CROCOTTA ENERGY INC. (TSX:CTA) is pleased to announce its financial and
operating results for year ended December 31, 2010, including financial
statements, notes to the financial statements, and Management's Discussion and
Analysis. All dollar figures are Canadian dollars unless otherwise noted.
HIGHLIGHTS
- Reduced net debt from $70.7 million to $35.2 million
- Property dispositions of $50.6 million
- Reduced operating costs from $10.37/boe to $9.32/boe
- Increased proved plus probable reserves 22% to 16.1 million boe
- All-in finding, development and acquisition costs, including future
development costs, on a proved plus probable basis of $8.03 per boe
- Increase in Net Asset Value per share of 7.8% to $2.78 per share at December
31, 2010
- Continued to prove up the large Montney resource in northeast British Columbia
by drilling 2 (2.0 net) successful vertical tests
- Successfully began proving up the liquids-rich Bluesky resource at Edson, AB
by drilling 3 (0.8 net) horizontal gas wells and 1 (0.4 net) oil well, setting
up 100% locations for 2011
- Subsequent to year-end, raised gross proceeds of $36.0 million through the
issuance of approximately 15.6 million common shares at a price of $2.30 per
share
Three Months Ended Year Ended
December 31 December 31
% %
FINANCIAL 2010 2009 Change 2010 2009 Change
----------------------------------------------------------------------------
($000s, except per share
amounts)
Oil and natural
gas sales 7,274 12,130 (40) 34,530 34,199 1
Funds from
operations (1) 4,258 3,972 7 14,254 9,325 53
per share - basic and
diluted 0.07 0.06 17 0.22 0.18 22
Net loss before
extraordinary items (1,140) (4,155) (73) (7,414) (14,572) (49)
per share - basic and
diluted (0.02) (0.06) (67) (0.11) (0.28) (61)
Net earnings (loss) (1,140) 3,276 (135) (7,414) (7,141) 4
per share - basic and
diluted (0.02) 0.05 (140) (0.11) (0.14) (21)
Capital expenditures 14,568 2,464 491 28,714 13,219 117
Corporate acquisition - 229 (100) - 84,544 (100)
Property acquisitions - (17) (100) - 2,425 (100)
Property dispositions (28,532) (9,687) 195 (50,630) (10,553) 380
Net debt (2) 35,200 70,656 (50)
Common shares outstanding
(000s)
weighted average - basic 65,142 64,719 1 65,129 51,883 26
weighted average - diluted 65,595 64,719 1 65,412 51,883 26
end of period - basic 65,142 65,084 -
end of period - diluted 72,540 74,760 (3)
(1) Funds from operations and funds from operations per share do not have
any standardized meaning prescribed by Canadian GAAP and therefore may
not be comparable to similar measures used by other companies. Please
refer to the Non-GAAP Measures section in the MD&A for more details and
the Funds from Operations section in the MD&A for a reconciliation to
cash flow from operating activities.
(2) Net debt includes current liabilities (including the revolving credit
facility and secured bridge facility) less current assets and excludes
the risk management contracts. Net debt does not have any standardized
meaning prescribed by Canadian GAAP and therefore may not be comparable
to similar measures used by other companies. Please refer to the
Non-GAAP Measures section in the MD&A for more details.
----------------------------------------------------------------------------
Three Months Ended Year Ended
December 31 December 31
% %
OPERATING 2010 2009 Change 2010 2009 Change
----------------------------------------------------------------------------
Number of producing days 92 92 365 365
Daily production
Oil and liquids - (bbls/d) 647 1,140 (43) 746 912 (18)
Natural gas - (mcf/d) 9,958 12,157 (18) 10,485 9,450 11
----------------------------------------------------------------------------
Oil equivalent -
(boe/d @ 6:1) 2,307 3,166 (27) 2,494 2,487 -
Revenue
Oil and liquids - ($/bbl) 61.04 66.58 (8) 62.79 58.65 7
Natural gas - ($/mcf) 3.97 4.60 (14) 4.56 4.26 7
----------------------------------------------------------------------------
Oil equivalent -
(boe/d @ 6:1) 34.27 41.64 (18) 37.94 37.68 1
Royalties
Oil and liquids - ($/bbl) 16.04 23.31 (31) 17.47 19.66 (11)
Natural gas - ($/mcf) (0.15) 0.15 (200) 0.17 0.14 21
----------------------------------------------------------------------------
Oil equivalent -
(boe/d @ 6:1) 3.83 8.98 (57) 5.93 7.74 (23)
Production expenses
Oil and liquids - ($/bbl) 9.59 10.24 (6) 9.94 9.09 9
Natural gas - ($/mcf) 1.56 1.36 15 1.51 1.85 (18)
----------------------------------------------------------------------------
Oil equivalent -
(boe/d @ 6:1) 9.44 8.91 6 9.32 10.37 (10)
Transportation expenses
Oil and liquids - ($/bbl) 1.12 1.24 (10) 1.23 1.55 (21)
Natural gas - ($/mcf) 0.20 0.16 25 0.18 0.17 6
----------------------------------------------------------------------------
Oil equivalent -
(boe/d @ 6:1) 1.18 1.06 11 1.13 1.21 (7)
Operating netback (1)
Oil and liquids - ($/bbl) 34.29 31.79 8 34.15 28.35 20
Natural gas - ($/mcf) 2.36 2.93 (19) 2.70 2.10 29
----------------------------------------------------------------------------
Oil equivalent -
(boe/d @ 6:1) 19.82 22.69 (13) 21.56 18.36 17
Other income - ($/boe) 4.75 - 100 1.11 - 100
Unrealized loss on investments
- ($/boe) (0.41) - 100 (0.10) - 100
Realized gain (loss) on
risk management contracts
- ($/boe) 0.10 (0.74) (114) (0.69) (0.23) 200
Unrealized gain (loss) on
risk management contracts -
($/boe) (0.35) (0.73) (52) 1.15 (1.15) (200)
General and administrative
expenses - ($/boe) (3.43) (3.59) (4) (3.58) (4.86) (26)
Interest expense - ($/boe) (1.18) (4.73) (75) (2.74) (2.99) (8)
Depletion, depreciation, and
accretion - ($/boe) (22.76) (24.47) (7) (25.30) (27.10) (7)
Stock-based compensation -
($/boe) (1.23) (5.70) (78) (1.19) (2.65) (55)
Future income tax recovery
(expense) - ($/boe) (0.68) 2.99 (123) 1.63 4.57 (64)
Gain on contingent
consideration - ($/boe) - 25.51 (100) - 8.19 (100)
----------------------------------------------------------------------------
Net earnings (loss) -
($/boe) (5.37) 11.23 (148) (8.15) (7.86) 4
(1) Operating netback does not have any standardized meaning prescribed by
Canadian GAAP and therefore may not be comparable to similar measures
used by other companies. Please refer to the Non-GAAP Measures section
in the MD&A for more details.
President's Message
In 2010, Crocotta took several steps forward in transforming itself from a
conventional producer to a resource-style producer. Conventional properties
totaling approximately $50 million were sold to strengthen the Company's
financial position and allow for more capital to be spent on its key resource
properties. Four wells were drilled into the Edson Bluesky pool to prove the
concept that horizontal multi-frac wells would successfully work in this large
resource and three vertical test wells were drilled into the Montney formation
near Dawson in Northeast British Columbia. Both projects have resulted in
material reserve additions and set up years of drilling for Crocotta.
Edson
Crocotta has assembled an average 75% working interest in over 65 sections of
land in the Edson area in addition to owning a large gathering system and
interests in two gas plants. The area is characterized by multiple horizons that
are productive on the lands including Cardium, Notikewin and Bluesky formations.
During 2010, Crocotta drilled and completed four Bluesky horizontal multi-frac
wells that resulted in one oil well and three liquids-rich gas wells. All wells
were highly successful with the liquids-rich gas wells stabilizing at
approximately 600 boepd and the oil well stabilizing at approximately 150 boepd.
While the average working interest on these wells was relatively low (28%),
Crocotta was able prove up its offsetting 100% lands of which three 100% wells
are scheduled to be drilled in the first half of 2011. The Bluesky gas well
economics are materially enhanced due to the high liquids content produced
(approximately 40% of total production).
Three vertical recompletions were performed in the Notikewin with average
initial rates of approximately 160 boepd. Geological mapping and review of
competitors' horizontal multi-frac wells have proven up numerous potential
horizontal multi-frac wells on Crocotta lands for future exploitation.
Cardium oil is also present extensively on Company lands but has not been tested
with horizontal multi-frac wells as of yet. Competitors are currently drilling
horizontal multi-frac oil wells offsetting Company lands which could prove up a
large oil resource on Crocotta lands. We are closely monitoring such activity to
determine the commercial viability and will have a better understanding by the
end of 2011.
Montney
Crocotta successfully drilled and completed three vertical tests targeting
Montney in Northeast British Columbia and Northwest Alberta.
At Sunrise, a vertical test was completed in the Upper Montney which stabilized
at 700 mcf per day. Horizontal wells drilled by competitors in the area have had
initial stabilized rates of 4 mmcf/d to 14 mmcf/d (650 boepd - 2,300 boepd).
Crocotta owns nine 100% working interest sections in the area with potential to
drill four horizontal wells per section.
At Kilkerran, Crocotta participated in the drilling of a successful vertical
test in the upper and lower Montney at rates of 500 mcf/d and 350 mcf/d
respectively. Commercial horizontal developments have already been established
on both sides of our lands which we believe are directly analogous to our tests.
Crocotta owns an average 50% working interest in 12 sections of land in the
area.
At Glacier, Crocotta drilled a successful vertical well to test the upper and
lower Montney. The upper Montney had a stabilized rate of 900 mcf/d with the
lower stabilizing at 400 mcf/d.
Crocotta is pleased with the results to date but will defer any horizontal wells
until at least the fourth quarter pending an increase in natural gas pricing.
New projects
Given the strengthening of Crocotta's financial position as a result of asset
sales and additional capital raised in early 2011, we are looking to add two to
three oil projects during 2011. While we do not believe that the projects will
have a material effect on 2011, such projects will assist in Crocotta's longer
term strategy to become balanced from a commodity perspective.
We look forward to updating our shareholders on all projects as they develop
through 2011.
Management's Discussion and Analysis ("MD&A")
March 21, 2011
Crocotta Energy Inc. ("Crocotta" or the "Company") is an oil and natural gas
company, actively engaged in the acquisition, development, exploration, and
production of oil and natural gas reserves in Western Canada. The Company trades
on the Toronto Stock Exchange under the symbol "CTA".
The MD&A should be read in conjunction with the audited financial statements and
notes thereto for the years ended December 31, 2010 and 2009. The audited
financial statements and financial data contained in the MD&A have been prepared
in accordance with Canadian generally accepted accounting principles ("GAAP") in
Canadian currency (except where noted as being in another currency).
Additional information related to the Company, including the Company's Annual
Information Form (AIF), may be found on the SEDAR website at www.sedar.com.
BOE Conversions
Barrel of oil equivalent ("boe") amounts have been calculated using a conversion
rate of six thousand cubic feet of natural gas to one barrel of oil (6:1) unless
otherwise stated. The term "boe" may be misleading, particularly if used in
isolation. A boe conversion rate of six thousand cubic feet of natural gas to
one barrel of oil equivalence is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead.
Non-GAAP Measures
This document contains the terms "funds from operations", "funds from operations
per share", "net debt", and "operating netback" which do not have any
standardized meaning prescribed by Canadian GAAP and therefore may not be
comparable to similar measures used by other companies. The Company uses these
measures to help evaluate its performance. Management uses funds from operations
to analyze performance and considers it a key measure as it demonstrates the
Company's ability to generate the cash necessary to fund future capital
investments and to repay debt. Funds from operations is a non-GAAP measure and
has been defined by the Company as net earnings (loss) plus non-cash items
(depletion, depreciation and accretion, stock-based compensation, unrealized
gains and losses on risk management contracts, unrealized gains and losses on
investments, future income taxes, and extraordinary gains and losses) and
excludes the change in non-cash working capital related to operating activities
and expenditures on asset retirement obligations and reclamation. The Company
also presents funds from operations per share whereby amounts per share are
calculated using weighted average shares outstanding, consistent with the
calculation of earnings per share. Funds from operations is reconciled to cash
flow from operating activities under the heading "Funds from Operations".
Management uses net debt as a measure to assess the Company's financial
position. Net debt includes current liabilities (including the revolving credit
facility and secured bridge facility) less current assets and excludes the risk
management contracts. Management considers operating netback an important
measure as it demonstrates its profitability relative to current commodity
prices. Operating netback, which is calculated as average unit sales price less
royalties, production expenses, and transportation expenses, represents the cash
margin for every barrel of oil equivalent sold. Operating netback per boe is
reconciled to net earnings (loss) per boe under the heading "Operating Netback".
Forward-Looking Information
This document contains forward-looking statements and forward-looking
information within the meaning of applicable securities laws. The use of any of
the words "expect", "anticipate", "continue", "estimate", "may", "will",
"should", "believe", "intends", "forecast", "plans", "guidance" and similar
expressions are intended to identify forward-looking statements or information.
More particularly and without limitation, this document contains forward looking
statements and information relating to the Company's risk management program,
oil, NGLs and natural gas production, capital programs, oil, NGLs, and natural
gas commodity prices, and debt levels. The forward-looking statements and
information are based on certain key expectations and assumptions made by the
Company, including expectations and assumptions relating to prevailing commodity
prices and exchange rates, applicable royalty rates and tax laws, future well
production rates, the performance of existing wells, the success of drilling new
wells, the availability of capital to undertake planned activities and the
availability and cost of labour and services.
Although the Company believes that the expectations reflected in such
forward-looking statements and information are reasonable, it can give no
assurance that such expectations will prove to be correct. Since forward-looking
statements and information address future events and conditions, by their very
nature they involve inherent risks and uncertainties. Actual results may differ
materially from those currently anticipated due to a number of factors and
risks. These include, but are not limited to, the risks associated with the oil
and gas industry in general such as operational risks in development,
exploration and production, delays or changes in plans with respect to
exploration or development projects or capital expenditures, the uncertainty of
estimates and projections relating to production rates, costs and expenses,
commodity price and exchange rate fluctuations, marketing and transportation,
environmental risks, competition, the ability to access sufficient capital from
internal and external sources and changes in tax, royalty and environmental
legislation. The forward-looking statements and information contained in this
document are made as of the date hereof for the purpose of providing the readers
with the Company's expectations for the coming year. The forward-looking
statements and information may not be appropriate for other purposes. The
Company undertakes no obligation to update publicly or revise any
forward-looking statements or information, whether as a result of new
information, future events or otherwise, unless so required by applicable
securities laws.
Crocotta Energy Inc.
Management's Discussion & Analysis
Year Ended December 31, 2010
----------------------------------------------------------------------------
Three Months Ended Year Ended
Summary of Financial December 31 December 31
Results 2010 2009 2008 2010 2009 2008
----------------------------------------------------------------------------
($000s, except per share
amounts)
Oil and natural gas sales 7,274 12,130 8,729 34,530 34,199 54,468
Funds from operations 4,258 3,972 3,463 14,254 9,325 30,607
per share - basic and
diluted 0.07 0.06 0.09 0.22 0.18 0.89
Net loss before
extraordinary items (1,140) (4,155)(2,511) (7,414) (14,572) 2,974
per share - basic and
diluted (0.02) (0.06) (0.07) (0.11) (0.28) 0.09
Net earnings (loss) (1,140) 3,276 (2,511) (7,414) (7,141) 2,974
per share - basic and
diluted (0.02) 0.05 (0.07) (0.11) (0.14) 0.09
Total assets 213,816 254,156 187,987
Total long-term liabilities 9,533 10,084 13,184
Net debt 35,200 70,656 20,944
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Production Three Months Ended Year Ended
December 31 December 31
% %
2010 2009 Change 2010 2009 Change
----------------------------------------------------------------------------
Average Daily Production
Oil and NGLs (bbls/d) 647 1,140 (43) 746 912 (18)
Natural gas (mcf/d) 9,958 12,157 (18) 10,485 9,450 11
----------------------------------------------------------------------------
Total (boe/d) 2,307 3,166 (27) 2,494 2,487 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Daily production for the three months ended December 31, 2010 decreased 27% to
2,307 boe/d compared to 3,166 boe/d for the comparative period in 2009. For the
year ended December 31, 2010, daily production increased marginally to 2,494
boe/d from 2,487 boe/d for the year ended December 31, 2009. The decrease in
production in the fourth quarter was due to the sale of certain oil and natural
gas assets during 2010.
Crocotta's production profile in 2010 was comprised of 70% natural gas and 30%
oil and NGLs. During the year ended December 31, 2009, Crocotta's production
profile was comprised of 63% natural gas and 37% oil and NGLs. The change in the
production profile was the result of the sale of certain oil weighted assets
during 2010.
Three Months Ended Year Ended
Revenue December 31 December 31
% %
($000s) 2010 2009 Change 2010 2009 Change
----------------------------------------------------------------------------
Oil and NGLs 3,636 6,983 (48) 17,097 19,521 (12)
Natural gas 3,638 5,147 (29) 17,433 14,678 19
----------------------------------------------------------------------------
Total revenue 7,274 12,130 (40) 34,530 34,199 1
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Average Sales Price
----------------------------------------------------------------------------
Oil and NGLs ($/bbl) 61.04 66.58 (8) 62.79 58.65 7
Natural gas ($/mcf) 3.97 4.60 (14) 4.56 4.26 7
----------------------------------------------------------------------------
Average sales price ($/boe) 34.27 41.64 (18) 37.94 37.68 1
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue totaled $7.3 million for the fourth quarter of 2010, down 40% from $12.1
million for the fourth quarter of 2009. For the year, revenue increased 1% to
$34.5 million in 2010 compared to $34.2 million in 2009. The decrease in revenue
in the fourth quarter of 2010 compared to 2009 was due to a decrease in
production resulting from the sale of certain oil and natural gas assets during
2010 combined with a decrease in oil, natural gas, and NGLs commodity prices.
The following table outlines the Company's realized wellhead prices and industry
benchmarks:
Three Months Ended December 31 Year Ended December 31
% %
Commodity Pricing 2010 2009 Change 2010 2009 Change
----------------------------------------------------------------------------
Oil and NGLs
Corporate Price ($Cdn/bbl) 61.04 66.58 (8) 62.79 58.65 7
West Texas Intermediate
($US/bbl) 85.08 75.96 12 79.43 61.63 29
Edmonton Par ($Cdn/bbl) 80.71 76.75 5 77.80 66.20 18
Natural gas
Corporate Price ($Cdn/mcf) 3.97 4.60 (14) 4.56 4.26 7
AECO Price ($Cdn/mcf) 3.59 4.42 (19) 4.12 3.93 5
Exchange Rates
U.S./Cdn. Dollar Average
Exchange Rate 0.9875 0.9471 4 0.9711 0.8802 10
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Corporate average oil and NGLs price were 75.6% and 80.7% of Edmonton Par price
for the three months and year ended December 31, 2010, respectively. Corporate
average natural gas prices were 110.6% and 110.7% of AECO prices for the three
months and year ended December 31, 2010, respectively. Differences between
corporate and benchmark prices can be a result of quality (higher or lower API,
higher or lower heat content), sour content, NGLs included in reporting, and
various other factors. Crocotta's differences are mainly the result of lower
priced NGLs included in oil price reporting and higher heat content natural gas
production that is priced higher than AECO reference prices.
Future prices received from the sale of the products may fluctuate as a result
of market factors. Other than noted below, the Company did not hedge any of its
oil, NGLs or natural gas production in 2010. For 2010, the Company had hedges in
the form of monthly settled puts (floors) as detailed below.
Product Period Production Floor Price
----------------------------------------------------------------------------
Oil January 2010 - December 2010 1,000 bbls/d WTI CDN $50.00/bbl
Gas January 2010 - December 2010 10.0 mmcf/d AECO CDN $4.00/mcf
----------------------------------------------------------------------------
----------------------------------------------------------------------------
For the three months ended December 31, 2010, the realized gain on the risk
management contracts was virtually $nil (2009 - $0.2 million realized loss) and
the unrealized loss on the risk management contracts was $0.1 million (2009 -
$0.2 million). For the year, the realized loss on the risk management contracts
was $0.6 million (2009 - $0.2 million) and the unrealized gain on the risk
management contracts was $1.0 million (2009 - $1.0 million unrealized loss).
Three Months Ended December 31 Year Ended December 31
Royalties % %
($000s) 2010 2009 Change 2010 2009 Change
----------------------------------------------------------------------------
Oil and NGLs 955 2,445 (61) 4,757 6,542 (27)
Natural gas (142) 171 (183) 640 482 33
----------------------------------------------------------------------------
Total royalties 813 2,616 (69) 5,397 7,024 (23)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Average Royalty Rate (% of
sales)
----------------------------------------------------------------------------
Oil and NGLs 26.3 35.0 (25) 27.8 33.5 (17)
Natural gas (3.9) 3.3 (218) 3.7 3.3 12
----------------------------------------------------------------------------
Average royalty rate 11.2 21.6 (48) 15.6 20.5 (24)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company pays royalties to provincial governments (Crown), freeholders, which
may be individuals or companies, and other oil and gas companies that own
surface or mineral rights. Crown royalties are calculated on a sliding scale
based on commodity prices and individual well production rates. Royalty rates
can change due to commodity price fluctuations and changes in production volumes
on a well-by-well basis, subject to a minimum and maximum rate restriction
ascribed by the Crown.
For the three months ended December 31, 2010, oil, NGLs, and natural gas
royalties decreased 69% to $0.8 million compared to $2.6 million for the
comparative period. For the year ended December 31, 2010, oil, NGLs, and natural
gas royalties decreased 23% to $5.4 million compared to $7.0 million for the
year ended December 31, 2009. The decrease in royalties for the three months and
year ended December 31, 2010 compared to the same period in 2009 was the result
of a significant decrease in oil and NGLs royalties, which was due to the
disposition of certain oil weighted assets in 2010. Natural gas royalties in Q4
2010 were negative as a result of a low natural gas commodity price environment
combined with increases to the monthly capital cost and processing fee
deductions. For the year ended December 31, 2010, natural gas royalties
increased over prior period as a result of an increase in production and an
increase in year-over-year commodity prices.
The overall effective royalty rate was 11.2% for the three months ended December
31, 2010, compared to 21.6% for the quarter ended December 31, 2009. For the
year, the overall effective royalty rate was 15.6% in 2010 compared to 20.5% in
2009. The effective oil and NGLs royalty rate for the three months and year
ended December 31, 2010 decreased as a result of the disposition of certain oil
weighted assets during the year that had higher associated royalty rates. The
effective natural gas royalty rate for the year ended December 31, 2010
increased from the comparative period due to an increase in year-over-year
natural gas commodity prices.
Three Months Ended December 31 Year Ended December 31
% %
Production Expenses 2010 2009 Change 2010 2009 Change
----------------------------------------------------------------------------
Oil and NGLs ($/bbl) 9.59 10.24 (6) 9.94 9.09 9
Natural gas ($/mcf) 1.56 1.36 15 1.51 1.85 (18)
----------------------------------------------------------------------------
Total ($/boe) 9.44 8.91 6 9.32 10.37 (10)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Per unit production expenses for the three months ended December 31, 2010 were
$9.44/boe, up from $8.91/boe for the comparative period ended December 31, 2009.
For the year, per unit production expenses declined 10% to $9.32/boe in 2010
compared to $10.37/boe in 2009.
Oil and NGLs per unit production expenses increased for the year ended December
31, 2010 from the comparative period in 2009 due to the disposition of certain
oil weighted assets in 2010 that had lower associated production expenses.
Natural gas per unit production expenses declined for the year ended December
31, 2010 from the comparative period in 2009 as a result of the acquisition of
Salvo Energy Corporation ("Salvo") and other oil and natural gas assets in
August 2009 which had lower associated operating costs. The natural gas assets
acquired included ownership interests in two separate gas plants that generate
processing and gathering income related to joint venture and third party
production resulting in a reduction in production expenses. The Company
continues to focus on opportunities that will improve operational efficiencies
and reduce per boe production expenses to enhance netbacks.
Three Months Ended December 31 Year Ended December 31
% %
Transportation Expenses 2010 2009 Change 2010 2009 Change
----------------------------------------------------------------------------
Oil and NGLs ($/bbl) 1.12 1.24 (10) 1.23 1.55 (21)
Natural gas ($/mcf) 0.20 0.16 25 0.18 0.17 6
----------------------------------------------------------------------------
Total ($/boe) 1.18 1.06 11 1.13 1.21 (7)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Transportation expenses are mainly third-party pipeline tariffs incurred to
deliver the products to the purchasers at main hubs. For the quarter ended
December 31, 2010 compared to the quarter ended December 31, 2009,
transportation expenses increased 11% to $1.18/boe from $1.06/boe. For the year,
transportation expenses decreased to $1.13/boe in 2010 from $1.21/boe in 2009.
Natural gas transportation expenses were consistent year-over-year, while oil
and NGLs transportation expenses decreased significantly. The decrease in oil
and NGLs transportation costs in 2010 from 2009 was due to an increase in the
percentage of NGLs volumes produced in 2010 combined with a change in marketer
and sales point for a significant portion of NGLs volumes produced.
Three Months Ended December 31 Year Ended December 31
% %
Operating Netback 2010 2009 Change 2010 2009 Change
----------------------------------------------------------------------------
Oil and NGLs ($/bbl)
Revenue 61.04 66.58 (8) 62.79 58.65 7
Royalties 16.04 23.31 (31) 17.47 19.66 (11)
Production expenses 9.59 10.24 (6) 9.94 9.09 9
Transportation expenses 1.12 1.24 (10) 1.23 1.55 (21)
----------------------------------------------------------------------------
Operating netback 34.29 31.79 8 34.15 28.35 20
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Natural gas ($/mcf)
Revenue 3.97 4.60 (14) 4.56 4.26 7
Royalties (0.15) 0.15 (200) 0.17 0.14 21
Production expenses 1.56 1.36 15 1.51 1.85 (18)
Transportation expenses 0.20 0.16 25 0.18 0.17 6
----------------------------------------------------------------------------
Operating netback 2.36 2.93 (19) 2.70 2.10 29
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Combined ($/boe) (6:1)
Revenue 34.27 41.64 (18) 37.94 37.68 1
Royalties 3.83 8.98 (57) 5.93 7.74 (23)
Production expenses 9.44 8.91 6 9.32 10.37 (10)
Transportation expenses 1.18 1.06 11 1.13 1.21 (7)
----------------------------------------------------------------------------
Operating netback 19.82 22.69 (13) 21.56 18.36 17
----------------------------------------------------------------------------
----------------------------------------------------------------------------
During the fourth quarter of 2010, Crocotta generated an operating netback of
$19.82/boe, down 13% from $22.69/boe for the fourth quarter of 2009. The
decrease was mainly due to a decline in oil, NGLs, and natural gas commodity
prices offset by a decline in royalties. For the year, the Company generated an
operating netback of $21.56/boe in 2010, up 17% from $18.36/boe in 2009. The
increase in the operating netback was mainly due to decreases in royalties,
production expenses, and transportation expenses.
The following is a reconciliation of operating netback per boe to net earnings
(loss) per boe for the periods noted:
Three Months Ended December 31 Year Ended December 31
% %
($/boe) 2010 2009 Change 2010 2009 Change
----------------------------------------------------------------------------
Operating netback 19.82 22.69 (13) 21.56 18.36 17
Other income 4.75 - 100 1.11 - 100
Unrealized loss on
investments (0.41) - 100 (0.10) - 100
Realized gain (loss) on
risk management
Contracts 0.10 (0.74) (114) (0.69) (0.23) 200
Unrealized gain (loss) on
risk management contracts (0.35) (0.73) (52) 1.15 (1.15) (200)
General and administrative
expenses (3.43) (3.59) (4) (3.58) (4.86) (26)
Interest expense (1.18) (4.73) (75) (2.74) (2.99) (8)
Depletion, depreciation,
and accretion (22.76) (24.47) (7) (25.30) (27.10) (7)
Stock-based compensation (1.23) (5.70) (78) (1.19) (2.65) (55)
Future income tax recovery
(expense) (0.68) 2.99 (123) 1.63 4.57 (64)
Gain on contingent
consideration - 25.51 (100) - 8.19 (100)
----------------------------------------------------------------------------
Net earnings (loss) (5.37) 11.23 (148) (8.15) (7.86) 4
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Months Ended December 31 Year Ended December 31
% %
Other Income 2010 2009 Change 2010 2009 Change
----------------------------------------------------------------------------
Other income ($000s) 1,009 - 100 1,009 - 100
Other income ($/boe) 4.75 - 100 1.11 - 100
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Other income relates to an assignment agreement entered into by Crocotta and an
unrelated party whereby Crocotta was allocated drilling credits from the
unrelated party in order to maximize Crocotta's Alberta Crown royalty reduction.
Three Months Ended December 31 Year Ended December 31
Unrealized Loss % %
on Investments 2010 2009 Change 2010 2009 Change
----------------------------------------------------------------------------
Unrealized loss on investments
($000s) 88 - 100 88 - 100
Unrealized loss on investments
($/boe) 0.41 - 100 0.10 - 100
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Investments include 875,000 warrants of Hyperion Exploration Corp. ("Hyperion")
at an exercise price of $2.00 per warrant. Each warrant is convertible into one
common share of Hyperion and expires on November 7, 2011. The warrants were
obtained as partial consideration for the sale of certain oil and natural gas
assets to Hyperion in the fourth quarter of 2010. The investment is measured at
fair value each reporting period using the Black-Scholes option-pricing model.
Based on Hyperion's closing trading price on December 31, 2010 of $1.60 per
share, an unrealized loss was recognized for the year on the revaluation of
warrants at December 31, 2010.
General and Three Months Ended December 31 Year Ended December 31
Administrative Expenses % %
($000s) 2010 2009 Change 2010 2009 Change
----------------------------------------------------------------------------
G&A expenses (gross) 1,265 1,381 (8) 4,873 5,504 (11)
G&A capitalized (113) (168) (33) (547) (735) (26)
G&A recoveries (424) (168) 152 (1,069) (361) 196
----------------------------------------------------------------------------
G&A expenses (net) 728 1,045 (30) 3,257 4,408 (26)
----------------------------------------------------------------------------
G&A expenses ($/boe) 3.43 3.59 (4) 3.58 4.86 (26)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
General and administrative expenses ("G&A") decreased to $3.43/boe for the
fourth quarter of 2010 compared to $3.59/boe for the quarter ended December 31,
2009. For the year, G&A expenses decreased 26% to $3.58/boe in 2010 from
$4.86/boe in 2009. The decrease per boe was due to an increase in G&A recoveries
combined with a decrease in employment costs. The increase in G&A recoveries was
due to a significant increase in capital activity in 2010 compared to 2009
combined with an increase in operating recoveries on the assets acquired from
Salvo in August 2009.
Three Months Ended December 31 Year Ended December 31
Interest % %
($000s) 2010 2009 Change 2010 2009 Change
----------------------------------------------------------------------------
Interest expense 513 1,436 (64) 2,846 2,808 1
Interest income (262) (57) 360 (352) (90) 291
----------------------------------------------------------------------------
Net interest expense 251 1,379 (82) 2,494 2,718 (8)
----------------------------------------------------------------------------
Interest expense ($/boe) 1.18 4.73 (75) 2.74 2.99 (8)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest expense in 2010 relates mainly to interest incurred on amounts drawn
from the Company's credit facility. Interest expense also includes interest
incurred on a secured bridge facility acquired in conjunction with the
acquisition of Salvo in August 2009, which was repaid in full during the first
quarter of 2010. Interest income relates to interest earned on the sale of
certain oil and natural gas properties during 2010. Quarter-over-quarter, net
interest expense decreased as a result of the repayment of the secured bridge
facility during 2010. Year-over-year, the decrease in net interest expense
correlates to an increase in interest income in 2010 compared to 2009 as a
result of an increase in sales of oil and natural gas properties.
Crocotta Energy Inc.
Management's Discussion & Analysis
Year Ended December 31, 2010
----------------------------------------------------------------------------
Depletion,
Depreciation Three Months Ended December 31 Year Ended December 31
and Accretion 2010 2009 % Change 2010 2009 % Change
----------------------------------------------------------------------------
DD&A ($000s) 4,831 7,128 (32) 23,024 24,599 (6)
DD&A ($/boe) 22.76 24.47 (7) 25.30 27.10 (7)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Depletion, depreciation and accretion ("DD&A") decreased 7% to $22.76/boe for
the three months ended December 31, 2010 compared to $24.47/boe for the three
months ended December 31, 2009. For the year, DD&A decreased 7% to $25.30/boe in
2010 from $27.10/boe in 2009. The decrease in DD&A was due to a significant
increase in proved reserves as a result of successful capital activity during
2010.The provision for DD&A for the three months and year ended December 31,
2010 includes $0.2 million (2009 - $0.2 million) and $0.7 million (2009 - $0.5
million), respectively, for accretion of asset retirement obligations.
Stock-based
Compensation Three Months Ended December 31 Year Ended December 31
2010 2009 % Change 2010 2009 % Change
----------------------------------------------------------------------------
Stock-based
compensation ($000s) 261 1,659 (84) 1,086 2,403 (55)
Stock-based
compensation ($/boe) 1.23 5.70 (78) 1.19 2.65 (55)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company grants stock options to officers, directors, employees and
consultants and calculates the related stock-based compensation using the
Black-Scholes option-pricing model. The Company recognizes the expense over the
vesting period of the stock options. Stock-based compensation expense decreased
to $1.23/boe for the three months ended December 31, 2010 from $5.70/boe in the
comparative period. For the year, stock-based compensation decreased to
$1.19/boe in 2010 from $2.65/boe in 2009. During 2010, the Company granted 1.2
million options (2009 - 3.0 million), 0.8 million options were forfeited (2009 -
nil), 2.6 million options were cancelled (2009 - nil), and 0.1 million options
were exercised (2009 - nil). The decrease in stock-based compensation was due to
a decrease in the number of options issued in 2010 compared to 2009. In
addition, stock-based compensation expense in 2009 included the issuance of 1.2
million warrants in conjunction with a private placement to management in
October 2009 as well as the extension of the term of 2.4 million warrants that
had been previously issued to officers, directors, and employees of the Company.
Gain on Contingent
Consideration Three Months Ended December 31 Year Ended December 31
2010 2009 % Change 2010 2009 % Change
----------------------------------------------------------------------------
Gain on contingent
consideration ($000s) - 7,431 (100) - 7,431 (100)
Gain on contingent
consideration ($/boe) - 25.51 (100) - 8.19 (100)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
On November 5, 2008, the Company closed a business combination whereby it
acquired all of the issued and outstanding shares of a private company
("PrivateCo"). At the time of the business combination, the Company agreed to
pay additional consideration to the PrivateCo shareholders in the event that the
oil and natural gas properties acquired from PrivateCo were sold within 12
months of closing of the business combination for an amount exceeding $3.0
million. Upon the business combination, the Company recorded a deferred gain in
the financial statements to reflect the potential liability to pay the
additional consideration. The oil and natural gas properties acquired were not
sold within 12 months of closing of the business combination. As a result, the
Company reversed the previously recorded deferred gain and recorded an
extraordinary gain in the financial statements at December 31, 2009.
Taxes
At December 31, 2010, the Company had approximately $198.2 million in effective
tax pools, losses, and share issue costs.
December 31, December 31,
2010 2009 % Change
----------------------------------------------------------------------------
($000s)
Canadian oil and gas property expense
(COGPE) 9,129 42,685 (79)
Canadian development expense (CDE) 67,789 44,796 51
Canadian exploration expense (CEE) 59,524 79,985 (26)
Undepreciated capital costs (UCC) 36,789 39,978 (8)
Non-capital losses carried forward 31,363 31,662 (1)
Capital losses carried forward - 1,796 (100)
Share issue costs 474 1,603 (70)
Valuation allowance (6,857) (6,581) 4
----------------------------------------------------------------------------
Total pools, losses, and share issue
costs 198,211 235,924 (16)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Funds from Operations
Funds from operations for the three months ended December 31, 2010 was $4.3
million ($0.07 per diluted share) compared to $4.0 million ($0.06 per diluted
share) for the three months ended December 31, 2009. For the year, funds from
operations was $14.3 million ($0.22 per diluted share) in 2010 compared to $9.3
million ($0.18 per diluted share) in 2009. The increase was a result of slightly
higher oil, NGLs, and natural gas commodity prices, combined with a decrease in
royalties and production expenses in 2010 compared to 2009, and realizing $1.0
million in other income in 2010 from the allocation of drilling credits from an
unrelated party.
The following is a reconciliation of funds from operations to cash flow from
operating activities for the periods noted:
Three Months Ended December 31 Year Ended December 31
2010 2009 % Change 2010 2009 % Change
----------------------------------------------------------------------------
Funds from operations
(non-GAAP) 4,258 3,972 7 14,254 9,325 53
Asset retirement
expenditures (204) (118) 73 (868) (163) 433
Change in non-cash
working capital (244) (365) 33 (743) 950 (178)
----------------------------------------------------------------------------
Cash flow from
operating activities
(GAAP) 3,810 3,489 9 12,643 10,112 25
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net Earnings (Loss)
The Company had a net loss of $1.1 million ($0.02 per diluted share) for the
three months ended December 31, 2010 compared to net earnings of $3.3 million
($0.05 per diluted share) for the three months ended December 31, 2009. Net
earnings arose during the fourth quarter of 2009 as a result of a $7.4 million
extraordinary gain that was recorded in relation to the acquisition of PrivateCo
in 2008. For the year, the Company had a net loss of $7.4 million ($0.11 per
diluted share) in 2010 compared to a net loss of $7.1 million ($0.14 per diluted
share) and a loss before extraordinary items of $14.6 million ($0.28 per diluted
share) in 2009. The decrease in the net loss (excluding the extraordinary gain)
was mainly a result of a decrease in expenses in 2010 compared to 2009 and
realizing $1.0 million in other income in 2010 from the allocation of drilling
credits from an unrelated party.
Capital Expenditures
For the three months ended December 31, 2010, the Company had net capital
dispositions of $14.0 million compared to $7.0 million for the three months
ended December 31, 2009. For the year ended December 31, 2010, the Company had
net capital dispositions of $21.9 million compared to net capital expenditures
of $89.6 million for the year ended December 31, 2009.
Three Months Ended December 31 Year Ended December 31
% %
($000s) 2010 2009 Change 2010 2009 Change
----------------------------------------------------------------------------
Land 1,362 394 246 2,931 1,179 149
Drilling, completions,
and workovers 10,932 1,970 455 18,986 8,774 116
Equipment 1,922 (145) 1,426 5,621 2,216 154
Geological and
geophysical 352 245 44 1,176 1,030 14
Other - - - - 20 (100)
----------------------------------------------------------------------------
Total exploration and
development 14,568 2,464 491 28,714 13,219 117
Corporate acquisition - 229 (100) - 84,544 (100)
Property acquisitions - (17) (100) - 2,425 (100)
Property dispositions (28,532) (9,687) 195 (50,630) (10,553) 380
----------------------------------------------------------------------------
Net property
dispositions (28,532) (9,704) 194 (50,630) (8,128) 523
----------------------------------------------------------------------------
Total capital
expenditures
(dispositions) (13,964) (7,011) (99) (21,916) 89,635 (124)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
During the year, Crocotta drilled 10 (5.8 net) wells, which resulted in 3 (1.0
net) oil wells, 5 (2.8 net) natural gas wells, and 2 (2.0 net) uneconomic wells.
During the year, the Company sold certain oil and natural gas properties to five
unrelated parties for cash proceeds of approximately $50.6 million and warrants
valued at approximately $0.2 million at closing of the sale (see "Unrealized
Loss on Investments"). Production from these assets totaled approximately 950
boe/d. The sale of these properties allowed the Company to reduce net debt to
$35.2 million at December 31, 2010 from $70.7 million at December 31, 2009 and
focus capital spending on its two core areas, Edson Bluesky and Dawson Montney.
Finding, Development and Acquisition Costs ("FD&A")
FD&A costs reflect the efficiency and value added by the Company's capital
spending. While NI 51-101 requires that the effects of acquisitions and
dispositions be excluded, Crocotta has included these items because it believes
that acquisitions can have a significant impact on the Company's ongoing reserve
replacement costs and that excluding these amounts could result in an inaccurate
portrayal of Crocotta's cost structure. Crocotta's capital program in 2010 was
focused at Edson in West Central Alberta and in Northeast British Columbia
targeting Montney. Capital expenditures for the year were $28.7 million taking
into account $2.7 million of capital expenditures spent on properties sold
during the year. The Company's FD&A costs for the period ended December 31, 2010
along with comparatives for the prior year and three year average are as
follows, both including and excluding net acquisitions (dispositions):
Crocotta Energy Inc.
Management's Discussion & Analysis
Year Ended December 31, 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2010 2009 3 Year Average
($000's, except were Proved & Proved & Proved &
noted) Proved Probable Proved Probable Proved Probable
----------------------------------------------------------------------------
Finding & Development
Costs (excluding net
acquisitions/
dispositions)
Exploration and
Development
Expenditures 26,029 26,029 13,219 13,219 98,212 98,212
Change in FDC (2) 33,107 52,443 13,814 23,867 46,625 83,500
----------------------------------------------------------------------------
Finding and
Development
Costs excluding Net
Acquisitions/
Dispositions
- Including FDC 59,136 78,472 27,033 37,086 144,837 181,712
All-in Finding and
Development Costs
(including net
acquisitions/
dispositions)
Exploration and
Development
Expenditures 26,029 26,029 13,219 13,219 98,212 98,212
Net Acquisitions
(Dispositions)
(including
related capital) (47,945) (47,945) 76,416 76,416 39,467 39,467
----------------------------------------------------------------------------
Exploration and
Development
Expenditures
including net
acquisitions
(dispositions) (21,916) (21,916) 89,635 89,635 137,679 137,679
Change in FDC 33,107 52,443 13,814 23,867 46,625 83,500
----------------------------------------------------------------------------
All-in Finding and
Development Costs -
Including FDC 11,191 30,527 103,449 113,502 184,304 221,179
Reserve Additions
(Mboe)
Exploration and
Development 4,482 7,074 236 265 5,853 9,157
Net
Acquisitions/
Dispositions (2,386) (3,271) 4,700 6,700 2,616 4,051
----------------------------------------------------------------------------
Total Reserve
Additions 2,096 3,803 4,936 6,965 8,470 13,208
Finding and
Development
Costs excluding net
acquisitions/
dispositions ($/boe)
Excluding FDC 5.81 3.68 56.01 49.88 16.78 10.73
Including FDC 13.19 11.09 114.55 139.95 24.74 19.84
All-in Finding and
Development Costs
($/boe)
Excluding FDC (10.46) (5.76) 18.16 12.87 16.26 10.42
Including FDC 5.34 8.03 20.96 16.30 21.76 16.75
----------------------------------------------------------------------------
(1) Based on total company interest reserves before deduction of royalties
to others and including any royalty interest of Crocotta. Based on
the evaluation by GLJ Petroleum Consultants Ltd. ("GLJ").
(2) Future development capital ("FDC") expenditures required to recover
reserves estimated by GLJ. The aggregate of the exploration and
development costs incurred in the most recent financial period and
the change during that period in estimated future development costs
generally will not reflect total finding and development costs related
to reserve additions for that period.
Liquidity and Capital Resources
The Company had net debt of $35.2 million at December 31, 2010 compared to net
debt of $70.7 million at December 31, 2009. The decrease of $35.5 million was
mainly due to $50.6 million in property dispositions and funds from operations
of $14.3 million, which were offset by $28.7 million used for the purchase and
development of oil and natural gas properties and equipment and $0.9 million for
asset retirement expenditures.
At December 31, 2010, the Company had total credit facilities of $55.0 million,
consisting of a $55.0 million revolving operating demand loan credit facility
with a Canadian chartered bank. The demand loan credit facility bears interest
at prime plus a range of 0.75% to 2.50% and is secured by a $235 million fixed
and floating charge debenture on the assets of the Company. At December 31,
2010, $35.4 million (December 31, 2009 - $52.4 million) had been drawn on the
demand loan credit facility. The next review of the demand loan credit facility
by the bank is scheduled on or before March 31, 2011.
During the year, the Company sold certain oil and natural gas properties to five
unrelated parties for cash proceeds of approximately $50.6 million and warrants
valued at approximately $0.2 million at closing of the sale (see "Unrealized
Loss on Investments"). Production from these assets totaled approximately 950
boe/d. Proceeds from the dispositions were used to retire the remaining balance
on the secured bridge facility and reduce net debt. The secured bridge facility
was acquired in conjunction with the acquisition of Salvo in 2009.
Subsequent to December 31, 2010, the Company issued, by way of private
placement, approximately 15.6 million common shares at a price of $2.30 per
share for gross proceeds of approximately $36.0 million. The proceeds will be
used to fund Crocotta's Edson Bluesky and Dawson Montney developments, other
capital projects, and for general corporate purposes.
The ongoing global economic conditions have continued to impact the liquidity in
financial and capital markets, restrict access to financing, and cause
significant volatility in commodity prices. Downward trends in commodity prices
have resulted in the Company experiencing reduced operating netbacks and funds
from operations. Although commodity prices remained consistent in 2010 compared
to 2009, continued pressure on commodity prices would result in the Company
experiencing reduced operating netbacks and funds from operations in future
periods. The Company partially mitigated this risk through commodity price
hedges on its 2010 production in the form of monthly settled puts (floors). The
sale of non-core properties during the latter half of 2009 and throughout 2010,
the repayment of the secured bridge facility during the first quarter of 2010,
the availability of the undrawn portion of the Company's $55.0 million revolving
operating demand loan credit facility, and the $36.0 million financing
subsequent to December 31, 2010 has allowed the Company to strengthen its
financial position on a go forward basis and focus capital spending on its two
core areas. Crocotta's capital program is flexible and can be adjusted as needed
based upon the economic environment. Crocotta has implemented adequate
strategies to protect its business as much as possible in the current economic
environment, including strategies to balance funds from operations, available
credit limits, and capital spending. However, Crocotta is still exposed to the
risks associated with the current economic situation. The Company will continue
to monitor the possible impact on its business and strategy and will make
adjustments as necessary.
Contractual Obligations
The following is a summary of the Company's contractual obligations and
commitments at December 31, 2010:
Less than 1 - 3 After 3
($000s) Total 1 year years years
----------------------------------------------------------------------------
Accounts payable and accrued
liabilities 10,930 10,930 - -
Revolving credit facility 35,386 35,386 - -
Office leases 842 661 181 -
Field equipment leases 1,537 686 851 -
Firm transportation agreements 1,283 491 635 157
Capital processing agreements 400 - - 400
----------------------------------------------------------------------------
Total contractual obligations 50,378 48,154 1,667 557
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Outstanding Share Data
The Company is authorized to issue an unlimited number of voting common shares,
an unlimited number of non-voting common shares, and Class A and Class B
preferred shares, issuable in series. The voting common shares of the Company
commenced trading on the TSX on October 17, 2007 under the symbol "CTA". The
following table summarizes the common shares outstanding and the number of
shares exercisable into common shares from options, warrants, and other
instruments:
December 31, March 21,
(000s) 2010 2011
----------------------------------------------------------------------------
Voting common shares 65,142 80,874
Options 3,877 6,286
Warrants 3,521 3,521
----------------------------------------------------------------------------
Total 72,540 90,681
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Summary of Quarterly Results
Q4 2010 Q3 2010 Q2 2010 Q1 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Number of producing days 92 92 91 90
Daily production
Oil and NGLs (bbls/d) 647 862 665 810
Natural gas (mcf/d) 9,958 10,530 10,698 10,763
----------------------------------------------------------------------------
Oil equivalent (boe/d @ 6:1) 2,307 2,617 2,448 2,604
($000s, except per share amounts)
----------------------------------------------------------------------------
Oil and natural gas sales 7,274 8,574 7,720 10,962
Funds from operations 4,258 3,279 2,597 4,120
per share - basic and diluted 0.07 0.05 0.04 0.06
Net loss before
extraordinary items (1,140) (2,477) (2,935) (862)
per share - basic and diluted (0.02) (0.04) (0.05) (0.01)
Net earnings (loss) (1,140) (2,477) (2,935) (862)
per share - basic and diluted (0.02) (0.04) (0.05) (0.01)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Q4 2009 Q3 2009 Q2 2009 Q1 2009
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Number of producing days 92 92 91 90
Daily production
Oil and NGLs (bbls/d) 1,140 1,000 722 781
Natural gas (mcf/d) 12,157 10,005 7,706 7,878
----------------------------------------------------------------------------
Oil equivalent (boe/d @ 6:1) 3,166 2,668 2,006 2,094
($000s, except per share amounts)
----------------------------------------------------------------------------
Oil and natural gas sales 12,130 8,649 6,358 7,062
Funds from operations 3,972 1,752 1,884 1,717
per share - basic and diluted 0.06 0.03 0.04 0.04
Net loss before
extraordinary items (4,155) (3,919) (3,193) (3,305)
per share - basic and diluted (0.06) (0.06) (0.07) (0.08)
Net earnings (loss) 3,276 (3,919) (3,193) (3,305)
per share - basic and diluted 0.05 (0.06) (0.07) (0.08)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Oil and natural gas sales in Q4 2010 decreased from Q3 due to a drop in
production stemming from the sale of certain oil and natural gas assets during
Q4 2010. In Q4 2010, funds from operations increased and net loss decreased over
prior quarters as a result of other income from the allocation of drilling
credits from an unrelated party and a reduction in overall expenses during the
quarter. Overall, results from the previous quarters were consistent from period
to period, with fluctuations mainly the result of changes in production levels
and commodity prices.
Outlook
The information below represents Crocotta's guidance for 2011 based on
management's best estimates and the assumptions noted below.
Estimated Average Daily Production Guidance 2011
----------------------------------------------------------------------------
Oil and NGLs (bbls/d) 1,235
Natural gas (mcf/d) 13,000
----------------------------------------------------------------------------
Total (boe/d) 3,400
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Estimated Financial Results Guidance 2011
----------------------------------------------------------------------------
Oil and natural gas sales ($000s) 53,700
Funds from operations ($000s) 25,100
$ per share - basic (1) 0.31
$ per share - diluted (2) 0.28
Capital expenditures ($000s) 50,100
West Texas Intermediate ($US/bbl) 81.01
AECO Daily Spot Price ($Cdn/mcf) 3.98
U.S./Cdn Dollar Average Exchange Rate 0.96
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Based on 80.9 million common shares outstanding at March 21, 2011
(2) Based on 80.9 million common shares, 6.3 million options, and 3.5
million warrants outstanding at March 21, 2011
Sensitivity Analysis
The outlook is based on estimates of key external market factors. Crocotta's
actual results will be affected by fluctuations in commodity prices as well as
the U.S./Canadian dollar exchange rate. The following table provides a summary
of estimates for 2011 of the sensitivity of Crocotta's funds from operations to
changes in commodity prices and the U.S./Canadian dollar exchange rate.
Variance in
Guidance Variance in Funds from
2011 Factor Operations
----------------------------------------------------------------------------
($)
West Texas Intermediate ($US/bbl) 81.01 1.00 330,000
AECO Daily Spot Price ($Cdn/mcf) 3.98 0.10 445,000
U.S./Cdn Dollar Average Exchange
Rate ($) 0.96 0.01 286,000
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Critical Accounting Policies
Management is required to make judgments, assumptions, and estimates in the
application of generally accepted accounting principles that have a significant
impact on the financial results of the Company. By their nature, these estimates
are subject to change and the effect on the financial statements of changes in
such estimates in future periods could be significant. The following summarizes
the accounting policies that are critical to determining the Company's financial
results.
Full Cost Accounting - The Company follows the full cost method of accounting
whereby all costs related to the acquisition of, exploration for, and
development of oil and natural gas reserves are capitalized and charged against
earnings. These costs, together with the estimated future costs to be incurred
in developing proved reserves, are depleted or depreciated using the
unit-of-production method based on the proved reserves before royalties as
estimated by independent petroleum engineers. The costs of undeveloped
properties are excluded from the costs subject to depletion and depreciation
until it is determined whether proved reserves are attributable to the
properties or impairment occurs. Reserve estimates can have a significant impact
on earnings, as they are a key component in the calculation of depletion. A
downward revision to the reserve estimate could result in higher depletion and
thus lower net earnings. In addition, estimated reserves are also used in the
calculation of the impairment (ceiling) test. Oil and natural gas properties are
evaluated each reporting period through an impairment test to determine the
recoverability of capitalized costs. The carrying amount is assessed as
recoverable when the sum of the undiscounted cash flows expected from proved
reserves plus the cost of unproved interests, net of impairments, exceeds the
carrying amount. When the carrying amount is assessed not to be recoverable, an
impairment loss is recognized to the extent that the carrying amount exceeds the
sum of the discounted cash flows from proved and probable reserves plus the cost
of unproved interests, net of impairments. The cash flows are estimated using
expected future prices and costs and are discounted using a risk-free interest
rate.
Proceeds from the sale of oil and natural gas properties are applied against
capitalized costs, with no gain or loss recognized, unless such a sale would
result in a change in the depletion rate of 20% or more.
Oil and Natural Gas Reserves - The Company's oil and natural gas reserves are
evaluated and reported on by independent petroleum engineers. The estimates of
reserves is a very subjective process as forecasts are based on engineering
data, projected future rates of production, estimated future commodity prices
and the timing of future expenditures, which are all subject to uncertainty and
interpretation.
Asset Retirement Obligations - The Company is required to provide for future
abandonment and site restoration costs. These costs are estimated based on
existing laws, contracts or other policies. The obligations are initially
measured at fair value and subsequently adjusted each reporting period for the
passage of time, with the accretion charged to earnings, and for revisions to
the estimated future cash flows. The asset retirement cost is capitalized to oil
and natural gas properties and equipment and amortized into earnings on a basis
consistent with depletion and depreciation. The estimate of future abandonment
and site restoration costs involves estimates relating to the timing of
abandonment, the economic life of the asset and the costs associated with
abandonment and site restoration which are all subject to uncertainty and
interpretation.
International Financial Reporting Standards ("IFRS")
On January 1, 2011 IFRS will become the generally accepted accounting principles
in Canada for publicly accountable enterprises. Crocotta will be required to
apply IFRS, in full and without modification, for all financial periods
beginning January 1, 2011. The adoption date of January 1, 2011 will require the
restatement, for comparative purposes, of amounts reported by Crocotta for the
year ended December 31, 2010, including the opening balance sheet as at January
1, 2010.
Since its inception, the project has been managed in-house by the financial
reporting group. The Company's auditors have been and will continue to be
involved throughout the process to ensure the Company's policies are in
accordance with these new standards. Crocotta has effectively completed all
phases of its IFRS transition project and continues to review its draft IFRS
financial statements and disclosures for completeness and quality assurance.
First Time Adoption of IFRS
Most adjustments required on transition to IFRS will be made retrospectively
against opening retained earnings as of the date of the first comparative
balance sheet presented, based on standards applicable at that time. IFRS 1
provides entities adopting IFRS for the first time with certain optional
exemptions and mandatory exceptions to the general requirement for full
retrospective application of IFRS. Management has analyzed the various
accounting policy choices available under IFRS 1 and has implemented those
determined to be the most appropriate for Crocotta. Accordingly, it has applied
the following IFRS 1 exemptions in its IFRS opening balance sheet:
- Property, Plant and Equipment ("PP&E") - IFRS 1 provides an option to entities
such as Crocotta who follow the full cost accounting guideline under Canadian
GAAP to value their oil and gas PP&E on the date of transition to IFRS at its
deemed cost, defined as the carrying value assigned to these assets under
Canadian GAAP at the date of transition, January 1, 2010. Under IFRS, Crocotta's
PP&E must be divided into multiple cash generating units ("CGU"), which is
unlike full cost accounting where all oil and gas assets are accumulated into
one cost centre. The deemed cost of Crocotta's oil and gas PP&E has been
allocated to 10 CGUs based on Crocotta's proved plus probable reserve values at
January 1, 2010. These CGUs are aligned with the major geographic regions in
which Crocotta operates and could change in the future as a result of
significant acquisition or disposition activity.
- Business Combinations - IFRS 1 provides an optional exemption to the
requirement to retrospectively restate any business combinations that have
previously been recorded under Canadian GAAP. Accordingly, Crocotta will not be
recording any adjustments to retrospectively restate any of its business
combinations that have occurred prior to January 1, 2010.
- Stock-based compensation - IFRS 1 provides an optional exemption to the
requirement from IFRS 2, Share-Based Payments, to retrospectively restate as of
the date of transition amounts recorded in respect of equity instruments not yet
vested.
The following is a listing of key areas where accounting policies differ and
where accounting policy decisions are necessary that will impact Crocotta's
reported financial position and results of operations:
- Re-classification of Exploration and Evaluation ("E&E") expenditures from PP&E
- Upon transition to IFRS, Crocotta will reclassify all E&E expenditures that
are currently recognized as PP&E on the Balance Sheet. This consists of the
carrying value of certain undeveloped land that relates to exploration
properties. E&E assets will not be amortized and must be assessed for impairment
when indicators suggest the possibility of impairment as well as upon transfer
to PP&E. Management has identified approximately $36.4 million of its property,
plant and equipment that meets the criteria to be classified as E&E in the
opening balance sheet prepared under IFRS as at January 1, 2010.
- Calculation of depletion expense for PP&E assets - Upon transition to IFRS,
Crocotta has the option to calculate depletion using a reserve base of proved
reserves or both proved plus probable reserves, as compared to the Canadian GAAP
method of calculating depletion using proved reserves only. Crocotta plans to
determine its depletion expense using proved plus probable reserves as its
depletion base. Accordingly, Crocotta expects that its depletion expense for the
year ended December 31, 2010 would be reduced as compared to its current
calculation under Canadian GAAP.
- Impairment of PP&E assets - Canadian GAAP generally uses a two-step approach
to impairment testing; first comparing asset carrying values with undiscounted
future cash flows to determine whether an impairment exists, and then measuring
impairment by comparing asset carrying values to their fair value (which is
calculated using discounted cash flows). Under Canadian GAAP, Crocotta includes
all assets in one impairment test.
IFRS uses a one-step approach for testing and measuring impairment, with asset
carrying values compared directly with the higher of fair value less costs to
sell and value in use. Under IFRS, impairment of PP&E must be calculated at a
more granular level than what is currently required under Canadian GAAP
resulting in impairment testing being done at the CGU level.
These differences may potentially result in impairment charges where the
carrying value of assets were previously supported under Canadian GAAP by
consolidated undiscounted cash flows, but could not be supported by cash flows
determined on a more granular discounted basis.
At January 1, 2010 impairment tests were performed in accordance with IFRS and
impairment of approximately $35.8 million was identified. Of the $35.8 million
impairment, $11.2 million related to assets held for sale at January 1, 2010 and
sold in Q1 2010 and $11.4 million related to assets sold in Q4 2010. After the
dispositions, the Company's CGUs were reduced to seven from 10.
- Assets held for sale - Under IFRS, assets held for sale are presented
separately from PP&E as current assets and are not depreciated. At January 1,
2010, Crocotta had assets held for sale of $21.9 million, which were
reclassified from non-current assets to current assets in the IFRS opening
balance sheet (see below).
- Asset retirement obligation - Under IFRS, Crocotta is required to revalue its
entire liability for asset retirement costs at each balance sheet date using a
current liability-specific discount rate, which can generally be interpreted to
mean the current risk-free rate of interest. Under Canadian GAAP, obligations
are discounted using a credit-adjusted risk-free rate and, once recorded, the
asset retirement obligation is not adjusted for future changes in discount
rates. At January 1, 2010 Crocotta's asset retirement obligations will increase
by approximately $3.6 million to $13.7 million as the liability is revalued to
reflect the estimated risk free rate of interest at that time of 4.08%. The
increase will be charged to opening retained earnings.
- Stock-based compensation - IFRS requires that the fair value of equity
instruments incorporate an estimated forfeiture rate and that each vesting
installment be treated as a separate award (graded vesting). IFRS 1 also permits
retrospective restatement for only those equity instruments not yet vested as of
January 1, 2010. Under Canadian GAAP, Crocotta applied straight-line vesting and
did not incorporate an estimated forfeiture rate, but instead accounted for
forfeitures as a change in estimate in the period in which they occurred. At
January 1, 2010, Crocotta's contributed surplus will increase by approximately
$0.8 million to $4.5 million as equity instruments are revalued to reflect the
incorporation of an estimated forfeiture rate and graded vesting.
The following table summarizes Crocotta's January 1, 2010 balance sheet under
Canadian GAAP and the transitional entries required to present the opening
balance sheet under IFRS. Crocotta has not yet prepared a full set of annual
financial statements under IFRS, therefore, amounts are unaudited.
Canadian IFRS
$000s GAAP Adjustments IFRS
----------------------------------------------------------------------------
Current assets 8,339 21,880 30,219
Non-current assets 245,817 (57,976) 187,841
----------------------------------------------------------------------------
Total assets 254,156 (36,096) 218,060
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Current liabilities 80,037 1,835 81,872
Non-current liabilities 10,084 3,614 13,698
Equity 164,035 (41,545) 122,490
----------------------------------------------------------------------------
Total liabilities and equity 254,156 (36,096) 218,060
----------------------------------------------------------------------------
In addition to accounting policy differences, Crocotta's transition to IFRS is
expected to impact its internal controls over financial reporting, disclosure
controls and procedures, certain of Crocotta's business activities and IT
systems as follows:
- Internal controls over financial reporting ("ICFR") - Crocotta is currently in
the process of reviewing its ICFR documentation and is identifying instances
where controls must be amended or added in order to address the accounting
policy changes required under IFRS. No material changes in control procedures
are expected as a result of transition to IFRS.
- Disclosure controls and procedures - Crocotta has assessed the impact of
transition to IFRS on its disclosure controls and procedures and has not
identified any material changes required in its control environment. It is
expected that there will be increased note disclosure around certain financial
statement items than what is currently required under Canadian GAAP. Management
is currently drafting its IFRS note disclosure in accordance with current IFRS
standards. Throughout the transition process, Crocotta has carefully considered
its stakeholders' information requirements and will continue to ensure that
adequate and timely information is provided to meet these needs.
- Business activities - Management has been cognizant of the upcoming transition
to IFRS, and as such, has worked with its counterparties and lenders to ensure
that any agreements that contain references to Canadian GAAP financial
statements are modified to allow for IFRS statements. Based on the changes to
Crocotta's accounting policies, no issues are expected to arise with the
existing wording of debt covenants and related agreements as a result of the
conversion to IFRS.
- IT systems - Crocotta has assessed the readiness of its accounting software
and has and continues to assess other system requirements that may be needed in
order to perform ongoing calculations and analysis under IFRS. These changes are
not considered to be significant.
Risk Assessment
The acquisition, exploration, and development of oil and natural gas properties
involves many risks common to all participants in the oil and natural gas
industry. Crocotta's exploration and development activities are subject to
various business risks such as unstable commodity prices, interest rate and
foreign exchange fluctuations, the uncertainty of replacing production and
reserves on an economic basis, government regulations, taxes and safety and
environmental concerns. While the management of Crocotta realizes these risks
cannot be eliminated, they are committed to monitoring and mitigating these
risks.
Reserves and Reserve Replacement
The recovery and reserve estimates on Crocotta's properties are estimates only
and the actual reserves may be materially different from that estimated. The
estimates of reserve values are based on a number of variables including price
forecasts, projected production volumes and future production and capital costs.
All of these factors may cause estimates to vary from actual results.
Crocotta's future oil and natural gas reserves, production, and funds from
operations to be derived therefrom are highly dependent on Crocotta successfully
acquiring or discovering new reserves. Without the continual addition of new
reserves, any existing reserves Crocotta may have at any particular time and the
production therefrom will decline over time as such existing reserves are
exploited. A future increase in Crocotta's reserves will depend on its abilities
to acquire suitable prospects or properties and discover new reserves.
To mitigate this risk, Crocotta has assembled a team of experienced technical
professionals who have expertise operating and exploring in areas which Crocotta
has identified as being the most prospective for increasing Crocotta's reserves
on an economic basis. To further mitigate reserve replacement risk, Crocotta has
targeted a majority of its prospects in areas which have multi-zone potential,
year-round access and lower drilling costs and employs advanced geological and
geophysical techniques to increase the likelihood of finding additional
reserves.
Operational Risks
Crocotta's operations are subject to the risks normally incidental to the
operation and development of oil and natural gas properties and the drilling of
oil and natural gas wells. Continuing production from a property, and to some
extent the marketing of production therefrom, are largely dependent upon the
ability of the operator of the property.
Market risk
Market risk is the risk that the fair value of future cash flows of a financial
instrument will fluctuate because of changes in market prices. Market risk is
comprised of foreign currency risk, interest rate risk, and other price risk,
such as commodity price risk. The objective of market risk management is to
manage and control market price exposures within acceptable limits, while
maximizing returns.
Foreign exchange risk
The prices received by the Company for the production of crude oil, natural gas,
and NGLs are primarily determined in reference to U.S. dollars, but are settled
with the Company in Canadian dollars. The Company's cash flow from commodity
sales will therefore be impacted by fluctuations in foreign exchange rates. The
Company currently does not have any foreign exchange contracts in place.
Interest rate risk
The Company is exposed to interest rate risk as it borrows funds at floating
interest rates. In addition, the Company may at times issue shares on a
flow-through basis. This results in the Company being exposed to interest rate
risk to the Canada Revenue Agency for interest on unexpended funds on the
Company's flow-through share obligations. The Company currently does not use
interest rate hedges or fixed interest rate contracts to manage the Company's
exposure to interest rate fluctuations.
Commodity price risk
The Company's oil, natural gas, and NGLs production is marketed and sold on the
spot market to area aggregators based on daily spot prices that are adjusted for
product quality and transportation costs. The Company's cash flow from product
sales will therefore be impacted by fluctuations in commodity prices. From time
to time the Company may attempt to mitigate commodity price risk through the use
of financial derivatives. During 2010, the Company entered into commodity price
hedges in the form of monthly settled puts (floors), as previously outlined.
Safety and Environmental Risks
The oil and natural gas business is subject to extensive regulation pursuant to
various municipal, provincial, national, and international conventions and
regulations. Environmental legislation provides for, among other things,
restrictions and prohibitions on spills, releases or emissions of various
substances produced in association with oil and natural gas operations. Crocotta
is committed to meeting and exceeding its environmental and safety
responsibilities. Crocotta has implemented an environmental and safety policy
that is designed, at a minimum, to comply with current governmental regulations
set for the oil and natural gas industry. Changes to governmental regulations
are monitored to ensure compliance. Environmental reviews are completed as part
of the due diligence process when evaluating acquisitions. Environmental and
safety updates are presented and discussed at each Board of Directors meeting.
Crocotta maintains adequate insurance commensurate with industry standards to
cover reasonable risks and potential liabilities associated with its activities
as well as insurance coverage for officers and directors executing their
corporate duties. To the knowledge of management, there are no legal proceedings
to which Crocotta is a party or of which any of its property is the subject
matter, nor are any such proceedings known to Crocotta to be contemplated.
Disclosure Controls and Procedures and Internal Controls over Financial Reporting
The Company's President and Chief Executive Officer ("CEO") and Vice President
Finance and Chief Financial Officer ("CFO") are responsible for establishing and
maintaining disclosure controls and procedures and internal controls over
financial reporting as defined in Multilateral Instrument 52-109 of the Canadian
Securities Administrators.
Disclosure controls and procedures have been designed to ensure that information
required to be disclosed by the Company is accumulated and communicated to
management as appropriate to allow timely decisions regarding required
disclosure. The Company evaluated its disclosure controls and procedures for the
year ended December 31, 2010. The Company's CEO and CFO have concluded that,
based on their evaluation, the Company's disclosure controls and procedures are
effective to provide reasonable assurance that all material or potentially
material information related to the Company is made known to them and is
disclosed in a timely manner if required.
Internal controls over financial reporting have been designed to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
Canadian GAAP. The Company's internal controls over financial reporting includes
those policies and procedures that: pertain to the maintenance of records that
in reasonable detail accurately and fairly reflect transactions and disposition
of the assets; provide reasonable assurance that transactions are recorded as
necessary to permit preparation of financial statements in accordance with
generally accepted accounting principles and that receipts and expenditures of
assets are being made only in accordance with authorizations of management and
directors; and provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use or disposition of assets that could
have a material effect on the financial statements.
The Company evaluated the effectiveness of our internal controls over financial
reporting as of December 31, 2010. In making this evaluation, management used
the criteria set forth by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on
their evaluation, the Company's CEO and CFO have identified weaknesses over
segregation of duties. Specifically, due to the limited number of finance and
accounting personnel at the Company, it is not feasible to achieve complete
segregation of duties with regards to certain complex and non-routine accounting
transactions that may arise. This weakness is considered to be a common
deficiency for many smaller listed companies in Canada. Notwithstanding the
weaknesses identified with regards to segregation of duties, the Company
concluded that all other of its internal controls over financial reporting were
effective as of December 31, 2010. No material changes in the Company's internal
controls over financial reporting were identified during the most recent
reporting period that have materially affected, or are likely to material
affect, the Company's internal controls over financial reporting.
Because of their inherent limitations, disclosure controls and procedures and
internal controls over financial reporting may not prevent or detect
misstatements, errors, or fraud. Control systems, no matter how well conceived
or operated, can provide only reasonable, not absolute, assurance that the
objectives of the control systems are met. As a result of the weaknesses
identified in the Company's internal controls over financial reporting, there is
a greater likelihood that a material misstatement would not be prevented or
detected. To mitigate the risk of such material misstatement in financial
reporting, the CEO and CFO oversee all material and complex transactions of the
Company and the financial statements are reviewed and approved by the board of
directors each quarter. In addition, the Company will seek the advice of
external parties, such as the Company's external auditors, in regards to the
appropriate accounting treatment for any complex and non-routine transactions
that may arise.
Crocotta Energy Inc.
Balance Sheets
As at December 31, 2010 2009
----------------------------------------------------------------------------
($000s)
----------------------------------------------------------------------------
Assets
Current assets:
Cash and cash equivalents - 1,854
Accounts receivable 10,159 5,042
Prepaid expenses and deposits 878 1,443
Investments (note 10(a)) 79 -
----------------------------------------------------------------------------
11,116 8,339
Oil and natural gas properties and equipment (note 4) 201,018 245,562
Future income tax asset (note 7) 1,682 255
----------------------------------------------------------------------------
213,816 254,156
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities and Shareholders' Equity
Current liabilities:
Accounts payable and accrued liabilities 10,930 6,397
Revolving credit facility (note 5) 35,386 52,355
Secured bridge facility (note 5) - 20,243
Risk management contracts (note 10(b)) - 1,042
----------------------------------------------------------------------------
46,316 80,037
Asset retirement obligations (note 6) 9,533 10,084
Shareholders' equity:
Capital stock (note 8) 166,758 166,632
Contributed surplus (note 8(c)) 4,934 3,714
Deficit (13,725) (6,311)
----------------------------------------------------------------------------
157,967 164,035
Subsequent events (notes 8(e) and 13)
----------------------------------------------------------------------------
213,816 254,156
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the financial statements
Approved by the Board of Directors:
Director, "signed" Rob Zakresky Director, "signed" Larry Moeller
Crocotta Energy Inc.
Statements of Operations, Comprehensive Loss, and Retained Earnings
(Deficit)
Year Ended December 31, 2010 2009
----------------------------------------------------------------------------
($000s, except per share amounts)
----------------------------------------------------------------------------
Revenue:
Oil and natural gas sales 34,530 34,199
Royalties (5,397) (7,024)
Other income 1,009 -
Realized loss on risk management contracts (note 10(b)) (628) (209)
Unrealized gain (loss) on risk management contracts
(note 10(b)) 1,042 (1,042)
----------------------------------------------------------------------------
30,556 25,924
Expenses:
Production 8,483 9,413
Transportation 1,026 1,102
General and administrative 3,257 4,408
Interest 2,494 2,718
Depletion, depreciation and accretion 23,024 24,599
Stock-based compensation 1,086 2,403
Unrealized loss on investments (note 10(a)) 88 -
----------------------------------------------------------------------------
39,458 44,643
----------------------------------------------------------------------------
Loss before income taxes (8,902) (18,719)
Income Taxes:
Future income tax recovery 1,488 4,147
----------------------------------------------------------------------------
Loss before extraordinary item (7,414) (14,572)
Extraordinary Item:
Gain on contingent consideration (note 2(b)) - 7,431
----------------------------------------------------------------------------
- 7,431
Net loss and comprehensive loss (7,414) (7,141)
Retained earnings (deficit), beginning of year (6,311) 830
----------------------------------------------------------------------------
Deficit, end of year (13,725) (6,311)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Loss per share before extraordinary items:
Basic and diluted (0.11) (0.28)
Net loss per share:
Basic and diluted (0.11) (0.14)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the financial statements
Crocotta Energy Inc.
Statements of Cash Flows
Year Ended December 31, 2010 2009
----------------------------------------------------------------------------
($000s)
----------------------------------------------------------------------------
Cash provided by (used in):
Operating:
Loss before extraordinary item (7,414) (14,572)
Items not affecting cash:
Depletion, depreciation and accretion 23,024 24,599
Stock-based compensation 1,086 2,403
Unrealized loss on investments (note 10(a)) 88 -
Unrealized loss (gain) on risk management contracts
(note 10(b)) (1,042) 1,042
Future income tax recovery (1,488) (4,147)
----------------------------------------------------------------------------
14,254 9,325
Asset retirement expenditures (868) (163)
Net change in non-cash working capital (743) 950
----------------------------------------------------------------------------
12,643 10,112
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Financing:
Revolving credit facility (16,969) 36,705
Secured bridge facility (20,243) (4,757)
Issuance of capital stock 75 1,260
Share issue costs - (34)
Capital lease payments - (432)
----------------------------------------------------------------------------
(37,137) 32,742
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Investing:
Purchase and development of oil and natural gas
properties and equipment (28,714) (15,644)
Disposition of oil and natural gas properties and
equipment (note 3) 50,630 10,553
Business combinations - (30,192)
Net change in non-cash investing working capital 724 (5,717)
----------------------------------------------------------------------------
22,640 (41,000)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Change in cash and cash equivalents (1,854) 1,854
Cash and cash equivalents, beginning of year 1,854 -
----------------------------------------------------------------------------
Cash and cash equivalents, end of year - 1,854
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the financial statements
Crocotta Energy Inc.
Notes to the Financial Statements
Year Ended December 31, 2010
(Tabular amounts in 000s, unless otherwise stated)
1. SIGNIFICANT ACCOUNTING POLICIES
a) Basis of presentation
Crocotta Energy Inc. ("Crocotta" or the "Company") is an oil and natural gas
company, actively engaged in the acquisition, development, exploration, and
production of oil and natural gas reserves in Western Canada. The Company trades
on the Toronto Stock Exchange under the symbol "CTA".
These financial statements have been prepared by management in accordance with
accounting principles generally accepted in Canada ("GAAP").
b) Oil and natural gas properties and equipment
The Company follows the full cost method of accounting whereby all costs related
to the acquisition of, exploration for, and development of oil and natural gas
reserves are capitalized. Such costs include land acquisition costs, geological
and geophysical expenses, production equipment, carrying charges of
non-producing properties, costs of drilling both productive and non-productive
wells, and overhead charges directly related to acquisition, exploration, and
development activities.
These costs, together with the estimated future costs to be incurred in
developing proved reserves, are depleted or depreciated using the
unit-of-production method based on the proved reserves before royalties as
estimated by independent petroleum engineers. Oil and natural gas reserves and
production are converted into equivalent units based upon estimated relative
energy content of six thousand cubic feet of natural gas to one barrel of oil.
The costs of undeveloped properties are excluded from the costs subject to
depletion and depreciation until it is determined whether proved reserves are
attributable to the properties or impairment occurs.
Oil and natural gas properties are evaluated each reporting period through an
impairment test to determine the recoverability of capitalized costs. The
carrying amount is assessed as recoverable when the sum of the undiscounted cash
flows expected from proved reserves plus the cost of unproved interests, net of
impairments, exceeds the carrying amount. When the carrying amount is assessed
not to be recoverable, an impairment loss is recognized to the extent that the
carrying amount exceeds the sum of the discounted cash flows from proved and
probable reserves plus the cost of unproved interests, net of impairments. The
cash flows are estimated using expected future prices and costs and are
discounted using a risk-free interest rate.
Proceeds from the sale of oil and natural gas properties are applied against
capitalized costs, with no gain or loss recognized, unless such a sale would
result in a change in the depletion rate of 20% or more.
A significant portion of the Company's oil and natural gas activities are
conducted jointly with others and accordingly these financial statements reflect
only the Company's proportionate interest in such activities.
c) Office and other equipment
Office and other equipment are depreciated using the straight-line method over
the estimated useful life of three years.
d) Asset retirement obligations ("ARO")
The Company recognizes the liability associated with future site reclamation
costs in the financial statements at the time when the liability is incurred,
normally when the asset is purchased or developed. ARO obligations are initially
measured at fair value and subsequently adjusted each reporting period for the
passage of time, with the accretion charged to earnings, and for revisions to
the estimated future cash flows. The asset retirement cost is capitalized to oil
and natural gas properties and equipment and amortized into earnings on a basis
consistent with depletion and depreciation. Actual costs incurred upon
settlement of the obligations are charged against the liability.
e) Flow-through shares
The Company may finance a portion of its exploration and development activities
through the issuance of flow-through common shares. Under the terms of the
flow-through share agreements, the resource expenditure deductions for income
tax purposes are renounced to investors in accordance with the appropriate
income tax legislation. The Company provides for the future effect on income
taxes related to flow-through shares as a charge to share capital in the period
in which the expenditures are renounced.
f) Stock-based compensation
The Company has a stock-based compensation plan, which is described in note
8(e). The Company applies the fair value method for valuing stock options
granted to officers, directors, employees and consultants. Under this method,
compensation cost attributable to stock options granted to officers, directors,
employees and consultants is measured at fair value and expensed over the
vesting period with a corresponding increase to contributed surplus. Upon the
exercise of the stock options, consideration paid together with the amount
previously recognized in contributed surplus is recorded as an increase to share
capital. The Company does not incorporate an estimated forfeiture rate for stock
options that will not vest, but instead accounts for forfeitures as a change in
estimate in the period in which they occur. In the event that vested stock
options expire without being exercised, previously recognized compensation costs
associated with such stock options are not reversed.
g) Revenue recognition
Oil and natural gas revenues are recognized when title and risk pass to the
purchaser, normally at the pipeline delivery point.
h) Cash and cash equivalents
Cash and cash equivalents includes short-term investments, such as money market
deposits or similar type instruments, with maturity of three months or less when
purchased.
i) Income taxes
The Company follows the asset and liability method of accounting for future
income taxes, whereby temporary differences arising from the difference between
the tax basis of an asset or liability and its carrying amount on the balance
sheet are used to calculate future income tax liabilities or assets. Future
income tax liabilities or assets are calculated using tax rates anticipated to
apply in the periods that the temporary differences are expected to reverse.
j) Per share information
Per share information is computed using the weighted average number of common
shares outstanding during the period. Diluted per share information is
calculated using the treasury stock method, which assumes that any proceeds from
the exercise of stock options, warrants, and other instruments would be used to
purchase common shares at the average market price during the period. No
adjustment to diluted earnings per share is made if the result of these
calculations is anti-dilutive.
k) Financial instruments
Financial assets, financial liabilities and non-financial derivatives are
measured at fair value on initial recognition. Measurement in subsequent periods
depends on whether the financial instrument has been classified as
held-for-trading, available-for-sale, held-to-maturity, loans and receivables,
or other financial liabilities. Financial assets and financial liabilities
classified as "held-for-trading" are measured at fair value with changes in
those fair values recognized in net earnings. Financial assets classified as
"available-for-sale" are measured at fair value, with changes in those fair
values recognized in other comprehensive income ("OCI"). Financial assets
classified as "held-to-maturity", "loans and receivables" and "other financial
liabilities" are measured at amortized cost using the effective interest method
of amortization.
Cash and cash equivalents are designated as "held-for-trading" and are measured
at carrying value, which approximates fair value due to the short-term nature of
these instruments. Investments are designated as "held-for-trading" and are
measured at fair value. Accounts receivable and deposits are designated as
"loans and receivables" and accounts payable, accrued liabilities, and credit
facilities are designated as "other financial liabilities".
Risk management assets and liabilities are derivative financial instruments
classified as "held-for-trading" unless designated for hedge accounting.
Derivative financial instruments that do not qualify as hedges, or are not
designated as hedges, are recorded using the mark-to-market method of accounting
whereby instruments are recorded in the balance sheet as either an asset or
liability with changes in fair value recognized in net earnings. Derivative
financial instruments are used by the Company to manage economic exposure to
market risks relating to commodity prices. Crocotta's policy is not to utilize
derivative financial instruments for speculative purposes.
l) Use of estimates
The amounts recorded for depletion and depreciation, asset retirement
obligations, stock-based compensation, purchase accounting for acquisitions,
held-for-trading derivative financial instruments, and the amounts used in
impairment test calculations are based on estimates of proved reserves,
production rates, oil and natural gas prices, future costs, and other relevant
assumptions. By their nature, these estimates are subject to change and the
effect on the financial statements of changes in such estimates in future
periods could be significant.
2. ACQUISITIONS
a) Salvo Energy Corporation
On August 13, 2009, the Company closed a business combination (the
"Acquisition") whereby it acquired all of the issued and outstanding shares of
Salvo Energy Corporation ("Salvo"). Prior to the Acquisition, Salvo acquired
certain oil and natural gas assets from an Alberta-based company on July 31,
2009 (the "Asset Acquisition"). Consideration for the Asset Acquisition was cash
of approximately $37.8 million which was financed through a secured bridge loan
facility to Salvo and an increase to Crocotta's revolving operating demand loan
credit facility. Salvo obtained a $25.0 million secured bridge facility (note
5), proceeds from which were used to repay Salvo's existing credit facility and
to partially fund the Asset Acquisition. Crocotta obtained an increase in its
revolving operating demand loan credit facility (note 5) and advanced Salvo
$29.8 million (prior to the close of the Acquisition) to facilitate the close of
the Asset Acquisition.
The following table details the purchase price allocation for the Acquisition:
Net assets acquired Amount
----------------------------------------------------------------------------
Oil and natural gas properties and equipment 84,544
Working capital, including cash of $0.1 million 286
Due to Crocotta (29,750)
Bridge facility (25,000)
Asset retirement obligation (6,531)
Future income tax asset 78
----------------------------------------------------------------------------
23,627
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consideration of acquisition
----------------------------------------------------------------------------
Issuance of 19,898,760 common shares (note 8(b)) 23,083
Transaction costs 544
----------------------------------------------------------------------------
23,627
----------------------------------------------------------------------------
The results of operations include net revenue from this transaction effective
August 13, 2009.
b) Private Company
On November 5, 2008, the Company closed a business combination whereby it
acquired all of the issued and outstanding shares of a private company
("PrivateCo"). At the time of the business combination, the Company agreed to
pay additional consideration to the PrivateCo shareholders in the event the oil
and natural gas properties acquired from PrivateCo were sold within 12 months of
closing of the business combination for an amount exceeding $3.0 million. Any
proceeds received by Crocotta in excess of $3.0 million were to be paid to
PrivateCo shareholders as follows:
(a) 70% of the proceeds between $3.0 million and $5.0 million; and
(b) 50% of the proceeds above $5.0 million.
In accordance with accounting principles generally accepted in Canada, the
Company recorded a deferred gain in the financial statements as at December 31,
2008 to reflect the potential liability to pay the additional consideration. The
oil and natural gas properties acquired were not sold within 12 months of
closing of the business combination. As a result, the Company removed the
previously recorded deferred gain from the balance sheet and recorded an
extraordinary gain to earnings in the year ended December 31, 2009.
3. PROPERTY DISPOSITIONS
2010
During the year ended December 31, 2010, the Company sold certain oil and
natural gas properties to five unrelated parties for cash proceeds of
approximately $50.6 million and warrants valued at approximately $0.2 million
(note 10(a)). The following table details the allocation of the proceeds on
disposition:
Net assets disposed Amount
----------------------------------------------------------------------------
Oil and natural gas properties 52,045
Asset retirement obligation (1,239)
----------------------------------------------------------------------------
50,806
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2009
During the year ended December 31, 2009, the Company sold certain oil and
natural gas properties to nine unrelated parties for cash proceeds of
approximately $10.6 million. The following table details the allocation of the
proceeds on disposition:
Net assets disposed Amount
----------------------------------------------------------------------------
Oil and natural gas properties 11,699
Asset retirement obligation (1,146)
----------------------------------------------------------------------------
10,553
----------------------------------------------------------------------------
----------------------------------------------------------------------------
4. OIL AND NATURAL GAS PROPERTIES AND EQUIPMENT
2010 2009
----------------------------------------------------------------------------
Oil and natural gas properties 279,882 302,070
Office and other equipment 347 347
----------------------------------------------------------------------------
280,229 302,417
Accumulated depletion and depreciation (79,211) (56,855)
----------------------------------------------------------------------------
Net book value 201,018 245,562
----------------------------------------------------------------------------
At December 31, 2010, the cost of oil and natural gas properties includes
approximately $29.5 million (December 31, 2009 - $36.4 million) relating to
properties from which there is no production and no reserves assigned and which
have been excluded from costs subject to depletion and depreciation. During the
year ended December 31, 2010, the provision for depletion, depreciation and
accretion includes $0.7 million (2009 - $0.5 million) for accretion of asset
retirement obligations. During the year ended December 31, 2010, the Company
capitalized $0.5 million (2009 - $0.7 million) of general and administrative
costs and $0.2 million (2009 - $0.3 million) of stock-based compensation.
The Company performed an impairment test calculation at December 31, 2010 to
assess the recoverable value of the oil and natural gas properties. The oil and
natural gas future prices are based on January 1, 2011 commodity price forecasts
of the Company's independent reserve evaluators. These prices have been adjusted
for commodity price differentials specific to the Company. The following table
summarizes the benchmark prices used in the impairment test calculation. Based
on these assumptions, there was no impairment at December 31, 2010.
Foreign Edmonton Light
WTI Oil Exchange Crude Oil AECO Gas
Year ($US/bbl) Rate ($Cdn/bbl) ($Cdn/mmbtu)
----------------------------------------------------------------------------
2011 88.00 0.980 86.22 4.16
2012 89.00 0.980 89.29 4.74
2013 90.00 0.980 90.92 5.31
2014 92.00 0.980 92.96 5.77
2015 95.17 0.980 96.19 6.22
2016 97.55 0.980 98.62 6.53
2017 100.26 0.980 101.39 6.76
2018 102.74 0.980 103.92 6.90
2019 105.45 0.980 106.68 7.06
2020 107.56 0.980 108.84 7.21
Escalate
Thereafter 2.0% per year 2.0% per year 2.0% per year
----------------------------------------------------------------------------
----------------------------------------------------------------------------
5. CREDIT FACILITIES
At December 31, 2010, the Company had total credit facilities of $55.0 million,
consisting of a $55.0 million revolving operating demand loan credit facility
with a Canadian chartered bank. The demand loan credit facility bears interest
at prime plus a range of 0.75% to 2.50% and is secured by a $235 million fixed
and floating charge debenture on the assets of the Company. At December 31,
2010, $35.4 million (December 31, 2009 - $52.4 million) had been drawn on the
demand loan credit facility. The next review of the demand loan credit facility
by the bank is scheduled on or before March 31, 2011.
During the first quarter of 2010, the Company sold certain non-core oil and
natural gas properties for approximately $19.5 million (note 3). The majority of
the proceeds were used to retire the remaining balance on the secured bridge
facility during the first quarter of 2010. The secured bridge facility was
acquired in conjunction with the acquisition of Salvo in August 2009 (note
2(a)).
6. ASSET RETIREMENT OBLIGATIONS
The Company's asset retirement obligations result from net ownership interests
in oil and natural gas properties including well sites, gathering systems, and
processing facilities. The Company estimates the total undiscounted amount of
cash flows (adjusted for inflation at 2% per year) required to settle its asset
retirement obligations is approximately $27.0 million which is estimated to be
incurred between 2011 and 2041. A credit-adjusted risk-free rate of 7% was used
to calculate the fair value of the asset retirement obligations. A
reconciliation of the asset retirement obligations is provided below:
2010 2009
----------------------------------------------------------------------------
Balance, beginning of period 10,084 4,158
Liabilities acquired upon business combination (note 2) - 6,531
Liabilities incurred in period 175 135
Liabilities disposed through property dispositions (note 3) (1,239) (1,146)
Liabilities settled in period (868) (163)
Accretion expense 667 468
Revisions to estimate 714 101
----------------------------------------------------------------------------
Balance, end of period 9,533 10,084
----------------------------------------------------------------------------
----------------------------------------------------------------------------
7. TAXES
a) The recovery of income taxes on the statements of operations, comprehensive
loss, and retained earnings (deficit) differs from the amount that would be
computed by applying the expected tax rates to loss before income taxes. The
reasons for the difference between such expected income tax recovery and the
amount recorded are as follows:
2010 2009
----------------------------------------------------------------------------
Income tax rate 28.0% 29.0%
Expected income tax recovery (2,493) (5,428)
Increase (decrease) in income taxes resulting from:
Stock-based compensation and other non-deductible amounts 304 699
Rate reduction and other 450 582
Valuation allowance 251 -
----------------------------------------------------------------------------
(1,488) (4,147)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
b) The components of the net future income tax asset at December 31 are as
follows:
2010 2009
----------------------------------------------------------------------------
Future income tax assets (liabilities):
Oil and natural gas properties and equipment (7,406) (9,606)
Asset retirement obligations 2,383 2,521
Risk management contracts - 261
Share issue costs 119 401
Non-capital losses 8,300 7,916
Capital losses - 225
Valuation allowance (1,714) (1,463)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net future income tax asset 1,682 255
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company has accumulated non-capital losses for income tax purposes of
approximately $31.4 million (2009 - $31.1 million), which can be used to offset
income in future periods. These losses expire as follows:
Year of expiry Amount
----------------------------------------------------------------------------
2028 7,001
2027 4,490
2026 4,664
2025 8,066
2024 2,209
2023 4,772
2013 161
----------------------------------------------------------------------------
31,363
----------------------------------------------------------------------------
----------------------------------------------------------------------------
8. SHARE CAPITAL
a) Authorized
Unlimited number of voting common shares.
Unlimited number of non-voting common shares.
Class A preferred shares, issuable in series.
Class B preferred shares, issuable in series.
b) Issued and outstanding
Number Amount
----------------------------------------------------------------------------
Voting common shares
----------------------------------------------------------------------------
Balance at December 31, 2008 43,985 144,593
Issued upon acquisition of Salvo (note 2) 19,899 23,083
Private placement 1,200 1,260
Share issue costs, net of future tax effect - (26)
Future tax effect of flow-through share renunciation - (2,278)
----------------------------------------------------------------------------
Balance at December 31, 2009 65,084 166,632
Exercise of stock options 58 126
----------------------------------------------------------------------------
Balance at December 31, 2010 65,142 166,758
----------------------------------------------------------------------------
----------------------------------------------------------------------------
c) Contributed surplus
Year Ended Year Ended
December 31, 2010 December 31, 2009
----------------------------------------------------------------------------
Balance, beginning of year 3,714 1,002
Stock-based compensation - expensed 1,086 2,403
Stock-based compensation - capitalized 185 309
Exercise of stock options (51) -
----------------------------------------------------------------------------
Balance, end of year 4,934 3,714
----------------------------------------------------------------------------
d) Warrants
The Company has an arrangement that allows warrants to be issued to directors,
officers, and employees. The maximum number of common shares that may be issued,
and that have been reserved for issuance under this arrangement, is 2.4 million.
Warrants granted under this arrangement vest over three years and have exercise
prices ranging from $3.75 per share to $6.75 per share. During the year ended
December 31, 2007, the Company issued 2.4 million warrants under this
arrangement. The fair value of the warrants granted under this arrangement at
the date of issue was determined to be $nil using the minimum value method as
they were issued prior to the Company becoming publicly traded. During 2009,
approval was obtained to extend the expiry date of the warrants to December 23,
2012.
Weighted
Number of Average
Warrants Price ($)
----------------------------------------------------------------------------
Balance at December 31, 2008 and 2009 2,404 4.80
Forfeited (83) 4.75
----------------------------------------------------------------------------
Balance at December 31, 2010 2,321 4.80
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Exercisable at December 31, 2010 2,321 4.80
----------------------------------------------------------------------------
On October 29, 2009, the Company issued an additional 1.2 million warrants at an
exercise price of $1.40 per share in conjunction with a private placement share
issuance. The warrants vested immediately and have an expiry date of October 29,
2012. The fair value of the warrants granted under this arrangement was
determined using the Black-Scholes option-pricing model (note 8(f)).
Weighted
Number of Average
Warrants Price ($)
----------------------------------------------------------------------------
Balance at December 31, 2008 - -
Granted 1,200 1.40
----------------------------------------------------------------------------
Balance at December 31, 2009 and 2010 1,200 1.40
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Exercisable at December 31, 2010 1,200 1.40
----------------------------------------------------------------------------
e) Stock options
The Company has authorized and reserved for issuance 6.5 million common shares
under a stock option plan enabling certain officers, directors, employees, and
consultants to purchase common shares. The Company will not issue options
exceeding 10% of the shares outstanding at the time of the option grants. Under
the plan, the exercise price of each option equals the market price of the
Company's shares on the date of the grant. The options vest over a period of 3
years and an option's maximum term is 5 years. As at December 31, 2010, 3.9
million options have been granted and are outstanding at exercise prices ranging
from $1.10 to $2.10 per share with expiry dates ranging from November 9, 2013 to
November 4, 2015.
Weighted
Number of Average
Options Price ($)
----------------------------------------------------------------------------
Balance at December 31, 2008 3,045 3.00
Granted 3,027 1.16
----------------------------------------------------------------------------
Balance at December 31, 2009 6,072 2.08
Granted 1,235 1.48
Exercised (58) 1.31
Forfeited (773) 2.19
Cancelled (2,599) 3.01
----------------------------------------------------------------------------
Balance at December 31, 2010 3,877 1.26
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Exercisable at December 31, 2010 971 1.22
----------------------------------------------------------------------------
Subsequent to December 31, 2010, the Company issued 2.5 million options at an
exercise price of $2.37 per share.
f) Stock-based compensation
Stock Options
The compensation cost charged to earnings during the year ended December 31,
2010 for the stock option plan was $1.1 million (2009 - $1.1 million).
The Company granted 1.2 million options during the year ended December 31, 2010
(2009 - 3.0 million). The fair value of each option granted during the year
ended December 31, 2010 was determined using the Black-Scholes option-pricing
model with the following weighted average assumptions:
Year Ended Year Ended
December 31, 2010 December 31, 2009
----------------------------------------------------------------------------
Fair value per option $0.94 $0.80
Risk-free rate 1.9% 2.0%
Expected life 4.0 years 4.0 years
Expected volatility 88.1% 99.3%
Dividend yield - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Warrants
There were no warrants issued during 2010. The compensation cost charged to
earnings during the year ended December 31, 2009 for warrants issued was $1.3
million.
During 2009, the Company extended the term of 2.4 million warrants issued in
2007 and issued 1.2 million warrants (note 8(d)). The fair value of the each
warrant extended and each warrant granted during the year ended December 31,
2009 was determined using the Black-Scholes option-pricing model with the
following weighted average assumptions:
Year Ended
December 31, 2009
----------------------------------------------------------------------------
Fair value per warrant $0.39
Risk-free rate 1.6%
Expected life 3.5 years
Expected volatility 102.6%
Dividend yield -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
g) Per share information
The weighted average number of shares outstanding for the determination of
basic and diluted per share amounts are as follows:
Year Ended Year Ended
December 31, 2010 December 31, 2009
----------------------------------------------------------------------------
Basic 65,129 51,883
Diluted 65,412 51,883
----------------------------------------------------------------------------
The weighted average number of shares outstanding for the determination of basic
and diluted per share amounts are as follows:
9. CAPITAL DISCLOSURES
The Company's objectives when managing capital are to maintain a flexible
capital structure, which optimizes the cost of capital at an acceptable risk,
and to maintain investor, creditor, and market confidence to sustain 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
assets. The Company considers its capital structure to include shareholders'
equity and net debt (current liabilities, including the revolving credit
facility and secured bridge facility and excluding the risk management
contracts, less current assets). To maintain or adjust the capital structure,
the Company may, from time to time, issue shares, raise debt, and/or adjust its
capital spending to manage its current and projected debt levels.
December 31, 2010 December 31, 2009
----------------------------------------------------------------------------
Shareholders' equity 157,967 164,035
Net debt 35,200 70,656
----------------------------------------------------------------------------
In addition, management prepares annual, quarterly, and monthly budgets, which
are updated depending on varying factors such as general market conditions and
successful capital deployment.
The Company's share capital is not subject to external restrictions; however,
the Company's revolving operating demand loan credit facility includes a
covenant requiring the Company to maintain a working capital ratio of not less
than one-to-one. The working capital ratio, as defined by its creditor, is
calculated as current assets plus any undrawn amounts available on its credit
facilities less current liabilities excluding any current portion drawn on the
credit facility. The Company was fully compliant with this covenant at December
31, 2010.
There were no changes in the Company's approach to capital management from the
previous year.
10. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
The Company is exposed to market risks related to the volatility of commodity
prices, foreign exchange rates, and interest rates. The Company employs risk
management strategies and policies to ensure that any exposure to risk is in
compliance with the Company's business objectives and risk tolerance levels.
Risk management is ultimately established by the Board of Directors and is
implemented by management.
a) Fair value of financial instruments
The Company's financial assets and financial liabilities are comprised of cash
and cash equivalents, accounts receivable, prepaid expenses and deposits,
investments, accounts payable and accrued liabilities, risk management
contracts, and amounts drawn on the revolving credit facility (note 5). The fair
values of the Company's financial assets and financial liabilities, excluding
investments, approximate their carrying amount due to the short-term maturity of
these instruments. The Company is required to classify fair value measurements
using a hierarchy that reflects the significance of the inputs used in making
the measurements. The fair value hierarchy is as follows:
- Level 1 - quoted prices in active markets for identical assets or liabilities;
- Level 2 - inputs other than quoted prices included in Level 1 that are
observable for the asset or liability, either directly or indirectly; and
- Level 3 - inputs for the asset or liability that are not based on observable
market data
The fair value of investments is considered to be level 2. Investments include
875,000 warrants of Hyperion Exploration Corp. ("Hyperion") at an exercise price
of $2.00 per warrant. Each warrant is convertible into one common share of
Hyperion and expires on November 7, 2011. The warrants were obtained as partial
consideration for the sale of certain oil and natural gas assets to Hyperion in
the fourth quarter of 2010 (note 3). The investment has been classified as held
for trading and is measured at fair value each reporting period using the
Black-Scholes option-pricing model. Based on Hyperion's closing trading price on
December 31, 2010 of $1.60 per share, an unrealized loss was recognized for the
year on the revaluation of warrants at December 31, 2010. The fair value of each
warrant was determined using the Black-Scholes option-pricing model with the
following assumptions:
November 8, 2010 December 31, 2010
----------------------------------------------------------------------------
Fair value per warrant $0.19 $0.09
Risk-free rate 1.5% 1.7%
Expected life 1.0 year 0.9 years
Expected volatility 35.0% 35.0%
Dividend yield - -
----------------------------------------------------------------------------
b) Market risk
Market risk is the risk that the fair value of future cash flows of a financial
instrument will fluctuate because of changes in market prices. Market risk is
comprised of foreign currency risk, interest rate risk, and other price risk,
such as commodity price risk. The objective of market risk management is to
manage and control market price exposures within acceptable limits, while
maximizing returns.
Foreign exchange risk
The prices received by the Company for the production of crude oil, natural gas,
and NGLs are primarily determined in reference to U.S. dollars, but are settled
with the Company in Canadian dollars. The Company's cash flow from commodity
sales will therefore be impacted by fluctuations in foreign exchange rates. A
$0.01 increase or decrease in the Canadian/U.S. dollar exchange rate would have
impacted net earnings and other comprehensive income by approximately $0.2
million for the year ended December 31, 2010 (2009 - $0.2 million).
Interest rate risk
The Company is exposed to interest rate risk as it borrows funds at floating
interest rates (note 5). In addition, the Company may at times issue shares on a
flow-through basis. This results in the Company being exposed to interest rate
risk to the Canada Revenue Agency for interest on unexpended funds on the
Company's flow-through share obligations. The Company currently does not use
interest rate hedges or fixed interest rate contracts to manage the Company's
exposure to interest rate fluctuations. A 100 basis point increase or decrease
in interest rates would have impacted net earnings and other comprehensive
income by approximately $0.4 million for the year ended December 31, 2010 (2009
- $0.4 million).
Commodity price risk
The Company's oil, natural gas, and NGLs production is marketed and sold on the
spot market to area aggregators based on daily spot prices that are adjusted for
product quality and transportation costs. The Company's cash flow from product
sales will therefore be impacted by fluctuations in commodity prices. From time
to time the Company may attempt to mitigate commodity price risk through the use
of financial derivatives.
At December 31, 2010, the Company did not have any risk management contracts
outstanding. During 2010, the Company had the following risk management
contracts:
Product Period Production Floor Price
----------------------------------------------------------------------------
Oil January 2010 - December 2010 1,000 bbls/d WTI CDN $50.00/bbl
Gas January 2010 - December 2010 10.0 mmcf/d AECO CDN $4.00/mcf
----------------------------------------------------------------------------
----------------------------------------------------------------------------
For the year ended December 31, 2010, the realized loss on the risk management
contracts was $0.6 million (2009 - $0.2 million realized gain) and the
unrealized gain on the risk management contracts was $1.0 million (2009 - $1.0
million unrealized loss).
A $1.00/boe increase or decrease in commodity prices would have impacted net
earnings and other comprehensive income by approximately $0.6 million for the
year ended December 31, 2010 (2009 - $0.5 million).
c) Credit risk
Credit risk represents the financial loss that the Company would suffer if the
Company's counterparties to a financial instrument, in owing an amount to the
Company, fail to meet or discharge their obligation to the Company. A
substantial portion of the Company's accounts receivable and deposits are with
customers and joint venture partners in the oil and natural gas industry and are
subject to normal industry credit risks. The Company generally grants unsecured
credit but routinely assesses the financial strength of its customers and joint
venture partners.
The Company sells the majority of its production to three petroleum and natural
gas marketers and therefore is subject to concentration risk. Historically, the
Company has not experienced any collection issues with its petroleum and natural
gas marketers. Joint venture receivables are typically collected within one to
three months of the joint venture invoice being issued to the partner. The
Company attempts to mitigate the risk from joint venture receivables by
obtaining partner approval for significant capital expenditures prior to the
expenditure being incurred. The Company does not typically obtain collateral
from petroleum and natural gas marketers or joint venture partners; however, in
certain circumstances, the Company may cash call a partner in advance of
expenditures being incurred.
The maximum exposure to credit risk is represented by the carrying amount on the
balance sheet. At December 31, 2010, there are no material financial assets that
the Company considers impaired.
d) Liquidity risk
Liquidity risk is the risk that the Company will not be able to meet its
financial obligations as they become due. The Company's processes for managing
liquidity risk include ensuring, to the extent possible, that it will have
sufficient liquidity to meet its liabilities when they become due. The Company
prepares annual, quarterly, and monthly capital expenditure budgets, which are
monitored and updated as required, and requires authorizations for expenditures
on projects to assist with the management of capital. In managing liquidity
risk, the Company ensures that it has access to additional financing, including
potential equity issuances and additional debt financing. The Company also
mitigates liquidity risk by maintaining an insurance program to minimize
exposure to insurable losses.
The following are the contractual maturities of financial liabilities at
December 31, 2010:
Less than 1 to less than
Financial Liability 1 Year 2 Years Thereafter Total
----------------------------------------------------------------------------
Accounts payable and
accrued liabilities 10,930 - - 10,930
Revolving credit facility 35,386 - - 35,386
----------------------------------------------------------------------------
46,316 - - 46,316
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year Ended Year Ended
December 31, 2010 December 31, 2009
----------------------------------------------------------------------------
Accounts receivable (5,117) 940
Prepaid expenses and deposits 565 9
Accounts payable and accrued liabilities 4,533 (5,899)
Non-cash working capital deficiency acquired on
Acquisitions (note 2) 183
----------------------------------------------------------------------------
Net change in non-cash working capital (19) (4,767)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Relating to:
Investing 724 (5,717)
Operating (743) 950
----------------------------------------------------------------------------
Net change in non-cash working capital (19) (4,767)
----------------------------------------------------------------------------
b) Interest and taxes
Year Ended Year Ended
December 31, 2010 December 31, 2009
----------------------------------------------------------------------------
Cash interest received 352 90
Cash interest paid (2,846) (2,808)
----------------------------------------------------------------------------
(2,494) (2,718)
Cash taxes paid - -
----------------------------------------------------------------------------
12. COMMITMENTS
The following is a summary of the Company's contractual obligations and
commitments at December 31, 2010:
2011 2012 2013 2014 2015 Thereafter Total
----------------------------------------------------------------------------
Office leases 662 135 45 - - - 842
Field equipment leases 686 619 232 - - - 1,537
Firm transportation agreements 491 457 178 117 28 12 1,283
Capital processing agreements - - - - - 400 400
----------------------------------------------------------------------------
1,839 1,211 455 117 28 412 4,062
----------------------------------------------------------------------------
13. SUBSEQUENT EVENT
Subsequent to December 31, 2010, the Company issued approximately 15.6 million
common shares at a price of $2.30 per share for gross proceeds of approximately
$36.0 million. The proceeds will be used to fund the Company's Edson Bluesky and
Dawson Montney developments and other capital projects and for general corporate
purposes.
CORPORATE INFORMATION
OFFICERS AND DIRECTORS
Robert J. Zakresky, CA BANK
President, CEO & Director National Bank of Canada
2700, 530 - 8th Avenue SW
Nolan Chicoine, MPAcc, CA Calgary, Alberta T2P 3S8
VP Finance & CFO
Terry L. Trudeau, P.Eng.
VP Operations & COO TRANSFER AGENT
Valiant Trust Company
Weldon Dueck, BSc., P.Eng. 310, 606 - 4th Street SW
VP Business Development Calgary, Alberta T2P 1T1
R.D. (Rick) Sereda, M.Sc., P.Geol.
VP Exploration
LEGAL COUNSEL
Helmut R. Eckert, P.Land Gowling Lafleur Henderson LLP
VP Land 1400, 700 - 2nd Street SW
Calgary, Alberta T2P 4V5
Kevin Keith
VP Production
Larry G. Moeller, CA, CBV AUDITORS
Chairman of the Board KPMG LLP
2700, 205 - 5th Avenue SW
Daryl H. Gilbert, P.Eng. Calgary, Alberta T2P 4B9
Director
Don Cowie
Director INDEPENDENT ENGINEERS
GLJ Petroleum Consultants Ltd.
Brian Krausert 4100, 400 - 3rd Avenue SW
Director Calgary, Alberta T2P 4H2
Gary W. Burns
Director
Don D. Copeland, P.Eng.
Director
Brian Boulanger
Director
Patricia Phillips
Director
Armadillo Resources Ltd (TSXV:ARO)
Historical Stock Chart
From Apr 2024 to May 2024
Armadillo Resources Ltd (TSXV:ARO)
Historical Stock Chart
From May 2023 to May 2024
