has sold
almost its entire position in W4M, exited the outside operated coal
bed methane business and remains focused exclusively on its W5M
assets. The Company has additional non-strategic assets which it is
currently marketing to improve its financial flexibility and to
focus its resources on its core oil assets.
It is Anderson's current intention to not disclose developments
with respect to its strategic alternatives process unless and until
the Board of Directors has approved a specific transaction or
otherwise determines that disclosure is necessary in accordance
with applicable law. The Company cautions that there are no
assurances or guarantees that the process will result in a
transaction or, if a transaction is undertaken, the terms or timing
of such a transaction. The Company has not set a definitive
schedule to complete its evaluation.
On April 1, 2012, the Company implemented a retention plan for
its employees as part of this process, which was updated in October
2012 in conjunction with the lay-off of some of its staff.
QUARTERLY INFORMATION
The following table provides financial and operating results for
the last eight quarters. Commodity prices remain volatile,
affecting funds from operations and earnings throughout those
quarters. In 2010, the Company changed its focus to oil projects in
light of the continued depressed natural gas market, and suspended
its shallow gas drilling program until natural gas prices improve.
Revenues, funds from operations and earnings (loss) over the past
year reflect the benefits from increased sales of crude oil
volumes. Since 2010, earnings have been affected by impairments in
the value of property, plant and equipment related to natural gas
reserves values. As discussed above, revenues and funds from
operations in the third quarter of 2012 were affected by lower
natural gas prices, larger differentials between WTI and Alberta
oil prices and lower production volumes. The disposition of
properties has reduced the volumes, revenues and operating costs
during the second and third quarters of 2012.
SELECTED QUARTERLY INFORMATION
($ amounts in thousands, except per share amounts and
prices)
------------------------------------------
Q3 2012 Q2 2012 Q1 2012 Q4 2011
------------------------------------------
Revenue, net of royalties $ 15,284 $ 18,290 $ 22,445 $ 28,457
Funds from operations $ 5,725 $ 7,606 $ 10,616 $ 16,997
Funds from operations per share,
basic and diluted $ 0.03 $ 0.04 $ 0.06 $ 0.10
Earnings (loss) before effect of
impairments $ 94 $ (1,828) $ (5,864) $ (4,939)
Earnings (loss) per share before
effect of impairments basic and
diluted $ - $ (0.01) $ (0.03) $ (0.03)
Earnings (loss) $ 94 $ (16,828) $ (5,864) $ (32,167)
Earnings (loss) per share, basic
and diluted $ - $ (0.10) $ (0.03) $ (0.19)
Capital expenditures, including
acquisitions net of (proceeds)
on dispositions $ (28,986) $ 4,786 $ 12,090 $ 40,924
Cash from operating activities $ 5,845 $ 7,712 $ 9,306 $ 16,462
Daily sales
Natural gas (Mcfd) 23,519 26,438 27,463 30,576
Oil (bpd) 1,274 1,669 1,956 2,122
NGL (bpd) 576 750 703 715
BOE (BOED) 5,770 6,825 7,236 7,933
Average prices
Natural gas ($/Mcf) $ 2.24 $ 1.72 $ 2.01 $ 3.20
Oil ($/bbl)(2) $ 80.44 $ 81.58 $ 88.48 $ 96.33
NGL ($/bbl) $ 51.59 $ 54.38 $ 67.36 $ 72.71
BOE ($/BOE)(1)(2) $ 32.05 $ 32.70 $ 38.28 $ 44.70
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Q3 2011 Q2 2011 Q1 2011 Q4 2010
------------------------------------------
Revenue, net of royalties $ 24,970 $ 27,776 $ 23,283 $ 21,690
Funds from operations $ 12,655 $ 13,944 $ 10,868 $ 9,282
Funds from operations per share,
basic and diluted $ 0.07 $ 0.08 $ 0.06 $ 0.05
Earnings (loss) before effect of
impairments or reversals
thereof $ 6,667 $ 5,932 $ (3,681) $ (4,864)
Earnings (loss) per share before
effect of impairments or
reversals thereof, basic and
diluted $ 0.04 $ 0.03 $ (0.02) $ (0.03)
Earnings (loss) $ 7,472 $ 5,932 $ (3,681) $ (36,545)
Earnings (loss) per share, basic
and diluted $ 0.04 $ 0.03 $ (0.02) $ (0.21)
Capital expenditures, including
acquisitions net of proceeds on
dispositions $ 49,713 $ 26,284 $ 42,354 $ 26,240
Cash from operating activities $ 11,893 $ 14,953 $ 11,001 $ 10,488
Daily sales
Natural gas (Mcfd) 30,038 31,990 33,931 38,479
Oil (bpd) 1,709 1,759 1,372 992
NGL (bpd) 636 667 699 823
BOE (BOED) 7,351 7,758 7,726 8,228
Average prices
Natural gas ($/Mcf) $ 3.85 $ 3.79 $ 3.58 $ 3.48
Oil ($/bbl)(2) $ 89.05 $ 99.39 $ 84.71 $ 77.62
NGL ($/bbl) $ 66.07 $ 74.24 $ 65.97 $ 58.87
BOE ($/BOE)(1)(2) $ 42.16 $ 44.71 $ 36.80 $ 31.63
----------------------------------------------------------------------------
(1) Includes royalty and other income classified with oil and gas sales.
(2) Excludes realized and unrealized gains (losses) on derivative contracts
as follows: Q3 2012 - $1.7 million and ($2.7) million respectively; Q2
2012 - $1.3 million and $4.7 million respectively; Q1 2012 - $0.2
million and ($1.7) million respectively; Q4 2011 - ($0.3) million and
($7.9) million respectively; Q3 2011 - $0.9 million and $6.4 million
respectively; Q2 2011 - ($0.8) million and $7.7 million respectively; Q1
2011 - ($0.4) million and ($2.8) million respectively; and Q4 2010 -
($0.1) million and ($1.9) million respectively.
FORWARD-LOOKING STATEMENTS
Certain statements in this news release including, without
limitation, management's assessment of future plans and operations;
benefits and valuation of the development prospects described
herein; number of locations in drilling inventory and wells to be
drilled; timing and location of drilling and tie-in of wells and
the costs thereof; productive capacity of the wells; timing of and
construction of facilities; expected production rates; percentage
of production from oil and natural gas liquids; dates of
commencement of production; amount of capital expenditures and the
timing and method of financing thereof; value of undeveloped land;
extent of reserves additions; ability to attain cost savings;
drilling program success; impact of changes in commodity prices on
operating results; estimates of future revenues, costs, netbacks,
funds from operations and debt levels; the expected proceeds from
disclosed asset dispositions and uses thereof, the timing of
completion of disclosed asset dispositions, potential results of
the strategic alternatives review process, including the
possibility of further asset dispositions and use of proceeds
therefrom, and enhancement of shareholder value, disclosure
intentions with respect to the strategic alternatives review
process; factors on which the successful future operations of
Anderson are dependent, commodity price outlook and general
economic outlook may constitute "forward-looking information"
(within the meaning of applicable Canadian securities legislation)
or "forward-looking statements" (within the meaning of the United
States Private Securities Litigation Reform Act of 1995, as
amended) and necessarily involve risks and assumptions made by
management of the Company including, without limitation, risks
associated with oil and gas exploration, development, exploitation,
production, marketing and transportation; loss of markets;
volatility of commodity prices; currency fluctuations; imprecision
of reserves estimates; environmental risks; competition from other
producers; inability to retain drilling rigs and other services;
adequate weather to conduct operations; sufficiency of budgeted
capital, operating and other costs to carry out planned activities;
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; inability to complete property
dispositions or to complete them at anticipated values; delays
resulting from or inability to obtain required regulatory
approvals; changes to government regulation; ability to access
sufficient capital from internal and external sources; and other
factors, many of which are beyond the Company's control.
The impact of any one risk, uncertainty or factor on a
particular forward-looking statement is not determinable with
certainty as the factors are interdependent, and management's
future course of action would depend on its assessment of all
information at the time. As a consequence, actual results may
differ materially from those anticipated in the forward-looking
statements and readers should not place undue reliance on the
assumptions and forward-looking statements. Readers are cautioned
that the foregoing list of factors is not exhaustive. Additional
information on these and other factors that could affect Anderson's
operations and financial results are included in reports on file
with Canadian securities regulatory authorities and may be accessed
through the SEDAR website (www.sedar.com) or at Anderson's website
(www.andersonenergy.ca).
The forward-looking statements contained in this news release
are made as at the date of this news release and the Company does
not undertake any obligation to update publicly or to revise any of
the included forward-looking statements, whether as a result of new
information, future events or otherwise, except as may be required
by applicable securities laws.
CONVERSION
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 Statements of Financial Position
(Stated in thousands of dollars)
(Unaudited)
September 30, December 31,
2012 2011
ASSETS
Current assets:
Cash $ - $ 1
Accounts receivable and accruals 11,038 14,272
Prepaid expenses and deposits 1,996 2,326
Unrealized gain on derivative contracts
(note 12) 1,731 1,384
----------------------------
14,765 17,983
Deferred tax asset 42,730 35,389
Property, plant and equipment (notes 3, 4) 336,366 406,947
----------------------------
$ 393,861 $ 460,319
---------------------------------------------------------------------------
---------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accruals $ 21,103 $ 60,573
Bank loans (note 5) 88,922 -
----------------------------
110,025 60,573
Bank loans (note 5) - 88,682
Convertible debentures 86,247 84,796
Decommissioning obligations (note 6) 55,838 62,848
----------------------------
252,110 296,899
Shareholders' equity:
Share capital (note 7) 171,460 171,460
Equity component of convertible debentures 5,019 5,019
Contributed surplus 10,314 9,385
Deficit (note 7) (45,042) (22,444)
----------------------------
141,751 163,420
Future operations (note 1)
Subsequent events (notes 5, 7, 12, 13, 14)
Commitments and contingencies (note 13)
----------------------------
$ 393,861 $ 460,319
---------------------------------------------------------------------------
See accompanying notes to the condensed interim consolidated financial
statements.
ANDERSON ENERGY LTD.
Consolidated Statements of Operations and Comprehensive Loss
(Stated in thousands of dollars, except per share amounts)
(Unaudited)
Three months ended Nine months ended
September 30 September 30
2012 2011 2012 2011
Oil and gas sales $ 17,013 $ 28,513 $ 62,532 $ 85,665
Royalties (1,729) (3,543) (6,513) (9,636)
-------------------------------------------
Revenue, net of royalties 15,284 24,970 56,019 76,029
Other income (note 9) 7,104 10,697 7,626 15,435
-------------------------------------------
22,388 35,667 63,645 91,464
Operating expenses 5,985 7,590 19,223 23,473
Transportation expenses 69 602 459 1,304
Depletion and depreciation 10,093 12,280 35,411 37,976
Impairment loss (reversal) (note
4) - (1,074) 20,000 (1,074)
General and administrative
expenses 2,205 2,813 7,226 7,963
-------------------------------------------
Earnings (loss) from operating
activities 4,036 13,456 (18,674) 21,822
Finance income (note 10) - 21 24 54
Finance expenses (note 10) (3,863) (3,342) (11,289) (8,520)
-------------------------------------------
Net finance expenses (3,863) (3,321) (11,265) (8,466)
Earnings (loss) before taxes 173 10,135 (29,939) 13,356
Deferred income tax expense
(benefit) 79 2,663 (7,341) 3,633
-------------------------------------------
Earnings (loss) and
comprehensive income (loss) for
the period $ 94 $ 7,472 $ (22,598)$ 9,723
----------------------------------------------------------------------------
Basic and diluted earnings
(loss) per share (note 8) $ - $ 0.04 $ (0.13)$ 0.06
----------------------------------------------------------------------------
See accompanying notes to the condensed interim consolidated financial
statements.
ANDERSON ENERGY LTD.
Consolidated Statements of Changes in Shareholders' Equity
NINE MONTHS ENDED SEPTEMBER 30, 2012 AND 2011
(Stated in thousands of dollars, except number of common shares)
(Unaudited)
Equity component
Number of common of convertible
shares Share capital debentures
Balance at January 1,
2011 172,485,301 $ 426,925 $ 2,592
Elimination of deficit
(note 7) - (255,543) -
Equity component of
convertible
debentures, net of
tax of $1.5 million - - 2,427
Share-based payments - - -
Options exercised 64,400 78 -
Earnings for the
period - - -
------------------------------------------------------
Balance at September
30, 2011 172,549,701 $ 171,460 $ 5,019
----------------------------------------------------------------------------
Balance at January 1,
2012 172,549,701 $ 171,460 $ 5,019
Share-based payments - - -
Loss for the period - - -
------------------------------------------------------
Balance at September
30, 2012 172,549,701 $ 171,460 $ 5,019
----------------------------------------------------------------------------
Retained Total
Contributed earnings shareholders'
surplus (deficit) equity
Balance at January 1,
2011 $ 7,921 $ (255,543) $ 181,895
Elimination of deficit
(note 7) - 255,543 -
Equity component of
convertible
debentures, net of
tax of $1.5 million - - 2,427
Share-based payments 1,155 - 1,155
Options exercised (27) - 51
Earnings for the
period - 9,723 9,723
------------------------------------------------------
Balance at September
30, 2011 $ 9,049 $ 9,723 $ 195,251
----------------------------------------------------------------------------
Balance at January 1,
2012 $ 9,385 $ (22,444) $ 163,420
Share-based payments 929 - 929
Loss for the period - (22,598) (22,598)
------------------------------------------------------
Balance at September
30, 2012 $ 10,314 $ (45,042) $ 141,751
----------------------------------------------------------------------------
See accompanying notes to the condensed interim consolidated financial
statements.
ANDERSON ENERGY LTD.
Consolidated Statements of Cash Flows
NINE MONTHS ENDED SEPTEMBER 30, 2012 AND 2011
(Stated in thousands of dollars)
(Unaudited)
2012 2011
CASH PROVIDED BY (USED IN)
OPERATIONS
Earning (loss) for the period $ (22,598) $ 9,723
Adjustments for:
Unrealized gain on derivative contracts
(note 9) (347) (11,166)
Gain on sale of property, plant and
equipment (note 9) (4,081) (4,622)
Depletion and depreciation 35,411 37,976
Impairment loss (reversal) (note 4) 20,000 (1,074)
Stock-based payments 573 730
Accretion on decommissioning obligations
(note 6, 10) 879 1,295
Accretion on convertible debentures (note
10) 1,451 972
Deferred income tax expense (benefit) (7,341) 3,633
Decommissioning expenditures (note 6) (392) (103)
Changes in non-cash working capital (note
11) (692) 483
------------------------------
22,863 37,847
FINANCING
Increase (decrease) in bank loans 240 (872)
Proceeds from issue of convertible
debentures, net of issue costs - 43,860
Proceeds from exercise of stock options - 51
Changes in non-cash working capital (note
11) (175) (253)
------------------------------
65 42,786
INVESTING
Property, plant and equipment expenditures (24,799) (129,921)
Proceeds from sale of property, plant and
equipment 36,909 11,570
Changes in non-cash working capital (note
11) (35,039) 33,694
------------------------------
(22,929) (84,657)
Decrease in cash and cash equivalents (1) (4,024)
Cash and cash equivalents, beginning of
period 1 4,024
------------------------------
Cash, end of period $ - $ -
----------------------------------------------------------------------------
Interest received in cash $ 29 $ 54
Interest paid in cash $ (10,355) $ (3,721)
----------------------------------------------------------------------------
See accompanying notes to the condensed interim consolidated financial
statements.
ANDERSON ENERGY LTD.
Notes to the Condensed Interim Consolidated Financial
Statements
THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2012 AND 2011
(Tabular amounts in thousands of dollars, unless otherwise
stated)
(Unaudited)
1. REPORTING ENTITY
Anderson Energy Ltd. and its wholly-owned subsidiaries
(collectively "Anderson" or the "Company") are engaged in the
acquisition, exploration and development of oil and gas properties
in western Canada. Anderson is a public company incorporated and
domiciled in Canada. Anderson's common shares and convertible
debentures are listed on the Toronto Stock Exchange. The Company's
registered office and principal place of business is 700, 555 - 4th
Avenue S.W., Calgary, Alberta, Canada, T2P 3E7. Effective November
26, 2012, the Company's registered office and principal place of
business will be 2200, 333 - 7th Avenue S.W., Calgary, Alberta,
Canada, T2P 2Z1.
The Company's Board of Directors is conducting a process to
identify, examine and consider a range of strategic alternatives
available to the Company with a view to enhancing shareholder
value. The strategic alternatives include, but are not limited to,
a sale of all or a material portion of the assets of Anderson,
either in one transaction or in a series of transactions, the
outright sale of the Company, or a merger or other strategic
transaction involving Anderson and a third party. The strategic
review process is still ongoing and the Company will continue to
identify, examine and consider a full range of strategic
alternatives. Since January 1, 2012, the Company has sold or has
agreed to sell approximately $74 million of oil and gas properties,
including approximately $37.5 million (subject to normal course
closing adjustments) subsequent to September 30, 2012. Pro forma
the close of these transactions, outstanding bank loans at
September 30, 2012 would be $51.4 million (bank loans and working
capital deficiency - $59.5 million.)
It is Anderson's current intention to not disclose developments
with respect to its strategic alternatives process unless and until
its Board of Directors has approved a specific transaction or
otherwise determines that disclosure is necessary in accordance
with applicable law. The Company cautions that there are no
assurances or guarantees that the process will result in a
transaction or, if a transaction is undertaken, the terms or timing
of such a transaction. The Company has not set a definitive
schedule to complete its evaluation.
These condensed interim consolidated financial statements have
been prepared on a going concern basis which assumes that the
Company will be able to realize its assets and discharge its
liabilities in the normal course of business. If this assumption
were not appropriate, adjustments to these condensed interim
consolidated financial statements may be necessary. When assessing
the Company's ability to continue on a going concern basis,
material uncertainties related to future commodity prices and
related cash flows from operations, current debt levels and
required capital commitments may cast significant doubt on the
Company's ability to continue as a going concern. The successful
future operations of the Company are dependent on the ability of
the Company to secure sufficient funds through operations, the
proceeds from the disposition of non-strategic assets or other
sources from the strategic alternatives process.
2. BASIS OF PREPARATION
(a) Statement of compliance. The condensed interim consolidated
financial statements comply with International Accounting Standard
34 Interim Financial Reporting and do not include all of the
information required for full annual financial statements.
The condensed interim consolidated financial statements were
authorized for issuance by the Board of Directors on November 12,
2012.
(b) Accounting policies, judgements, estimates and disclosures.
In preparing these condensed interim consolidated financial
statements, the accounting policies, methods of computation and
significant judgements made by management in applying the Company's
accounting policies and key sources of estimation uncertainty were
the same as those that applied to the audited consolidated
financial statements as at and for the years ended December 31,
2011 and 2010.
Refer to note 4 for management's estimates of changes in the
fair value of its cash generating units ("CGUs").
The following disclosures are incremental to those included with
the annual audited consolidated financial statements. Certain
disclosures that are normally required in the notes to the annual
audited consolidated financial statements have been condensed or
omitted. These condensed interim consolidated financial statements
should be read in conjunction with the Company's audited
consolidated financial statements and notes thereto for the years
ended December 31, 2011 and 2010.
3. PROPERTY, PLANT AND EQUIPMENT
Cost or deemed cost
Oil and natural Other
gas assets equipment Total
Balance at January 1, 2011 $ 585,495 $ 1,779 $ 587,274
Additions 183,182 84 183,266
Disposals (14,802) - (14,802)
-------------------------------------
Balance at December 31, 2011 $ 753,875 $ 1,863 $ 755,738
Additions 30,500 25 30,525
Disposals (69,974) - (69,974)
-------------------------------------
Balance at September 30, 2012 $ 714,401 $ 1,888 $ 716,289
----------------------------------------------------------------------------
Accumulated depletion, depreciation and impairment losses
Oil and natural Other
gas assets equipment Total
Balance at January 1, 2011 $ 265,358 $ 1,243 $ 266,601
Depletion and depreciation 52,794 135 52,929
Impairment loss 35,230 - 35,230
Disposals (5,969) - (5,969)
-------------------------------------
Balance at December 31, 2011 $ 347,413 $ 1,378 $ 348,791
Depletion and depreciation 35,300 111 35,411
Impairment loss 20,000 - 20,000
Disposals (24,279) - (24,279)
-------------------------------------
Balance at September 30, 2012 $ 378,434 $ 1,489 $ 379,923
----------------------------------------------------------------------------
Carrying amounts
Oil and natural Other
gas assets equipment Total
At December 31, 2011 $ 406,462 $ 485 $ 406,947
At September 30, 2012 $ 335,967 $ 399 $ 336,366
----------------------------------------------------------------------------
Capitalized overhead. For the nine months ended September 30, 2012,
additions to property, plant and equipment included internal overhead costs
of $3.0 million (year ended December 31, 2011 -$4.6 million).
4. IMPAIRMENT LOSS (REVERSAL)
In the third quarter of 2012, there were indicators of
impairment due to the ongoing strategic alternatives process. An
impairment test was performed on the Company's CGU's and management
concluded that no impairment existed at September 30, 2012.
In the second quarter of 2012, declines in forecasted natural
gas commodity prices and the ongoing strategic alternatives process
were indicators of impairment for certain CGUs. Forecasted natural
gas commodity prices at June 30, 2012 declined between eight and 18
per cent when compared to December 31, 2011. Accordingly, the
Company tested its gas-weighted CGUs for impairment and determined
that the aggregate carrying value of these CGUs was $20 million
higher than the recoverable amounts and impairments were
recorded.
At September 30, 2011, there were significant changes in the
future commodity price forecasts used by the Company's independent
qualified reserves evaluators when compared to December 31, 2010.
The Company considered the downward price adjustments on natural
gas to be an indicator of impairment for the Company's Shallow Gas
and Non-Core CGUs. Similarly, the Company considered the upward
price adjustments on natural gas liquids to be an indicator of
impairment reversal for its Deep Gas CGU as a result of this CGU
having a significant amount of natural gas liquids. All of the
Company's oil and gas reserves were evaluated and reported on by
independent qualified reserves evaluators at October 1, 2011. Based
on this assessment, the Company determined that $9.7 million of
previous impairments were reversed from its Deep Gas CGU and its
Shallow Gas and Non-Core CGUs were impaired by $3.2 million and
$5.4 million respectively.
5. BANK LOANS
At September 30, 2012, total bank facilities were $98 million,
consisting of an $88 million revolving term credit facility and a
$10 million working capital credit facility with a syndicate of
Canadian banks. Total bank facilities are stepping down on October
31, 2012 in conjunction with certain dispositions, to $81.4
million, and on November 30, 2012 to $70 million. The revolving
term credit facility and the working capital credit facility have a
maturity date of July 10, 2013, and all outstanding advances become
repayable on July 10, 2013. Accordingly, at September 30, 2012, the
bank loans have been classified as a current liability. Under the
agreement, advances 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. These
margins vary from 3% to 4% depending on the borrowing option used.
At September 30, 2012, no amounts were drawn in U.S. funds.
The average effective interest rate on advances under the
facilities in 2012 was 4.5% (September 30, 2011 - 5.7%). The
Company had approximately $0.4 million in letters of credit
outstanding at September 30, 2012 that reduce the amount of credit
available to the Company.
Loans are secured by a floating charge debenture over all assets
and guarantees by material subsidiaries.
The available lending limits of the facilities are scheduled to
be reviewed on or before December 15, 2012 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 as a result of future dispositions, changes in reserve
values, future commodity prices or at the next scheduled
review.
6. DECOMMISSIONING OBLIGATIONS
September 30, 2012 December 31, 2011
Balance at January 1 $ 62,848 $ 51,550
Provisions incurred 932 4,878
Total abandonment expenditures (392) (249)
Provisions disposed (11,143) (1,316)
Change in estimates 2,714 6,355
Accretion expense 879 1,630
--------------------------------------
Ending balance $ 55,838 $ 62,848
---------------------------------------------------------------------------
The Company's decommissioning obligations result from its
ownership interest in oil and natural gas assets including well
sites and gathering systems. The Company has estimated the net
present value of the decommissioning obligations to be $55.8
million as at September 30, 2012 (December 31, 2011 - $62.8
million) based on an undiscounted inflation-adjusted total future
liability of $67.2 million (December 31, 2011 - $80.8 million).
These payments are expected to be made over the next 25 years with
the majority of costs to be incurred between 2013 and 2030. At
September 30, 2012, the liability has been calculated using an
inflation rate of 2.0% (December 31, 2011 - 2.0%) and discounted
using a risk-free rate of 1.0% to 2.5% (December 31, 2011 - 0.9% to
3.1%) depending on the estimated timing of the future
obligation.
7. SHARE CAPITAL
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.
Elimination of deficit. On May 16, 2011, the Company's
shareholders approved the elimination of the Company's consolidated
deficit as at January 1, 2011, without reduction to the Company's
stated capital or paid up capital.
Stock options. The Company has an employee stock option plan
under which employees, directors and consultants are eligible to
purchase common shares of the Company. Options are granted using an
exercise price of stock options equal to the weighted average
trading price of the Company's common 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 nine months ended
September 30, 2012 and the year ended December 31, 2011 are as
follows:
September 30, 2012 December 31, 2011
Weighted Weighted
average average
Number of exercise Number of exercise
options price options price
Outstanding at January 1 14,014,182 $ 1.69 12,006,232 $ 2.32
Granted during the period 15,000 0.57 4,484,800 0.74
Exercised during the period - - (64,400) 0.79
Expired during the period (3,380,582) 3.72 (1,564,150) 4.27
Forfeited during the period (463,400) 0.82 (848,300) 1.01
--------------------------------------------
Ending balance 10,185,200 $ 1.05 14,014,182 $ 1.69
----------------------------------------------------------------------------
Exercisable, end of period 6,480,083 $ 1.18 6,764,582 $ 2.60
----------------------------------------------------------------------------
The range of exercise prices of the outstanding options is as follows:
Weighted Weighted
average average
Number of exercise remaining
Range of exercise prices options price life (years)
$0.45 to $0.67 187,500 $ 0.49 3.1
$0.68 to $1.02 5,770,300 0.74 3.0
$1.03 to $1.54 3,375,750 1.07 2.9
$2.33 to $3.50 574,950 2.69 1.0
$3.51 to $4.90 276,700 4.25 0.9
-------------------------------------
Total at September 30, 2012 10,185,200 $ 1.05 2.8
---------------------------------------------------------------------------
The weighted average common share price at the date of exercise
for stock options exercised in 2011 was $1.20.
Subsequent to September 30, 2012, 5.7 million stock options were
issued to staff and 0.7 million options expired or were forfeited
to November 12, 2012.
The fair value of the options granted in the nine months ended
September 30, 2012 and 2011 were estimated using the Black-Scholes
model with the following weighted average inputs:
September 30, 2012 September 30, 2011
Fair value at grant date $ 0.30 $ 0.39
Common share price $ 0.57 $ 0.75
Exercise price $ 0.57 $ 0.75
Volatility 61% 59%
Option life 5 years 5 years
Dividends 0% 0%
Risk-free interest rate 1.28% 1.67%
Forfeiture rate 15% 15%
----------------------------------------------------------------------------
This estimated forfeiture rate is adjusted to the actual
forfeiture rate when each tranche vests. Stock-based compensation
cost of $0.5 million (September 30, 2011 - $0.7 million) was
expensed during the nine months ended September 30, 2012.
Stock-based compensation cost of $0.1 million (September 30, 2011 -
$0.2 million) was expensed during the three months ended September
30 2012. In addition, stock-based compensation expense of $0.4
million (September 30, 2011 - $0.5 million) was capitalized during
the nine months ended September 30, 2012. For the three months
ended September 30, 2012, $0.1 million of stock-based compensation
was capitalized (September 30, 2011 - $0.2 million).
8. EARNINGS (LOSS) PER SHARE
Basic and diluted earnings (loss) per share were calculated as
follows:
Three months ended Nine months ended
September 30 September 30
2012 2011 2012 2011
Earnings (loss) for the period $ 94 $ 7,472 $ (22,598) $ 9,723
----------------------------------------------------------------------------
Weighted average number of
common shares (basic) (in
thousands of shares)
Common shares outstanding at
beginning of period 172,550 172,550 172,550 172,485
Effect of stock options
exercised - - - 49
------------------------------------------
Weighted average number of
common shares (basic) 172,550 172,550 172,550 172,534
Effect of dilutive stock
options - - - 506
------------------------------------------
Weighted average number of
common shares (diluted) 172,550 172,550 172,550 173,040
----------------------------------------------------------------------------
Basic and diluted earnings
(loss) per share $ - $ 0.04 $ (0.13) $ 0.06
----------------------------------------------------------------------------
The average market value of the Company's common shares for
purposes of calculating the dilutive effect of stock options was
based on quoted market prices for the period that the options were
outstanding. For the three months ended September 30, 2012,
10,185,200 options (September 30, 2011 - 14,289,032 options) and
59,316,889 common shares reserved for convertible debentures
(September 30, 2011 - 59,316,889) were excluded from calculating
dilutive earnings as they were anti-dilutive. For the nine months
ended September 30, 2012, 10,185,200 options (September 30, 2011 -
11,702,932 options) and 59,316,889 common share reserved for
convertible debentures (September 30, 2011 - 59,316,889) were
excluded from calculating dilutive earnings as they were
anti-dilutive.
9. OTHER INCOME (EXPENSES)
Other income (expenses) includes the following:
Three months Nine months
ended ended
September 30 September 30
2012 2011 2012 2011
Realized gain (loss) on derivative
contracts $ 1,680 $ 871 $ 3,198 $ (353)
Unrealized gain (loss) on derivative
contracts (2,656) 6,350 347 11,166
Gain on sale of property, plant and
equipment 8,080 3,476 4,081 4,622
------------------------------------
$ 7,104 $ 10,697 $ 7,626 $ 15,435
----------------------------------------------------------------------------
10. FINANCE INCOME AND EXPENSES
Three months ended Nine months ended
September 30 September 30
2012 2011 2012 2011
Income:
Interest income on cash
equivalents $ - $ - $ - $ 5
Other - 21 24 49
Expenses:
Interest and financing costs on
bank loans (1,319) (667) (3,603) (2,376)
Interest on convertible
debentures (1,771) (1,771) (5,314) (3,859)
Accretion on convertible
debentures (498) (462) (1,451) (972)
Accretion on decommissioning
obligations (242) (439) (879) (1,295)
Other (33) (3) (42) (18)
---------------------------------------
Net finance expenses $ (3,863) $ (3,321) $ (11,265) $ (8,466)
--------------------------------------------------------------------------
11. SUPPLEMENTAL CASH FLOW INFORMATION
Changes in non-cash working capital is comprised of:
September 30, 2012 September 30, 2011
Source (use) of cash
Accounts receivable and accruals $ 3,234 $ 4,863
Prepaid expenses and deposits 330 363
Accounts payable and accruals (39,470) 28,698
----------------------------------------
$ (35,906) $ 33,924
----------------------------------------------------------------------------
Related to operating activities $ (692) $ 483
Related to financing activities $ (175) $ (253)
Related to investing activities $ (35,039) $ 33,694
----------------------------------------------------------------------------
12. FINANCIAL RISK MANAGEMENT
(a) Liquidity risk. Liquidity risk is the risk that the Company
will not be able to meet its financial obligations as they fall
due. The Company's objective is to ensure, as far as possible, that
it will always have sufficient liquidity to meet its liabilities
when due, under both normal and stressed conditions, without
incurring unacceptable losses or risking damage to the Company's
reputation.
The following are the contractual maturities of financial
liabilities, including associated interest payments on convertible
debentures and excluding the impact of netting agreements at
September 30, 2012:
One to Two to Three Four to
Less than two three to four five
Financial Liabilities one year years years years years
Non-derivative financial
liabilities
Accounts payable and
accruals (1) $ 21,103 $ - $ - $ - $ -
Bank loans - principal (2) 88,922 - - - -
Convertible debentures
- Interest (1) 5,626 7,085 7,085 5,210 3,335
- Principal - - - 50,000 46,000
---------------------------------------------
Total $115,651 $ 7,085 $ 7,085 $ 55,210 $ 49,335
----------------------------------------------------------------------------
(1) Accounts payable and accruals includes $1.5 million of interest
relating to convertible debentures. The total cash interest payable in
less than one year on the convertible debentures is $7.1 million.
(2) Assumes the remaining credit facilities are not renewed on July 10,
2013.
(b) Market risk. Market risk is the risk that changes in market
prices, such as commodity prices, foreign exchange rates and
interest rates will affect the Company's income or the value of the
financial instruments. The objective of market risk management is
to manage and control market risk exposures within acceptable
parameters, while optimizing the return.
The Company may use both financial derivatives and physical
delivery sales contracts to manage market risks. All such
transactions are conducted within risk management tolerances that
are reviewed by the Board of Directors.
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 interest charged on the outstanding bank loans
fluctuates with the interest rates posted by the lenders. The
Company has not entered into any mitigating interest rate hedges or
swaps, however the Company has $50 million and $46 million of
convertible debentures with fixed interest rates of 7.5% and 7.25%
respectively, maturing January 31, 2016 and June 30, 2017. Had the
borrowing rate on bank loans been 100 basis points higher (or
lower) throughout the nine months ended September 30, 2012,
earnings would have been affected by approximately $0.6 million
(September 30, 2011 - $0.3 million) based on the average bank debt
balance outstanding during the period.
Commodity price risk. Commodity price risk is the risk that fair
value or future cash flows will fluctuate as a result of changes in
commodity prices. Commodity prices for oil and natural gas are
impacted by both the relationship between the Canadian and U.S.
dollar and world economic events that dictate the levels of supply
and demand.
At September 30, 2012, the Company had fixed price swap
contracts for an average of 1,500 barrels per day of crude oil with
a remaining term of October to December 2012 at a weighted average
NYMEX crude oil price of Canadian $103.87 per barrel.
The estimated fair value of the financial oil contracts has been
determined on the amounts the Company would receive or pay to
terminate the oil contracts. At September 30, 2012, the Company
estimates that it would receive approximately $1.7 million to
terminate these contracts (December 31, 2011 - receive $1.4
million). Subsequent to September 30, 2012, the Company settled two
derivative contracts, each for 250 barrel per day of oil for
November and December of 2012 for $0.4 million.
The fair value of derivative contracts at September 30, 2012
would have been impacted as follows had the oil prices used to
estimate the fair value changed by:
Effect of an Effect of a decrease
increase in price on in price on after-
after-tax earnings tax earnings
Canadian $1.00 per barrel change
in the oil prices $ 104 $ (104)
----------------------------------------------------------------------------
The Company realized a gain of $0.1 million related to its
physical sales contracts to sell 7,000 GJ per day of natural gas
for August and September 2012 at an average AECO price of $2.45 per
GJ which is included in oil and gas sales.
(c) Capital management. Anderson'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 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
$141.8 million, bank loans of $88.9 million, convertible debentures
with a face value of $96.0 million and the cash working capital
deficiency of $8.1 million, which excludes the current portion of
unrealized gains on derivative contracts. 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 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 cash working capital
deficiency, the liability component of convertible debentures and
outstanding bank loans) by either the annualized current quarter
funds from operations or the twelve-month trailing funds from
operations (cash flow from operating activities before changes in
non-cash working capital and decommissioning 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. Funds from operations in the quarter,
annualized current quarter funds from operations, twelve-month
trailing funds from operations and total net debt to funds from
operations are not defined by International Financial Reporting
Standards and therefore are referred to as non-GAAP measures.
September December
30, 2012 31, 2011
Bank loans $ 88,922 $ 88,682
Accounts payable and accruals 21,103 60,573
Current assets(1) (13,034) (16,599)
---------------------------------------------------------------------------
Net debt before convertible debentures $ 96,991 $ 132,656
Convertible debentures (liability component) 86,247 84,796
---------------------------------------------------------------------------
Total net debt $ 183,238 $ 217,452
Cash from operating activities in the quarter $ 5,845 $ 16,462
Decommissioning expenditures in the quarter 27 146
Changes in non-cash working capital in the quarter (147) 389
---------------------------------------------------------------------------
Funds from operations in the quarter $ 5,725 $ 16,997
Annualized current quarter funds from operations $ 22,900 $ 67,988
Twelve-month trailing funds from operations $ 40,944 $ 54,464
---------------------------------------------------------------------------
Net debt before convertible debentures to funds from
operations
- Annualized current quarter funds from operations 4.2 2.0
- Twelve-month trailing funds from operations 2.4 2.4
Total net debt to funds from operations
- Annualized current quarter funds from operations 8.0 3.2
- Twelve-month trailing funds from operations 4.5 4.0
---------------------------------------------------------------------------
(1) Excludes unrealized gains on derivative contracts.
There were no changes in the Company's approach to capital
management during the three months ended September 30, 2012.
The high ratios reflect low natural gas prices and the capital
expenditures required to make the transition from a gas-weighted
company to an oil-weighted company. The increase in the ratio from
December 31, 2011 is the result of a 30 per cent decline in natural
gas prices and a 16 per cent decline Canadian oil prices compared
to the fourth quarter of 2011. Since September 30, 2012, the
Company has applied proceeds on disposition of assets of
approximately $18.7 million to reduce bank loans. Also see note
14.
Neither the Company nor any of its subsidiaries are subject to
externally imposed capital requirements. The credit facilities are
subject to a semi-annual review of the borrowing base which is
directly impacted by the value of the oil and natural gas
reserves.
13. COMMITMENTS AND CONTINGENCIES
(a) Capital commitments. At September 30, 2012, the Company has
"farm-in" agreements whereby the Company may earn working interests
in oil and gas properties in exchange for undertaking capital
spending programs to develop the properties. The Company has
farm-in obligations to drill four gross (3.9 net capital)
horizontal wells in the Cardium geological formation prior to the
end of 2012. One agreement has a $100,000 non-performance fee
clause should the Company fail to drill the well. Another agreement
pertains to two wells; there is a $35,000 non-performance fee
should the Company fail to drill both wells, and if only one well
is drilled, the Company would also forfeit fifty per cent of the
interest in the first well drilled under the agreement; in a second
agreement pertaining to one of these wells, there is also a $25,000
non-performance fee should the Company fail to drill the well. In a
third agreement, there is a $200,000 non-performance fee should the
Company fail to drill the well. One gross (1 net) well has been
drilled subsequent to September 30, 2012.
(b) Other commitments and contingencies. At September 30, 2012,
the Company had firm service gas transportation agreements in which
the Company guarantees that certain minimum volumes of natural gas
will be shipped on various gas transportation systems. The terms of
the various agreements expire in one to eight years. If no volumes
were shipped pursuant to the agreements, the maximum amounts
payable under the guarantees based on current tariff rates are as
follows:
2012 2013 2014 2015 2016 Thereafter
Firm service commitment $ 277 $ 1,021 $ 818 $ 697 $ 110 $ 299
--------------------------------------------------
Firm service committed
volumes (MMcfd) 15 14 8 7 3 3
----------------------------------------------------------------------------
Subsequent to September 30, 2012, the Company entered into a new
head office lease at a rate of approximately $560,000 per year
starting December 1, 2012 and ending on June 30, 2014.
There are no material changes to other commitments and
contingencies from those disclosed in the Company's annual audited
consolidated financial statements as at and for the years ended
December 31, 2011 and 2010.
14. SUBSEQUENT EVENTS
Subsequent to September 30, 2012, the Company sold or has
entered into agreements to sell properties considered to be
non-strategic assets for cash consideration of approximately $37.5
million (subject to normal course closing adjustments). Proceeds
were used or will be used to repay bank loans.
Corporate Information
Head Office
700 Selkirk House
555 4th Avenue S.W.
Calgary, Alberta
Canada T2P 3E7
Head Office (effective November 26, 2012)
2200, 333 7th Avenue S.W.
Calgary, Alberta
Canada T2P 2Z1
Phone (403) 262-6307
Fax (403) 261-2792
Website www.andersonenergy.ca
Directors
J.C. Anderson(4)
Calgary, Alberta
Brian H. Dau
Calgary, Alberta
Christopher L. Fong (1)(2)(3)(4)
Calgary, Alberta
Glenn D. Hockley (1)(3)(4)
Calgary, Alberta
David J. Sandmeyer (2)(3)(4)
Calgary, Alberta
David G. Scobie (1)(2)(4)
Calgary, Alberta
Member of:
(1) Audit Committee
(2) Compensation & Corporate
Governance Committee
(3) Reserves Committee
(4) Special Committee
Auditors
KPMG LLP
Independent Engineers
GLJ Petroleum Consultants Ltd.
Legal Counsel
Bennett Jones LLP
Registrar & Transfer Agent
Valiant Trust Company
Stock Exchange
The Toronto Stock Exchange
Symbol AXL, AXL.DB, AXL.DB.B
Officers
J.C. Anderson
Chairman of the Board
Brian H. Dau
President & Chief Executive Officer
David M. Spyker
Chief Operating Officer
M. Darlene Wong
Vice President Finance, Chief Financial
Officer & Secretary
Blaine M. Chicoine
Vice President, Drilling and Completions
Sandra M. Drinnan
Vice President, Land
Philip A. Harvey
Vice President, Exploitation
Jamie A. Marshall
Vice President, Exploration
Patrick M. O'Rourke
Vice President, Production
Abbreviations used
AECO - intra-Alberta Nova inventory transfer price bbl -
barrel
bpd - barrels per day
BOE - barrels of oil equivalent
BOED - barrels of oil equivalent per day
MBOE - thousand barrels of oil equivalent
MMBOE - million barrels of oil equivalent
GJ - gigajoule
Mcf - thousand cubic feet
Mcfd - thousand cubic feet per day
MMcfd - million cubic feet per day
NGL - natural gas liquids
WTI - West Texas Intermediate
NYMEX - The New York Mercantile Exchange
Contacts: Anderson Energy Ltd. Brian H. Dau President &
Chief Executive Officer (403) 262-6307info@andersonenergy.ca