CROCOTTA ENERGY INC. (TSX:CTA) is pleased to announce its financial and
operating results for the year ended December 31, 2013, including consolidated
financial statements, notes to the consolidated financial statements, and
Management's Discussion and Analysis. All dollar figures are Canadian dollars
unless otherwise noted.
HIGHLIGHTS
-- Increased average production 26% to 8,724 boepd in 2013 from 6,911 boepd
in 2012
-- Increased netbacks to $27.49 per boe in Q4 2013 versus $21.50 per boe
average in 2012
-- Reduced operating costs to $4.72 per boe in Q4 2013 (excluding 2012
adjustments relating to third party processing facilities) versus $5.83
per boe average in 2012
-- Reduced operating costs at its core Edson AB property to approximately
$4.00 per boe in Q4 2013 (excluding 2012 adjustments relating to third
party processing facilities) versus $5.11 per boe average in 2012
-- Increased proved plus probable reserves 22% to 46.3 Mmboe in 2013 from
38.1 Mmboe in 2012
-- Increased funds from operations 33% to $67.2 million in 2013 from $50.6
million in 2012
-- Drilled 14.5 net Cardium and Bluesky wells at Edson, AB at a 100%
success rate
-- Drilled 3.0 net Montney wells in Northeast BC at a 100% success rate
-- Entered into a $150 million syndicated credit facility
FINANCIAL RESULTS
Three Months Ended Year Ended
December 31 December 31
($000s, except per
share amounts) 2013 2012 % Change 2013 2012 % Change
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Oil and natural gas
sales 31,090 24,938 25 111,459 80,518 38
Funds from operations
(1) 19,691 14,478 36 67,197 50,615 33
Per share - basic 0.20 0.16 25 0.72 0.57 26
Per share - diluted 0.20 0.16 25 0.71 0.56 27
Net earnings (loss) 4,387 (2,082) 311 11,570 (5,254) 320
Per share - basic 0.05 (0.02) 350 0.12 (0.06) 300
Per share - diluted 0.04 (0.02) 300 0.12 (0.06) 300
Capital expenditures 32,659 36,320 (10) 127,270 98,548 29
Property acquisitions - 5,406 (100) - 5,406 (100)
Net debt (2) 117,840 80,112 47
Common shares
outstanding (000s)
Weighted average -
basic 96,306 88,980 8 93,051 88,319 5
Weighted average -
diluted 98,197 91,522 7 94,973 90,705 5
End of period - basic 96,712 89,261 8
End of period -
diluted 105,561 100,183 5
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(1) Funds from operations and funds from operations per share do not have
any standardized meaning prescribed by IFRS 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 from cash flow
from operating activities.
(2) Net debt includes current liabilities (excluding risk management
contracts) and the credit facility less current assets. Net debt does
not have any standardized meaning prescribed by IFRS 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.
OPERATING RESULTS Three Months Ended Year Ended
December 31 December 31
2013 2012 % Change 2013 2012 % Change
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Daily production
Oil and NGLs (bbls/d) 2,605 2,476 5 2,488 2,227 12
Natural gas (mcf/d) 39,767 29,160 36 37,416 28,099 33
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Oil equivalent
(boe/d) 9,233 7,336 26 8,724 6,911 26
Revenue
Oil and NGLs ($/bbl) 74.62 67.55 10 71.67 64.81 11
Natural gas ($/mcf) 3.61 3.56 1 3.40 2.69 26
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Oil equivalent
($/boe) 36.60 36.95 (1) 35.00 31.83 10
Royalties
Oil and NGLs ($/bbl) 7.38 7.14 3 7.98 9.17 (13)
Natural gas ($/mcf) 0.06 0.17 (65) 0.09 0.14 (36)
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Oil equivalent
($/boe) 2.34 3.07 (24) 2.64 3.52 (25)
Production expenses
Oil and NGLs ($/bbl) 6.26 5.96 5 6.01 5.31 13
Natural gas ($/mcf) 0.93 1.11 (16) 1.08 1.01 7
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Oil equivalent
($/boe) 5.78 6.41 (10) 6.33 5.83 9
Transportation
expenses
Oil and NGLs ($/bbl) 1.15 0.95 21 1.30 0.87 49
Natural gas ($/mcf) 0.15 0.15 - 0.13 0.17 (24)
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Oil equivalent
($/boe) 0.99 0.90 10 0.95 0.98 (3)
Operating netback (1)
Oil and NGLs ($/bbl) 59.83 53.50 12 56.38 49.46 14
Natural gas ($/mcf) 2.47 2.13 16 2.10 1.37 53
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Oil equivalent
($/boe) 27.49 26.57 3 25.08 21.50 17
Depletion and
depreciation ($/boe) (14.64) (13.49) 9 (14.01) (14.50) (3)
Asset impairment
($/boe) (0.30) (11.47) (97) (0.25) (5.31) (95)
General and
administrative
expenses ($/boe) (2.06) (3.87) (47) (1.89) (2.17) (13)
Share based
compensation ($/boe) (0.80) (1.01) (21) (0.65) (1.39) (53)
Finance expenses
($/boe) (1.42) (0.85) 67 (1.40) (0.75) 87
Deferred tax reduction
(expense) ($/boe) (2.83) 0.44 743 (2.76) (0.07) 3,843
Realized gain (loss)
on risk management
contracts ($/boe) (1.02) (0.59) 73 (0.88) 1.25 (170)
Unrealized gain (loss)
on risk management
contracts ($/boe) 0.75 1.18 (36) 0.38 (0.63) 160
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Net earnings (loss)
($/boe) 5.17 (3.09) (267) 3.62 (2.07) (275)
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(1) Operating netback does not have any standardized meaning prescribed by
IFRS 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
Crocotta's goals for 2013 were to continue to expand core areas, add new core
areas, and improve netbacks by increasing efficiencies.
The focus on efficiencies resulted in increasing netbacks on our Edson property
by over $5 per boe and increasing netbacks on our Dawson Montney property by
over $6 per boe. At Edson, Crocotta moved substantially all of its liquids-rich
production to the Alliance system and signed an agreement with Aux Sable for its
liquids production. This resulted in higher liquids pricing and reduced
operating costs that contributed to the $5 per boe increase in netbacks. By
comparison, Edson's netbacks improved by 22% from $25.37 per boe in Q1-Q3 2013
to $30.88 per boe in Q4 2013. At Dawson, Crocotta commissioned its sweet gas
plant in late Q3 2013 and started to see the benefits in Q4 2013 through reduced
operating costs and increased liquids yields. Operating costs were reduced from
$10.50 per boe in Q1-Q3 2013 to $6.30 per boe in Q4 2013 and overall netback
improved by 71% from $13.85 per boe in Q1-Q3 2013 to $23.65 per boe in Q4 2013.
Core properties received a high portion of the capital allocation with Edson
seeing 45% of total capital spent to expand the Cardium drilling inventory and
to augment the infrastructure. Crocotta drilled 14 gross (12.3 net) Cardium
wells while increasing drilling inventory to 67.5 net wells despite drilling
12.3 net wells of the opening 2013 Cardium inventory. 3 gross (3.0 net) wells
were drilled at Dawson-Sunrise in the Montney to further prove up lands for
future development and infrastructure was put in place to enhance netbacks. For
2014, Edson will continue to see a substantial portion of the capital budget,
however, this will shift more to the Montney for Q4 2014 and beyond.
Capital of $13.2 million was spent on new initiatives including a light oil play
at Stoddart in Northeast British Columbia. Crocotta has drilled one horizontal
well with encouraging results and plans to put this well on production in Q3
2014 to test commerciality of the play. Crocotta has accumulated approximately
45 prospective sections on this regional oil play.
For 2014, Crocotta will take the same approach as in 2013 to expand core areas,
develop new core areas, and focus on improving netbacks.
During Q1 2014, average production is estimated at approximately 9,000 boepd
which was slightly lower than forecasted. A number of factors affected the
production including delays in bringing on new Montney wells, operational
difficulties with the new Montney facility, and pipeline construction delays.
Rob Zakresky, President & Chief Executive Officer
MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A")
March 20, 2014
The MD&A should be read in conjunction with the audited consolidated financial
statements and related notes for the years ended December 31, 2013 and 2012. The
audited consolidated financial statements and financial data contained in the
MD&A have been prepared in accordance with International Financial Reporting
Standards ("IFRS") in Canadian currency (except where noted as being in another
currency).
DESCRIPTION OF BUSINESS
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".
FREQUENTLY RECURRING TERMS
The Company uses the following frequently recurring industry terms in the MD&A:
"bbls" refers to barrels, "mcf" refers to thousand cubic feet, and "boe" refers
to barrel of oil equivalent. Disclosure provided herein in respect of a 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 equivalent has been used
for the calculation of boe amounts in the MD&A. This boe conversion rate 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 MD&A refers to certain financial measures that are not determined in
accordance with IFRS (or "GAAP"). This MD&A 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 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 and depreciation, asset
impairments, share based compensation, non-cash finance expenses, unrealized
gains and losses on risk management contracts, and deferred income taxes) and
excludes the change in non-cash working capital related to operating activities
and expenditures on decommissioning obligations. 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 from 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 (excluding risk management
contracts) and the credit facility less current assets.
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".
2013 HIGHLIGHTS
-- Increased average production 26% to 8,724 boepd in 2013 from 6,911 boepd
in 2012
-- Increased netbacks to $27.49 per boe in Q4 2013 versus $21.50 per boe
average in 2012
-- Reduced operating costs to $4.72 per boe in Q4 2013 (excluding 2012
adjustments relating to third party processing facilities) versus $5.83
per boe average in 2012
-- Reduced operating costs at its core Edson AB property to approximately
$4.00 per boe in Q4 2013 (excluding 2012 adjustments relating to third
party processing facilities) versus $5.11 per boe average in 2012
-- Increased proved plus probable reserves 22% to 46.3 Mmboe in 2013 from
38.1 Mmboe in 2012
-- Increased funds from operations 33% to $67.2 million in 2013 from $50.6
million in 2012
-- Drilled 14.5 net Cardium and Bluesky wells at Edson, AB at a 100%
success rate
-- Drilled 3.0 net Montney wells in Northeast BC at a 100% success rate
-- Entered into a $150 million syndicated credit facility
SUMMARY OF FINANCIAL RESULTS
Three Months Ended Year Ended
December 31 December 31
($000s, except per
share amounts) 2013 2012 2011 2013 2012 2011
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Oil and natural gas
sales 31,090 24,938 20,391 111,459 80,518 54,974
Funds from operations 19,691 14,478 12,115 67,197 50,615 30,608
Per share - basic 0.20 0.16 0.15 0.72 0.57 0.39
Per share - diluted 0.20 0.16 0.14 0.71 0.56 0.38
Net earnings (loss) 4,387 (2,082) (7,052) 11,570 (5,254) (5,592)
Per share - basic 0.05 (0.02) (0.09) 0.12 (0.06) (0.07)
Per share - diluted 0.04 (0.02) (0.09) 0.12 (0.06) (0.07)
Total assets 373,301 300,980 239,554
Total long-term
liabilities 158,610 21,852 20,063
Net debt 117,840 80,112 27,736
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The Company has experienced significant growth in oil and natural gas sales,
funds from operations, and net earnings over the past three years. Successful
capital activity during the previous three years at Edson, AB and Northeast BC
led to a significant increase in production which resulted in increased revenue,
funds from operations, and net earnings. The Company had a net loss in 2011 and
2012 mainly due to asset impairments recorded on non-core properties in each
year due to declines in commodity prices and limited capital activity in these
non-core areas to maintain reserves. Net debt increased significantly in 2013
due to capital expenditures of $127.3 million during the year, offset by an
equity financing that raised gross proceeds of $22.0 million and funds from
operations of $67.2 million. Net debt in 2012 was higher than 2011 due to
capital expenditures of $104.0 million, offset by funds from operations of $50.6
million.
PRODUCTION Three Months Ended Year Ended
December 31 December 31
2013 2012 % Change 2013 2012 % Change
----------------------------------------------------------------------------
Average Daily
Production
Oil and NGLs (bbls/d) 2,605 2,476 5 2,488 2,227 12
Natural gas (mcf/d) 39,767 29,160 36 37,416 28,099 33
----------------------------------------------------------------------------
Combined (boe/d) 9,233 7,336 26 8,724 6,911 26
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Daily production for the three months ended December 31, 2013 increased 26% to
9,233 boe/d compared to 7,336 boe/d for the comparative period in 2012. For the
year, daily production increased 26% to 8,724 boe/d in 2013 from 6,911 boe/d in
2012. The significant increase in production was due to successful drilling
activity at Edson, AB and Northeast BC during the past year. Compared to the
previous quarter, daily production increased 7% in Q4 2013 from 8,596 boe/d in
Q3 2013.
Crocotta's production profile for 2013 was comprised of 71% natural gas and 29%
oil and NGLs compared with the production profile for 2012 which was comprised
of 68% natural gas and 32% oil and NGLs. The increase in gas weighting is due to
a higher percentage of total production coming from Northeast BC in 2013
compared to 2012.
REVENUE Three Months Ended Year Ended
December 31 December 31
($000s) %
2013 2012 Change 2013 2012 % Change
----------------------------------------------------------------------------
Oil and NGLs 17,882 15,389 16 65,070 52,839 23
Natural gas 13,208 9,549 38 46,389 27,679 68
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Total 31,090 24,938 25 111,459 80,518 38
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Average Sales Price
----------------------------------------------------------------------------
Oil and NGLs ($/bbl) 74.62 67.55 10 71.67 64.81 11
Natural gas ($/mcf) 3.61 3.56 1 3.40 2.69 26
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Combined ($/boe) 36.60 36.95 (1) 35.00 31.83 10
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Revenue totaled $31.1 million for the fourth quarter of 2013, up 25% from $24.9
million in the comparative period. For the year, revenue increased 38% to $111.5
million in 2013 from $80.5 million in 2012. The increase in revenue was mainly
due to significant increases in production, combined with increases in oil,
NGLs, and natural gas commodity prices.
The following table outlines the Company's realized wellhead prices and industry
benchmarks:
Commodity Pricing Three Months Ended Year Ended
December 31 December 31
2013 2012 % Change 2013 2012 % Change
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Oil and NGLs
Corporate price
($CDN/bbl) 74.62 67.55 10 71.67 64.81 11
Edmonton par
($CDN/bbl) 86.38 84.43 2 93.27 86.57 8
West Texas
Intermediate
($US/bbl) 97.46 88.30 10 97.98 94.19 4
Natural gas
Corporate price
($CDN/mcf) 3.61 3.56 1 3.40 2.69 26
AECO price
($CDN/mcf) 3.52 3.22 9 3.13 2.39 31
Exchange rate
CDN/US dollar
average exchange
rate 0.9528 1.0093 (6) 0.9712 1.0009 (3)
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Differences between corporate and benchmark prices can be the result of quality
differences (higher or lower API oil and higher or lower heat content natural
gas), 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. The Company's corporate average oil
and NGLs prices were 86.4% and 76.8% of Edmonton Par price for the three months
and year ended December 31, 2013, respectively, up from 80.0% and 74.9% for the
respective comparative periods in 2012. The Company experienced an increase in
realized NGLs prices for a significant portion of its NGLs volumes at Edson, AB
and Northeast BC as they were transitioned to new marketing arrangements in June
2013 and September 2013, respectively, which allowed the Company to access
higher propane and butane prices in the United States. Corporate average natural
gas prices were 102.6% and 108.6% of AECO prices for the three months and year
ended December 31, 2013, respectively, down from 110.6% and 112.6% in the
respective comparative periods. The decreases in realized natural gas prices
were also due to gas volumes at Edson, AB and Northeast BC being transitioned to
the new marketing arrangements in 2013, which decreased the premium received on
the Company's natural gas production.
Future prices received from the sale of the products may fluctuate as a result
of market factors. In addition, the Company may enter into commodity price
contracts to manage future cash flows. For the year ended December 31, 2013, the
realized loss on the Company's oil contracts was $1.2 million and the realized
loss on the gas contracts was $1.6 million. For the year ended December 31,
2013, the unrealized loss on the oil contracts was $0.2 million and the
unrealized gain on the gas contracts was $1.4 million.
At December 31, 2013, the Company had the following commodity price contracts
outstanding:
Quantity
Commodity Period Type of Contract Contracted Contract Price
----------------------------------------------------------------------------
January 1, 2014 -
Oil December 31, 2014 Financial - Swap 500 bbls/d WTI CDN $100.80/bbl
January 1, 2014 -
Oil March 31, 2014 Financial - Swap 500 bbls/d WTI CDN $106.55/bbl
Natural April 1, 2014 -
Gas October 31, 2014 Financial - Swap 5,000 GJ/d AECO CDN $3.505/GJ
Natural April 1, 2014 -
Gas October 31, 2014 Financial - Swap 5,000 GJ/d AECO CDN $3.650/GJ
----------------------------------------------------------------------------
Subsequent to December 31, 2013, the Company entered into the following
commodity price contracts:
Quantity
Commodity Period Type of Contract Contracted Contract Price
----------------------------------------------------------------------------
April 1, 2014 -
Oil June 30, 2014 Financial - Swap 500 bbls/d WTI CDN $108.00/bbl
July 1, 2014 -
Oil September 30, 2014 Financial - Swap 500 bbls/d WTI CDN $110.00/bbl
Natural April 1, 2014 - 10,000
Gas October 31, 2014 Financial - Swap GJ/d AECO CDN $3.745/GJ
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ROYALTIES Three Months Ended Year Ended
December 31 December 31
($000s) % %
2013 2012 Change 2013 2012 Change
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Oil and NGLs 1,768 1,627 9 7,241 7,476 (3)
Natural gas 224 444 (50) 1,163 1,435 (19)
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Total 1,992 2,071 (4) 8,404 8,911 (6)
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Average Royalty Rate (%
of sales)
----------------------------------------------------------------------------
Oil and NGLs 9.9 10.6 (7) 11.1 14.1 (21)
Natural gas 1.7 4.6 (63) 2.5 5.2 (52)
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Combined 6.4 8.3 (23) 7.5 11.1 (32)
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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. The provincial government has also enacted various
royalty incentive programs that are available for wells that meet certain
criteria, such as natural gas deep drilling, which can result in fluctuations in
royalty rates.
For the three months ended December 31, 2013, oil, NGLs, and natural gas
royalties decreased 4% to $2.0 million from $2.1 million in the comparative
period. For the year ended December 31, 2013, oil, NGLs, and natural gas
royalties decreased to $8.4 million from $8.9 million in 2012. The overall
effective royalty rate was 6.4% for the three months ended December 31, 2013
compared to 8.3% for the three months ended December 31, 2012. For the year, the
overall effective royalty rate was 7.5% in 2013 compared to 11.1% in 2012. These
decreases were the result of royalty incentives received on new wells brought on
production during the year combined with an increase in the monthly capital cost
and processing fee deductions in 2013 compared to 2012.
PRODUCTION EXPENSES Three Months Ended Year Ended
December 31 December 31
%
2013 2012 Change 2013 2012 % Change
----------------------------------------------------------------------------
Oil and NGLs ($/bbl) 6.26 5.96 5 6.01 5.31 13
Natural gas ($/mcf) 0.93 1.11 (16) 1.08 1.01 7
----------------------------------------------------------------------------
Combined ($/boe) 5.78 6.41 (10) 6.33 5.83 9
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Per unit production expenses for the three months ended December 31, 2013 were
$5.78/boe, down 10% from $6.41/boe for the comparative period ended December 31,
2012. For the year ended December 31, 2013, per unit production expenses
increased 9% to $6.33/boe from $5.83/boe for the year ended December 31, 2012.
The increase in year-over-year production expenses is mainly due to higher costs
associated with wells brought on production in Northeast BC during 2012 and the
first part of 2013. Production expenses in this area were approximately
$10.00/boe due mainly to third party processing and throughput charges. During
the latter part of the third quarter of 2013, the Company completed the
expansion of its infrastructure in this area and as a result, production
expenses in Northeast BC decreased to approximately $6.00/boe. This decrease led
to production expenses per boe being lower in Q4 2013 compared to Q4 2012.
Year-to-date, production expenses in Edson, AB continued to be very competitive
at approximately $5.50/boe, declining in the latter half of the year as a result
of the transition to a new marketing arrangement. The Company continues to focus
on opportunities to maintain operational efficiencies to enhance operating
netbacks.
TRANSPORTATION Three Months Ended Year Ended
EXPENSES December 31 December 31
2013 2012 % Change 2013 2012 % Change
----------------------------------------------------------------------------
Oil and NGLs ($/bbl) 1.15 0.95 21 1.30 0.87 49
Natural gas ($/mcf) 0.15 0.15 - 0.13 0.17 (24)
----------------------------------------------------------------------------
Combined ($/boe) 0.99 0.90 10 0.95 0.98 (3)
----------------------------------------------------------------------------
Transportation expenses are mainly third-party pipeline tariffs incurred to
deliver production to the purchasers at main hubs. For the quarter ended
December 31, 2013 compared to the quarter ended December 31, 2012,
transportation expenses increased 10% to $0.99/boe from $0.90/boe. For the year,
transportation expenses decreased to $0.95/boe in 2013 from $0.98/boe in 2012.
Oil and NGLs transportation expenses were higher in 2013 compared to 2012 as a
result of the Company's production in Northeast BC being diverted to a different
processing facility from the second quarter through the third quarter of 2013 to
obtain credit for NGLs volumes that were not being extracted previously. During
September 2013, the Company transitioned production in Northeast BC to a new
marketing arrangement, which resulted in a decrease in oil and NGLs
transportation expenses from $1.93/boe in Q3 2013 to $1.15/boe in Q4 2013. The
decrease in natural gas transportation expenses per boe is due to obtaining a
lower contracted transportation fee in the fourth quarter of 2012 on the
majority of the Company's natural gas production. The Company shifted this
natural gas production to a new marketing arrangement during the second half of
2013 under which lower natural gas transportation expenses continued to be
realized.
OPERATING NETBACK Three Months Ended Year Ended
December 31 December 31
2013 2012 % Change 2013 2012 % Change
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Oil and NGLs ($/bbl)
Revenue 74.62 67.55 10 71.67 64.81 11
Royalties (7.38) (7.14) 3 (7.98) (9.17) (13)
Production expenses (6.26) (5.96) 5 (6.01) (5.31) 13
Transportation
expenses (1.15) (0.95) 21 (1.30) (0.87) 49
----------------------------------------------------------------------------
Operating netback 59.83 53.50 12 56.38 49.46 14
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Natural gas ($/mcf)
Revenue 3.61 3.56 1 3.40 2.69 26
Royalties (0.06) (0.17) (65) (0.09) (0.14) (36)
Production expenses (0.93) (1.11) (16) (1.08) (1.01) 7
Transportation
expenses (0.15) (0.15) - (0.13) (0.17) (24)
----------------------------------------------------------------------------
Operating netback 2.47 2.13 16 2.10 1.37 53
----------------------------------------------------------------------------
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Combined ($/boe)
Revenue 36.60 36.95 (1) 35.00 31.83 10
Royalties (2.34) (3.07) (24) (2.64) (3.52) (25)
Production expenses (5.78) (6.41) (10) (6.33) (5.83) 9
Transportation
expenses (0.99) (0.90) 10 (0.95) (0.98) (3)
----------------------------------------------------------------------------
Operating netback 27.49 26.57 3 25.08 21.50 17
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During the fourth quarter of 2013, Crocotta generated an operating netback of
$27.49/boe, an increase of 3% from $26.57/boe for the fourth quarter of 2012.
For the year ended December 31, 2013, Crocotta generated an operating netback of
$25.08/boe compared to $21.50/boe in the comparative period. The increases were
due to higher oil, natural gas, and NGLs commodity prices and decreases in
royalties. Operating netbacks in Q4 2013 increased from operating netbacks of
$24.08/boe in Q3 2013 due to increases in natural gas commodity prices and a
reduction in production expenses and transportation expenses.
The following is a reconciliation of operating netback per boe to net earnings
(loss) per boe for the periods noted:
Three Months Ended Year Ended
December 31 December 31
($/boe) 2013 2012 % Change 2013 2012 % Change
----------------------------------------------------------------------------
Operating netback 27.49 26.57 3 25.08 21.50 17
Depletion and
depreciation (14.64) (13.49) 9 (14.01) (14.50) (3)
Asset impairment (0.30) (11.47) (97) (0.25) (5.31) (95)
General and
administrative
expenses (2.06) (3.87) (47) (1.89) (2.17) (13)
Share based
compensation (0.80) (1.01) (21) (0.65) (1.39) (53)
Finance expenses (1.42) (0.85) 67 (1.40) (0.75) 87
Deferred tax reduction
(expense) (2.83) 0.44 743 (2.76) (0.07) 3,843
Realized gain (loss)
on risk management
contracts (1.02) (0.59) 73 (0.88) 1.25 (170)
Unrealized gain (loss)
on risk management
contracts 0.75 1.18 (36) 0.38 (0.63) 160
----------------------------------------------------------------------------
Net earnings (loss) 5.17 (3.09) (267) 3.62 (2.07) (275)
----------------------------------------------------------------------------
DEPLETION AND Three Months Ended Year Ended
DEPRECIATION December 31 December 31
2013 2012 % Change 2013 2012 % Change
----------------------------------------------------------------------------
Depletion and
depreciation ($000s) 12,434 9,107 37 44,596 36,685 22
Depletion and
depreciation ($/boe) 14.64 13.49 9 14.01 14.50 (3)
----------------------------------------------------------------------------
The Company calculates depletion on property, plant, and equipment based on
proved plus probable reserves. Plant turnarounds and major overhauls are
depreciated over three or four years, depending on each facility. Depletion and
depreciation for the three months ended December 31, 2013 was $14.64/boe
compared to $13.49/boe in the comparative period. The increase was due to a
significant increase in estimated future capital costs associated with proved
plus probable reserves at Edson AB in Q4 2013 compared to Q4 2012. For the year,
depletion and depreciation was $14.01/boe in 2013, consistent with depletion and
depreciation of $14.50/boe in 2012.
ASSET IMPAIRMENT Three Months Ended Year Ended
December 31 December 31
% %
2013 2012 Change 2013 2012 Change
----------------------------------------------------------------------------
Asset impairment ($000s) 256 7,743 (97) 802 13,439 (94)
Asset impairment ($/boe) 0.30 11.47 (97) 0.25 5.31 (95)
----------------------------------------------------------------------------
Exploration and evaluation assets and property, plant, and equipment are grouped
into cash-generating units ("CGU") for purposes of impairment testing.
Exploration and evaluation assets are assessed for impairment when they are
transferred to property, plant, and equipment or if facts and circumstances
suggest that the carrying amount exceeds the recoverable amount. For property,
plant, and equipment, an impairment is recognized if the carrying value of a CGU
exceeds the greater of its fair value less costs to sell or value in use.
For the year ended December 31, 2013, total exploration and evaluation asset
impairments of $0.6 million were recognized relating to the expiry of
undeveloped land rights (CGUs - Miscellaneous AB, and Saskatchewan). For the
year ended December 31, 2012, total exploration and evaluation asset impairments
of $4.7 million were recognized, including asset impairments of $2.4 million
relating to the determination of certain exploration and evaluation activities
to be uneconomical (CGU - Miscellaneous AB) and $2.3 million relating to the
expiry of undeveloped land rights (CGUs - Lookout Butte AB, Miscellaneous AB,
and Saskatchewan).
At December 31, 2013, with the exception of Lookout Butte AB, there were no
indicators of impairment of property, plant, and equipment. Due to higher than
expected production declines and no capital expenditures during 2013 at Lookout
Butte AB to maintain reserve values, the Company recorded property, plant, and
equipment impairments of $0.2 million during the fourth quarter. For the year
ended December 31, 2012, the Company recorded property, plant, and equipment
impairments of $8.7 million relating to Smoky AB, Lookout Butte AB,
Miscellaneous AB, and Saskatchewan CGUs mainly as a result of weakening natural
gas prices and limited capital expenditures in these CGUs to maintain their
reserve values.
GENERAL AND Three Months Ended Year Ended
ADMINISTRATIVE December 31 December 31
($000s) 2013 2012 % Change 2013 2012 % Change
----------------------------------------------------------------------------
G&A expenses (gross) 2,132 3,076 (31) 7,711 7,020 10
G&A capitalized (117) (195) (40) (539) (435) 24
G&A recoveries (264) (272) (3) (1,142) (1,098) 4
----------------------------------------------------------------------------
G&A expenses (net) 1,751 2,609 (33) 6,030 5,487 10
G&A expenses ($/boe) 2.06 3.87 (47) 1.89 2.17 (13)
----------------------------------------------------------------------------
General and administrative expenses ("G&A") decreased 47% to $2.06/boe for the
fourth quarter of 2013 compared to $3.87/boe for the fourth quarter of 2012. For
the year, G&A expenses decreased 13% to $1.89/boe in 2013 from $2.17/boe in
2012.The decreases in G&A expenses per boe were the result of significant
increases in production.
SHARE BASED COMPENSATION Three Months Ended Year Ended
December 31 December 31
% %
2013 2012 Change 2013 2012 Change
----------------------------------------------------------------------------
Share based compensation
($000s) 681 684 - 2,084 3,512 (41)
Share based compensation
($/boe) 0.80 1.01 (21) 0.65 1.39 (53)
----------------------------------------------------------------------------
The Company grants stock options to officers, directors, employees and
consultants and calculates the related share based compensation using the
Black-Scholes-Merton option pricing model. The Company recognizes the expense
over the individual vesting periods for the graded vesting awards and estimates
a forfeiture rate at the date of grant and updates it throughout the vesting
period. Share based compensation expense decreased to $0.80/boe and $0.65/boe,
respectively, for the three months and year ended December 31, 2013 from
$1.01/boe and $1.39/boe in the comparative periods, respectively. During 2013,
the Company granted 1.7 million options (2012 - 0.7 million). The decrease in
share based compensation per boe is a result of a significant increase in
production.
FINANCE EXPENSES Three Months Ended Year Ended
December 31 December 31
($000s) 2013 2012 % Change 2013 2012 % Change
----------------------------------------------------------------------------
Interest expense 1,043 452 131 3,851 1,449 166
Accretion of
decommissioning
obligations 167 120 39 590 453 30
----------------------------------------------------------------------------
Finance expenses 1,210 572 112 4,441 1,902 133
Finance expenses
($/boe) 1.42 0.85 67 1.40 0.75 87
----------------------------------------------------------------------------
Interest expense relates mainly to interest incurred on amounts drawn from the
Company's credit facility. The increase in interest expense is a result of
higher amounts being drawn on the Company's credit facility in 2013 compared to
2012. At December 31, 2013, $116.3 million (2012 - $68.5 million) had been drawn
on the Company's credit facility.
DEFERRED INCOME TAX EXPENSE
Deferred income tax expense on the earnings before taxes was $8.8 million in
2013 (2012 - $0.2 million). This was larger than expected by applying the
statutory tax rate to the loss before taxes due mainly to flow-through shares
and share based compensation.
Estimated tax pools at December 31, 2013 total approximately $341.1 million
(2012 - $299.6 million).
FUNDS FROM OPERATIONS
Funds from operations for the three months and year ended December 31, 2013 were
$19.7 million ($0.20 per diluted share) and $67.2 million ($0.71 per diluted
share), respectively, compared to $14.5 million ($0.16 per diluted share) and
$50.6 million ($0.56 per diluted share) for the three months and year ended
December 31, 2012, respectively. The increase was mainly due to a significant
increase in revenue in 2013 as a result of a significant increase in production
and oil, natural gas, and NGLs commodity prices.
The following is a reconciliation of cash flow from operating activities to
funds from operations for the periods noted:
Three Months Ended Year Ended
December 31 December 31
($000s) % %
2013 2012 Change 2013 2012 Change
----------------------------------------------------------------------------
Cash flow from operating
activities (GAAP) 19,796 12,096 64 65,513 47,449 38
Add back:
Decommissioning
expenditures 421 113 273 691 734 (6)
Change in non-cash
working capital (526) 2,269 (123) 993 2,432 (59)
----------------------------------------------------------------------------
Funds from operations
(non-GAAP) 19,691 14,478 36 67,197 50,615 33
----------------------------------------------------------------------------
NET EARNINGS (LOSS)
The Company had net earnings of $4.4 million ($0.04 per diluted share) for the
three months ended December 31, 2013 compared to a net loss of $2.1 million
($0.02 per diluted share) for the three months ended December 31, 2012. For the
year, the Company had net earnings of $11.6 million ($0.12 per diluted share) in
2013 compared to a net loss of $5.3 million ($0.06 per diluted share) in 2012.
Net earnings in 2013 arose mainly due to a significant increase in revenue as a
result of a significant increase in production and oil, natural gas, and NGLs
commodity prices The net loss in 2012 arose mainly due to asset impairments
recorded on non-core properties due to declines in commodity prices, limited
capital activity in the associated non-core areas to maintain reserve values,
and exploration and evaluation activities determined to be uneconomical.
CAPITAL EXPENDITURES Three Months Ended Year Ended
December 31 December 31
($000s) % %
2013 2012 Change 2013 2012 Change
----------------------------------------------------------------------------
Land 5,661 2,701 110 8,856 7,107 25
Drilling, completions,
and workovers 23,630 27,504 (14) 92,913 74,663 24
Equipment 2,802 5,781 (52) 23,745 15,949 49
Geological and
geophysical 566 334 69 1,756 829 112
Property acquisitions - 5,406 (100) - 5,406 (100)
----------------------------------------------------------------------------
Exploration and
development 32,659 41,726 (22) 127,270 103,954 22
----------------------------------------------------------------------------
For the three months ended December 31, 2013, the Company had capital
expenditures of $32.7 million compared to capital expenditures of $41.7 million
for the three months ended December 31, 2012. For the year ended December 31,
2013, the Company had capital expenditures of $127.3 million compared to capital
expenditures of $104.0 million for the comparative period in 2012. The increase
in exploration and development expenditures in 2013 was due mainly to an
increase in capital activity in the Company's core areas of Edson, AB and
Northeast BC. During 2013, Crocotta drilled a total of 21 (18.5 net) wells,
which resulted in 15 (13.3 net) oil wells and 6 (5.2 net) liquids-rich natural
gas wells. During 2012, Crocotta drilled a total of 21 (16.0 net) wells, which
resulted in 12 (7.8 net) oil wells, 8 (7.2 net) liquids-rich natural gas wells,
and 1 (1.0 net) exploratory well in a non-core area that was uneconomic.
LIQUIDITY AND CAPITAL RESOURCES
The Company had net debt of $117.8 million at December 31, 2013 compared to net
debt of $80.1 million at December 31, 2012. The increase of $37.7 million was
due to $127.3 million used for the purchase and development of oil and natural
gas properties and equipment and $0.7 million for decommissioning expenditures,
offset by funds from operations of $67.2 million and share issuances of $23.0
million (net of $1.0 million in share issue costs).
In June 2013, the Company issued approximately 6.0 million common shares on a
flow-through basis for gross proceeds of approximately $22.0 million.
Approximately 4.2 million shares were issued at a price of $3.70 per share in
respect of Canadian exploration expenses ("CEE") and approximately 1.8 million
shares were issued at a price of $3.50 per share in respect of Canadian
development expenses ("CDE"). The proceeds were used by the Company to fund
eligible CEE and CDE projects.
During the third quarter of 2013, the Company entered into a syndicated credit
facility with three Canadian chartered banks. The syndicated credit facility
replaced the Company's previous $140 million revolving operating demand loan
credit facility. The syndicated facility has a borrowing base of $150 million,
consisting of a $140 million revolving line of credit and a $10 million
operating line of credit. The syndicated facility revolves for a 364 day period
and will be subject to its next 364 day extension by July 11, 2014. If not
extended, the syndicated facility will cease to revolve, the margins thereunder
will increase by 0.50%, and all outstanding advances will become repayable in
one year from the extension date.
Advances under the syndicated facility are available by way of prime rate loans,
with interest rates between 1.00% and 2.50% over the Canadian prime lending
rate, and bankers' acceptances and LIBOR loans, which are subject to stamping
fees and margins ranging from 2.00% to 3.50% depending upon the debt to cash
flow ratio of the Company. Standby fees are charged on the undrawn syndicated
facility at rates ranging from 0.50% to 0.875%. The credit facility is secured
by a $300 million fixed and floating charge debenture on the assets of the
Company. At December 31, 2013, $116.3 million (December 31, 2012 - $68.5
million) had been drawn on the credit facility. In addition, at December 31,
2013, 2013, the Company had outstanding letters of guarantee of approximately
$2.5 million (December 31, 2012 - $1.5 million) which reduce the amount that can
be borrowed under the credit facility. The next scheduled borrowing base review
of the syndicated facility is scheduled on or before June 30, 2014.
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. Despite the economic downturn and
financial market volatility, the Company continued to have access to both debt
and equity markets recently. The Company raised gross proceeds of approximately
$22.0 million from the issuance of common shares during the second quarter of
2013 and during the year, the Company entered into a $150 million syndicated
credit facility which replaced the previous $140 million revolving operating
demand loan credit facility. The Company has also maintained a very successful
drilling program which has resulted in significant increases in production and
funds flow from operations in recent quarters. Management anticipates that the
Company will continue to have adequate liquidity to fund budgeted capital
investments through a combination of cash flow, equity, and debt. Crocotta's
capital program is flexible and can be adjusted as needed based upon the current
economic environment. The Company will continue to monitor the economic
environment and 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, 2013:
Less than One to After
($000s) Total One Year Three Years Three Years
----------------------------------------------------------------------------
Accounts payable and accrued
liabilities 19,480 19,480 - -
Credit facility 116,324 - 116,324 -
Risk management contracts 368 368 - -
Decommissioning obligations 22,438 50 965 21,423
Office leases 395 395 - -
Field equipment leases 559 559 - -
Firm transportation
agreements 22 8 14 -
----------------------------------------------------------------------------
Total contractual
obligations 159,586 20,860 117,303 21,423
----------------------------------------------------------------------------
OUTSTANDING SHARE DATA
The Company is authorized to issue an unlimited number of voting common shares,
an unlimited number of non-voting common shares, Class A preferred shares,
issuable in series, 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:
(000s) December 31, 2013 March 20, 2014
----------------------------------------------------------------------------
Voting common shares 96,712 96,720
Stock options 8,849 8,940
----------------------------------------------------------------------------
Total 105,561 105,660
----------------------------------------------------------------------------
SUMMARY OF QUARTERLY RESULTS
Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1
2013 2013 2013 2013 2012 2012 2012 2012
----------------------------------------------------------------------------
Average Daily
Production
Oil and NGLs
(bbls/d) 2,605 2,497 2,158 2,691 2,476 2,103 2,053 2,277
Natural gas
(mcf/d) 39,767 36,593 36,412 36,869 29,160 29,053 27,309 26,852
----------------------------------------------------------------------------
Combined (boe/d) 9,233 8,596 8,227 8,836 7,336 6,945 6,604 6,752
($000s, except per
share amounts)
----------------------------------------------------------------------------
Oil and natural
gas sales 31,090 26,950 25,152 28,267 24,938 17,922 17,518 20,140
Funds from
operations 19,691 16,102 14,280 17,124 14,478 10,888 12,275 12,974
Per share - basic 0.20 0.17 0.16 0.19 0.16 0.12 0.14 0.15
Per share -
diluted 0.20 0.16 0.15 0.19 0.16 0.12 0.14 0.14
Net earnings
(loss) 4,387 975 3,604 2,604 (2,082)(3,944) 1,065 (293)
Per share - basic 0.05 0.01 0.04 0.03 (0.02) (0.04) 0.01 -
Per share -
diluted 0.04 0.01 0.04 0.03 (0.02) (0.04) 0.01 -
----------------------------------------------------------------------------
The Company has experienced significant increases in production over the
previous two years stemming from successful drilling activities during that
period. These production increases resulted in substantial increases in revenue,
funds from operations, and net earnings over the previous two years. The Company
had a net loss in three of the four quarters in 2012 mainly as a result of asset
impairments recognized in each quarter on non-core properties.
2014 OUTLOOK
The information below represents Crocotta's guidance for 2014 based on
management's best estimates and the assumptions noted below.
Estimated Average Daily Production Guidance 2014
----------------------------------------------------------------------------
Oil and NGLs (bbls/d) 2,700
Natural gas (mcf/d) 43,800
----------------------------------------------------------------------------
Total (boe/d) 10,000
----------------------------------------------------------------------------
Exit production (boe/d) 11,000 - 11,500
----------------------------------------------------------------------------
Estimated Financial Results Guidance 2014
----------------------------------------------------------------------------
Oil and natural gas sales ($000s) 137,000
Funds from operations ($000s) 90,000
$ per share - basic (1) 0.93
$ per share - diluted (2) 0.85
Capital expenditures ($000s) 110,000
West Texas Intermediate ($US/bbl) 97.50
AECO Daily Spot Price ($CDN/mcf) 4.05
US/CDN Dollar Average Exchange Rate 0.95
----------------------------------------------------------------------------
(1) Based on 96.7 million common shares outstanding
(2) Based on 96.7 million common shares and 8.9 million options outstanding
Sensitivity Analysis
The outlook is based on estimates of key external market factors. Crocotta's
actual results will be affected by fluctuations in commodity prices as well as
the U.S./Canadian dollar exchange rate. The following table provides a summary
of estimates for 2014 of the sensitivity of Crocotta's funds from operations to
changes in commodity prices and the U.S./Canadian dollar exchange rate.
Variance in Funds from
Guidance 2014 Factor Operations
----------------------------------------------------------------------------
West Texas Intermediate ($US/bbl) 97.50 1.00 750,000
AECO Daily Spot Price ($CDN/mcf) 4.05 0.10 1,590,000
US/CDN Dollar Average Exchange Rate 0.95 0.01 760,000
----------------------------------------------------------------------------
2013 OUTLOOK
The information below represents Crocotta's guidance for 2012 and a comparison
to actual results for 2013:
Estimated Average Daily Production Guidance 2013 Actual 2013 % Change
----------------------------------------------------------------------------
Oil and NGLs (bbls/d) 3,100 2,488 (20)
Natural gas (mcf/d) 37,300 37,416 -
----------------------------------------------------------------------------
Total (boe/d) 9,300 8,724 (6)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Exit production (boe/d) 10,500 10,500 -
----------------------------------------------------------------------------
Estimated Financial Results Guidance 2013 Actual 2013 % Change
----------------------------------------------------------------------------
Oil and natural gas sales ($000s) 120,000 111,459 (7)
Funds from operations ($000s) 70,500 67,197 (5)
$ per share - basic (1) 0.79 0.72 (9)
$ per share - diluted (2) 0.70 0.71 1
Capital expenditures ($000s) 100,000 127,270 27
----------------------------------------------------------------------------
West Texas Intermediate ($US/bbl) 90.00 97.98 9
AECO Daily Spot Price ($CDN/mcf) 3.38 3.13 (7)
US/CDN Dollar Average Exchange Rate 1.00 0.97 (3)
----------------------------------------------------------------------------
(1) Based on 89.3 million common shares outstanding
(2) Based on 89.3 million common shares, 8.6 million options, and 2.3
million warrants outstanding
During 2013, actual production was lower than budget due to a longer than
expected spring break-up and wet season. As a result, capital was shifted into
the second half of the year still allowing the exit production guidance of
10,500 boe/d to be successfully achieved. Oil and natural gas sales and funds
from operations were lower than budget as a result of lower than budgeted
production and natural gas commodity prices. Capital expenditures exceeded
budget by $27.3 million as a result of drilling more farm-in locations, spending
more on facilities and infrastructure, and acquiring more land.
CRITICAL ACCOUNTING ESTIMATES
Management is required to make estimates, judgments, and assumptions in the
application of IFRS that affect the reported amounts of assets and liabilities
at the date of the financial statements and revenues and expenses for the period
then ended. Certain of these estimates may change from period to period
resulting in a material impact on the Company's results from operations,
financial position, and change in financial position. The following summarizes
the Company's significant critical accounting estimates.
Oil and natural gas reserves
The Company engages a qualified, independent oil and gas reserves evaluator to
perform an estimation of the amount of the Company's oil and natural gas
reserves at least annually. Reserves form the basis for the calculation of
depletion and assessment of impairment of oil and natural gas assets. Reserves
are estimated using the definitions of reserves prescribed by National
Instrument 51-101 and the Canadian Oil and Gas Evaluation Handbook.
Proved plus probable reserves are defined as the estimated quantities of crude
oil, natural gas liquids including condensate, and natural gas that geological
and engineering data demonstrate a 50 percent probability of being recovered at
the reported level. Due to the inherent uncertainties and the necessarily
limited nature of reservoir data, estimates of reserves are inherently
imprecise, require the application of judgment, and are subject to change as
additional information becomes available. The estimates are made using all
available geological and reservoir data as well as historical production data.
Estimates are reviewed and revised as appropriate. Revisions occur as a result
of changes in prices, costs, fiscal regimes, reservoir performance, or changes
in the Company's plans.
Impairment testing
Exploration and evaluation assets
Exploration and evaluation assets are assessed for impairment (i) if sufficient
data exists to determine technical feasibility and commercial viability, (ii) if
facts and circumstances suggest that the carrying amount exceeds the recoverable
amount, and (iii) upon transfer to property, plant, and equipment. For purposes
of impairment testing, exploration and evaluation assets are allocated to CGUs.
Impairment tests by their nature involve estimates and judgment, which for
exploration and evaluation assets include estimates of proved and probable
reserves found, the market value of undeveloped land, and future development
plans. Crocotta allocated its exploration and evaluation assets to specific CGUs
for the purpose of impairment testing.
Property, plant, and equipment
For the purpose of impairment testing, items of property, plant, and equipment,
which includes oil and natural gas development and production assets, are
grouped together into the smallest group of assets that generates cash inflows
from continuing use that are largely independent of the cash inflows of other
assets or groups of assets (CGU). The recoverable amount of an asset or a CGU is
the greater of its value in use and its fair value less costs to sell. The
Company uses fair value less costs to sell for its impairment tests which is
determined as the net present value of the estimated future cash flows expected
to arise from the continued use of the CGU, including any expansion prospects,
and its eventual disposal, using assumptions that an independent market
participant may take into account. These cash flows are discounted by an
appropriate discount rate which would be applied by such a market participant to
arrive at a net present value of the CGU. The significant estimates and
judgments include proved plus probable reserves, the estimated value of those
reserves, including future commodity prices, the discount rate used to present
value the estimated future cash flows, and other assumptions that an independent
market participant may take into account, including acquisition metrics of
recent transactions for similar assets.
Decommissioning obligations
Decommissioning obligations are estimated based on existing laws, contracts, or
other policies. Decommissioning obligations are measured at the present value of
management's best estimate of the expenditure required to settle the present
obligation as at the reporting date. Subsequent to the initial measurement, the
obligation is adjusted at the end of each reporting period to reflect the
passage of time, changes in the estimated future cash flows underlying the
obligation, and changes in the risk-free rate. The increase in the provision due
to the passage of time is recognized as accretion whereas increases or decreases
due to changes in the estimated future cash flows or changes in the discount
rate are capitalized. Actual costs incurred upon settlement of the
decommissioning obligations are charged against the provision to the extent the
provision was established. By their nature, these estimates are subject to
measurement uncertainty and the impact on the financial statements could be
material.
Share based compensation
Measurement of compensation cost attributable to the Company's share based
compensation plan is subject to the estimation of fair value using the
Black-Scholes-Merton option pricing model. The valuation is based on significant
assumptions including the estimated forfeiture rate, the expected volatility
(based on the weighted average historic volatility adjusted for changes expected
due to publicly available information), the weighted average expected life of
the instrument (based on historical experience and general information), the
expected dividends, and the risk free interest rate (based on government bonds).
Deferred income taxes
The determination of the Company's income taxes requires interpretation of
complex laws and regulations. Tax interpretations, regulations, and legislation
in the various jurisdictions in which the Company operates are subject to
change. Deferred income tax assets are assessed by management at the end of the
reporting period to determine the likelihood that they will be realized from
future taxable earnings.
CHANGES IN ACCOUNTING POLICIES
On January 1, 2013, the Company adopted new standards with respect to
consolidations (IFRS 10), joint arrangements (IFRS 11), disclosure of interests
in other entities (IFRS 12), fair value measurements (IFRS 13), and amendments
to financial statement disclosures (IFRS 7). The adoption of these standards had
no impact on the amounts recorded in the consolidated financial statements.
FUTURE CHANGES IN ACCOUNTING POLICIES
In May 2013, the IASB issued amendments to IAS 36, Impairment of Assets, which
reduce the circumstances in which the recoverable amount of CGUs is required to
be disclosed and clarify the disclosures required when an impairment loss has
been recognized or reversed in the period. The amendments are required to be
adopted retrospectively for fiscal years beginning January 1, 2014, with earlier
adoption permitted. These amendments will be applied by the Company on January
1, 2014 and the adoption will only impact disclosures in the notes to the
financial statements in periods when an impairment loss or impairment reversal
is recognized.
The IASB has undertaken a three-phase project to replace IAS 39, Financial
Instruments: Recognition and Measurement, with IFRS 9, Financial Instruments. In
November 2009, the IASB issued the first phase of IFRS 9, which details the
classification and measurement requirements for financial assets. Requirements
for financial liabilities were added to the standard in October 2010. The new
standard replaces the current multiple classification and measurement models for
financial assets and liabilities with a single model that has only two
classification categories: amortized cost and fair value.
In November 2013, the IASB issued the third phase of IFRS 9 which details the
new general hedge accounting model. Hedge accounting remains optional and the
new model is intended to allow reporters to better reflect risk management
activities in the financial statements and provide more opportunities to apply
hedge accounting. The Company does not employ hedge accounting for its risk
management contracts currently in place. In July 2013, the IASB deferred the
mandatory effective date of IFRS 9 and has left this date open pending the
finalization of the impairment and classification and measurement requirements.
IFRS 9 is still available for early adoption. The full impact of the standard on
the Company's financial statements will not be known until the project is
complete.
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 management 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 the Company
successfully acquiring or discovering new reserves. Without the continual
addition of new reserves, any existing reserves the Company 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 the Company
has identified as being the most prospective for increasing 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.
Financial instruments
The Company classified the fair value of its financial instruments at fair value
according to the following hierarchy based on the amount of observable inputs
used to value the instrument:
-- Level 1 - observable inputs, such as quoted market prices in active
markets
-- Level 2 - inputs, other that the quoted market prices in active markets,
which are observable, either directly or indirectly
-- Level 3 - unobservable inputs for the asset or liability in which little
or no market data exists, therefore requiring an entity to develop its
own assumptions
The fair value of derivative contracts used for risk management as shown in the
statement of financial position as at December 31, 2013 is measured using level
2. During the year ended December 31, 2013, there were no transfers between
level 1, level 2, and level 3 classified assets and liabilities.
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. The Company may use financial derivatives or physical
delivery sales contracts to manage market risks. All such transactions are
conducted within risk management tolerances that are reviewed by the Board of
Directors.
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 US 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
Oil and natural gas prices are impacted by not only the relationship between the
Canadian and US dollar but also by world economic events that dictate the levels
of supply and demand. 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. In addition, the Company may enter into
commodity price contracts to manage future cash flows. For the year ended
December 31, 2013, the realized loss on the Company's oil contracts was $1.2
million and the realized loss on the gas contracts was $1.6 million. For the
year ended December 31, 2013, the unrealized loss on the oil contracts was $0.2
million and the unrealized gain on the gas contracts was $1.4 million.
At December 31, 2013, the Company had the following commodity price contracts
outstanding:
Quantity
Commodity Period Type of Contract Contracted Contract Price
----------------------------------------------------------------------------
January 1, 2014 -
Oil December 31, 2014 Financial - Swap 500 bbls/d WTI CDN $100.80/bbl
January 1, 2014 -
Oil March 31, 2014 Financial - Swap 500 bbls/d WTI CDN $106.55/bbl
Natural April 1, 2014 -
Gas October 31, 2014 Financial - Swap 5,000 GJ/d AECO CDN $3.505/GJ
Natural April 1, 2014 -
Gas October 31, 2014 Financial - Swap 5,000 GJ/d AECO CDN $3.650/GJ
----------------------------------------------------------------------------
Subsequent to December 31, 2013, the Company entered into the following
commodity price contracts:
Quantity
Commodity Period Type of Contract Contracted Contract Price
----------------------------------------------------------------------------
April 1, 2014 -
Oil June 30, 2014 Financial - Swap 500 bbls/d WTI CDN $108.00/bbl
July 1, 2014 -
Oil September 30, 2014 Financial - Swap 500 bbls/d WTI CDN $110.00/bbl
Natural April 1, 2014 - 10,000
Gas October 31, 2014 Financial - Swap GJ/d AECO CDN $3.745/GJ
----------------------------------------------------------------------------
Credit risk
Credit risk represents the financial loss that the Company would suffer if the
Company's counterparties to a financial asset 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 oil 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 of
accounts receivable on the statement of financial position. At December 31,
2013, $15.4 million or 95.2% of the Company's outstanding accounts receivable
were current while $0.8 million or 4.8% were outstanding over 90 days but not
impaired. During the year ended December 31, 2013, the Company did not deem any
outstanding accounts receivable to be uncollectable.
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.
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, 2013. 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
IFRS. The Company's internal controls over financial reporting include 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 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 annual financial statements or interim financial
statements.
The Company evaluated the effectiveness of its internal controls over financial
reporting as of December 31, 2013. 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 issued in
1992. 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, 2013. 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.
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 MD&A 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.
ADDITIONAL INFORMATION
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.
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS
The Management of Crocotta Energy Inc. is responsible for the preparation of the
consolidated financial statements. The consolidated financial statements have
been prepared in accordance with International Financial Reporting Standards and
include certain estimates that reflect Management's best estimates and
judgments. Management has determined such amounts on a reasonable basis in order
to ensure that the consolidated financial statements are presented fairly in all
material respects.
Management is responsible for the integrity of the consolidated financial
statements. Internal control systems are designed and maintained to provide
reasonable assurance that assets are safeguarded from loss or unauthorized use
and to produce reliable accounting records for financial reporting purposes.
KPMG LLP were appointed by the Company's shareholders to express an audit
opinion on the consolidated financial statements. Their examination included
such tests and procedures, as they considered necessary, to provide a reasonable
assurance that the consolidated financial statements are presented fairly in
accordance with International Financial Reporting Standards.
The Board of Directors is responsible for ensuring that Management fulfills its
responsibilities for financial reporting and internal control. The Board of
Directors exercises this responsibility through the Audit Committee, with
assistance from the Reserves Committee regarding the annual review of our oil
and natural gas reserves. The Audit Committee meets regularly with Management
and the Auditors to ensure that Management's responsibilities are properly
discharged, to review the consolidated financial statements and recommend that
the consolidated financial statements be presented to the Board of Directors for
approval. The Audit Committee also considers the independence of KPMG LLP and
reviews their fees. The Auditors have access to the Audit Committee without the
presence of Management.
Rob Zakresky, President, Chief Executive Officer and Director
Nolan Chicoine, Vice President, Finance and Chief Financial Officer
Calgary, Canada
March 20, 2014
INDEPENDENT AUDITORS' REPORT
To the Shareholders of Crocotta Energy Inc.
We have audited the accompanying consolidated financial statements of Crocotta
Energy Inc., which comprise the consolidated statements of financial position as
at December 31, 2013 and December 31, 2012, the consolidated statements of
earnings (loss) and comprehensive earnings (loss), shareholders' equity and cash
flows for the years then ended, and notes, comprising a summary of significant
accounting policies and other explanatory information.
Management's Responsibility for the Consolidated Financial Statements
Management is responsible for the preparation and fair presentation of these
consolidated financial statements in accordance with International Financial
Reporting Standards and for such internal control as management determines is
necessary to enable the preparation of consolidated financial statements that
are free from material misstatement, whether due to fraud or error.
Auditors' Responsibility
Our responsibility is to express an opinion on these consolidated financial
statements based on our audits. We conducted our audits in accordance with
Canadian generally accepted auditing standards. Those standards require that we
comply with ethical requirements and plan and perform the audit to obtain
reasonable assurance about whether the consolidated financial statements are
free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the
amounts and disclosures in the consolidated financial statements. The procedures
selected depend on our judgment, including the assessment of the risks of
material misstatement of the consolidated financial statements, whether due to
fraud or error. In making those risk assessments, we consider internal control
relevant to the entity's preparation and fair presentation of the consolidated
financial statements in order to design audit procedures that are appropriate in
the circumstances, but not for the purpose of expressing an opinion on the
effectiveness of the entity's internal control. An audit also includes
evaluating the appropriateness of accounting policies used and the
reasonableness of accounting estimates made by management, as well as evaluating
the overall presentation of the consolidated financial statements.
We believe that the audit evidence we have obtained in our audits is sufficient
and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the consolidated financial statements present fairly, in all
material respects, the consolidated financial position of Crocotta Energy Inc.
as at December 31, 2013 and December 31, 2012, and its consolidated financial
performance and its consolidated cash flows for the years then ended in
accordance with International Financial Reporting Standards.
signed "KPMG LLP"
Chartered Accountants
March 20, 2014
Calgary, Canada
Crocotta Energy Inc.
Consolidated Statements of Financial Position
December 31 December 31
($000s) Note 2013 2012
----------------------------------------------------------------------------
Assets
Current assets
Accounts receivable 16,166 15,983
Prepaid expenses and deposits 1,798 1,550
----------------------------------------------------------------------------
17,964 17,533
Property, plant, and equipment (6) 313,142 241,703
Exploration and evaluation assets (5) 39,629 28,302
Deferred income taxes (14) 2,566 13,442
----------------------------------------------------------------------------
355,337 283,447
----------------------------------------------------------------------------
373,301 300,980
----------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable and accrued
liabilities 19,480 29,165
Risk management contracts (16) 368 1,592
Revolving credit facility (7) - 68,480
----------------------------------------------------------------------------
19,848 99,237
Credit facility (7) 116,324 -
Decommissioning obligations (8) 22,438 21,852
----------------------------------------------------------------------------
158,610 121,089
Shareholders' Equity
Shareholders' capital (9) 250,563 228,277
Contributed surplus 12,970 12,026
Deficit (48,842) (60,412)
----------------------------------------------------------------------------
214,691 179,891
Subsequent events (16)
----------------------------------------------------------------------------
373,301 300,980
----------------------------------------------------------------------------
The accompanying notes are an integral part of these consolidated financial
statements.
Approved on behalf of the Board of Directors
Director, "signed" Rob Zakresky
Director, "signed" Larry Moeller
Crocotta Energy Inc.
Consolidated Statements of Earnings (Loss) and Comprehensive Earnings
(Loss)
Year Ended December 31
($000s, except per share amounts) Note 2013 2012
----------------------------------------------------------------------------
Revenue
Oil and natual gas sales 111,459 80,518
Royalties (8,404) (8,911)
----------------------------------------------------------------------------
103,055 71,607
Realized gain (loss) on risk
management contracts (16) (2,809) 3,166
Unrealized gain (loss) on risk
management contracts (16) 1,224 (1,592)
----------------------------------------------------------------------------
101,470 73,181
Expenses
Production 20,154 14,743
Transportation 3,014 2,479
Depletion and depreciation (6) 44,596 36,685
Asset impairment (5,6) 802 13,439
General and administrative 6,030 5,487
Share based compensation (10) 2,084 3,512
----------------------------------------------------------------------------
76,680 76,345
----------------------------------------------------------------------------
Operating earnings (loss) 24,790 (3,164)
Other Expenses
Finance expense (13) 4,441 1,902
----------------------------------------------------------------------------
Earnings (loss) before taxes 20,349 (5,066)
Taxes
Deferred income tax expense (14) 8,779 188
----------------------------------------------------------------------------
Net earnings (loss) and comprehensive
earnings (loss) 11,570 (5,254)
----------------------------------------------------------------------------
Net earnings (loss) per share
Basic and diluted (11) 0.12 (0.06)
----------------------------------------------------------------------------
The accompanying notes are an integral part of these consolidated financial
statements.
Crocotta Energy Inc.
Consolidated Statements of Shareholders' Equity
Year Ended December 31
($000s) Note 2013 2012
----------------------------------------------------------------------------
Shareholders' Capital
Balance, beginning of year 228,277 225,848
Issue of shares (net of share issue
costs and flow-through share premium) (9) 18,887 -
Issued on exercise of stock options (9) 2,052 17
Issued on exercise of warrants (9) - 1,680
Share based compensation - exercised (9) 1,347 732
----------------------------------------------------------------------------
Balance, end of year 250,563 228,277
----------------------------------------------------------------------------
Contributed Surplus
Balance, beginning of year 12,026 8,927
Share based compensation - expensed (10) 2,084 3,512
Share based compensation - capitalized (10) 207 319
Share based compensation - exercised (9) (1,347) (732)
----------------------------------------------------------------------------
Balance, end of year 12,970 12,026
----------------------------------------------------------------------------
Deficit
Balance, beginning of year (60,412) (55,158)
Net earnings (loss) 11,570 (5,254)
----------------------------------------------------------------------------
Balance, end of year (48,842) (60,412)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Shareholders' Equity 214,691 179,891
----------------------------------------------------------------------------
The accompanying notes are an integral part of these consolidated financial
statements.
Crocotta Energy Inc.
Consolidated Statements of Cash Flows
Year Ended December 31
($000s) Note 2013 2012
----------------------------------------------------------------------------
Operating Activities
Net earnings (loss) 11,570 (5,254)
Depletion and depreciation (6) 44,596 36,685
Asset impairment (5,6) 802 13,439
Share based compensation (10) 2,084 3,512
Finance expense (13) 4,441 1,902
Interest paid (3,851) (1,449)
Deferred income tax expense (14) 8,779 188
Unrealized loss (gain) on risk
management contracts (16) (1,224) 1,592
Decommissioning expenditures (8) (691) (734)
Change in non-cash working capital (19) (993) (2,432)
----------------------------------------------------------------------------
65,513 47,449
----------------------------------------------------------------------------
Financing Activities
Issuance of shares (9) 24,035 1,697
Share issue costs (9) (999) -
Revolving credit facility (7) (68,480) 63,298
Credit facility (7) 116,324 -
----------------------------------------------------------------------------
70,880 64,995
----------------------------------------------------------------------------
Investing Activities
Capital expenditures - property, plant,
and equipment (6) (66,694) (54,756)
Capital expenditures - exploration and
evaluation assets (5) (60,576) (49,198)
Change in non-cash working capital (19) (9,123) (8,490)
----------------------------------------------------------------------------
(136,393) (112,444)
----------------------------------------------------------------------------
Change in cash and cash equivalents - -
Cash and cash equivalents, beginning of
year - -
----------------------------------------------------------------------------
Cash and cash equivalents, end of year - -
----------------------------------------------------------------------------
The accompanying notes are an integral part of these consolidated financial
statements.
Crocotta Energy Inc.
Notes to the Consolidated Financial Statements
Year Ended December 31, 2013
(Tabular amounts in 000s, unless otherwise stated)
1. REPORTING ENTITY
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
conducts many of its activities jointly with others and these consolidated
financial statements reflect only the Company's proportionate interest in such
activities. The Company currently has one wholly-owned subsidiary.
The Company's place of business is located at 700, 639 - 5th Avenue SW, Calgary,
Alberta, Canada, T2P 0M9.
2. BASIS OF PRESENTATION
(a) Statement of compliance
These consolidated financial statements have been prepared in accordance with
International Financial Reporting Standards ("IFRS").
These consolidated financial statements were authorized for issuance by the
Board of Directors on March 20, 2014.
(b) Basis of measurement
These consolidated financial statements have been prepared on the historical
cost basis except for risk management contracts, which are measured at fair
value. The methods used to measure fair value are discussed in note 4.
(c) Functional and presentation currency
These consolidated financial statements are presented in Canadian dollars, which
is the functional currency of the Company and its subsidiary.
(d) Use of estimates and judgments
The preparation of the consolidated financial statements in conformity with IFRS
requires management to make estimates and use judgment regarding the reported
amounts of assets and liabilities as at the date of the consolidated financial
statements and the reported amounts of revenues and expenses during the year.
These judgments, estimates, and assumptions are based on current trends and all
relevant information available to the Company at the time of preparation of the
consolidated financial statements. As the effect of future events cannot be
determined with certainty, the actual results may differ from the estimated
amounts.
Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions
to accounting estimates are recognized in the period in which the estimates are
revised and in any future periods affected.
Significant estimates and judgments made by management in the preparation of
these consolidated financial statements are outlined below.
Critical accounting judgments
The following are critical judgments that management has made in the process of
applying the Company's accounting policies and that have the most significant
effect on the amounts recognized in the consolidated financial statements.
Cash-generating units ("CGU")
The Company's assets are aggregated into CGUs for the purposes of calculating
depletion and depreciation and impairment. CGUs are determined based on the
smallest group of assets that generate cash flows independent of other assets or
groups of assets. Determination of the CGUs is subject to the Company's judgment
and is based on geographical proximity, shared infrastructure, similar exposure
to market risk, and materiality.
Impairment
Judgments are required to assess when impairment indicators exist and impairment
testing is required. In determining the recoverable amount of assets, in the
absence of quoted market prices, impairment tests are based on estimates of
reserves, production rates, future oil and natural gas prices, future costs,
discount rates, market value of land, and other relevant assumptions.
Exploration and evaluation assets
The application of the Company's accounting policy for exploration and
evaluation assets requires the Company to make certain judgments as to future
events and circumstances as to whether economic quantities of reserves will be
found so as to assess if technical feasibility and commercial viability has been
achieved.
Deferred taxes
Judgments are made by the Company to determine the likelihood of whether
deferred income tax assets at the end of the reporting period will be realized
from future taxable earnings.
Significant estimates
The following are key estimates and assumptions made by the Company affecting
the measurement of balances and transactions in the consolidated financial
statements.
Recoverability of asset carrying values
The recoverability of development and production asset carrying values is
assessed at a CGU level. The key estimates used in the determination of cash
flows from oil and natural gas reserves include the following:
i. Reserves - Assumptions that are valid at the time of reserve estimation
may change significantly when new information becomes available. Changes
in forward price estimates, production costs, or recovery rates may
change the economic status of reserves and may ultimately result in
reserves being restated.
ii. Oil and natural gas prices - Forward price estimates are used in the
cash flow model. Commodity prices can fluctuate for a variety of reasons
including supply and demand fundamentals, inventory levels, exchange
rates, weather, and economic and geopolitical factors.
iii.Discount rate - The discount rate used to calculate the net present
value of cash flows is based on estimates of an approximate industry
peer group weighted average cost of capital. Changes in the general
economic environment could result in significant changes to this
estimate.
The key assumptions used in the impairment tests are described in note 6.
Depletion and depreciation
Amounts recorded for depletion and depreciation are based on estimates of total
proved and probable oil and natural gas reserves and future development capital.
By their nature, the estimates of reserves, including the estimates of future
prices, costs, and future cash flows, are subject to measurement uncertainty.
Accordingly, the impact to the consolidated financial statements in future
periods could be material.
Decommissioning obligations
Amounts recorded for decommissioning obligations and the related accretion
expense requires the use of estimates with respect to the amount and timing of
decommissioning expenditures. Actual costs and cash outflows can differ from
estimates because of changes in laws and regulations, public expectations,
market conditions, discovery and analysis of site conditions and changes in
technology. Other provisions are recognized in the period when it becomes
probable that there will be a future cash outflow.
Share based compensation
Compensation costs recognized for share based compensation plans are subject to
the estimation of what the ultimate value will be using pricing models such as
the Black-Scholes-Merton model, which is based on significant assumptions such
as volatility, expected term, and forfeiture rate.
Derivatives
The Company's estimate of the fair value of derivative financial instruments is
dependent on estimated forward prices and volatility in those prices.
Deferred taxes
Deferred taxes are based on estimates as to the timing of the reversal of
temporary differences, substantively enacted tax rates, and the likelihood of
assets being realized. Tax interpretations, regulations, and legislation in the
various jurisdictions in which the Company operates are subject to change. As
such, income taxes are subject to measurement uncertainty.
3. SIGNIFICANT ACCOUNTING POLICIES
The accounting policies set out below have been applied consistently by the
Company and its subsidiary to all periods presented in these consolidated
financial statements.
(a) Basis of consolidation
Subsidiaries
Subsidiaries are entities controlled by the Company. Control exists when the
Company is exposed to, or has rights to, variable returns from its involvement
with the entity and has the ability to affect those returns through its power
over the entity. In assessing control, potential voting rights that currently
are exercisable are taken into account. The financial statements of subsidiaries
are included in the consolidated financial statements from the date that control
commences until the date that control ceases.
Jointly controlled operations
Many of the Company's oil and natural gas activities involve jointly controlled
operations. The consolidated financial statements include the Company's share of
these jointly controlled operations and a proportionate share of the relevant
assets, liabilities, revenue, and related costs.
Transactions eliminated on consolidation
Intercompany balances and transactions, and any unrealized income and expenses
arising from intercompany transactions, are eliminated in preparing the
consolidated financial statements.
(b) Financial instruments
Non-derivative financial instruments
Non-derivative financial instruments comprise cash and cash equivalents,
accounts receivable, accounts payable and accrued liabilities, and credit
facility. Non-derivative financial instruments are recognized initially at fair
value net of any directly attributable transaction costs. Subsequent to initial
recognition, non-derivative financial instruments are measured as described
below.
Cash and cash equivalents
Cash and cash equivalents comprise cash on hand, term deposits held with banks,
and other short-term highly liquid investments with original maturities of three
months or less, measured at amortized cost.
Other
Other non-derivative financial instruments, such as accounts receivable,
accounts payable and accrued liabilities, and credit facility, are measured at
amortized cost using the effective interest method, less any impairment losses.
Derivative financial instruments
From time to time, the Company may enter into certain financial derivative
contracts in order to manage the exposure to market risks from fluctuations in
commodity prices. These instruments are not used for trading or speculative
purposes. The Company does not designate financial derivative contracts as
effective accounting hedges, and thus does not apply hedge accounting, even
though the Company considers all commodity contracts to be economic hedges. As a
result, all financial derivative contracts are classified as fair value through
profit or loss and are measured at fair value, with changes therein recognized
in profit or loss. Transaction costs are recognized in profit or loss when
incurred.
Share capital
Common shares are classified as equity. Incremental costs directly attributable
to the issue of common shares are recognized as a deduction from equity, net of
any tax effects.
(c) Property, plant, and equipment and exploration and evaluation assets
Recognition and measurement
Exploration and evaluation expenditures
Pre-license costs are recognized in profit or loss as incurred.
Exploration and evaluation costs, including the costs of acquiring undeveloped
land and drilling costs, are initially capitalized until the drilling of the
well is complete and the results have been evaluated. The costs are accumulated
in cost centers by well, field, or exploration area pending determination of
technical feasibility and commercial viability. The technical feasibility and
commercial viability of extracting a mineral resource is considered to be
determinable when proved or probable reserves are determined to exist. If proved
or probable reserves are found, the accumulated costs and associated undeveloped
land are transferred to property, plant, and equipment. The exploration and
evaluation costs are reviewed for impairment prior to any such transfer.
Exploration and evaluation assets are assessed for impairment if (i) sufficient
data exists to determine technical feasibility and commercial viability, and
(ii) facts and circumstances suggest that the carrying amount exceeds the
recoverable amount. For purposes of impairment testing, exploration and
evaluation assets are allocated to CGUs.
Development and production costs
Items of property, plant, and equipment, which include oil and natural gas
development and production assets, are measured at cost less accumulated
depletion and depreciation and accumulated impairment losses. The cost of
development and production assets includes: transfers from exploration and
evaluation assets, which generally include the cost to drill the well and the
cost of the associated land upon determination of technical feasibility and
commercial viability; the cost to complete and tie-in the well; facility costs;
the cost of recognizing provisions for future restoration and decommissioning
obligations; geological and geophysical costs; and directly attributable
overhead.
Development and production assets are grouped into CGUs for impairment testing.
The Company has grouped its development and production assets into the following
six CGUs: (i) Edson AB (ii) Smoky AB (iii) Northeast BC (iv) Lookout Butte AB
(v) Miscellaneous AB, and (vi) Saskatchewan.
When significant parts of an item of property, plant, and equipment, including
oil and natural gas interests, have different useful lives, they are accounted
for as separate items (major components). The Company capitalizes the cost of
major plant turnarounds and overhauls and depreciates these costs over their
estimated useful life of three or four years, depending on each plant.
Gains and losses on disposal of an item of property, plant, and equipment,
including oil and natural gas interests, are determined by comparing the
proceeds from disposal with the carrying amount of property, plant, and
equipment and are recognized in profit or loss. The carrying amount of any
replaced or disposed item of property, plant, and equipment is derecognized.
Subsequent costs
Costs incurred subsequent to the determination of technical feasibility and
commercial viability and the costs of replacing parts of property, plant, and
equipment are recognized as property, plant, and equipment only when they
increase the future economic benefits embodied in the specific asset to which
they relate. Capitalized property, plant, and equipment generally represent
costs incurred in developing proved or probable reserves and bringing in or
enhancing production from such reserves and are accumulated on a field or
geotechnical area basis. The costs of the day-to-day servicing of property,
plant, and equipment are recognized in operating expenses as incurred.
Non-monetary asset swaps
Exchanges or swaps of property, plant, and equipment are measured at fair value
unless the exchange transaction lacks commercial substance or neither the fair
value of the assets given up nor the assets received can be reliably estimated.
The cost of the acquired asset is measured at the fair value of the asset given
up, unless the fair value of the asset received is more clearly evident. Where
fair value is not used, the cost of the acquired asset is measured at the
carrying amount of the asset given up. Any gain or loss on derecognition of the
asset given up is included in profit or loss.
Exchanges or parts of exchanges that involve principally exploration and
evaluation assets are measured at the carrying amount of the asset exchanged,
reduced by the amount of any cash consideration received. No gain or loss is
recognized unless the cash consideration received exceeds the carrying value of
the asset held.
Depletion and depreciation
The net carrying value of development and production assets is depleted using
the unit of production method by reference to the ratio of production in the
period to the related proved plus probable reserves, taking into account the
estimated future development costs necessary to bring those reserves into
production and the estimated salvage value of the assets at the end of their
useful lives. Future development costs are estimated taking into account the
level of development required to produce the reserves.
Proved plus probable reserves are estimated at least annually by independent
qualified reserve evaluators and represent the estimated quantities of oil,
natural gas, and natural gas liquids which geological, geophysical, and
engineering data demonstrate with a specified degree of certainty to be
recoverable in future years from known reservoirs and which are considered
commercially producible.
The Company has determined the estimated useful lives for gas processing plants,
pipeline facilities, and compression facilities to be consistent with the
reserve lives of the areas for which they serve. As such, the Company includes
the cost of these assets within their associated CGU for the purpose of
depletion using the unit of production method. For plant turnarounds and
overhauls, the Company has estimated an average useful life of three or four
years, depending on each plant, before further work must be performed and
depreciates these costs using the straight-line method over the corresponding
useful life.
The cost of office and other equipment is depreciated using the straight-line
method over the estimated useful life of three years.
Depreciation methods, useful lives, and residual values are reviewed at each
reporting date.
Leased assets
Leases wherein the Company assumes substantially all the risks and rewards of
ownership are classified as finance leases, when applicable. Upon initial
recognition, the leased asset is measured at an amount equal to the lower of its
fair value and the present value of the minimum lease payments. Subsequent to
initial recognition, the asset is accounted for in accordance with the
accounting policy applicable to that asset. Minimum lease payments made under
finance leases are apportioned between the finance expenses and the reduction of
the outstanding liability. The finance expenses are allocated to each year
during the lease term so as to produce a constant periodic rate of interest on
the remaining balance of the liability. Other leases are classified as operating
leases, which are not recognized on the Company's statement of financial
position. Payments made under operating leases are recognized in profit or loss
on a straight-line basis over the term of the lease. The Company's presently
outstanding leases have been determined to be operating leases.
(d) Impairment
Financial assets
A financial asset is assessed at each reporting date to determine whether there
is any objective evidence that it is impaired. A financial asset is considered
to be impaired if objective evidence indicates that one or more events have had
a negative effect on the estimated future cash flows of that asset. An
impairment loss in respect of a financial asset measured at amortized cost is
calculated as the difference between its carrying amount and the present value
of the estimated future cash flows discounted at the original effective interest
rate.
Individually significant financial assets are tested for impairment on an
individual basis. The remaining financial assets are assessed collectively in
groups that share similar credit risk characteristics. All impairment losses are
recognized in profit or loss. An impairment loss is reversed if the reversal can
be related objectively to an event occurring after the impairment loss was
recognized. For financial assets measured at amortized cost, the reversal is
recognized in profit or loss.
Non-financial assets
The carrying amounts of the Company's non-financial assets, other than
exploration and evaluation assets and deferred tax assets, are reviewed at each
reporting date to determine whether there is any indication of impairment. If
any such indication exists, then the asset's recoverable amount is estimated.
Exploration and evaluation assets are assessed for impairment when they are
transferred to property, plant, and equipment or if facts and circumstances
suggest that the carrying amount exceeds the recoverable amount.
For the purpose of impairment testing, assets are grouped together into the
smallest group of assets that generate cash inflows from continuing use that are
largely independent of the cash inflows of other assets or groups of assets
(CGU). The recoverable amount of an asset or a CGU is the greater of its value
in use and its fair value less costs to sell.
Fair value less costs to sell is determined as the amount that would be obtained
from the sale of a CGU in an arm's length transaction between knowledgeable and
willing parties. The fair value less costs to sell of oil and natural gas assets
is generally determined as the net present value of the estimated future cash
flows expected to arise from the continued use of the CGU, including any
expansion projects and its eventual disposal, using assumptions that an
independent market participant may take into account. These cash flows are
discounted using an appropriate discount rate which would be applied by such a
market participant to arrive at a net present value of the CGU. Consideration is
given to acquisition metrics of recent transactions completed on similar assets
to those contained within the relevant CGU.
Value in use is determined as the net present value of the estimated future cash
flows expected to arise from the continued use of the asset in its present form
and its eventual disposal. Value in use is determined by applying assumptions
specific to the Company's continued use and can only take into account approved
future development costs. Estimates of future cash flows used in the evaluation
of impairment of assets are made using management's forecasts of commodity
prices and expected production volumes. The latter takes into account
assessments of field reservoir performance and includes expectations about
proved and unproved volumes, which are risk-weighted using geological,
production, recovery, and economic projections.
An impairment loss is recognized if the carrying amount of a CGU exceeds its
estimated recoverable amount. Impairment losses are recognized in profit or
loss. Impairment losses recognized in respect of CGUs are allocated to the
assets in the CGUs on a pro rata basis. Impairment losses recognized in prior
periods are assessed each reporting date if facts or circumstances indicate that
the loss has decreased or no longer exists. An impairment loss is reversed if
there has been a change in the estimates used to determine the recoverable
amount. An impairment loss is reversed only to the extent that the asset's
carrying amount does not exceed the carrying amount that would have been
determined, net of depletion and depreciation, if no impairment loss had been
recognized.
(e) Share based compensation
The Company has a share based compensation plan, which is described in note 10.
The Company uses the fair value method for valuing share based compensation.
Under this method, the compensation cost attributed to stock options is measured
at fair value at the grant date and expensed over the vesting period with a
corresponding increase to contributed surplus. A forfeiture rate is estimated on
the grant date and is adjusted to reflect the actual number of options that
vest. Upon the settlement of the stock options, the previously recognized value
in contributed surplus is recorded as an increase to share capital.
(f) Provisions
A provision is recognized if, as a result of a past event, the Company has a
present legal or constructive obligation that can be estimated reliably, and it
is probable that an outflow of economic benefits will be required to settle the
obligation. Provisions are determined by discounting the expected future cash
flows at a pre-tax rate that reflects current market assessments of the time
value of money and the risks specific to the liability. Provisions are not
recognized for future operating losses.
Decommissioning obligations
The Company's activities give rise to dismantling, decommissioning, and site
disturbance remediation activities. A provision is made for the estimated cost
of abandonment and site restoration and capitalized in the relevant asset
category. The capitalized amount is depreciated on a unit of production basis
over the life of the associated proved plus probable reserves. Decommissioning
obligations are measured at the present value of management's best estimate of
the expenditure required to settle the present obligation at the reporting date.
Subsequent to the initial measurement, the obligation is adjusted at the end of
each period to reflect the passage of time, changes in the estimated future cash
flows underlying the obligation, and changes in the risk-free rate. The increase
in the provision due to the passage of time is recognized as accretion (within
finance expenses) whereas increases or decreases due to changes in the estimated
future cash flows or changes in the discount rate are capitalized. Actual costs
incurred upon settlement of the decommissioning obligations are charged against
the provision to the extent the provision was established.
(g) Revenue
Revenue from the sale of oil and natural gas is recorded when the significant
risks and rewards of ownership of the product are transferred to the buyer which
is usually when legal title passes to the external party.
(h) Finance income and expenses
Finance income and expenses comprises interest expense, including interest on
credit facility, accretion on decommissioning obligations, and interest income.
(i) Income tax
Income tax expense is comprised of current and deferred tax. Income tax expense
is recognized in profit or loss except to the extent that it relates to items
recognized directly in equity, in which case it is recognized in equity.
Current tax is the expected tax payable on the taxable income for the year,
using tax rates enacted or substantively enacted at the reporting date, and any
adjustment to tax payable in respect of previous years.
Deferred tax is recognized on the temporary differences between the carrying
amounts of assets and liabilities for financial reporting purposes and the
amounts used for taxation purposes. Deferred tax is not recognized on the
initial recognition of assets or liabilities in a transaction that is not a
business combination. In addition, deferred tax is not recognized for taxable
temporary differences arising on the initial recognition of goodwill. Deferred
tax is measured at the tax rates that are expected to be applied to temporary
differences when they reverse, based on the laws that have been enacted or
substantively enacted by the reporting date. Deferred tax assets and liabilities
are offset if there is a legally enforceable right to offset, they relate to
income taxes levied by the same tax authority on the same taxable entity, or on
different tax entities, but they intend to settle current tax liabilities and
assets on a net basis, or their tax assets and liabilities will be realized
simultaneously.
A deferred tax asset is recognized to the extent that it is probable that future
taxable earnings will be available against which the temporary difference can be
utilized. Deferred tax assets are reviewed at each reporting date and are
reduced to the extent that it is no longer probable that the related tax benefit
will be realized.
(j) Flow-through shares
The Company, from time to time, issues flow-through shares to finance a portion
of its exploration capital expenditure program. Pursuant to the terms of the
flow-through share agreements, the tax deductions associated with the
exploration expenditures are renounced to the subscribers. On issuance of
flow-through shares, the premium received on such shares, being the difference
between the fair value ascribed to flow-through shares issued and the fair value
that would have been received for common shares at the date of issuance of the
flow-through shares, is recognized as a liability on the statement of financial
position. When the exploration expenditures are incurred, the liability is drawn
down, a deferred tax liability is recorded equal to the estimated amount of
deferred income tax payable by the Company as a result of the foregone tax
benefits, and the difference is recognized in profit or loss.
(k) Earnings per share
Basic earnings per share is calculated by dividing the net earnings or loss
attributable to common shareholders of the Company by the weighted average
number of common shares outstanding during the period. Diluted earnings per
share is determined by adjusting the weighted average number of common shares
outstanding during the period for the effects of dilutive instruments such as
stock options granted.
(l) Changes in accounting policies
On January 1, 2013, the Company adopted new standards with respect to
consolidations (IFRS 10), joint arrangements (IFRS 11), disclosure of interests
in other entities (IFRS 12), fair value measurements (IFRS 13), and amendments
to financial statement disclosures (IFRS 7). The adoption of these standards had
no impact on the amounts recorded in the consolidated financial statements.
(m) New standards and interpretations not yet adopted
In May 2013, the IASB issued amendments to IAS 36, Impairment of Assets, which
reduce the circumstances in which the recoverable amount of CGUs is required to
be disclosed and clarify the disclosures required when an impairment loss has
been recognized or reversed in the period. The amendments are required to be
adopted retrospectively for fiscal years beginning January 1, 2014, with earlier
adoption permitted. These amendments will be applied by the Company on January
1, 2014 and the adoption will only impact disclosures in the notes to the
financial statements in periods when an impairment loss or impairment reversal
is recognized.
The IASB has undertaken a three-phase project to replace IAS 39, Financial
Instruments: Recognition and Measurement, with IFRS 9, Financial Instruments. In
November 2009, the IASB issued the first phase of IFRS 9, which details the
classification and measurement requirements for financial assets. Requirements
for financial liabilities were added to the standard in October 2010. The new
standard replaces the current multiple classification and measurement models for
financial assets and liabilities with a single model that has only two
classification categories: amortized cost and fair value.
In November 2013, the IASB issued the third phase of IFRS 9 which details the
new general hedge accounting model. Hedge accounting remains optional and the
new model is intended to allow reporters to better reflect risk management
activities in the financial statements and provide more opportunities to apply
hedge accounting. The Company does not employ hedge accounting for its risk
management contracts currently in place. In July 2013, the IASB deferred the
mandatory effective date of IFRS 9 and has left this date open pending the
finalization of the impairment and classification and measurement requirements.
IFRS 9 is still available for early adoption. The full impact of the standard on
the Company's financial statements will not be known until the project is
complete.
4. DETERMINATION OF FAIR VALUES
A number of the Company's accounting policies and disclosures require the
determination of fair value, for both financial and non-financial assets and
liabilities. Fair values have been determined for measurement and disclosure
purposes based on the following methods. When applicable, further information
about the assumptions made in determining fair values is disclosed in the notes
specific to that asset or liability.
Property, plant, and equipment and exploration and evaluation assets
The fair value of property, plant, and equipment and exploration and evaluation
assets recognized in a business combination, is based on market values. The
market value of property, plant, and equipment and exploration and evaluation
assets is the estimated amount for which the assets could be exchanged on the
acquisition date between a willing buyer and a willing seller in an arm's length
transaction after proper marketing wherein the parties had each acted
knowledgeably, prudently, and without compulsion. The market value of property,
plant, and equipment is estimated with reference to the discounted cash flows
expected to be derived from oil and natural gas production based on externally
prepared reserve reports. The risk-adjusted discount rate used to discount the
expected cash flows is specific to the asset with reference to general market
conditions.
The market value of other items of property, plant, and equipment is based on
the quoted market prices for similar items.
Stock options
The fair value of stock options is measured using a Black-Scholes-Merton option
pricing model. Measurement inputs include the share price on the measurement
date, exercise price of the instrument, estimated forfeiture rate, expected
volatility (based on the weighted average historic volatility adjusted for
changes expected due to publicly available information), weighted average
expected life of the instrument (based on historical experience and general
information), expected dividends, and the risk free interest rate (based on
government bonds).
Derivatives
The fair value of risk management contracts is determined by discounting the
difference between the contracted price and published forward curves as at the
statement of financial position date using the remaining contracted volumes and
a risk-free interest rate (based on published government rates).
5. EXPLORATION AND EVALUATION ASSETS
Total
---------------------------------------------------------------------------
Balance, December 31, 2011 20,641
Additions 49,198
Transfer to property, plant, and equipment (36,838)
Impairment (4,699)
---------------------------------------------------------------------------
Balance, December 31, 2012 28,302
Additions 60,576
Transfer to property, plant, and equipment (48,610)
Impairment (639)
---------------------------------------------------------------------------
Balance, December 31, 2013 39,629
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Exploration and evaluation assets consist of the Company's exploration projects
which are pending the determination of proved or probable reserves. Additions
represent the Company's share of costs incurred on exploration and evaluation
assets during the year, consisting primarily of undeveloped land and drilling
costs until the drilling of the well is complete and the results have been
evaluated. Included in the $60.6 million in additions during the year ended
December 31, 2013 were additions of $43.4 million related to the Edson AB CGU,
$9.6 million related to the Miscellaneous AB CGU, and $7.3 million related to
the Northeast BC CGU. Transfers to property, plant, and equipment during the
year ended December 31, 2013 included $39.2 million from the Edson AB CGU and
$9.4 million from the Northeast BC CGU as a result of successful capital
activity in the Company's core areas.
Included in the $49.2 million in additions during the year ended December 31,
2012 were additions of $33.1 million related to the Edson AB CGU, $9.4 million
related to the Miscellaneous AB CGU, and $6.4 million related to the Northeast
BC CGU. Transfers to property, plant, and equipment during the year ended
December 31, 2012 included $31.9 million from the Edson AB CGU and $4.9 million
from the Northeast BC CGU as a result of successful capital activity in the
Company's core areas.
Impairments
Exploration and evaluation assets are assessed for impairment when they are
transferred to property, plant, and equipment or if facts and circumstances
suggest that the carrying amount exceeds the recoverable amount. For the year
ended December 31, 2013, total exploration and evaluation asset impairments of
$0.6 million were recognized relating to the expiry of undeveloped land rights
(CGUs - Miscellaneous AB, and Saskatchewan).
For the year ended December 31, 2012, total exploration and evaluation asset
impairments of $4.7 million were recognized. Asset impairments of $2.4 million
were recognized relating to the determination of certain exploration and
evaluation activities to be uneconomical (CGU - Miscellaneous AB). Additional
exploration and evaluation impairments of $2.3 million were recognized in 2012
relating to the expiry of undeveloped land rights (CGUs - Lookout Butte AB,
Miscellaneous AB, and Saskatchewan).
6. PROPERTY, PLANT, AND EQUIPMENT
Cost Total
----------------------------------------------------------------------------
Balance, December 31, 2011 236,846
Additions 54,756
Transfer from exploration and evaluation assets 36,838
Change in decommissioning obligation estimates 2,883
Capitalized share based compensation 319
----------------------------------------------------------------------------
Balance, December 31, 2012 331,642
Additions 66,694
Transfer from exploration and evaluation assets 48,610
Change in decommissioning obligation estimates 687
Capitalized share based compensation 207
----------------------------------------------------------------------------
Balance, December 31, 2013 447,840
----------------------------------------------------------------------------
Accumulated Depletion, Depreciation, and Impairment Total
----------------------------------------------------------------------------
Balance, December 31, 2011 44,514
Depletion and depreciation 36,685
Impairment 8,740
----------------------------------------------------------------------------
Balance, December 31, 2012 89,939
Depletion and depreciation 44,596
Impairment 163
----------------------------------------------------------------------------
Balance, December 31, 2013 134,698
----------------------------------------------------------------------------
Net Book Value Total
----------------------------------------------------------------------------
December 31, 2011 192,332
December 31, 2012 241,703
December 31, 2013 313,142
----------------------------------------------------------------------------
During the year ended December 31, 2013, approximately $0.5 million (2012 - $0.4
million) of directly attributable general and administrative costs were
capitalized as expenditures on property, plant, and equipment.
Depletion and depreciation
The calculation of depletion and depreciation expense for the year ended
December 31, 2013 included an estimated $335.8 million (2012 - $231.8 million)
for future development costs associated with proved plus probable undeveloped
reserves and excluded approximately $12.6 million (2012 - $11.4 million) for the
estimated salvage value of production equipment and facilities.
Impairments
At December 31, 2013, with the exception of Lookout Butte AB, there were no
indicators of impairment of property, plant, and equipment. Due to higher than
expected production declines and no capital expenditures during 2013 at Lookout
Butte AB to maintain reserve values, the Company recorded property, plant, and
equipment impairments of $0.2 million during the fourth quarter. The impairment
test at December 31, 2013 for Lookout Butte AB was primarily based on the net
present value of cash flows from oil and natural gas reserves at a pre-tax
discount rate of 15 percent. The impairment test was carried out using the
following commodity price estimates of the Company's independent reserve
evaluators:
West Texas Foreign Edmonton Oil AECO Gas
Intermediate Oil Exchange Rate Par Price Price
Year ($US/bbl) (USD/CDN) ($CDN/bbl) ($CDN/mmbtu)
----------------------------------------------------------------------------
2014 97.50 0.950 92.76 4.03
2015 97.50 0.950 97.37 4.26
2016 97.50 0.950 100.00 4.50
2017 97.50 0.950 100.00 4.74
2018 97.50 0.950 100.00 4.97
2019 97.50 0.950 100.00 5.21
2020 98.54 0.950 100.77 5.33
2021 100.51 0.950 102.78 5.44
2022 102.52 0.950 104.83 5.55
2023 104.57 0.950 106.93 5.66
Escalate
Thereafter 2.0% per year 2.0% per year 2.0% per year
----------------------------------------------------------------------------
For the year ended December 31, 2012, the Company recorded property, plant, and
equipment impairments of $8.7 million relating to Smoky AB, Lookout Butte AB,
Miscellaneous AB, and Saskatchewan CGUs mainly as a result of weakening natural
gas prices and limited capital expenditures in these CGUs to maintain their
reserve values.
7. CREDIT FACILITY
During the third quarter of 2013, the Company entered into a syndicated credit
facility with three Canadian chartered banks. The syndicated credit facility
replaced the Company's previous $140 million revolving operating demand loan
credit facility. The syndicated facility has a borrowing base of $150 million,
consisting of a $140 million revolving line of credit and a $10 million
operating line of credit. The syndicated facility revolves for a 364 day period
and will be subject to its next 364 day extension by July 11, 2014. If not
extended, the syndicated facility will cease to revolve, the margins thereunder
will increase by 0.50%, and all outstanding advances will become repayable in
one year from the extension date.
Advances under the syndicated facility are available by way of prime rate loans,
with interest rates between 1.00% and 2.50% over the Canadian prime lending
rate, and bankers' acceptances and LIBOR loans, which are subject to stamping
fees and margins ranging from 2.00% to 3.50% depending upon the debt to cash
flow ratio of the Company. Standby fees are charged on the undrawn syndicated
facility at rates ranging from 0.50% to 0.875%. The credit facility is secured
by a $300 million fixed and floating charge debenture on the assets of the
Company. At December 31, 2013, $116.3 million (December 31, 2012 - $68.5
million) had been drawn on the credit facility. In addition, at December 31,
2013, 2013, the Company had outstanding letters of guarantee of approximately
$2.5 million (December 31, 2012 - $1.5 million) which reduce the amount that can
be borrowed under the credit facility. The next scheduled borrowing base review
of the syndicated facility is scheduled on or before June 30, 2014.
8. PROVISIONS - DECOMMISSIONING OBLIGATIONS
The Company's decommissioning obligations result from its ownership interest in
oil and natural gas assets including well sites and gathering systems. The total
decommissioning obligation is estimated based on the Company's net ownership
interest in all wells and facilities, estimated costs to abandon and reclaim the
wells and facilities, and the estimated timing of the costs to be incurred in
future periods. The total undiscounted amount of the estimated cash flows
(adjusted for inflation at 2% per year) required to settle the decommissioning
obligations is approximately $33.4 million which is estimated to be incurred
over the next 27 years. At December 31, 2013, a risk-free rate of 3.1% (December
31, 2012 - 2.3%) was used to calculate the net present value of the
decommissioning obligations.
Year Ended Year Ended
December 31, 2013 December 31, 2012
----------------------------------------------------------------------------
Balance, beginning of year 21,852 19,250
Provisions incurred 2,253 2,208
Provisions disposed (80) -
Provisions settled (691) (734)
Revisions (1,486) 675
Accretion 590 453
----------------------------------------------------------------------------
Balance, end of year 22,438 21,852
----------------------------------------------------------------------------
9. SHAREHOLDERS' CAPITAL
The Company is authorized to issue an unlimited number of voting common shares,
an unlimited number of non-voting common shares, Class A preferred shares,
issuable in series, and Class B preferred shares, issuable in series. No
non-voting common shares or preferred shares have been issued.
Voting Common Shares Number Amount
----------------------------------------------------------------------------
Balance, December 31, 2011 88,095 225,848
Exercise of stock options 13 29
Exercise of warrants 1,200 2,400
Expiry of sunset clauses (47) -
----------------------------------------------------------------------------
Balance, December 31, 2012 89,261 228,277
Exercise of stock options 1,409 3,399
Share issuances 6,042 21,983
Share issue costs, net of future tax effect
of $0.2 million (749)
Flow-through share premium (2,347)
----------------------------------------------------------------------------
Balance, December 31, 2013 96,712 250,563
----------------------------------------------------------------------------
In June 2013, the Company issued approximately 6.0 million common shares on a
flow-through basis for gross proceeds of approximately $22.0 million.
Approximately 4.2 million shares were issued at a price of $3.70 per share in
respect of Canadian exploration expenses ("CEE") and approximately 1.8 million
shares were issued at a price of $3.50 per share in respect of Canadian
development expenses ("CDE"). Upon issuance, the premium received on the
flow-through shares, being the difference between the fair value of the
flow-through shares issued and the fair value that would have been received for
common shares at the date of the announcement of the financing, was recognized
as a liability. Under the terms of the flow-through share agreements, the
Company is committed to spend approximately $22.0 million on qualifying
exploration and development expenditures prior to December 31, 2014. As at
December 31, 2013, the Company had satisfied this flow-through share commitment.
Proceeds from the share issuance were used to fund the Company's Edson Bluesky
and Dawson Montney developments, other capital projects, and general corporate
purposes.
10. SHARE BASED COMPENSATION PLANS
Stock options
The Company has authorized and reserved for issuance 9.7 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
three years and an option's maximum term is 5 years. At December 31, 2013, 8.8
million options are outstanding at exercise prices ranging from $1.10 to $3.46
per share.
The number and weighted average exercise price of stock options are as follows:
Number of Weighted Average
Options Exercise Price ($)
----------------------------------------------------------------------------
Balance, December 31, 2011 7,942 1.97
Granted 713 3.43
Exercised (13) 1.30
Forfeited (41) 2.51
----------------------------------------------------------------------------
Balance, December 31, 2012 8,601 2.09
Granted 1,717 2.77
Exercised (1,409) 1.46
Forfeited (60) 2.83
----------------------------------------------------------------------------
Balance, December 31, 2013 8,849 2.32
----------------------------------------------------------------------------
For the stock options exercised during 2013, the weighted average share price of
the Company's common shares at the date of exercise was $2.95 per share (2012 -
$2.40 per share).
The following table summarizes the stock options outstanding and exercisable at
December 31, 2013:
Options Outstanding Options Exercisable
----------------------------------------------------------------------------
Weighted Weighted Weighted
Average Average Average
Remaining Exercise Exercise
Exercise Price Number Life Price Number Price
----------------------------------------------------------------------------
$1.10 to $2.00 2,514 1.1 1.23 2,514 1.23
$2.01 to $3.00 5,593 2.9 2.65 2,766 2.62
$3.01 to $3.46 742 3.0 3.44 264 3.46
----------------------------------------------------------------------------
8,849 2.4 2.32 5,544 2.03
----------------------------------------------------------------------------
Warrants
The Company had an arrangement that allowed warrants to be issued to directors,
officers, and employees. During the year ended December 31, 2007, the Company
issued 2.4 million warrants under this arrangement. The warrants expired
unexercised in December 2013.
On October 29, 2009, the Company issued an additional 1.2 million warrants at an
exercise price of $1.40 per share in conjunction with a private placement share
issuance. The warrants vested immediately and had an expiry date of October 29,
2012. The warrants were exercised during 2012.
The number and weighted average exercise price of warrants are as follows:
Weighted
Number of Average
Warrants Exercise Price
----------------------------------------------------------------------------
Balance, December 31, 2011 3,521 3.64
Exercised (1,200) 1.40
----------------------------------------------------------------------------
Balance, December 31, 2012 2,321 4.80
Expired (2,321) 4.80
----------------------------------------------------------------------------
Balance, December 31, 2013 - -
----------------------------------------------------------------------------
Share based compensation
The Company accounts for its share based compensation plans using the fair value
method. Under this method, compensation cost is charged to earnings over the
vesting period for stock options and warrants granted to officers, directors,
employees, and consultants with a corresponding increase to contributed surplus.
The fair value of the stock options granted was estimated on the date of grant
using the Black-Scholes-Merton option pricing model with the following weighted
average assumptions:
December 31, 2013 December 31, 2012
----------------------------------------------------------------------------
Risk-free interest rate (%) 1.6 1.3
Expected life (years) 4.0 4.0
Expected volatility (%) 51.6 77.2
Expected dividend yield (%) - -
Forfeiture rate (%) 5.9 7.4
Weighted average fair value of options
granted ($ per option) 1.15 1.96
----------------------------------------------------------------------------
11. PER SHARE AMOUNTS
The following table summarizes the weighted average number of shares used in the
basic and diluted net earnings per share calculations:
December 31, 2013 December 31, 2012
----------------------------------------------------------------------------
Weighted average number of shares -
basic 93,051 88,319
Dilutive effect of share based
compensation plans 1,922 -
----------------------------------------------------------------------------
Weighted average number of shares -
diluted 94,973 88,319
----------------------------------------------------------------------------
For the year ended December 31, 2013, 3.9 million stock options (2012 - 8.6
million) and nil warrants (2012 - 2.3 million) were anti-dilutive and were not
included in the diluted earnings per share calculation.
12. KEY MANAGEMENT PERSONNEL
The Company considers its directors and executives to be key management
personnel. The key management personnel compensation is comprised of the
following:
December 31, 2013 December 31, 2012
----------------------------------------------------------------------------
Short-term wages and benefits 2,996 2,511
Share based compensation (1) 1,700 2,645
----------------------------------------------------------------------------
Total (2) (3) 4,696 5,156
----------------------------------------------------------------------------
(1) Represents the amortization of share based compensation expense
associated with the Company's share based compensation plans granted to
key management personnel.
(2) Balances outstanding and payable at December 31, 2013 were $0.5 million
(2012 - $0.5 million).
(3) At December 31, 2013, key management personnel included 15 individuals
(2012 - 16 individuals).
13. FINANCE EXPENSES
Finance expenses include the following:
December 31, 2013 December 31, 2012
----------------------------------------------------------------------------
Interest expense (note 7) 3,851 1,449
Accretion of decommissioning obligations
(note 8) 590 453
----------------------------------------------------------------------------
Finance expenses 4,441 1,902
----------------------------------------------------------------------------
14. INCOME TAXES
(a) The provision for income taxes in the consolidated statements of earnings
(loss) and comprehensive earnings (loss) reflects an effective tax rate which
differs from the expected statutory tax rate. The differences were accounted for
as follows:
December 31, 2013 December 31, 2012
----------------------------------------------------------------------------
Earnings (loss) before taxes 20,349 (5,066)
Statutory income tax rate 25.0% 25.0%
----------------------------------------------------------------------------
Expected income tax expense (reduction) 5,087 (1,267)
Increase in income taxes resulting from:
Share based compensation and other
non-deductible amounts 524 878
Flow-through shares 5,496 1,250
Other 19 19
Recognition of previously unrecognized
tax assets - 121
----------------------------------------------------------------------------
11,126 1,001
Flow-through share premium (2,347) (813)
----------------------------------------------------------------------------
8,779 188
----------------------------------------------------------------------------
The Company has recognized a net deferred tax asset based on the independently
evaluated reserve report as cash flows are expected to be sufficient to realize
the deferred tax asset.
(b) Recognized deferred tax balances for the years ended December 31, 2013 and
2012 are as follows:
Balance Recognized in Balance
January 1, Earnings or Recognized in December 31,
2013 2013 Loss Equity 2013
----------------------------------------------------------------------------
Deferred income tax
assets
(liabilities):
Oil and natural gas
properties and
equipment (719) (10,758) - (11,477)
Decommissioning
obligations 5,463 147 - 5,610
Risk management
contracts 398 (306) - 92
Share issue costs 534 (230) 250 554
Non-capital losses 7,766 21 - 7,787
----------------------------------------------------------------------------
Net deferred income
tax asset 13,442 (11,126) 250 2,566
----------------------------------------------------------------------------
Balance Recognized in Balance
January 1, Earnings or Recognized in December 31,
2012 2012 Loss Equity 2012
----------------------------------------------------------------------------
Deferred income tax
assets
(liabilities):
Oil and natural gas
properties and
equipment 1,120 (1,839) - (719)
Decommissioning
obligations 4,812 651 - 5,463
Risk management
contracts - 398 - 398
Share issue costs 745 (211) - 534
Non-capital losses 7,766 - - 7,766
----------------------------------------------------------------------------
Net deferred income
tax asset 14,443 (1,001) - 13,442
----------------------------------------------------------------------------
At December 31, 2013, the Company has estimated federal tax pools of $341.1
million (2012 - $299.6 million) available for deduction against future taxable
income.
The Company has accumulated non-capital losses for income tax purposes of
approximately $31.1 million (2012 - $31.1 million), which can be used to offset
income in future periods. These losses are as follows:
Year of expiry Amount
----------------------------------------------------------------------------
2032 83
2031 -
2030 -
2029 248
2028 903
2027 8,121
2026 6,744
2025 8,066
2024 2,209
2023 4,772
----------------------------------------------------------------------------
31,146
----------------------------------------------------------------------------
(c) Deferred tax assets have not been recognized in respect of the following items:
2013 2012
----------------------------------------------------------------------------
Deductible temporary differences 8,100 8,100
Capital losses 1,797 1,797
----------------------------------------------------------------------------
9,897 9,897
----------------------------------------------------------------------------
The capital losses and the deductible temporary differences do not expire under
current tax legislation. Deferred tax assets have not been recognized in respect
of these items because it is not probable that future taxable profits will be
available against which the Company can utilize the benefits.
In 2012, $0.1 million of previously recognized tax losses were derecognized as a
result of changes in estimates of future results from operating activities.
15. FAIR VALUE OF FINANCIAL INSTRUMENTS
Cash and cash equivalents, accounts receivable, accounts payable and accrued
liabilities, credit facility
The fair value of cash and cash equivalents, accounts receivable, and accounts
payable and accrued liabilities at December 31, 2013 approximated their carrying
value due to their short term to maturity.
The fair value of the credit facility approximates its carrying value as it
bears interest at floating rates and the premium charged is indicative of the
Company's current credit spreads.
The Company classified the fair value of its financial instruments at fair value
according to the following hierarchy based on the amount of observable inputs
used to value the instrument:
-- Level 1 - observable inputs, such as quoted market prices in active
markets
-- Level 2 - inputs, other that the quoted market prices in active markets,
which are observable, either directly or indirectly
-- Level 3 - unobservable inputs for the asset or liability in which little
or no market data exists, therefore requiring an entity to develop its
own assumptions
The fair value of derivative contracts used for risk management as shown in the
statement of financial position as at December 31, 2013 is measured using level
2. During the year ended December 31, 2013, there were no transfers between
level 1, level 2, and level 3 classified assets and liabilities.
16. FINANCIAL RISK MANAGEMENT
The Company's activities expose it to a variety of financial risks that arise as
a result of its exploration, development, production, and financing activities.
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.
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. The Company may use financial derivatives or physical
delivery sales contracts to manage market risks. All such transactions are
conducted within risk management tolerances that are reviewed by the Board of
Directors.
Foreign exchange risk
The prices received by the Company for the production of oil, natural gas, and
NGLs are primarily determined in reference to US 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. Assuming
that all other variables remain constant, a $0.01 increase or decrease in the
Canadian/US dollar exchange rate would have impacted net earnings and
comprehensive earnings by approximately $0.8 million for the year ended December
31, 2013 (2012 - $0.5 million).
Interest rate risk
The Company is exposed to interest rate risk as it borrows funds at floating
interest rates (note 7). In addition, the Company may at times issue shares on a
flow-through basis (note 9). 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 comprehensive
earnings by approximately $0.6 million for the year ended December 31, 2013
(2012 - $0.4 million).
Commodity price risk
Oil and natural gas prices are impacted by not only the relationship between the
Canadian and US dollar but also by world economic events that dictate the levels
of supply and demand. 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. A $1.00/boe increase or decrease in commodity
prices would have impacted net earnings and comprehensive earnings by
approximately $2.2 million for the year ended December 31, 2013 (2012 - $1.7
million).
In addition, the Company may enter into commodity price contracts to manage
future cash flows. For the year ended December 31, 2013, the realized loss on
the Company's oil contracts was $1.2 million and the realized loss on the gas
contracts was $1.6 million. For the year ended December 31, 2013, the unrealized
loss on the oil contracts was $0.2 million and the unrealized gain on the gas
contracts was $1.4 million.
At December 31, 2013, the Company had the following commodity price contracts
outstanding:
Quantity
Commodity Period Type of Contract Contracted Contract Price
----------------------------------------------------------------------------
January 1, 2014 -
Oil December 31, 2014 Financial - Swap 500 bbls/d WTI CDN $100.80/bbl
January 1, 2014 -
Oil March 31, 2014 Financial - Swap 500 bbls/d WTI CDN $106.55/bbl
Natural April 1, 2014 -
Gas October 31, 2014 Financial - Swap 5,000 GJ/d AECO CDN $3.505/GJ
Natural April 1, 2014 -
Gas October 31, 2014 Financial - Swap 5,000 GJ/d AECO CDN $3.650/GJ
----------------------------------------------------------------------------
Financial assets and liabilities are only offset if the Company has the legal
right to offset and intends to settle on a net basis or settle the asset and
liability simultaneously. The following table summarizes the gross asset and
liability positions of the Company's risk management contracts that are offset
on the statement of financial position:
December 31, 2013 December 31, 2012
----------------------------------------------------------------------------
Gross liability (447) (1,592)
Gross asset 79 -
----------------------------------------------------------------------------
Net liability (368) (1,592)
----------------------------------------------------------------------------
Subsequent to December 31, 2013, the Company entered into the following
commodity price contracts:
Quantity
Commodity Period Type of Contract Contracted Contract Price
----------------------------------------------------------------------------
April 1, 2014 -
Oil June 30, 2014 Financial - Swap 500 bbls/d WTI CDN $108.00/bbl
July 1, 2014 -
Oil September 30, 2014 Financial - Swap 500 bbls/d WTI CDN $110.00/bbl
Natural April 1, 2014 - 10,000
Gas October 31, 2014 Financial - Swap GJ/d AECO CDN $3.745/GJ
----------------------------------------------------------------------------
Credit risk
Credit risk represents the financial loss that the Company would suffer if the
Company's counterparties to a financial asset 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 oil 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 of
accounts receivable on the statement of financial position. At December 31,
2013, $15.4 million or 95.2% of the Company's outstanding accounts receivable
were current while $0.8 million or 4.8% were outstanding over 90 days but not
impaired. During the year ended December 31, 2013, the Company did not deem any
outstanding accounts receivable to be uncollectable.
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, 2013:
----------------------------------------------------------------------------
Carrying Contractual Less than One to More than
Amount Cash Flows One Year Two Years Two Years
----------------------------------------------------------------------------
Non-derivative
financial
liabilities
Accounts payable
and accrued
liabilities 19,480 19,480 19,480 - -
Credit facility 116,324 116,324 - 116,324 -
Derivative
financial
liabilities
Risk management
contracts 368 368 368 - -
----------------------------------------------------------------------------
136,172 136,172 19,848 116,324 -
----------------------------------------------------------------------------
17. CAPITAL MANAGEMENT
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 credit facility and
excluding risk management contracts, less current assets). To maintain or adjust
the capital structure, the Company may, from time to time, issue shares, raise
debt, or adjust its capital spending to manage its current and projected debt
levels.
December 31, 2013 December 31, 2012
----------------------------------------------------------------------------
Shareholders' equity 214,691 179,891
Net debt 117,840 80,112
----------------------------------------------------------------------------
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 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 facility less current liabilities
excluding any current portion drawn on the credit facility and risk management
contracts. The Company was fully compliant with this covenant at December 31,
2013.
There were no changes in the Company's approach to capital management from the
previous year.
18. SUPPLEMENTAL DISCLOSURES
Presentation of expenses
The Company's consolidated statements of earnings (loss) and comprehensive
earnings (loss) is prepared primarily by nature of expense, with the exception
of employee compensation costs which are included in both production and general
and administrative expenses. Included in production expenses and general and
administrative expenses for the year ended December 31, 2013 are $0.1 million
and $5.2 million of wages and benefits, respectively (2012 - $0.1 million and
$4.3 million, respectively).
19. SUPPLEMENTAL CASH FLOW INFORMATION
December 31, 2013 December 31, 2012
----------------------------------------------------------------------------
Accounts receivable (183) (4,685)
Prepaid expenses and deposits (248) (710)
Accounts payable and accrued liabilities (9,685) (5,527)
----------------------------------------------------------------------------
Change in non-cash working capital (10,116) (10,922)
----------------------------------------------------------------------------
Relating to:
Investing (9,123) (8,490)
Operating (993) (2,432)
----------------------------------------------------------------------------
Change in non-cash working capital (10,116) (10,922)
----------------------------------------------------------------------------
20. COMMITMENTS
The following is a summary of the Company's contractual obligations and
commitments at December 31, 2013:
2014 2015 2016 2017 2018 Thereafter Total
----------------------------------------------------------------------------
Office leases 395 - - - - - 395
Field equipment leases 559 - - - - - 559
Firm transportation
agreements 8 8 6 - - - 22
----------------------------------------------------------------------------
962 8 6 - - - 976
----------------------------------------------------------------------------
CORPORATE INFORMATION
OFFICERS AND DIRECTORS
Robert J. Zakresky, CA BANK
President, CEO & Director National Bank of Canada
1800, 311 - 6th Avenue SW
Nolan Chicoine, MPAcc, CA Calgary, Alberta T2P 3H2
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 1600, 421 - 7th Avenue SW
Calgary, Alberta T2P 4K9
Larry G. Moeller, CA, CBV
Chairman of the Board
Daryl H. Gilbert, P.Eng. AUDITORS
Director KPMG LLP
2700, 205 - 5th Avenue SW
Don Cowie Calgary, Alberta T2P 4B9
Director
Brian Krausert
Director INDEPENDENT ENGINEERS
GLJ Petroleum Consultants Ltd.
Gary W. Burns 4100, 400 - 3rd Avenue SW
Director Calgary, Alberta T2P 4H2
Don D. Copeland, P.Eng.
Director
Brian Boulanger
Director
Patricia Phillips
Director
FOR FURTHER INFORMATION PLEASE CONTACT:
Crocotta Energy Inc.
Robert J. Zakresky
President & CEO
(403) 538-3736
Crocotta Energy Inc.
Nolan Chicoine
VP Finance & CFO
(403) 538-3738
Crocotta Energy Inc.
Suite 700, 639 - 5th Avenue SW
Calgary, Alberta T2P 0M9
(403) 538-3737
(403) 538-3735 (FAX)
www.crocotta.ca
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