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| Share Name | Share Symbol | Market | Type |
|---|---|---|---|
| TSXV:CDE | TSX Venture | Common Stock |
| Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
|---|---|---|---|---|---|---|---|---|---|---|
| 0.00 | 0.00% | 0 | - |
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Premium
CROCOTTA ENERGY INC. (TSX:CTA) is pleased to announce its financial and
operating results for the three and six months ended June 30, 2013, including
condensed interim consolidated financial statements, notes to the condensed
interim consolidated financial statements, and Management's Discussion and
Analysis. All dollar figures are Canadian dollars unless otherwise noted.
HIGHLIGHTS
-- Entered into rich gas premium agreements which are anticipated to
increase net revenues and reduce costs
-- Drilled Cardium step-out wells and acquired additional lands to increase
Cardium horizontal inventory to 71 gross (50 net) from 30 net at year-
end
-- Increased funds from operations 16% to $14.3 million in Q2 2013 from
$12.3 million in Q2 2012
-- Raised gross proceeds of $22.0 million through the issuance of 6.0
million common shares on a flow-through basis
-- Subsequent to Q2 2013, entered into a $145 million syndicated credit
facility
FINANCIAL RESULTS
Three Months Ended Six Months Ended
June 30 June 30
($000s, except per
share amounts) 2013 2012 % Change 2013 2012 % Change
----------------------------------------------------------------------------
Oil and natural gas
sales 25,152 17,518 44 53,419 37,658 42
Funds from operations
(1) 14,280 12,275 16 31,404 25,249 24
Per share - basic 0.16 0.14 14 0.35 0.29 21
Per share - diluted 0.15 0.14 7 0.34 0.28 21
Net earnings 3,604 1,065 238 6,208 772 704
Per share - basic
and diluted 0.04 0.01 300 0.07 0.01 600
Capital expenditures 14,182 11,049 28 45,700 38,688 18
Net debt (2) 73,473 41,525 77
Common shares
outstanding (000s)
Weighted average -
basic 90,549 88,095 3 89,909 88,095 2
Weighted average -
diluted 93,299 90,234 3 92,451 91,000 2
End of period -
basic 95,448 88,095 8
End of period -
diluted 106,276 100,271 6
----------------------------------------------------------------------------
(1) Funds from operations and funds from operations per share do not have
any standardized meaning prescribed by International Financial Reporting
Standards ("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 (including the revolving credit
facility and excluding risk management contracts) 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.
Three Months Ended Six Months Ended
OPERATING RESULTS June 30 June 30
% %
2013 2012 Change 2013 2012 Change
----------------------------------------------------------------------------
Daily production
Oil and NGLs
(bbls/d) 2,158 2,053 5 2,423 2,165 12
Natural gas (mcf/d) 36,412 27,309 33 36,639 27,081 35
----------------------------------------------------------------------------
Oil equivalent
(boe/d) 8,227 6,604 25 8,529 6,678 28
Revenue
Oil and NGLs ($/bbl) 63.16 64.77 (2) 65.76 67.17 (2)
Natural gas ($/mcf) 3.85 2.18 77 3.71 2.27 63
----------------------------------------------------------------------------
Oil equivalent
($/boe) 33.60 29.15 15 34.60 30.98 12
Royalties
Oil and NGLs ($/bbl) 8.51 8.72 (2) 8.87 8.97 (1)
Natural gas ($/mcf) 0.03 0.20 (85) 0.12 0.14 (14)
----------------------------------------------------------------------------
Oil equivalent
($/boe) 2.35 3.55 (34) 3.04 3.46 (12)
Production expenses
Oil and NGLs ($/bbl) 6.62 5.39 23 5.86 5.09 15
Natural gas ($/mcf) 1.18 1.04 13 1.14 0.97 18
----------------------------------------------------------------------------
Oil equivalent
($/boe) 6.97 5.96 17 6.54 5.57 17
Transportation
expenses
Oil and NGLs ($/bbl) 1.23 0.87 41 1.05 1.00 5
Natural gas ($/mcf) 0.10 0.18 (44) 0.10 0.18 (44)
----------------------------------------------------------------------------
Oil equivalent
($/boe) 0.76 1.00 (24) 0.74 1.05 (30)
Operating netback (1)
Oil and NGLs ($/bbl) 46.80 49.79 (6) 49.98 52.11 (4)
Natural gas ($/mcf) 2.54 0.76 234 2.35 0.98 140
----------------------------------------------------------------------------
Oil equivalent
($/boe) 23.52 18.64 26 24.28 20.90 16
Depletion and
depreciation ($/boe) (13.74) (14.56) (6) (13.59) (14.73) (8)
Asset impairment
($/boe) (0.17) (0.96) (82) (0.21) (2.70) (92)
General and
administrative
expenses ($/boe) (2.18) (1.62) 35 (2.05) (1.69) 21
Share based
compensation ($/boe) (0.60) (1.87) (68) (0.62) (1.71) (64)
Finance expenses
($/boe) (1.26) (0.98) 29 (1.19) (0.72) 65
Deferred tax expense
($/boe) (2.56) (1.77) 45 (1.92) (1.14) 68
Realized gain (loss)
on risk management
contracts ($/boe) (1.20) 4.22 (128) (0.88) 2.09 (142)
Unrealized gain on
risk management
contracts ($/boe) 3.01 0.67 349 0.20 0.33 (39)
----------------------------------------------------------------------------
Net earnings ($/boe) 4.82 1.77 172 4.02 0.63 538
----------------------------------------------------------------------------
(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.
OPERATIONS UPDATE
In Q2 2013, Crocotta focused its efforts on completing its rich-gas premium
agreements with Aux Sable and interconnection agreement with Alliance to provide
access to premium liquids markets in the United States. There were a number of
benefits which included superior pricing and reduced downtime. As of June 1st,
the Edson plant was fully operational and Crocotta started delivery of its
liquids- rich Edson gas into the Alliance pipeline. Since start-up, Crocotta has
not experienced any production disruptions or downtime on the Edson volumes
producing through the facility.
The wet weather in late May and early June contributed to delays in getting two
new wells on production as well as pushing back the start of the summer drilling
program into late June. Since the end of Q2 2013, Crocotta has added a second
rig at Edson and is on schedule to meet its production exit target of 10,500
boepd.
Operating costs at Edson continued to be very competitive ($5.50/boe) while
Dawson/Sunrise remained very high ($11.00/boe) due to third party processing and
throughput charges. Crocotta anticipates the Dawson/Sunrise costs to reduce to
approximately $6.00/boe once the newly constructed plant is operational in late
August.
Further area specific data is outlined below:
Edson, Alberta
Crocotta has been very active in the Cardium formation where it has signed
various farm-in agreements and purchased lands in the immediate vicinity. A
significant step-out well was drilled as part of a farm-in that has added
approximately 12 gross (8.0 net) locations to inventory and 2.5 net sections
were purchased that added 11 (8.2 net) Cardium locations. This increases
Crocotta's undrilled Cardium inventory to 50 net locations as at the end of Q2
2013.
We currently have two rigs drilling in the Cardium at Edson and anticipate
having 8 gross (6.8 net) wells drilled in Q3 2013.
In the Bluesky, we have 1 (0.6 net) wells scheduled to be drilled and on-stream
in Q3 2013.
Dawson/Sunrise, NEBC
Crocotta's operations for Q3 2013 include completion of a gas plant, delivery of
liquids-rich gas into the Alliance system, and drilling three 100% working
interest wells. The wells include two wells into the upper Montney and one
exploratory well into the lower Montney. If successful, the three wells will
help prove up between 80 and 100 locations in the upper and lower Montney. The
Dawson/Sunrise property has many valuable qualities including high liquids
content, good accessibility to drill, and Crocotta-owned facilities.
Exploration Initiatives
Crocotta is drilling two oil exploration properties in 2013. In the Stoddart
area of northeast British Columbia, one horizontal well has been drilled and is
waiting on completion. In the Red Earth area of Alberta, Crocotta is planning
one vertical oil test well in late Q4 2013.
MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A")
August 9, 2013
The MD&A should be read in conjunction with the unaudited interim consolidated
financial statements and related notes for the three and six months ended June
30, 2013 and the audited consolidated financial statements and related notes for
the year ended December 31, 2012. The unaudited interim 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 (including the revolving credit
facility and excluding risk management contracts) 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".
Q2 2013 HIGHLIGHTS
-- Entered into rich gas premium agreements which are anticipated to
increase net revenues and reduce costs
-- Drilled Cardium step-out wells and acquired additional lands to increase
Cardium horizontal inventory to 71 gross (50 net) from 30 net at year-
end
-- Increased funds from operations 16% to $14.3 million in Q2 2013 from
$12.3 million in Q2 2012
-- Raised gross proceeds of $22.0 million through the issuance of 6.0
million common shares on a flow-through basis
-- Subsequent to Q2 2013, entered into a $145 million syndicated credit
facility
SUMMARY OF FINANCIAL
RESULTS
Three Months Ended Six Months Ended
June 30 June 30
($000s, except per
share amounts) 2013 2012 % Change 2013 2012 % Change
----------------------------------------------------------------------------
Oil and natural gas
sales 25,152 17,518 44 53,419 37,658 42
Funds from operations 14,280 12,275 16 31,404 25,249 24
Per share - basic 0.16 0.14 14 0.35 0.29 21
Per share - diluted 0.15 0.14 7 0.34 0.28 21
Net earnings 3,604 1,065 238 6,208 772 704
Per share - basic
and diluted 0.04 0.01 300 0.07 0.01 600
Total assets 315,945 255,954 23
Total long-term
liabilities 22,712 21,181 7
Net debt 73,473 41,525 77
----------------------------------------------------------------------------
The Company has experienced significant growth in oil and natural gas sales and
funds from operations during the first six months of 2013 compared to the first
half of 2012. Successful capital activity during the past year, at Edson, AB and
Northeast BC, resulted in a significant increase in production which, combined
with higher period-over-period natural gas commodity prices, led to increased
revenue and funds from operations.
Three Months Ended Six Months Ended
PRODUCTION June 30 June 30
2013 2012 % Change 2013 2012 % Change
----------------------------------------------------------------------------
Average Daily
Production
Oil and NGLs (bbls/d) 2,158 2,053 5 2,423 2,165 12
Natural gas (mcf/d) 36,412 27,309 33 36,639 27,081 35
----------------------------------------------------------------------------
Combined (boe/d) 8,227 6,604 25 8,529 6,678 28
----------------------------------------------------------------------------
Daily production for the three months ended June 30, 2013 increased 25% to 8,227
boe/d compared to 6,604 boe/d for the comparative period in 2012. Year-to-date,
daily production increased 28% to 8,529 boe/d in 2013 compared to 6,678 boe/d in
2012. The significant increase in production was mainly due to successful
drilling activity at Edson, AB and Northeast BC during the past year. Compared
to the previous quarter, daily production decreased in Q2 2013 to 8,227 boe/d
from 8,836 boe/d in Q1 2013 due to natural declines and decreased capital
activity due to breakup. The Company expects production to increase in Q3 2013.
Crocotta's production profile for the first half of 2013 was comprised of 72%
natural gas and 28% 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.
Three Months Ended Six Months Ended
REVENUE June 30 June 30
% %
($000s) 2013 2012 Change 2013 2012 Change
----------------------------------------------------------------------------
Oil and NGLs 12,403 12,098 3 28,841 26,465 9
Natural gas 12,749 5,420 135 24,578 11,193 120
----------------------------------------------------------------------------
Total 25,152 17,518 44 53,419 37,658 42
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Average Sales Price
----------------------------------------------------------------------------
Oil and NGLs ($/bbl) 63.16 64.77 (2) 65.76 67.17 (2)
Natural gas ($/mcf) 3.85 2.18 77 3.71 2.27 63
----------------------------------------------------------------------------
Combined ($/boe) 33.60 29.15 15 34.60 30.98 12
----------------------------------------------------------------------------
Revenue totaled $25.2 million for the second quarter of 2013, up 44% from $17.5
million in the comparative period. For the six months ended June 30, 2013,
revenue totaled $53.4 million, an increase of 42% from $37.7 million for the six
months ended June 30, 2012. The increase in revenue was due to significant
increases in production combined with significant increases in natural gas
commodity prices.
The following table outlines the Company's realized wellhead prices and industry
benchmarks:
Three Months Ended Six Months Ended
Commodity Pricing June 30 June 30
% %
2013 2012 Change 2013 2012 Change
----------------------------------------------------------------------------
Oil and NGLs
Corporate price
($CDN/bbl) 63.16 64.77 (2) 65.76 67.17 (2)
Edmonton par
($CDN/bbl) 92.94 84.39 10 90.77 88.54 3
West Texas
Intermediate
($US/bbl) 94.29 93.51 1 94.32 98.15 (4)
Natural gas
Corporate price
($CDN/mcf) 3.85 2.18 77 3.71 2.27 63
AECO price ($CDN/mcf) 3.45 1.90 82 3.32 2.03 64
Exchange rate
CDN/US dollar average
exchange rate 0.9774 0.9906 (1) 0.9846 0.9946 (1)
----------------------------------------------------------------------------
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 68.0% and 72.4% of Edmonton Par price for the three and six
months ended June 30, 2013, down from 76.8% and 75.9% for the comparative period
in 2012. The Company experienced a decline in realized NGLs prices during the
second quarter of 2013 due to a temporary shift in marketers. The shift was for
a bridge period in April and May as the Company transitioned to selling a
significant portion of its Edson, AB NGLs volumes under a new marketing
arrangement in June 2013. Corporate average natural gas prices were 111.6% and
111.7% of AECO prices for the three and six months ended June 30, 2013,
consistent with 114.7% and 111.8% in the comparative period.
Future prices received from the sale of the products may fluctuate as a result
of market factors. Other than noted below, the Company did not hedge any of its
oil, NGLs or natural gas production in 2013. During 2013, the Company had
entered into the following commodity price contracts:
Quantity Contract
Commodity Period Type of Contract Contracted Price
----------------------------------------------------------------------------
Oil February 1, 2013 - 1,000 WTI US
December 31, 2013 Financial - Swap bbls/d $94.72/bbl
Natural Gas January 1, 2013 - AECO CDN
December 31, 2013 Financial - Swap 10,000 GJ/d $2.705/GJ
Natural Gas January 1, 2013 - AECO CDN
December 31, 2013 Financial - Call 10,000 GJ/d $4.000/GJ
Natural Gas April 1, 2013 - AECO CDN
October 31, 2013 Financial - Put 15,000 GJ/d $3.000/GJ
----------------------------------------------------------------------------
For the three months ended June 30, 2013, the realized loss on the contracts was
$0.9 million and the unrealized gain on the contracts was $2.3 million. For the
six months ended June 30, 2013, the realized loss on the contracts was $1.4
million and the unrealized gain on the contracts was $0.3 million.
Three Months Ended Six Months Ended
ROYALTIES June 30 June 30
% %
($000s) 2013 2012 Change 2013 2012 Change
----------------------------------------------------------------------------
Oil and NGLs 1,671 1,628 3 3,889 3,532 10
Natural gas 87 503 (83) 799 670 19
----------------------------------------------------------------------------
Total 1,758 2,131 (18) 4,688 4,202 12
----------------------------------------------------------------------------
Average Royalty Rate
(% of sales)
----------------------------------------------------------------------------
Oil and NGLs 13.5 13.5 - 13.5 13.3 2
Natural gas 0.7 9.3 (92) 3.2 6.0 (47)
----------------------------------------------------------------------------
Combined 7.0 12.2 (43) 8.8 11.2 (21)
----------------------------------------------------------------------------
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 June 30, 2013, oil, NGLs, and natural gas royalties
decreased 18% to $1.8 million from $2.1 million in the comparative period. For
the six months ended June 30, 2013, oil, NGLs, and natural gas royalties
increased 12% to $4.7 million from $4.2 million in 2012. Oil and NGLs royalties
in 2013 increased from the comparative periods as a result of higher revenue
which stemmed from an increase in production. Natural gas royalties were
significantly lower in Q2 2013 compared to Q2 2012 as a result of a favourable
prior period adjustment to the annual capital cost and processing fee deductions
and an increase in the monthly capital cost and processing fee deductions.
The overall effective royalty rate was 7.0% for the three months ended June 30,
2013 compared to 12.2% for the three months ended June 30, 2012. Year-to-date,
the overall effective royalty rate was 8.8% in 2013 compared to 11.2% in 2012.
The effective oil and NGLs royalty rates in 2013 were consistent with the
comparative periods. The effective natural gas royalty rates in 2013 decreased
from the comparative periods as a result of a favourable prior period adjustment
to the annual capital cost and processing fee deductions and an increase in the
monthly capital cost and processing fee deductions.
Three Months Ended Six Months Ended
PRODUCTION EXPENSES June 30 June 30
2013 2012 % Change 2013 2012 % Change
----------------------------------------------------------------------------
Oil and NGLs ($/bbl) 6.62 5.39 23 5.86 5.09 15
Natural gas ($/mcf) 1.18 1.04 13 1.14 0.97 18
----------------------------------------------------------------------------
Combined ($/boe) 6.97 5.96 17 6.54 5.57 17
----------------------------------------------------------------------------
Per unit production expenses for the three and six months ended June 30, 2013
were $6.97/boe and $6.54/boe, respectively, compared to $5.96/boe and $5.57/boe
for the comparative periods ended June 30, 2012. The increase in production
expenses is mainly due to higher costs associated with wells brought on
production in Northeast BC during the latter part of 2012. Production expenses
in this area were approximately $11.00/boe due mainly to third party processing
and throughput charges. The Company is currently expanding its infrastructure in
this area and anticipates production expenses in Northeast BC to decrease to
approximately $6.00/boe once completed in late August 2013. Production expenses
in Edson, AB continued to be very competitive at approximately $5.50/boe during
the second quarter.
Compared to the previous quarter ended March 31, 2013, per unit production
expenses increased 14% from $6.13/boe. The increase from the previous quarter
was due to property taxes of $0.75/boe being incurred during the second quarter.
On an annualized basis, property taxes are anticipated to be approximately
$0.17/boe of total production expenses. The Company continues to focus on
opportunities to maintain operational efficiencies to enhance operating
netbacks.
TRANSPORTATION Three Months Ended Six Months Ended
EXPENSES June 30 June 30
% %
2013 2012 Change 2013 2012 Change
----------------------------------------------------------------------------
Oil and NGLs ($/bbl) 1.23 0.87 41 1.05 1.00 5
Natural gas ($/mcf) 0.10 0.18 (44) 0.10 0.18 (44)
----------------------------------------------------------------------------
Combined ($/boe) 0.76 1.00 (24) 0.74 1.05 (30)
----------------------------------------------------------------------------
Transportation expenses are mainly third-party pipeline tariffs incurred to
deliver production to the purchasers at main hubs. For the quarter ended June
30, 2013 compared to the quarter ended June 30, 2012, transportation expenses
decreased 24% to $0.76/boe from $1.00/boe. Year-to-date, transportation expenses
decreased 30% to $0.74/boe in 2012 from $1.05/boe in 2012. Oil and NGLs
transportation expenses were higher in Q2 2013 as a result of the Company's
production in Northeast BC being diverted to a different processing facility to
obtain credit for NGLs volumes that were not being extracted previously. The
decrease in natural gas transportation expenses per boe is due to obtaining a
lower contracted transportation fee in the fourth quarter of 2012 on the
majority of the Company's natural gas production. The lower contracted
transportation fee is in effect until the fourth quarter of 2013.
Three Months Ended Six Months Ended
OPERATING NETBACK June 30 June 30
% %
2013 2012 Change 2013 2012 Change
----------------------------------------------------------------------------
Oil and NGLs ($/bbl)
Revenue 63.16 64.77 (2) 65.76 67.17 (2)
Royalties 8.51 8.72 (2) 8.87 8.97 (1)
Production expenses 6.62 5.39 23 5.86 5.09 15
Transportation
expenses 1.23 0.87 41 1.05 1.00 5
----------------------------------------------------------------------------
Operating netback 46.80 49.79 (6) 49.98 52.11 (4)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Natural gas ($/mcf)
Revenue 3.85 2.18 77 3.71 2.27 63
Royalties 0.03 0.20 (85) 0.12 0.14 (14)
Production expenses 1.18 1.04 13 1.14 0.97 18
Transportation
expenses 0.10 0.18 (44) 0.10 0.18 (44)
----------------------------------------------------------------------------
Operating netback 2.54 0.76 234 2.35 0.98 140
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Combined ($/boe)
Revenue 33.60 29.15 15 34.60 30.98 12
Royalties 2.35 3.55 (34) 3.04 3.46 (12)
Production expenses 6.97 5.96 17 6.54 5.57 17
Transportation
expenses 0.76 1.00 (24) 0.74 1.05 (30)
----------------------------------------------------------------------------
Operating netback 23.52 18.64 26 24.28 20.90 16
----------------------------------------------------------------------------
----------------------------------------------------------------------------
During the second quarter of 2013, Crocotta generated an operating netback of
$23.52/boe, up 26% from $18.64/boe for the second quarter of 2012. During the
first half of 2013, Crocotta generated an operating netback of $24.28/boe
compared to $20.90/boe in the comparative period. The increases were due to
significant increases in natural gas commodity prices combined with decreases in
natural gas royalties and transportation expenses, partially offset by increases
in operating expenses. Operating netbacks in Q2 2013 were down slightly from
operating netbacks of $25.01/boe in Q1 2013 due mainly to lower oil and NGLs
realized prices and higher operating expenses.
The following is a reconciliation of operating netback per boe to net earnings
per boe for the periods noted:
Three Months Ended Six Months Ended
June 30 June 30
% %
($/boe) 2013 2012 Change 2013 2012 Change
----------------------------------------------------------------------------
Operating netback 23.52 18.64 26 24.28 20.90 16
Depletion and
depreciation (13.74) (14.56) (6) (13.59) (14.73) (8)
Asset impairment (0.17) (0.96) (82) (0.21) (2.70) (92)
General and
administrative
expenses (2.18) (1.62) 35 (2.05) (1.69) 21
Share based
compensation (0.60) (1.87) (68) (0.62) (1.71) (64)
Finance expenses (1.26) (0.98) 29 (1.19) (0.72) 65
Deferred tax expense (2.56) (1.77) 45 (1.92) (1.14) 68
Realized gain (loss)
on risk management
contracts (1.20) 4.22 (128) (0.88) 2.09 (142)
Unrealized gain on
risk management
contracts 3.01 0.67 349 0.20 0.33 (39)
----------------------------------------------------------------------------
Net earnings 4.82 1.77 172 4.02 0.63 538
----------------------------------------------------------------------------
----------------------------------------------------------------------------
DEPLETION AND Three Months Ended Six Months Ended
DEPRECIATION June 30 June 30
% %
2013 2012 Change 2013 2012 Change
----------------------------------------------------------------------------
Depletion and
depreciation ($000s) 10,285 8,748 18 20,985 17,903 17
Depletion and
depreciation ($/boe) 13.74 14.56 (6) 13.59 14.73 (8)
----------------------------------------------------------------------------
Depletion and depreciation for the three months ended June 30, 2013 was
$13.74/boe, down 6% from $14.56/boe for the comparative period ended June 30,
2012. Year-to-date, depletion and depreciation was down 8% to 13.59/boe in 2013
from $14.73/boe in 2012. The decrease is due to a significant increase in proved
and probable reserves stemming from successful drilling activities during 2012.
Depletion and depreciation of $13.74/boe in Q2 2013 was consistent with
depletion and depreciation of $13.46/boe for the previous quarter ended March
31, 2013.
Three Months Ended Six Months Ended
ASSET IMPAIRMENT June 30 June 30
% %
2013 2012 Change 2013 2012 Change
----------------------------------------------------------------------------
Asset impairment
($000s) 128 579 (78) 327 3,284 (90)
Asset impairment
($/boe) 0.17 0.96 (82) 0.21 2.70 (92)
----------------------------------------------------------------------------
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 six months ended June 30, 2013, total exploration and evaluation asset
impairments of $0.3 million were recognized relating to the expiry of
undeveloped land rights (CGUs - Miscellaneous AB and Saskatchewan). For the
comparative period ended June 30, 2012, total exploration and evaluation asset
impairments of $1.4 million were recognized. Asset impairments of $0.4 million
were recognized relating to the determination of certain exploration and
evaluation activities in southern Alberta to be uneconomical (CGU -
Miscellaneous AB). Additional exploration and evaluation impairments of $1.0
million were recognized relating to the expiry of undeveloped land rights (CGUs
- Smoky AB and Miscellaneous AB). For the three months ended June 30, 2013,
asset impairments of $0.1 million were recognized relating to the expiry of
undeveloped land rights (CGUs - Miscellaneous AB and Saskatchewan). For the
three months ended June 30, 2012, asset impairments of $0.6 million were
recognized relating to the expiry of undeveloped land rights (CGUs - Smoky AB,
Miscellaneous AB, and Saskatchewan).
For the six months ended June 30, 2012, the Company recorded property, plant,
and equipment impairments of $1.8 million relating to Smoky AB, Lookout Butte
AB, Miscellaneous AB, and Saskatchewan CGUs mainly as a result of weakening
natural gas prices during the first quarter of 2012. No property, plant, and
equipment impairments were recorded for the three and six months ended June 30,
2013.
GENERAL AND Three Months Ended Six Months Ended
ADMINISTRATIVE June 30 June 30
% %
($000s) 2013 2012 Change 2013 2012 Change
----------------------------------------------------------------------------
G&A expenses (gross) 1,887 1,301 45 3,896 2,785 40
G&A capitalized (68) (69) (1) (255) (146) 75
G&A recoveries (189) (256) (26) (479) (585) (18)
----------------------------------------------------------------------------
G&A expenses (net) 1,630 976 67 3,162 2,054 54
G&A expenses ($/boe) 2.18 1.62 35 2.05 1.69 21
----------------------------------------------------------------------------
General and administrative expenses ("G&A") increased to $2.18/boe and $2.05/boe
for the three and six months ended June 30, 2013, respectively, compared to
$1.62/boe and $1.69/boe for the three and six months ended June 30, 2012. The
increases were mainly due to an increase in employment costs.
SHARE BASED Three Months Ended Six Months Ended
COMPENSATION June 30 June 30
% %
2013 2012 Change 2013 2012 Change
----------------------------------------------------------------------------
Share based
compensation ($000s) 445 1,123 (60) 960 2,083 (54)
Share based
compensation ($/boe) 0.60 1.87 (68) 0.62 1.71 (64)
----------------------------------------------------------------------------
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 $0.60/boe for the three
months ended June 30, 2013 from $1.87/boe in the comparative period.
Year-to-date, share based compensation expense decreased to $0.62/boe in 2013
from $1.71/boe in 2012. The decrease was a result of a decrease in options
issued in 2013 combined with a significant increase in production in the first
half of 2013 compared to 2012. During the first half of 2013, the Company
granted 0.1 million options (2012 - 0.7 million).
Three Months Ended Six Months Ended
FINANCE EXPENSES June 30 June 30
($000s) 2013 2012 % Change 2013 2012 % Change
----------------------------------------------------------------------------
Interest expense 796 492 62 1,567 648 142
Accretion of
decommissioning
obligations 147 99 48 270 222 22
----------------------------------------------------------------------------
Finance expenses 943 591 60 1,837 870 111
Finance expenses
($/boe) 1.26 0.98 29 1.19 0.72 65
----------------------------------------------------------------------------
Interest expense relates 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 the first half of
2013 compared to the first half of 2012. At June 30, 2013, $63.8 million (June
30, 2012 - $39.7 million) had been drawn on the Company's credit facility.
DEFERRED INCOME TAXES
Deferred income tax expense on the earnings before taxes for the three and six
months ended June 30, 2013 were $1.9 million and $3.0 million, respectively,
compared to $1.1 million and $1.4 million for the comparative periods. This was
slightly larger than expected by applying the statutory tax rate to the earnings
before taxes due to non-deductible items such as share based compensation as
well as renouncing tax deductions related to flow-through shares.
Estimated tax pools at June 30, 2013 total approximately $312.6 million
(December 31, 2012 - $299.6 million).
FUNDS FROM OPERATIONS
Funds from operations for the three and six months ended June 30, 2013 were
$14.3 million ($0.15 per diluted share) and $31.4 million ($0.34 per diluted
share), respectively, compared to $12.3 million ($0.14 per diluted share) and
$25.2 million ($0.28 per diluted share) for the three and six months ended June
30, 2012. The increase was mainly due to a significant increase in revenue which
resulted from significant increases in production and natural gas prices. Of
note, included in funds from operations for the three and six months ended June
30, 2013 were realized losses on risk management contracts of $0.9 million and
$1.4 million, respectively, compared to realized gains on risk management
contracts of $2.5 million for both the three and six months ended June 30, 2012.
The following is a reconciliation of cash flow from operating activities to
funds from operations for the periods noted:
Three Months Ended Six Months Ended
June 30 June 30
%
($000s) 2013 2012 % Change 2013 2012 Change
----------------------------------------------------------------------------
Cash flow from
operating activities
(GAAP) 18,882 13,178 43 36,277 25,667 41
Add back:
Decommissioning
expenditures 163 163 - 247 350 (29)
Change in non-cash
working capital (4,765) (1,066) 347 (5,120) (768) 567
----------------------------------------------------------------------------
Funds from operations
(non-GAAP) 14,280 12,275 16 31,404 25,249 24
----------------------------------------------------------------------------
NET EARNINGS
The Company had net earnings of $3.6 million ($0.04 per diluted share) for the
three months ended June 30, 2013 compared to net earnings of $1.1 million ($0.01
per diluted share) for the three months ended June 30, 2012. Year-to-date, the
Company had net earnings of $6.2 million ($0.07 per diluted share) in 2013
compared to net earnings of $0.8 million ($0.01 per diluted share) in 2012. Net
earnings for the three and six months ended June 30, 2013 arose mainly due to a
significant increase in revenue which resulted from significant increases in
production and natural gas prices.
Three Months Ended Six Months Ended
CAPITAL EXPENDITURES June 30 June 30
% %
($000s) 2013 2012 Change 2013 2012 Change
----------------------------------------------------------------------------
Land 449 1,430 (69) 1,669 3,080 (46)
Drilling, completions,
and workovers 9,840 8,495 16 29,925 28,038 7
Equipment 3,589 826 335 13,335 7,152 86
Geological and
geophysical 304 298 2 771 418 84
----------------------------------------------------------------------------
Capital expenditures 14,182 11,049 28 45,700 38,688 18
----------------------------------------------------------------------------
For the three months ended June 30, 2013, the Company had net capital
expenditures of $14.2 million compared to net capital expenditures of $11.0
million for the three months ended June 30, 2012. For the six months ended June
30, 2013, the Company had net capital expenditures of $45.7 million compared to
$38.7 million for the comparative period in 2012. The increase in exploration
and development expenditures in the first half of 2013 was due mainly to an
increase in capital activity in the Company's core areas of Edson, AB and
Northeast BC. During the first six months of 2013, Crocotta drilled a total of 7
(6.0 net) wells, which resulted in 5 (4.4 net) oil wells and 2 (1.6 net)
liquids-rich natural gas wells.
LIQUIDITY AND CAPITAL RESOURCES
The Company had net debt of $73.5 million at June 30, 2013 compared to net debt
of $80.1 million at December 31, 2012. The decrease of $6.6 million was mainly
due to gross proceeds of $22.0 million from an equity financing in June 2013 and
funds from operations of $31.4 million, offset by $45.7 million used for the
purchase and development of oil and natural gas properties and equipment, $1.0
million in share issue costs, and $0.2 million in decommissioning expenditures.
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 will be used by the Company to fund
eligible CEE and CDE projects.
At June 30, 2013, the Company had a $140.0 million revolving operating demand
loan credit facility with a Canadian chartered bank. The revolving credit
facility bears interest at prime plus a range of 0.50% to 2.50% and is secured
by a $125 million fixed and floating charge debenture on the assets of the
Company. At June 30, 2013, $63.8 million (December 31, 2012 - $68.5 million) had
been drawn on the revolving credit facility. In addition, at June 30, 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.
Subsequent to June 30, 2013, the Company entered into a syndicated credit
facility with a syndicate of three Canadian chartered banks. The syndicated
credit facility replaces the Company's previous revolving operating demand loan
credit facility. The syndicated facility has a borrowing base of $145 million,
consisting of a $135 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 next scheduled borrowing
base review of the syndicated facility is scheduled on or before November 1,
2013.
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 subsequent to June 30, 2013, the Company entered into a $145 million
syndicated credit facility which replaced the previous $140 million 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 in spite of continued pressure on
oil and natural gas commodity prices. 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 June 30, 2013:
Less than One to After
($000s) Total One Year Three Years Three Years
----------------------------------------------------------------------------
Accounts payable and accrued
liabilities 21,619 21,619 - -
Revolving credit facility 63,786 63,786 - -
Risk management contracts 1,279 1,279 - -
Decommissioning obligations 20,867 49 189 20,629
Office leases 585 402 183 -
Field equipment leases 1,049 959 90 -
Firm transportation agreements 199 110 84 5
----------------------------------------------------------------------------
Total contractual obligations 109,384 88,204 546 20,634
----------------------------------------------------------------------------
In addition to the above commitments, as a result of the issuance of
flow-through shares in June 2013, the Company is committed to spend
approximately $22.0 million on qualifying exploration and development
expenditures prior to December 31, 2014. As at June 30, 2013, the Company had
spent $2.5 million in connection with this flow-through share commitment.
Under the terms of a farm-in agreement, the Company is also committed to drill
and complete one Edson Cardium well. Under the terms of the agreement, the
Company is committed to spud the well prior to August 2013. The well was spudded
subsequent to June 30, 2013 and the estimated total cost to drill and complete
the well is approximately $3.5 million.
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) June 30, 2013 August 9, 2013
----------------------------------------------------------------------------
Voting common shares 95,448 96,098
Stock options 8,507 7,857
Warrants 2,321 2,321
----------------------------------------------------------------------------
Total 106,276 106,276
----------------------------------------------------------------------------
SUMMARY OF QUARTERLY RESULTS
Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3
2013 2013 2012 2012 2012 2012 2011 2011
----------------------------------------------------------------------------
Average Daily
Production
Oil and NGLs
(bbls/d) 2,158 2,691 2,476 2,103 2,053 2,277 1,879 1,336
Natural gas
(mcf/d) 36,412 36,869 29,160 29,053 27,309 26,852 23,354 15,996
----------------------------------------------------------------------------
Combined (boe/d) 8,227 8,836 7,336 6,945 6,604 6,752 5,771 4,002
($000s, except
per share
amounts)
----------------------------------------------------------------------------
Oil and natural
gas sales 25,152 28,267 24,938 17,922 17,518 20,140 20,391 14,814
Funds from
operations 14,280 17,124 14,478 10,888 12,275 12,974 12,115 9,551
Per share -
basic 0.16 0.19 0.16 0.12 0.14 0.15 0.15 0.12
Per share -
diluted 0.15 0.19 0.16 0.12 0.14 0.14 0.14 0.11
Net earnings
(loss) 3,604 2,604 (2,082) (3,944) 1,065 (293) (7,052) 5,535
Per share -
basic and
diluted 0.04 0.03 (0.02) (0.04) 0.01 - (0.09) 0.07
----------------------------------------------------------------------------
Significant increases in production stemming from successful drilling activities
during the past two years has resulted in increasing oil and natural gas sales
and funds from operations over the same period. The Company had a net loss in
four of the eight previous quarters mainly as a result of asset impairments
recognized in each quarter on non-core properties.
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 Company's significant
critical accounting estimates have not changed from the year ended December 31,
2012.
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.
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
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. During 2013, the Company had entered into the
following commodity price contracts:
Quantity Contract
Commodity Period Type of Contract Contracted Price
----------------------------------------------------------------------------
Oil February 1, 2013 - 1,000 WTI US
December 31, 2013 Financial - Swap bbls/d $94.72/bbl
Natural Gas January 1, 2013 - AECO CDN
December 31, 2013 Financial - Swap 10,000 GJ/d $2.705/GJ
Natural Gas January 1, 2013 - AECO CDN
December 31, 2013 Financial - Call 10,000 GJ/d $4.000/GJ
Natural Gas April 1, 2013 - AECO CDN
October 31, 2013 Financial - Put 15,000 GJ/d $3.000/GJ
----------------------------------------------------------------------------
For the three months ended June 30, 2013, the realized loss on the contracts was
$0.9 million and the unrealized gain on the contracts was $2.3 million. For the
six months ended June 30, 2013, the realized loss on the contracts was $1.4
million and the unrealized gain on the contracts was $0.3 million.
Credit risk
Credit risk represents the financial loss that the Company would suffer if the
Company's counterparties to a financial instrument, in owing an amount to the
Company, fail to meet or discharge their obligation to the Company. A
substantial portion of the Company's accounts receivable and deposits are with
customers and joint venture partners in the oil and natural gas industry and are
subject to normal industry credit risks. The Company generally grants unsecured
credit but routinely assesses the financial strength of its customers and joint
venture partners.
The Company sells the majority of its production to three petroleum and natural
gas marketers and therefore is subject to concentration risk. Historically, the
Company has not experienced any collection issues with its 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 on the
statement of financial position. At June 30, 2013, $8.6 million or 87.0% of the
Company's outstanding accounts receivable were current while $1.3 million or
13.0% were outstanding over 90 days but not impaired. During the six months
ended June 30, 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, 2012. 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, 2012. In making this evaluation, management used
the criteria set forth by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on
their evaluation, the Company's CEO and CFO have identified weaknesses over
segregation of duties. Specifically, due to the limited number of finance and
accounting personnel at the Company, it is not feasible to achieve complete
segregation of duties with regards to certain complex and non-routine accounting
transactions that may arise. This weakness is considered to be a common
deficiency for many smaller listed companies in Canada. Notwithstanding the
weaknesses identified with regards to segregation of duties, the Company
concluded that all other of its internal controls over financial reporting were
effective as of December 31, 2012. 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.
Crocotta Energy Inc.
Condensed Consolidated Statements of Financial Position
(unaudited)
June 30 December 31
($000s) Note 2013 2012
----------------------------------------------------------------------------
Assets
Current assets
Accounts receivable 9,902 15,983
Prepaid expenses and deposits 2,030 1,550
----------------------------------------------------------------------------
11,932 17,533
Property, plant, and equipment (5) 263,957 241,703
Exploration and evaluation assets (4) 29,529 28,302
Deferred income taxes 10,527 13,442
----------------------------------------------------------------------------
304,013 283,447
----------------------------------------------------------------------------
315,945 300,980
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable and accrued
liabilities 21,619 29,165
Revolving credit facility (6) 63,786 68,480
Risk management contracts 1,279 1,592
----------------------------------------------------------------------------
86,684 99,237
Decommissioning obligations (7) 20,867 21,852
Flow-through share premium (8) 2,157 -
----------------------------------------------------------------------------
109,708 121,089
Shareholders' Equity
Shareholders' capital (8) 247,469 228,277
Contributed surplus 12,972 12,026
Deficit (54,204) (60,412)
----------------------------------------------------------------------------
206,237 179,891
Subsequent events (6,9)
----------------------------------------------------------------------------
315,945 300,980
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The accompanying notes are an integral part of these condensed interim
consolidated financial statements.
Crocotta Energy Inc.
Condensed Consolidated Statements of Operations and Comprehensive Earnings
(unaudited)
Three Months Ended Six Months Ended
June 30 June 30
($000s, except per share
amounts) Note 2013 2012 2013 2012
----------------------------------------------------------------------------
Revenue
Oil and natural gas sales 25,152 17,518 53,419 37,658
Royalties (1,758) (2,131) (4,688) (4,202)
----------------------------------------------------------------------------
23,394 15,387 48,731 33,456
Realized gain (loss) on risk
management contracts (900) 2,536 (1,358) 2,536
Unrealized gain on risk
management contracts 2,250 400 313 400
----------------------------------------------------------------------------
24,744 18,323 47,686 36,392
Expenses
Production 5,219 3,579 10,098 6,765
Transportation 569 601 1,142 1,276
Depletion and depreciation (5) 10,285 8,748 20,985 17,903
Asset impairment (4,5) 128 579 327 3,284
General and administrative 1,630 976 3,162 2,054
Share based compensation (9) 445 1,123 960 2,083
----------------------------------------------------------------------------
18,276 15,606 36,674 33,365
----------------------------------------------------------------------------
Operating earnings 6,468 2,717 11,012 3,027
Other Expenses
Finance expense 943 591 1,837 870
----------------------------------------------------------------------------
Earnings before taxes 5,525 2,126 9,175 2,157
Taxes
Deferred income tax expense 1,921 1,061 2,967 1,385
----------------------------------------------------------------------------
Net earnings and comprehensive
earnings 3,604 1,065 6,208 772
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings per share
Basic and diluted (10) 0.04 0.01 0.07 0.01
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The accompanying notes are an integral part of these condensed interim
consolidated financial statements.
Crocotta Energy Inc.
Condensed Consolidated Statements of Shareholders' Equity
(unaudited)
Six Months Ended June 30
($000s) 2013 2012
----------------------------------------------------------------------------
Shareholders' Capital
Balance, beginning of period 228,277 225,848
Issue of shares (net of share issue costs and
flow-through share premium) 18,911 -
Issued on exercise of stock options 166 -
Share based compensation - exercised 115 -
----------------------------------------------------------------------------
Balance, end of period 247,469 225,848
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Contributed Surplus
Balance, beginning of period 12,026 8,927
Share based compensation - expensed 960 2,083
Share based compensation - capitalized 101 169
Share based compensation - exercised (115) -
----------------------------------------------------------------------------
Balance, end of period 12,972 11,179
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Deficit
Balance, beginning of period (60,412) (55,158)
Net earnings 6,208 772
----------------------------------------------------------------------------
Balance, end of period (54,204) (54,386)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Shareholders' Equity 206,237 182,641
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The accompanying notes are an integral part of these condensed interim
consolidated financial statements.
Crocotta Energy Inc.
Condensed Consolidated Statements of Cash Flows
(unaudited)
Three Months Ended Six Months Ended
June 30 June 30
($000s) Note 2013 2012 2013 2012
----------------------------------------------------------------------------
Operating Activities
Net earnings 3,604 1,065 6,208 772
Depletion and depreciation (5) 10,285 8,748 20,985 17,903
Asset impairment (4,5) 128 579 327 3,284
Share based compensation (9) 445 1,123 960 2,083
Finance expense (11) 943 591 1,837 870
Interest paid (796) (492) (1,567) (648)
Deferred income tax expense 1,921 1,061 2,967 1,385
Unrealized gain on risk
management contracts (2,250) (400) (313) (400)
Decommissioning expenditures (7) (163) (163) (247) (350)
Change in non-cash working
capital (13) 4,765 1,066 5,120 768
----------------------------------------------------------------------------
18,882 13,178 36,277 25,667
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Financing Activities
Revolving credit facility (6) (24,675) 5,615 (4,694) 34,496
Issuance of shares (8) 22,149 - 22,149 -
Share issue costs (8) (967) - (967) -
----------------------------------------------------------------------------
(3,493) 5,615 16,488 34,496
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Investing Activities
Capital expenditures -
property, plant, and
equipment (5) (7,847) (4,934) (36,024) (29,482)
Capital expenditures -
exploration and evaluation
assets (4) (6,335) (6,115) (9,676) (9,206)
Change in non-cash working
capital (13) (1,207) (7,744) (7,065) (21,475)
----------------------------------------------------------------------------
(15,389) (18,793) (52,765) (60,163)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Change in cash and cash
equivalents - - - -
Cash and cash equivalents,
beginning of period - - - -
----------------------------------------------------------------------------
Cash and cash equivalents, end
of period - - - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The accompanying notes are an integral part of these condensed interim
consolidated financial statements.
Crocotta Energy Inc.
Notes to the Condensed Interim Consolidated Financial Statements
Three and Six Months Ended June 30, 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 condensed interim
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 condensed interim consolidated financial statements have been prepared in
accordance with International Accounting Standard ("IAS") 34, Interim Financial
Reporting and accordingly do not include all of the information required in the
preparation of annual consolidated financial statements. The condensed interim
consolidated financial statements should be read in conjunction with the audited
consolidated financial statements and related notes for the year ended December
31, 2012.
The condensed interim consolidated financial statements were authorized for
issuance by the Board of Directors on August 9, 2013.
(b) Basis of measurement
The condensed interim consolidated financial statements have been prepared on
the historical cost basis except for risk management contracts, which are
measured at fair value.
(c) Functional and presentation currency
The condensed interim consolidated financial statements are presented in
Canadian dollars, which is the Company's functional currency.
(d) Use of estimates and judgments
The preparation of the condensed interim 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
interim consolidated financial statements and the reported amounts of revenues
and expenses during the period. By their nature, estimates are subject to
measurement uncertainty and changes in such estimates in future periods could
require a material change in the interim consolidated financial statements.
Accordingly, actual results may differ from the estimated amounts as future
confirming events occur. The significant estimates and judgments made by
management in the preparation of these condensed interim consolidated financial
statements were consistent with those applied to the consolidated financial
statements as at and for the year ended December 31, 2012.
3. SIGNIFICANT ACCOUNTING POLICIES
The condensed interim consolidated financial statements have been prepared
following the same accounting policies as the audited consolidated financial
statements for the year ended December 31, 2012. The accounting policies have
been applied consistently by the Company to all periods presented in these
condensed interim consolidated financial statements.
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 condensed interim consolidated
financial statements.
4. 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 9,676
Transfer to property, plant, and equipment (8,122)
Impairment (327)
----------------------------------------------------------------------------
Balance, June 30, 2013 29,529
----------------------------------------------------------------------------
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 period, 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 $9.7 million of additions during the six months ended
June 30, 2013 were additions of $9.0 million related to the Edson AB CGU and
$0.5 million related to the Miscellaneous AB CGU.
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 six
months ended June 30, 2013, total exploration and evaluation asset impairments
of $0.3 million were recognized relating to the expiry of undeveloped land
rights (CGUs - Miscellaneous AB and Saskatchewan).
5. 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 36,024
Transfer from exploration and evaluation assets 8,122
Change in decommissioning obligation estimates (1,008)
Capitalized share based compensation 101
----------------------------------------------------------------------------
Balance, June 30, 2013 374,881
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 20,985
----------------------------------------------------------------------------
Balance, June 30, 2013 110,924
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net Book Value Total
----------------------------------------------------------------------------
December 31, 2011 192,332
December 31, 2012 241,703
June 30, 2013 263,957
----------------------------------------------------------------------------
During the three and six months ended June 30, 2013, approximately $nil (2012 -
$0.1 million) and $0.1 million (2012 - $0.2 million), respectively, 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 three months ended
June 30, 2013 included an estimated $215.2 million (2012 - $177.4 million) for
future development costs associated with proved plus probable undeveloped
reserves and excluded approximately $13.6 million (2012 - $9.0 million) for the
estimated salvage value of production equipment and facilities.
6. CREDIT FACILITY
At June 30, 2013, the Company had a $140.0 million revolving operating demand
loan credit facility with a Canadian chartered bank. The revolving credit
facility bears interest at prime plus a range of 0.50% to 2.50% and is secured
by a $125 million fixed and floating charge debenture on the assets of the
Company. At June 30, 2013, $63.8 million (December 31, 2012 - $68.5 million) had
been drawn on the revolving credit facility. In addition, at June 30, 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.
Subsequent to June 30, 2013, the Company entered into a syndicated credit
facility with a syndicate of three Canadian chartered banks. The syndicated
credit facility replaces the Company's previous revolving operating demand loan
credit facility. The syndicated facility has a borrowing base of $145 million,
consisting of a $135 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 next scheduled borrowing
base review of the syndicated facility is scheduled on or before November 1,
2013.
7. 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 $30.4 million which is estimated to be incurred
over the next 28 years. At June 30, 2013, a risk-free rate of 2.9% (December 31,
2012 - 2.3%) was used to calculate the net present value of the decommissioning
obligations.
Six Months Ended Year Ended
June 30, 2013 December 31, 2012
----------------------------------------------------------------------------
Balance, beginning of period 21,852 19,250
Provisions incurred 615 2,208
Provisions settled (247) (734)
Revisions (1,623) 675
Accretion 270 453
----------------------------------------------------------------------------
Balance, end of period 20,867 21,852
----------------------------------------------------------------------------
8. 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, 2012 89,261 228,277
Exercise of stock options 145 281
Share issuances 6,042 21,983
Share issue costs, net of future tax effect of $0.2
million (725)
Flow-through share premium (2,347)
----------------------------------------------------------------------------
Balance, June 30, 2013 95,448 247,469
----------------------------------------------------------------------------
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 June
30, 2013, the Company had spent $2.5 million in connection with this flow-
through share commitment.
9. SHARE BASED COMPENSATION PLANS
Stock options
The Company has authorized and reserved for issuance 9.5 million common shares
under a stock option plan enabling certain officers, directors, employees, and
consultants to purchase common shares. The Company will not issue options
exceeding 10% of the shares outstanding at the time of the option grants. Under
the plan, the exercise price of each option equals the market price of the
Company's shares on the date of the grant. The options vest over a period of
three years and an option's maximum term is 5 years. At June 30, 2013, 8.5
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, 2012 8,601 2.09
Granted 53 3.06
Exercised (145) 1.14
Forfeited (2) 3.46
----------------------------------------------------------------------------
Balance, June 30, 2013 8,507 2.11
----------------------------------------------------------------------------
The following table summarizes the stock options outstanding and exercisable at
June 30, 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 3,497 1.4 1.24 3,154 1.22
$2.01 to $3.00 4,269 2.7 2.59 2,349 2.50
$3.01 to $3.46 741 3.7 3.44 231 3.46
----------------------------------------------------------------------------
8,507 2.3 2.11 5,734 1.83
----------------------------------------------------------------------------
Subsequent to June 30, 2013, 0.7 million options at an exercise price of $1.26
per share were exercised. The options have an expiry date of January 15, 2014.
Warrants
The Company has an arrangement that allows warrants to be issued to directors,
officers, and employees. The maximum number of common shares that may be issued,
and that have been reserved for issuance under this arrangement, is 2.4 million.
Warrants granted under this arrangement vest over three years and have exercise
prices ranging from $3.75 per share to $6.75 per share. During the year ended
December 31, 2007, the Company issued 2.4 million warrants under this
arrangement. The fair value of the warrants granted under this arrangement at
the date of issue was determined to be $nil using the minimum value method as
they were issued prior to the Company becoming publicly traded. During 2012,
approval was obtained to extend the expiry date of the warrants to December 23,
2013. The resulting compensation cost charged to earnings during 2012 in
relation to the extension of the warrants was $0.2 million.
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:
Number of Weighted Average
Warrants Exercise Price
----------------------------------------------------------------------------
Balance, December 31, 2012 and June 30,
2013 2,321 4.80
----------------------------------------------------------------------------
The following table summarizes the warrants outstanding and exercisable at June
30, 2013:
Warrants Outstanding and Exercisable
----------------------------------------------------------------------------
Weighted Average Weighted Average
Exercise Price Number Remaining Life Exercise Price
----------------------------------------------------------------------------
$3.75 to $4.05 740 0.50 3.76
$4.50 to $5.25 807 0.50 4.55
$6.00 to $6.75 774 0.50 6.05
----------------------------------------------------------------------------
2,321 0.50 4.80
----------------------------------------------------------------------------
Share based compensation
The Company accounts for its share based compensation plans using the fair value
method. Under this method, compensation cost is charged to earnings over the
vesting period for stock options and warrants granted to officers, directors,
employees, and consultants with a corresponding increase to contributed surplus.
The fair value of the stock options granted were estimated on the date of grant
using the Black-Scholes-Merton option pricing model with the following weighted
average assumptions:
Three Months Ended Six Months Ended
June 30, 2013 June 30, 2013
----------------------------------------------------------------------------
Risk-free interest rate (%) 1.1 1.1
Expected life (years) 4.0 4.0
Expected volatility (%) 57.3 57.8
Expected dividend yield (%) - -
Forfeiture rate (%) 6.2 6.2
Weighted average fair value of
options granted ($ per option) 1.38 1.38
----------------------------------------------------------------------------
10. PER SHARE AMOUNTS
The following table summarizes the weighted average number of shares used in the
basic and diluted net earnings per share calculations:
Three Months Ended Six Months Ended
June 30, 2013 June 30, 2013
----------------------------------------------------------------------------
Weighted average number of shares -
basic 90,549 89,909
Dilutive effect of share based
compensation plans 2,750 2,542
----------------------------------------------------------------------------
Weighted average number of shares -
diluted 93,299 92,451
----------------------------------------------------------------------------
For the three months ended June 30, 2013, 2.3 million stock options (2012 - 4.9
million) and 2.3 million warrants (2012 - 2.3 million) were anti-dilutive and
were not included in the diluted earnings per share calculation. For the six
months ended June 30, 2013, 2.3 million stock options (2012 - 2.3 million) and
2.3 million warrants (2012 - 2.3 million) were anti-dilutive and were not
included in the diluted earnings per share calculation.
11. FINANCE EXPENSES
Finance expenses include the following:
Three Months Ended Six Months Ended
June 30, 2013 June 30, 2013
----------------------------------------------------------------------------
Interest expense (note 6) 796 1,567
Accretion of decommissioning
obligations (note 7) 147 270
----------------------------------------------------------------------------
Finance expenses 943 1,837
----------------------------------------------------------------------------
12. FAIR VALUE OF FINANCIAL INSTRUMENTS
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).
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 June 30, 2013 is measured using level 2.
During the six months ended June 30, 2013, there were no transfers between level
1, level 2, and level 3 classified assets and liabilities.
12. SUPPLEMENTAL CASH FLOW INFORMATION
Three Months Ended Six Months Ended
June 30, 2013 June 30, 2013
----------------------------------------------------------------------------
Accounts receivable 7,483 6,081
Prepaid expenses and deposits (653) (480)
Accounts payable and accrued
liabilities (3,272) (7,546)
----------------------------------------------------------------------------
Change in non-cash working capital 3,558 (1,945)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Relating to:
Investing (1,207) (7,065)
Operating 4,765 5,120
----------------------------------------------------------------------------
Change in non-cash working capital 3,558 (1,945)
----------------------------------------------------------------------------
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 1400, 700 - 2nd Street SW
Calgary, Alberta T2P 4V5
Kevin Keith
VP Production
Larry G. Moeller, CA, CBV AUDITORS
Chairman of the Board KPMG LLP
2700, 205 - 5th Avenue SW
Daryl H. Gilbert, P.Eng. Calgary, Alberta T2P 4B9
Director
Don Cowie
Director INDEPENDENT ENGINEERS
GLJ Petroleum Consultants Ltd.
Brian Krausert 4100, 400 - 3rd Avenue SW
Director Calgary, Alberta T2P 4H2
Gary W. Burns
Director
Don D. Copeland, P.Eng.
Director
Brian Boulanger
Director
Patricia Phillips
Director
FOR FURTHER INFORMATION PLEASE CONTACT:
Crocotta Energy Inc.
Robert J. Zakresky
President & CEO
(403) 538-3736
(403) 538-3735 (FAX)
Crocotta Energy Inc.
Nolan Chicoine
VP Finance & CFO
(403) 538-3738
(403) 538-3735 (FAX)
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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