Antrim Energy Inc. (TSX:AEN) (AIM:AEY)
MANAGEMENT'S DISCUSSION AND ANALYSIS
This management's discussion and analysis ("MD&A") provides a detailed
explanation of Antrim Energy Inc.'s (the "Company" or "Antrim") operating
results for the fourth quarter and year ended December 31, 2012 compared to the
fourth quarter and year ended December 31, 2011 and should be read in
conjunction with the audited consolidated financial statements of Antrim. This
MD&A has been prepared using information available up to March 26, 2013. The
audited consolidated financial statements of the Company have been prepared in
accordance with International Financial Reporting Standards ("IFRS"). Unless
otherwise noted all amounts are reported in United States dollars.
Non-IFRS Measures
Cash flow from operations, cash flow from operations per share and netback do
not have standard meanings under IFRS and may not be comparable to those
reported by other companies. Antrim utilizes cash flow from operations and
netback to assess operational and financial performance to allocate capital
among alternative projects and to assess the Company's capacity to fund future
capital programs.
Cash flow from operations is defined as cash flow from operating activities
before changes in working capital. Cash flow from operations per share is
calculated as cash flow from operations divided by the weighted-average number
of outstanding shares. Reconciliation of cash flow from operations to its
nearest measure prescribed by IFRS is provided below.
Calculation of Cash Flow from Operations
Three Months Ended Year Ended
December 31 December 31
2012 2011 2012 2011
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($000's)
Cash flow provided by (used in) 3,495 10,843 (8,671) 8,941
operating activities
Less: change in non-cash working 11,633 11,676 4,717 12,688
capital
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Cash deficiency from operations (8,138) (833) (13,388) (3,747)
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Overview
During 2012, Antrim completed the sale of its Argentina operations and focused
solely on its UK North Sea and Irish assets. In November 2012, Antrim achieved a
significant milestone when the Causeway Field commenced production. Following
first production from the Causeway Field, the Company achieved first production
from the Cormorant East Field in January 2013 from the discovery of oil at well
211/21-N94 (the "Contender Well") drilled in October 2012. On March 26, 2013,
planning was discontinued for the development of the Fyne Field following a
significant escalation of expected future development costs.
Overview of Continuing Operations
Causeway Licences
Licence P201 Block 211/22a South East Area and P1383 Block 211/23d, Antrim 35.5%
The Causeway Licences include the Causeway Field, the Fionn Field and the West
Causeway area. The Causeway Licences total gross proved plus probable reserves
decreased by 4% from 12.5 million barrels (4.4 million net to Antrim) to 12.0
million barrels (4.3 million net to Antrim) as at December 31, 2012 due to 2012
production and technical revisions following initial field performance data.
Subsequent to December 31, 2012, with an early indication of significant cost
increases, Antrim elected to opt out of the Fionn Field development, which will
result in a decrease of total gross proved plus probable reserves of 4.9 million
barrels (1.7 million net to Antrim).
Production from the Causeway Field averaged 4,081 gross barrels of oil per day
("bopd") (Antrim net 1,194 bopd) from November to December 31, 2012 compared to
nil in 2011. Oil production is transported by pipeline to the North Cormorant
production platform where it is processed before being exported to the Sullom
Voe terminal via the Brent Pipeline System for sale. Under a contract with the
purchaser, Antrim invoices and receives payment for its oil in the month after
production; however, the purchaser retains certain rights impacting the timing
of liftings which may result in no sales in a particular month resulting in
deferred revenue. During 2012, no oil revenue was recorded ($nil - 2011) as
there were no oil liftings. Deferred revenue of $1.1 million ($nil - 2011) was
recognized in 2012 relating to oil produced and collected but not lifted from
the terminal.
Rig operations commenced in January 2013 to complete the water injector for the
Causeway Field and were completed in February 2013. Anticipated startup of the
downhole electrical submersible pump ("ESP") will follow completion of topside
modifications on the North Cormorant production platform, and is scheduled for
the second half of 2013. The recently completed water injection well is expected
to commence operation in 2014, with a possibility of it being accelerated to the
second half of 2013.
As part of the sale of a 30% working interest in the Causeway Licences to
Valiant Petroleum plc ("Valiant") in October 2011, Antrim entered into a
Differential Lifting Agreement ("DLA") giving Valiant the right to 6.25% of
Antrim's share of produced oil. Antrim's share of oil produced will be reduced
to 29.25% until a cumulative value of $8.9 million after-tax is received by
Valiant. Once satisfied, Antrim's working interest in production will revert
back from 29.25% to 35.5%.
Under the terms of the Fionn Field Supplementary Agreement with Valiant, Antrim
had an option for three months following first oil production from the Causeway
Field to opt out of participating in the Fionn Field development and sell its
35.5% working interest share to Valiant for the cost of its 35.5% working share
of the Fionn Field pre-investment costs, or to confirm its continued
participation by repaying its share of the Fionn pre-investment costs plus
interest.
In February 2013, Antrim announced that it had elected to opt out of
participating in further development of the Fionn Field. The projected costs
associated with the development of Fionn had increased to the extent that the
project no longer met Antrim's economic criteria. Subject to all necessary
approvals from the UK Department of Energy and Climate Change ("DECC"), Antrim
intends to withdraw from the Fionn Field subarea and will not incur any further
liabilities. As a result, an impairment charge of $50.4 million was recorded in
the fourth quarter of 2012 representing the full carrying value relating to the
Fionn Field.
Contender Licence
P201 Block 211/22a Contender Area, Antrim 8.4%
The Contender Licence contains the Cormorant East Field. Cormorant East Field
total gross proved plus probable reserves increased from nil to 7.3 million
barrels (0.6 million net to Antrim) as at December 31, 2012 due to the
successful drilling of exploration well 211/21-N94 (the "Contender Well") as
announced on October 22, 2012.
On January 14, 2013, Antrim announced that first oil production had been
achieved from the Cormorant East Field after 85 days following discovery of the
field. Production is processed through the North Cormorant platform before being
exported to the Sullom Voe terminal. The Cormorant East Field is initially being
produced under primary depletion with a single production well, with the
potential to install a water injection scheme and/or additional production wells
at a later date. Future drilling locations are being considered by the partners.
Under the terms of the farm-out agreement with the operator, 100% of the
drilling, completion and tie in costs of the Contender Well were funded by the
operator. Antrim will receive its share of production after Antrim's working
interest share of the completion and tie in costs is recovered from production
revenue.
Kerloch Licence
P201 Block 211/22a Kerloch Area, Antrim 13.65%
The Kerloch Licence includes the Kerloch discovery made in 2007. With the
successful drilling of the Contender Well, TAQA also earned a 35% working
interest in the adjacent Licence P201 Block 211/22a Kerloch Area, reducing
Antrim's working interest from 21% to 13.65%.
Fyne Licence
P077 Block 21/28a - Fyne, Dandy and Crinan, Antrim 100%
The Fyne Licence includes the Fyne Field, the Dandy Field and the Crinan Field
(formerly referred to as "Area 4"). Total proved plus probable reserves at
December 31, 2012 decreased by 50% to 11.8 million barrels from 23.3 million
barrels (gross) in 2011. The change was due to the results of well 21/28a-11
drilled in the East Fyne area, a decrease in reserves attributed to the Dandy
Field due to no further development currently being planned, and the upgrade in
reserve category in the Crinan Field due to it being cited as part of a
potential phase 2 development of the Fyne Licence. Antrim's net reserves in the
Fyne Licence increased by 44% from 8.2 million barrels to 11.8 million barrels
as the decrease in gross reserves was offset by an increase in working interest
from 35.1% to 100%.
On March 26, 2013 the Company discontinued development of the Fyne Field. Until
very recently, estimated costs indicated that the planned Fyne development
satisfied the Company's economic threshold and contingent on timing of the
redeployment of the FPSO from its current location was on track for a late 2014
start-up. However, projected capital costs have recently increased
substantially, and in the Company's view now make the project uneconomic.
The majority of costs associated with the Fyne Field were written off in March
2012. No further material write downs associated with the Fyne Field are
anticipated as recent work has been confined to front end engineering design
work for the subsea facilities and modification to the FPSO.
Erne
P1875 21/29d, Antrim 50%
Licence P1875 contains the Erne discovery drilled in 2011 and the Corrib
prospect. The Erne sidetrack well 21/29d-11Z well is suspended for possible
future incorporation into neighbouring infrastructure A separate prospect has
been identified to the southwest, named Corrib, which may also be assessed for
possible future incorporation into neighbouring infrastructure.
Carra
P1563 Blocks 21/28b and 21/29c, Antrim 100%
Licence P1563 contains the Carra Prospect, the Riddon and Scavaig discoveries
and several other prospects. In October 2012, DECC agreed to waive the
contingent well obligation on Licence P1563 Blocks 21/28b & 21/29c as it was
determined by Antrim that there was insufficient potential to proceed with
drilling. The licence was relinquished in February 2013.
Cyclone and Typhoon
Licence P1784 Block 21/7b, Antrim 30%
Licence P1784 Block 21/7b is located in the Central North Sea, north of the
Greater Fyne Area and contains the "Cyclone" and "Typhoon" Tertiary Cromarty
prospects. The licence was acquired jointly with Premier (70%, Operator) with a
firm well commitment.
In November 2012, Cyclone well 21/7b-4 was drilled and encountered 105 feet of
very porous and permeable Tertiary Cromarty sands. Well logs identified only
residual oil, suggesting that the trap was breached and the well was plugged and
abandoned. As a result, an impairment charge of $5.9 million was recorded in the
fourth quarter of 2012, representing the full carrying value relating to Block
21/7b.
Ireland
Licensing Option 11/5 Blocks 44/4, 44/5 (part), 44/9, 44/10, 44/14, 44/15,
Antrim 100%
Antrim holds a Frontier Licence Option (the "Skellig Block") in the Porcupine
Basin approximately 110 km off the southwest coast of Ireland. Antrim has
licenced, reprocessed and interpreted 2D seismic data and has identified the
"Dunree Prospect". Antrim is currently planning a 3D seismic programme and is
seeking partners to joint venture on the block. Participation in the block has
received strong interest from industry.
Tanzania
Production Sharing Agreement - Pemba and Zanzibar
Antrim holds an option to acquire a 20% interest in the production sharing
agreement for the Pemba-Zanzibar exploration licence offshore and onshore
Tanzania (the "P-Z PSA") following the pre-drilling (seismic) phase and an
additional 10% interest to be exercised up to 180 days following receipt of the
initial drilling results. Should Antrim exercise the initial option, costs for
the seismic phase associated with Antrim's acquired interests would be repaid
from future production. RAK Gas, the Operator, has submitted a proposal for a
revised work programme to the federal government of Tanzania. Environmental
impact assessment work has commenced, with seismic operations expected to
proceed in the near future.
On October 29, 2012, an agreement between the federal government of Tanzania and
the government of Zanzibar on the sharing of any future hydrocarbon revenues was
announced, potentially ending a moratorium which has delayed exploration of the
licence. The agreement has still to be ratified and final details are still to
be agreed. It is not yet known what, if any, impact this agreement will have on
the P-Z PSA.
Reserves Update
In February 2013 Antrim elected out of participating further in the Fionn Field
development and on March 26, 2013 the Company discontinued development of the
Fyne and Crinan Fields following a significant escalation of expected future
development costs. The impact on Antrim's reserves is as follows:
Net
UK proved plus probable reserves (Mbbls)
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At December 31, 2012 16,626
Less:
Fionn Field (1,727)
Fyne and Crinan Fields (11,758)
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Revised proved plus probable reserves 3,141
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The updated present value cash flow after tax using a 10% discount rate is
$144,775,000.
Corporate
On January 23, 2013, Antrim announced that it entered into a $30 million Payment
Swap transaction with a major financial institution. The Payment Swap provided
Antrim with sufficient funding to meet its commitments for cost overruns on the
completion of the production well in the Causeway Field, future costs related to
the Causeway water injection well and initial FEED work associated with the Fyne
Field.
Under the terms of the Payment Swap, $30 million is repayable in 29 instalments
commencing September 2013 and concluding January 2016. The interest rate under
the Payment Swap is fixed at 5.1%. To enable Antrim to pay amounts under the
Payment Swap, Antrim also entered into a Brent Oil Price Commodity Swap for a
forward sale of 657,350 barrels of Brent crude oil at a fixed price of $89.37
covering the period from February 2013 to December 2015.
Financial Discussion of Continuing Operations
All amounts reported in this MD&A related to the three month periods ended
December 31, 2012 and 2011 are unaudited.
Three Months Ended Year Ended
December 31 December 31
2012 2011 2012 2011
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Financial Results ($000's except per
share amounts)
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Cash deficiency from operations (1)
- continuing operations 8,138 833 13,388 3,747
Cash deficiency from operations per
share (1) 0.04 0.00 0.07 0.02
Net loss - continuing operations 67,155 15,975 134,859 55,110
Net loss 67,155 14,951 134,544 52,970
Net loss per share - basic,
continuing operations 0.37 0.09 0.73 0.32
Total assets 96,520 239,177 96,520 239,177
Working capital (deficiency) (10,734) 52,674 (10,734) 52,674
Capital expenditures 26,771 10,634 63,034 14,702
Bank debt - - - -
Common shares outstanding (000's)
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End of period 184,731 184,116 184,731 184,116
Weighted average - basic 184,848 184,108 184,388 173,997
Weighted average - diluted 185,681 185,530 185,528 175,412
(1) Cash flow from operations and cash flow from operations per share are
Non-IFRS Measures. Refer to "Non-IFRS Measures" in Management's
Discussion and Analysis.
Production
From early November to December 31, 2012, gross daily oil production from the
Causeway Field averaged gross 4,081 bopd (Antrim net 1,194 bopd).
The following table provides oil production and sales from the Causeway Field
for the year ended December 31, 2012.
(barrels) 2012 2011
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Gross production (1) 146,870 -
Net production (2) 42,950 -
Ending inventory (3) 42,950 -
Sales - -
(1) Gross production is after linefill and deadstock of 106,153 barrels
(2) Per the DLA, Antrim's share of oil produced is reduced to 29.25% until a
cumulative value of $8.9 million after tax is received by Valiant
(3) Ending oil inventory is net of process and shrinkage
Revenue
Revenue is recognized when title and risk transfer to the purchaser, which
occurs at the time of lifting into a tanker at the Sullom Voe terminal. All
sales from Causeway are made under contract to one UK customer. Under the
contract with the purchaser, Antrim invoices and receives payment for its oil in
the month after production; however, the purchaser retains certain rights
impacting the timing of liftings which may result in no sales in a particular
month resulting in deferred revenue.
The Company did not record any revenue in 2012 (2011 - nil) as there was no oil
lifted from the terminal in 2012.
General and Administrative
General and administrative ("G&A") costs increased to $5.8 million for the year
ended December 31, 2012 compared to $5.0 million in 2011. The increase in G&A
costs was primarily due to employee compensation.
During 2012, Antrim capitalized $0.6 million (2011 - $0.6 million) of G&A costs
related to exploration and development activity.
Exploration & Evaluation Expenditures
Exploration and evaluation ("E&E") expenditures increased to $7.6 million for
the year ended December 31, 2012 compared to $0.3 million for the same period in
2011. E&E expenditures increased to $6.3 million for the three month period
ended December 31, 2012 compared to $0.03 million for the same period in 2011.
The increase in E&E expenditures is primarily related to work on the development
plan for the Fyne Licence.
Impairment
In January 2013, the Company elected not to participate in further development
work on the Fionn Field. As a result, an impairment charge of $50.4 million was
recognized in the fourth quarter of 2012, representing the full carrying value
relating to the Fionn Field. Antrim retains a 35.5% interest in the remainder of
Licence P201 Block 211/22a South East Area.
In December 2012, the Company announced that the Cyclone exploration well in UK
Block 21/7b was plugged and abandoned. As a result, an impairment charge of $5.9
million was recognized in the fourth quarter of 2012 representing the full
carrying value of the licence.
Licence P1625 Block 21/24b ("West Teal") is nearing the end of its initial
exploration term and based on an evaluation performed by management the licence
is not considered economically viable. As a result, the Company recognized an
impairment charge of $1.8 million in the fourth quarter of 2012, representing
the full carrying value of the licence.
In October 2012, DECC agreed to waive the seismic and contingent well
obligations on Licence P1563 Blocks 21/28b & 21/29c ("Carra") and allowed the
Company to relinquish the licence in its entirety. The Company recognized a $2.3
million impairment charge in the third quarter of 2012 representing the full
carrying value of the licence.
In addition the Company recorded impairment charges consisting of $60.1 million
for the Fyne Licence and $2.1 million on the drilling of the Erne discovery well
and the Erne sidetrack well in the first and second quarters of 2012. The
impaired costs relating to the Erne discovery well and the Erne sidetrack well
are in addition to a $10.3 million impairment charge recorded in 2011.
Discontinued Operations
On May 28, 2012, Antrim completed the sale of Antrim Argentina S.A. to Crown
Point Energy Inc. ("Crown Point") (formerly known as Crown Point Ventures Ltd.)
by way of a plan of arrangement effected under the Business Corporation Act
(Alberta) (the "Arrangement"). Under the terms of the Arrangement, the Company
received a cash payment of $9.9 million (net of adjustments of $1.0 million) and
35,761,290 common shares of Crown Point ("Crown Point Shares"). The Crown Point
Shares were distributed to Antrim's shareholders in accordance with the terms of
the Arrangement on June 7, 2012 (the "Distribution Date"). As a result of the
sale, the Company recognized a gain on the disposal of the Argentina assets of
$5.9 million and income from discontinued operations for the year ended December
31, 2012 of $0.3 million (2011 - $2.1 million).
The financial and operating results for discontinued operations for the year
ended December 31, 2012 include only the results up to May 28, 2012, the date of
sale of the Argentina operations, and are no longer comparable with the 2011
results.
Reduction in the Fair Value of Financial Assets
On the Distribution Date, the closing price of the Crown Point Shares on the TSX
Venture Exchange was Cdn $0.51 which had decreased from the May 28, 2012 closing
share price of Cdn $0.80. This reduction in the share price of the Crown Point
Shares resulted in the Company recognizing a capital loss on the Crown Point
Shares of $10.0 million. This amount has been recognized in the 2012
consolidated statement of comprehensive loss as a reduction in the fair value of
financial assets.
Finance Income
Finance income relates to interest income on short-term deposits and was $0.3
million (2011 - $0.7 million) for the year ended December 31, 2012.
Finance Costs
Finance costs were $0.2 million for the year ended December 31, 2012 (2011 -
$0.6 million) and relate to accretion of decommissioning obligations, interest
expense and bank charges.
Income Taxes
Current income tax assets and liabilities are measured at the amount expected to
be recovered from or paid to the taxation authorities. The Company did not pay
or recover any taxes during the year ended December 31, 2012.
The Company follows the liability method of accounting for income taxes. As at
December 31, 2012, no deferred income tax assets were recorded due to
uncertainty with respect to the ability of Antrim to generate sufficient taxable
income to utilize the unrecognized losses.
Cash Flow and Net Loss
In the three month period ended December 31, 2012, Antrim had a cash deficiency
from operations of $8.1 million ($0.04 per share) compared to cash deficiency
from operations of $0.8 million ($0.00 per share) in the same period in 2011.
For the year ended December 31, 2012, Antrim incurred a cash deficiency from
operations of $13.4 million ($0.07 per share) in 2012 compared to a cash
deficiency from operations of $3.7 million ($0.02 per share) in 2011. The cash
deficiency from operations increased in 2012 primarily due to higher exploration
and evaluation expenditures.
In the fourth quarter of 2012 and 2011, Antrim incurred net losses of $67.2
million and $15 million respectively. For the year ended December 31, 2012, the
Company incurred a net loss of $134.5 million compared to $53 million in 2011.
The increase in the net loss was due to impairment charges for the Fionn Field,
the Fyne Licence, West Teal Licence and the Cyclone - Typhoon licence and E&E
expenditures on the Fyne Licence.
Capital Expenditures
Antrim incurred capital expenditures in 2012 related to petroleum and natural
gas properties of $63 million (2011 - $14.7 million). Capital expenditures in
2012 consisted of $54.5 million for the ongoing development costs of the
Causeway Licence, $5.5 million in exploration costs related to the Cyclone well,
and $1.6 million for the drilling of the Erne discovery well.
Foreign Exchange Loss and Comprehensive Income (Loss)
The measurement currency of the Company is the Canadian dollar, while its
reporting currency is the US dollar. A significant portion of the Company's
activities are transacted in or referenced to US dollars, Canadian dollars and
British pounds sterling. The Company's operating costs and certain of the
Company's payments in order to maintain property interest are made in the local
currency of the jurisdiction where the applicable property is located. As a
result of these factors, fluctuations in the Canadian dollar, British pounds
sterling and US dollar could result in unanticipated fluctuations in the
Company's financial results.
The Company incurred a foreign exchange loss of $0.5 million from continuing
operations for the year ended December 31, 2012 compared to a loss of $0.7
million in 2011.
The Company realized a gain of $3.2 million in accumulated other comprehensive
income related to discontinued operations for the year ended December 31, 2012.
Financial Resources and Liquidity
In the fourth quarter of 2012, the Company incurred unexpected cost overruns on
the development of the Causeway Field, resulting in a working capital deficiency
of $10.7 million as at December 31, 2012. In January 2013, Antrim entered into
the $30 million Payment Swap transaction which provides Antrim with sufficient
funding to meet its commitments.
Accounts payable and accrued liabilities were $18.1 million at December 31, 2012
primarily related to costs for the development of the Causeway and Fyne Fields
and the Cyclone drilling program in November, compared to $17.2 million as at
December 31, 2011.
Antrim invests unrestricted cash not required for immediate operational needs in
short-term bankers' acceptances and money market instruments.
Although there have been improvements in the global economy and financial
markets, restrictions on availability of credit remain and may limit Antrim's
ability to access debt or equity financing for its development projects. Antrim
forecasts cash flows against a range of macroeconomic and financing market
scenarios in an effort to identify future commitments and arrange financing, if
necessary.
Antrim's planned capital program for 2013 includes ongoing development of the
Causeway Field, the Cormorant East Field and new ventures.
Contractual Obligations, Commitments and Contingencies
Antrim has several commitments in respect of its petroleum and natural gas
properties and operating leases as at December 31, 2012 as follows:
($000's) 2013 2014 2015 2016 2017 Thereafter
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United Kingdom
Causeway (1) 16,079 7,073 27 29 31 31
Cormorant East 654 8 8 8 8 8
Fyne and Dandy (2) 2,913 33 33 33 33 33
Cyclone-Typhoon (3) 13 12 - - - -
West Teal (4) - - - - - -
Carra (5) - - - - - -
Erne 13 13 - - - -
Ireland 69 - - - - -
Office leases 358 359 372 372 350 10
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Total 20,099 7,498 440 442 422 82
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(1) Relates to Antrim's 35.5% interest in the Causeway Licences.
(2) In 2012, Antrim signed a Heads of Term's agreement for an option to
lease an FPSO for use in the development of the Fyne Field. As the
Company decided not to proceed with the development of the Fyne Field.,
there is a $2.8 million obligation related to front end engineering
design work. This obligation is included in the consolidated balance
sheet as at December 31, 2012 under accounts payable and accrued
liabilities.
(3) The Company has a $6.2 million contingent drilling commitment on this
licence for the Typhoon prospect in 2014. Due to the results of the
Cyclone well, the Company has asked DECC to accept this well as a
fulfillment of the drilling obligation. Contingent on DECC acceptance,
there are no remaining obligations for the initial term of the licence.
(4) The Company has a $24.0 million contingent drilling commitment on this
licence for the West Teal prospect in 2013. Due to the Company being
unable to identify a commercially viable export route a request was made
to DECC to waive the contingent well requirement and, with DECC's
consent, allow the licence to be relinquished.
(5) In October 2012, DECC waived all commitments related to the Licence
P1563 Blocks 21/28b & 21/29c. In February 2013 the licence and all
commitments were officially relinquished.
In 2011, the Company entered into a variation to an existing contract for
drilling management services in the UK North Sea which required the drilling of
two wells, estimated to take 50 days in a letter of intent preceding the
contract variation. The Company contends that it met its contractual obligations
under this variation through the drilling of the Erne discovery well (21/29d-11)
and the Erne sidetrack well (21/29d-11Z). The drilling of these two wells took
place over a period of 58 days. Subsequent to releasing the rig, the Company
received an invoice from the drilling management services contractor charging
the Company for approximately $5 million in additional costs as the contractor
claims all conditions of the contract had not yet been satisfied. In July 2012,
the drilling management services contractor filed a claim against the Company
for the additional invoice costs plus interest and lost management time, in the
High Court of England and Wales. In August 2012, the Company filed a defence
against this claim in the High Court of England and Wales. A case management
conference where the Court will set the timetable for the claim going forward
has been listed for April 12, 2013. The Company is disputing the additional
costs and believes it is more likely than not that it will not have to pay. As a
result, a contingent liability has not been recorded.
In January 2013 the Company elected not to participate in further development
work on the Fionn Field. Subject to all necessary approvals from DECC, Antrim
intends to withdraw from the Fionn Field subarea and will not incur any further
liabilities. In accordance with the Fionn Field Supplemental Agreement signed in
January 2012, the Company is of the position that there are no further
obligations with respect to the decommissioning or well abandonment liabilities
of the three currently suspended wells in the Fionn Field subarea. The operator
contends this position in regards to two of the three currently suspended wells.
The Company is disputing the operator's position and believes it is more likely
than not that Antrim will be released of these obligations. Accordingly, no
amounts have been recorded in decommissioning obligation in relation to the
Fionn Field.
Risks and Uncertainties
The oil and gas industry involves a wide range of risks which include but are
not limited to the uncertainty of finding new commercial fields, securing
markets for existing reserves, commodity price fluctuations, exchange and
interest rate costs and changes to government regulations, including regulations
relating to prices, taxes, royalties, land tenure, allowable production and
environmental protection and access to off-shore production facilities in the
UK. The oil and natural gas industry is intensely competitive and the Company
competes with a large number of companies that have greater resources.
Substantial Capital Requirements
The Company's ability to increase reserves in the future will depend not only on
its ability to develop its present properties but also on its ability to select
and acquire suitable exploration or producing properties or prospects. The
acquisition and development of properties also requires that sufficient funds,
including funds from outside sources, will be available in a timely manner. The
availability of equity or debt financing is affected by many factors, many of
which are outside the control of the Company. Recent world financial market
events and the resultant negative impact on economic conditions have increased
the risk and uncertainty of the availability of equity or debt financing.
In January 2013, Antrim entered into a payment swap for $30 million and a
forward sale of 657,350 barrels of Brent crude oil. The Company's anticipated
revenue for 2013, as well as the Company's ability to repay the payment swap, is
dependent upon the future production rates from the Causeway and Cormorant East
fields as well as oil prices.
Foreign Operations
A number of risks are associated with conducting foreign operations over which
the Company has no control, including currency instability, potential and actual
civil disturbances, restriction of funds movement outside of these countries,
the ability of joint venture partners to fund their obligations, changes of laws
affecting foreign ownership and existing contracts, environmental requirements,
crude oil and natural gas price and production regulation, royalty rates, OPEC
quotas, potential expropriation of property without fair compensation,
retroactive tax changes and possible interruption of oil deliveries.
Further discussions regarding the Company's risks and uncertainties, can be
found in the Company's Annual Information Form dated March 26, 2013 which is
filed on SEDAR at www.sedar.com.
Outlook
Antrim expects to see increased production from the Causeway Field following
deployment of the ESP in the second half of 2013, and the implementation of the
water injection scheme scheduled to commence operation in 2014, with a
possibility of it being accelerated to the second half of 2013.
Following the discovery of the Cormorant East Field by the Contender Well,
Antrim anticipates planning at least one appraisal well, downdip of the
discovery well and a plan to explore the adjacent fault compartments.
Recent seismic studies on the Skellig block in the Porcupine Basin offshore
Southwest Ireland has high graded the Dunree Prospect, adjacent to the licence
holding the Dunquin Propsect, which is expected to be drilled by its operator
and joint venture partners in the second quarter of 2013. Antrim is currently
seeking partners to joint venture on the block and has received strong interest
from the industry.
Summary of Quarterly Results
Oil, Natural
Gas
and NGL Cash Flow Net
Revenue, from Loss Per
($000, except per share Net of Operations Net Share -
amounts) Royalties (Deficiency) Loss Basic
----------------------------------------------------------------------------
2012
Fourth quarter(1) - (8,138) 67,155 0.37
Third quarter (1) - (472) 5,240 0.03
Second quarter (1) - (3,177) 6,373 0.03
First quarter (1) - (1,601) 56,091 0.30
----------------------------------------------------------------------------
- (13,388) 134,859 0.73
----------------------------------------------------------------------------
2011
Fourth quarter (1) - (833) 15,362 0.10
Third quarter (1) - (894) 36,800 0.20
Second quarter (1) - (1,215) 1,503 0.01
First quarter (1) - (805) 1,445 0.01
----------------------------------------------------------------------------
- (3,747) 55,110 0.32
----------------------------------------------------------------------------
(1) Quarterly results reflect continuing operations only
Key factors relating to the comparison of net loss for the last eight quarters
are as follows:
-- In the fourth quarter of 2012, the Company recognized a $50.4 million
impairment charge related to the decision not to participate in further
development of its 35.5% working interest in the Fionn Field, a $5.9
million impairment charge related to the abandonment of the Cyclone well
21/7b-4 and a $1.8 million impairment charge related to the West Teal
Licence;
-- In the third quarter of 2012, the Company recognized a $2.3 million
impairment charge related to the planned relinquishment of Carra Licence
P1563 Blocks 21/28b & 21/29c;
-- The second quarter 2012 net loss was impacted by a $10 million reduction
in the fair value of the Crown Point shares partially offset by a $5.9
million gain on the disposal of the Argentina assets;
-- During the first quarter of 2012, net loss was negatively impacted by
$54.7 million in impairment costs related to the Fyne Licence and the
Erne discovery well and Erne sidetrack well;
-- In the fourth quarter of 2011, the Company recognized an impairment
charge of $10.3 million related to the Erne discovery well 21/29d-11 and
Erne sidetrack well 21/29d-11Z;
-- During the third quarter of 2011, the Company recognized an impairment
charge of $35.6 million due to the sale of the 30% interest in the
Causeway Licences.
Critical Accounting Estimates
Our significant accounting policies are detailed in Note 3 to the audited
consolidated financial statements. In determination of financial results, Antrim
makes certain critical accounting estimates described as follows:
Estimation of reserve quantities
Depletion, impairment and asset retirement charges are measured based on the
Company's estimate of oil and gas reserves. The estimation of reserves is an
inherently complex process and involves the exercise of professional judgment.
Reserves have been evaluated at the balance sheet date by an independent
qualified reserve evaluator in accordance with National Instrument 51-101
Standards of Disclosure for Oil and Gas Activities and are based on the
definitions and guidelines contained in the Canadian Oil and Gas Evaluation
Handbook.
Oil and gas reserve estimates are based on a range of geological, technical and
economic factors including projected future rates of production, estimated
commodity prices, engineering data, reserve type and timing and amount of future
expenditures, all of which are subject to uncertainty. Assumptions reflect
market and regulatory conditions existing at the balance sheet date, which could
differ significantly from other points in time throughout the year, or future
periods. Changes in market and regulatory conditions and assumptions can
materially impact the estimation of net reserves.
Recoverability of exploration and evaluation costs
Exploration and evaluation costs are initially capitalized with the intent to
establish commercially viable reserves. The Company is required to make
estimates and judgments about future events and circumstances regarding the
economic viability of extracting the underlying resources. The costs are subject
to technical, commercial and management review to confirm the continued intent
to develop and extract the underlying resources. Fluctuations in future
commodity prices, resource quantities, expected production techniques, drilling
results, production costs and required capital expenditures are important
factors when making this determination. If a judgment is made that extraction of
the reserves is not viable, the exploration and evaluation costs will be written
off to net earnings.
Decommissioning obligations
The Company recognizes liabilities for the future decommissioning and
restoration of property, plant and equipment. These provisions are based on
estimated costs, which take into account the anticipated method and extent of
restoration consistent with legal requirements, technological advances and the
possible use of the site. Actual costs are uncertain and estimates can vary as a
result of changes to relevant laws and regulations, the emergence of new
technology, operating experience and prices. The actual timing of future
decommissioning and restoration is not known and may change due to certain
factors, including reserve life. Changes to assumptions made about future
expected costs, discount rates, inflation and timing may have a material impact
on the amounts presented. The Company has chosen to measure decommissioning
obligations using a risk-free discount rate.
Impairment of property, plant and equipment
The recoverable amounts of cash-generating units ("CGUs") and individual assets
have been determined based on greater of value-in-use or fair value less costs
to sell calculations. The key assumptions the Company uses in estimating future
cash flows for purposes of calculating value-in use or fair value less costs to
sell are future oil prices, expected production volumes, future development
costs, operating costs and the discount rate applied to reflect the time value
of money. Changes to these assumptions will affect the recoverable amounts of
CGUs and individual assets and may then require a material adjustment to their
related carrying value.
The determination of CGUs requires judgement in defining a group of assets that
generate cash inflows that are largely independent of the cash inflows from
other assets or groups of assets. CGUs are determined by similar geological
structure, shared infrastructure, geographical proximity, commodity type,
similar exposure to market risks and materiality.
Fair value of share-based compensation
The fair value of share-based compensation is calculated using a Black-Scholes
option-pricing model. There are a number of estimates used in the calculation
such as future forfeiture rate, expected option life and the future price
volatility of the underlying security which can vary from actual future events.
The factors applied in the calculation are management's best estimates based on
historical information and future forecasts.
Fair value of contingent consideration
When consideration transferred relating to an acquisition includes consideration
contingent on future events, the Company is required to estimate the fair value
of the contingent consideration and record a contingent consideration liability.
The fair value of such consideration is based on assumptions and judgements
regarding the likelihood of future events.
Deferred income taxes
Deferred tax assets are recognized when it is considered probable that
deductible temporary differences will be recovered in the foreseeable future. To
the extent that future taxable income and the application of existing tax laws
in each jurisdiction differ significantly from the Company's estimate, the
ability of the Company to realize the deferred tax assets could be impacted.
New Accounting Pronouncements
The following pronouncements and amendments are effective for annual periods
beginning on or after January 1, 2013 unless otherwise stated. Adopting these
standards is expected to have minimal or no impact on the consolidated financial
statements.
IFRS 10 - Consolidation replaces SIC-12 Consolidation - Special Purpose Entities
and parts of IAS 27 Consolidated and Separate Financial Statements and requires
an entity to consolidate an investee when it is exposed, or has rights, to
variable returns from its involvement with the investee and has the ability to
affect those returns through its power over the investee.
IFRS 11 - Joint Arrangements requires a venturer to classify its interest in a
joint arrangement as a joint venture or joint operation. Joint ventures will be
accounted for using the equity method of accounting whereas joint operations,
the venturer will recognize its share of the assets, liabilities, revenue and
expenses of the joint operation. IFRS 11 supersedes IAS 31 Interests in Joint
Ventures, and SIC-13 Jointly Controlled Entities - Non-monetary Contributions by
Venturers.
IFRS 12 - Disclosure of Interest in Other Entities establishes disclosure
requirements for interests in other entities, such as joint arrangements,
associates, and special purpose vehicles and off balance sheet vehicles. The
standard carries forward existing disclosures and also introduces additional
disclosures addressing the nature of, and risks associated with, an entity's
interests in other entities.
IFRS 13 - Fair Value Measurement is a comprehensive standard that defines fair
value, requires disclosure about fair value measurement and provides a framework
for measuring fair value when it is required or permitted within the IFRS
standards.
IAS 27 - Separate Financial Statement addresses accounting for subsidiaries,
jointly controlled entities and associates in non-consolidated financial
statements.
IAS 28 - Investments in Associates and Joint Ventures has been amended to
include joint ventures in its scope and to address the changes in IFRS 10 - 13.
IAS 1 - Presentation of Financial Statements amendment requires components of
other comprehensive income to be separately presented between those that may be
reclassified to income and those that will not. The amendments are effective for
annual periods beginning on or after July 1, 2012.
IAS 32 - Financial Instruments: Presentation amendment provides clarification on
the application of offsetting rules. The amendments are effective for annual
periods beginning on or after July 1, 2012.
Disclosure Controls and Procedures and Internal Controls Over Financial Reporting
Antrim has established disclosure controls, procedures and corporate policies so
that its consolidated financial results are presented accurately, fairly and on
a timely basis. The Chief Executive Officer and Chief Financial Officer have
designed or have caused such internal controls over financial reporting to be
designed under their supervision to provide reasonable assurance regarding the
reliability of financial reporting and preparation of the Company's financial
statements in accordance with IFRS. The Company tested and evaluated the
effectiveness of its disclosure controls and procedures and internal controls
over financial reporting as at December 31, 2012. During this evaluation the
Corporation identified a weakness due to the limited number of finance and
accounting personnel at the Corporation dealing with complex and non-routine
accounting transactions that may arise.
There were no changes in the Company's internal controls over financial
reporting that occurred during 2012 that have materially affected, or are
reasonably likely to materially affect, the Company's internal controls over
financial reporting.
All internal control systems, no matter how well designed, have inherent
limitations. Therefore, these systems provide reasonable but not absolute
assurance that financial information is accurate and complete.
Related Party and Off-Balance Sheet Transactions
Antrim may from time to time enter into arrangements with related parties. In
2012, Antrim incurred fees of $421,607 (2011 - $266,741) payable to Burstall
Winger LLP, a law firm in which a director of the Company is a partner. The
Company had no off-balance sheet transactions in the year ended December 31,
2012.
Forward-Looking Statements
This MD&A and any documents incorporated by reference herein contain certain
forward-looking statements and forward-looking information which are based on
Antrim's internal reasonable expectations, estimates, projections, assumptions
and beliefs as at the date of such statements or information. Forward-looking
statements often, but not always, are identified by the use of words such as
"seek", "anticipate", "believe", "plan", "estimate", "expect", "targeting",
"forecast", "achieve" and "intend" and statements that an event or result "may",
"will", "should", "could" or "might" occur or be achieved and other similar
expressions. These statements are not guarantees of future performance and
involve known and unknown risks, uncertainties, assumptions and other factors
that may cause actual results or events to differ materially from those
anticipated in such forward-looking statements and information. Antrim believes
that the expectations reflected in those forward-looking statements and
information are reasonable but no assurance can be given that these expectations
will prove to be correct and such forward-looking statements and information
included in this MD&A and any documents incorporated by reference herein should
not be unduly relied upon. Such forward-looking statements and information speak
only as of the date of this MD&A or the particular document incorporated by
reference herein and Antrim does not undertake any obligation to publicly update
or revise any forward-looking statements or information, except as required by
applicable laws.
In particular, this MD&A and any documents incorporated by reference herein,
contain specific forward-looking statements and information pertaining to the
quantity of and future net revenues from Antrim's reserves of oil, natural gas
liquids ("NGL") and natural gas production levels. This MD&A may also contain
specific forward-looking statements and information pertaining to Antrim's plans
for developing its licences, expected production rates and future development
plans with respect to Cormorant East and future development plans for the
Causeway Field, commodity prices, foreign currency exchange rates and interest
rates, capital expenditure programs and other expenditures, supply and demand
for oil, NGL's and natural gas, expectations regarding Antrim's ability to raise
capital, to continually add to reserves through acquisitions and development,
the schedules and timing of certain projects, Antrim's strategy for growth,
Antrim's future operating and financial results, treatment under governmental
and other regulatory regimes and tax, environmental and other laws.
With respect to forward-looking statements contained in this MD&A and any
documents incorporated by reference herein, Antrim has made assumptions
regarding Antrim's ability to obtain additional drilling rigs and other
equipment in a timely manner, obtain regulatory approvals, future oil and
natural gas production levels from Antrim's properties and the price obtained
from the sales of such production, the level of future capital expenditure
required to exploit and develop reserves, the ability of Antrim's partners to
meet their commitments as they relate to the Company and Antrim's reliance on
industry partners for the development of some of its properties, Antrim's
ability to obtain financing for future Fyne development on acceptable terms, the
general stability of the economic and political environment in which Antrim
operates and the future of oil and natural gas pricing. In respect to these
assumptions, the reader is cautioned that assumptions used in the preparation of
such information may prove to be incorrect.
Antrim's actual results could differ materially from those anticipated in these
forward-looking statements and information as a result of assumptions proving
inaccurate and of both known and unknown risks, including risks associated with
the exploration for and development of oil and natural gas reserves such as the
risk that drilling operations may not be successful, unanticipated delays with
respect to the development of Antrim's properties, operational risks and
liabilities that are not covered by insurance, volatility in market prices for
oil, NGLs and natural gas, changes or fluctuations in oil, NGLs and natural gas
production levels, changes in foreign currency exchange rates and interest
rates, the ability of Antrim to fund its substantial capital requirements and
operations and to repay its obligations under the Payment Swap and Brent Oil
Price Commodity Swap. Antrim's reliance on industry partners for the development
of some of its properties, risks associated with ensuring title to the Company's
properties, liabilities and unexpected events inherent in oil and gas
operations, including geological, technical, drilling and processing problems
the risk of adverse results from litigation, the accuracy of oil and gas reserve
estimates and estimated production levels as they are affected by the Antrim's
exploration and development drilling and estimated decline rates, in particular
the future production rates at the Causeway and Cormorant East Fields in the UK
North Sea. Additional risks include the ability to effectively compete for,
among other things, capital, acquisitions of reserves, undeveloped lands and
skilled personnel, incorrect assessments of the value of acquisitions, Antrim's
success at acquisition, exploitation and development of reserves, changes in
general economic, market and business conditions in Canada, North America, the
United Kingdom, Europe and worldwide, actions by governmental or regulatory
authorities including changes in income tax laws or changes in tax laws, royalty
rates and incentive programs relating to the oil and gas industry and more
specifically, changes in environmental or other legislation applicable to
Antrim's operations, and Antrim's ability to comply with current and future
environmental and other laws, adverse regulatory rulings, order and decisions
and risks associated with the nature of the Common Shares.
Many of these risk factors, other specific risks, uncertainties and material
assumptions are discussed in further detail throughout this MD&A and in Antrim's
annual information form for the year ended December 31, 2012. Readers are
specifically referred to the risk factors described in this MD&A under "Risk
Factors" and in other documents Antrim files from time to time with securities
regulatory authorities. Copies of these documents are available without charge
from Antrim or electronically on the internet on Antrim's SEDAR profile at
www.sedar.com. Readers are cautioned that this list of risk factors should not
be construed as exhaustive.
The calculation of barrels of oil equivalent ("boe") is based on a conversion
rate of six thousand cubic feet of natural gas ("mcf") to one barrel of crude
oil ("bbl"). Boe's may be misleading, particularly if used in isolation. A boe
conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead.
In accordance with AIM guidelines, Mr. Kerry Fulton, P. Eng and Vice President,
Operations for Antrim, is the qualified person that has reviewed the technical
information contained in this MD&A. Mr. Fulton has over 30 years operating
experience in the upstream oil and gas industry.
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING
The accompanying consolidated financial statements are the responsibility of
management. The consolidated financial statements have been prepared by
management in accordance with International Financial Reporting Standards
outlined in the notes to the consolidated financial statements. The consolidated
financial statements include certain estimates that reflect the management's
best judgments. Management has determined such amounts on a reasonable basis in
order to ensure that the consolidated financial statements are presented fairly,
in all material respects. In the opinion of management, the consolidated
financial statements have been prepared within acceptable limits of materiality
and are in accordance with International Financial Reporting Standards. The
financial information contained in the annual report is consistent with that in
the consolidated financial statements.
Management is also responsible for establishing and maintaining appropriate
systems of internal control over the company's financial reporting. The internal
control system was designed to provide reasonable assurance to management
regarding the preparation and presentation of the consolidated financial
statements. Management tested and evaluated the effectiveness of its disclosure
controls and procedures and internal controls over financial reporting as at
December 31, 2012. During this evaluation Management identified a weakness due
to the limited number of finance and accounting personnel at the Corporation
dealing with complex and non-routine accounting transactions that may arise. All
internal control systems, no matter how well designed, have inherent
limitations. Therefore, these systems provide reasonable but not absolute
assurance that financial information is accurate and complete.
PricewaterhouseCoopers LLP, an independent firm of Chartered Accountants, has
been engaged, as approved by a vote of the shareholders at the Company's most
recent annual general meeting, to examine the consolidated financial statements
in accordance with Canadian generally accepted auditing standards and provide an
independent professional opinion.
The audit committee of the Board of Directors with all of its members being
independent directors, have reviewed the consolidated financial statements
including notes thereto, with management and PricewaterhouseCoopers LLP. The
consolidated financial statements have been approved by the Board of Directors
on the recommendation of the audit committee.
Stephen Greer, President & Chief Executive Officer
Anthony Potter, Chief Financial Officer
To view the Independent Auditor's Report, please visit the following link:
http://media3.marketwire.com/docs/auditor.pdf.
Antrim Energy Inc.
Consolidated Balance Sheets
As at December 31, 2012 and 2011
(Amounts in US$ thousands)
----------------------------------------------------------------------------
December 31 December 31
Note 2012 2011
------------------------
Assets
Current assets
Cash and cash equivalents 1,503 47,105
Restricted cash 5 808 17,249
Accounts receivable 332 5,294
Inventory and prepaid expenses 6 5,877 240
Assets held for sale 4 - 31,651
------------------------
8,520 101,539
Property, plant and equipment 7 81,069 15,207
Exploration and evaluation assets 8 6,931 122,431
------------------------
96,520 239,177
------------------------
------------------------
Liabilities
Current liabilities
Accounts payable and accrued liabilities 18,165 17,214
Deferred revenue 9 1,089 -
Liabilities held for sale 4 - 4,180
------------------------
19,254 21,394
------------------------
Decommissioning obligations 10 10,270 3,595
Contingent consideration 11 - 7,000
------------------------
29,524 31,989
------------------------
Commitments and contingencies 21
Subsequent events 24
Shareholders' equity
Share capital 12 361,922 361,587
Contributed surplus 20,626 19,579
Accumulated other comprehensive income (loss) 4,656 (5,971)
Deficit (320,208) (168,007)
------------------------
66,996 207,188
------------------------
96,520 239,177
------------------------
------------------------
The accompanying notes are an integral part of the consolidated financial
statements.
Approved on behalf of the Board of Directors of Antrim Energy Inc.:
Gerry Orbell, Director
James Smith, Director
Antrim Energy Inc.
Consolidated Statements of Comprehensive Loss
For the years ended December 31, 2012 and 2011
(Amounts in US$ thousands, except per share data)
----------------------------------------------------------------------------
Note 2012 2011
------------------------
Revenue 15 - -
Expenses
General and administrative expenses 16 5,843 5,004
Depreciation 7 94 191
Share-based compensation 13 998 883
Exploration and evaluation expenditures 7,640 273
Impairment 7, 8 122,698 49,101
Change in fair value of contingent
consideration 11 (7,000) (1,000)
Reduction in the fair value of financial assets 4 10,040 -
Gain on disposal of Argentina assets 4 (5,894) -
Loss on disposal - 70
------------------------
134,419 54,522
Financial items
Finance income 17 (276) (706)
Finance costs 18 213 586
Foreign exchange loss 503 708
------------------------
Loss from continuing operations before income
taxes 134,859 55,110
Income tax expense 20 - -
------------------------
Loss from continuing operations after income
taxes 134,859 55,110
Income from discontinued operations 4 (315) (2,140)
------------------------
Net loss for the year 134,544 52,970
------------------------
Other comprehensive (income) loss
Foreign currency translation adjustment (7,414) 4,123
Foreign currency translation adjustment -
disposal of assets 4 (3,213) (2,271)
------------------------
Other comprehensive (income) loss for the year (10,627) 1,852
------------------------
Comprehensive loss for the year 123,917 54,822
------------------------
------------------------
Net loss (income) per common share
Basic & diluted - continuing operations 14 0.73 0.32
Basic & diluted - discontinued operations 14 (0.00) (0.01)
The accompanying notes are an integral part of the consolidated financial
statements.
Antrim Energy Inc.
Consolidated Statements of Cash Flows
For the years ended December 31, 2012 and 2011
(Amounts in US$ thousands)
----------------------------------------------------------------------------
Note 2012 2011
------------------------
Operating Activities
Loss from continuing operations after income
taxes (134,859) (55,110)
Items not involving cash:
Depreciation 7 94 191
Share-based compensation 13 998 883
Accretion of decommissioning obligations 10 145 209
Foreign exchange loss 390 1,909
Impairment 7, 8 122,698 49,101
Change in the fair value of contingent
consideration 11 (7,000) (1,000)
Reduction in the fair value of financial
assets 4 10,040 -
Gain on disposal of Argentina assets 4 (5,894) -
Loss on disposal - 70
Changes in non-cash working capital items -
continuing operations 19 4,717 12,688
------------------------
Cash (used in) provided by operating activities
- continuing operations (8,671) 8,941
Cash used in operating activities -
discontinued operations 4 (365) (1,204)
------------------------
Cash (used in) provided by operating activities (9,036) 7,737
------------------------
Financing Activities
Issue of common shares 12 186 52,431
Share issue expenses 12 - (2,998)
------------------------
Cash provided by financing activities 186 49,433
------------------------
Investing Activities
Capital expenditures (63,034) (14,702)
Restricted cash 5 16,441 (17,249)
Cash proceeds from the disposal of Argentina
assets 4 9,976 -
------------------------
Cash used in investing activities - continuing
operations (36,617) (31,951)
Cash used in investing activities -
discontinued operations 4 (1,121) (2,372)
------------------------
Cash used in investing activities (37,738) (34,323)
------------------------
Effect of foreign exchange on cash and cash
equivalents 986 (1,392)
Net (decrease) increase in cash and cash
equivalents (45,602) 21,455
Cash and cash equivalents - beginning of year 47,105 25,650
------------------------
Cash and cash equivalents - end of year 19 1,503 47,105
------------------------
------------------------
The accompanying notes are an integral part of the consolidated financial
statements.
Antrim Energy Inc.
Consolidated Statements of Changes in Equity
For the years ended December 31, 2012 and 2011
(Amounts in US$ thousands)
----------------------------------------------------------------------------
Share capital
---------------------------
Number of Contributed
Note common shares Amount surplus
---------------------------------------
Balance, December 31, 2010 135,571,542 312,062 18,377
Net loss for the year - - -
Other comprehensive loss - - -
Issuance of common shares 12 48,191,700 52,297 -
Share issuance costs 12 - (2,998) -
Share-based compensation 13 - - 1,294
Stock options exercised 352,836 226 (92)
---------------------------------------
Balance, December 31, 2011 184,116,078 361,587 19,579
---------------------------------------
---------------------------------------
Balance, December 31, 2011 184,116,078 361,587 19,579
Net loss for the year - - -
Capital distribution 4 - - -
Other comprehensive income - - -
Share-based compensation 13 - - 1,196
Stock options exercised 614,998 335 (149)
---------------------------------------
Balance, December 31, 2012 184,731,076 361,922 20,626
---------------------------------------
---------------------------------------
Antrim Energy Inc.
Consolidated Statements of Changes in Equity
For the years ended December 31, 2012 and 2011
(Amounts in US$ thousands)
-----------------------------------------------------------------------
Accumulated
other
comprehensive
income (loss) Deficit Total
---------------------------------------
Balance, December 31, 2010 (4,119) (115,037) 211,283
Net loss for the year - (52,970) (52,970)
Other comprehensive loss (1,852) - (1,852)
Issuance of common shares - - 52,297
Share issuance costs - - (2,998)
Share-based compensation - - 1,294
Stock options exercised - - 134
---------------------------------------
Balance, December 31, 2011 (5,971) (168,007) 207,188
---------------------------------------
---------------------------------------
Balance, December 31, 2011 (5,971) (168,007) 207,188
Net loss for the year - (134,544) (134,544)
Capital distribution - (17,657) (17,657)
Other comprehensive income 10,627 - 10,627
Share-based compensation - - 1,196
Stock options exercised - - 186
---------------------------------------
Balance, December 31, 2012 4,656 (320,208) 66,996
---------------------------------------
---------------------------------------
The accompanying notes are an integral part of the consolidated financial
statements.
Notes to Consolidated Financial Statements
For the years ended December 31, 2012 and 2011
(Amounts in US$ thousands, except as otherwise noted)
1) Nature of Operations
Antrim Energy Inc. ("Antrim" or the "Company") is a Calgary based oil and
natural gas company. Through subsidiaries, the Company conducts exploration
activities in the United Kingdom and Ireland. Antrim Energy Inc. is incorporated
and domiciled in Canada. The Company's common shares are listed on the Toronto
Stock Exchange ("TSX") and the London Alternative Investment Market ("AIM")
under the symbols "AEN" and "AEY", respectively. The address of its registered
office is 1600, 333 - 7th Avenue S.W, Calgary, Alberta, Canada.
2) Basis of Presentation
a) Statement of compliance
The consolidated financial statements have been prepared in accordance with
International Financial Reporting Standards ("IFRS") as issued by the
International Accounting Standards Board ("IASB"). The policies applied in these
consolidated financial statements are based on IFRS issued and outstanding as at
March 26, 2013, the date the Board of Directors approved the year ended
consolidated financial statements.
The consolidated financial statements have been prepared on the historical cost
basis, except as explained in Note 3, Summary of Significant Accounting
Policies. The accounting policies described in Note 3 have been applied
consistently to all periods presented in these financial statements. Historical
cost is generally based on the fair value of the consideration given in exchange
for the assets.
b) Presentation currency
In these consolidated financial statements, unless otherwise indicated, all
dollar amounts are expressed in United States ("US") dollars. Antrim's
functional currency is Canadian dollars; however, the Company has adopted the US
dollar as its presentation currency to facilitate a more direct comparison to
North American oil and gas companies with international operations.
c) Critical accounting judgments and key sources of estimation uncertainty
In the application of the Company's accounting policies, management is required
to make judgments, estimates and assumptions about carrying values of assets and
liabilities that are not readily apparent from other sources. The estimates and
underlying assumptions are reviewed on an ongoing basis. The estimates and
associated assumptions are based on historical experience and other factors,
including expectations of future events that are believed to be reasonable under
the circumstances. Actual results may differ from these estimates.
The following are the critical judgments and estimates that management has made
in the process of applying the Company's accounting policies and that have the
most significant effect on the amounts recognized in the financial statements:
Estimation of reserve quantities
Depletion, impairment and decommissioning charges are dependent on the Company's
estimate of oil and gas reserves. The estimation of reserves is an inherently
complex process and involves the exercise of professional judgment. Reserves
have been evaluated at the balance sheet date by an independent qualified
reserve evaluator in accordance with National Instrument 51-101 Standards of
Disclosure for Oil and Gas Activities and are based on the definitions and
guidelines contained in the Canadian Oil and Gas Evaluation Handbook.
Oil and gas reserve estimates are based on a range of geological, technical and
economic factors including projected future rates of production, estimated
commodity prices, engineering data, reserve type and timing and amount of future
expenditures, all of which are subject to uncertainty. Assumptions reflect
market and regulatory conditions existing at the balance sheet date, which could
differ significantly from other points in time throughout the year, or future
periods. Changes in market and regulatory conditions and assumptions can
materially impact the estimation of net reserves.
Recoverability of exploration and evaluation costs
Exploration and evaluation costs are initially capitalized with the intent to
establish commercially viable reserves. The Company is required to make
estimates and judgments about future events and circumstances regarding the
economic viability of extracting the underlying resources. The costs are subject
to technical, commercial and management review to confirm the continued intent
to develop and extract the underlying resources. Fluctuations in future
commodity prices, resource quantities, expected production techniques, drilling
results, production costs and required capital expenditures are important
factors when making this determination. If a judgment is made that extraction of
the reserves is not viable, the exploration and evaluation costs will be written
off to net earnings.
Decommissioning obligations
The Company recognizes liabilities for the future decommissioning and
restoration of property, plant and equipment. These provisions are based on
estimated costs, which take into account the anticipated method and extent of
restoration consistent with legal requirements, technological advances and the
possible use of the site. Actual costs are uncertain and estimates can vary as a
result of changes to relevant laws and regulations, the emergence of new
technology, operating experience and prices. The actual timing of future
decommissioning and restoration is not known and may change due to certain
factors, including reserve life. Changes to assumptions made about future
expected costs, discount rates, inflation and timing may have a material impact
on the amounts presented. The Company has chosen to measure decommissioning
obligations using a risk-free discount rate.
Impairment of property, plant and equipment
The recoverable amounts of cash-generating units ("CGUs") and individual assets
have been determined based on greater of value-in-use or fair value less costs
to sell calculations. The key assumptions the Company uses in estimating future
cash flows for purposes of calculating value-in use or fair value less costs to
sell are future oil prices, expected production volumes, future development
costs, operating costs and the discount rate applied to reflect the time value
of money. Changes to these assumptions will affect the recoverable amounts of
cash-generating units and individual assets and may then require a material
adjustment to their related carrying value.
The determination of CGUs requires judgement in defining a group of assets that
generate cash inflows that are largely independent of the cash inflows from
other assets or groups of assets. CGUs are determined by similar geological
structure, shared infrastructure, geographical proximity, commodity type,
similar exposure to market risks and materiality.
Fair value of share-based compensation
The fair value of share-based compensation is calculated using a Black-Scholes
option-pricing model. There are a number of estimates used in the calculation
such as future forfeiture rate, expected option life and the future price
volatility of the underlying security which can vary from actual future events.
The factors applied in the calculation are management's best estimates based on
historical information and future forecasts.
Fair value of contingent consideration
When consideration transferred relating to an acquisition includes consideration
contingent on future events, the Company is required to estimate the fair value
of the contingent consideration and records a contingent consideration
liability. The fair value of such consideration is based on assumptions and
judgements regarding the likelihood of future events.
Deferred income taxes
Deferred tax assets are recognized when it is considered probable that
deductible temporary differences will be recovered in the foreseeable future. To
the extent that future taxable income and the application of existing tax laws
in each jurisdiction differ significantly from the Company's estimate, the
ability of the Company to realize the deferred tax assets could be impacted.
3) Summary of Significant Accounting Policies
The following significant accounting policies have been adopted in the
preparation and presentation of the consolidated financial statements:
a) Basis of consolidation
These consolidated financial statements incorporate the financial statements of
the Company and entities controlled by the Company. Control is achieved where
the Company has the power to govern the financial and operating policies of the
entity so as to obtain benefits from its activities. The financial statements of
subsidiaries are included in the consolidated financial statements from the date
that control commences until the date that control ceases. All intra-company
transactions, balances, income and expenses are eliminated on consolidation.
b) Foreign currency translation
In preparing the financial statements of the Company's subsidiaries,
transactions in currencies other than the entity's functional currency are
recorded at the rates of exchange prevailing on the date of the transaction.
Monetary assets and liabilities denominated in foreign currencies are translated
to the appropriate functional currency at foreign exchange rates at the balance
sheet date. Foreign exchange differences arising on translation are recognized
in earnings. Non-monetary assets that are measured at historical cost in a
foreign currency are translated using the exchange rate at the date of the
transactions.
In preparing the Company's consolidated financial statements, the financial
statements of each entity are first translated into Canadian dollars, the
functional currency of the Company. The consolidated financial statements of the
Company are then translated into U.S. dollars, the Company's presentation
currency. The assets and liabilities of foreign operations are translated into
Canadian dollars at exchange rates at the balance sheet date. Revenues and
expenses of foreign operations are translated into Canadian dollars using
foreign exchange rates that approximate those on the date of the underlying
transaction. Foreign exchange differences are recognized in other comprehensive
income and reclassified to net earnings upon disposal of the foreign operation.
c) Jointly controlled operations and jointly controlled assets
A significant portion of the Company's operations are conducted with others and
involve jointly controlled assets. The consolidated financial statements reflect
only the Company's interest in such activities and assets.
d) Oil and natural gas exploration and evaluation expenditures
Pre-licence costs
Costs incurred prior to obtaining the legal right to explore for hydrocarbon
resources are expensed in the period in which they are incurred.
Exploration and evaluation costs
Exploration and evaluation assets are stated at cost, less accumulated
impairment losses.
Once the legal right to explore has been acquired, costs directly associated
with an exploration well are capitalized as exploration and evaluation assets
until the drilling of the well is complete and the results have been evaluated.
These costs include licence costs, geological and geophysical costs, employee
remuneration, materials and fuel used, rig costs and payments made to
contractors. If no reserves are found, the exploration asset is tested for
impairment. If extractable hydrocarbons are found and, subject to further
appraisal activity (e.g. by drilling further wells), are likely to be developed
commercially, the costs continue to be carried as exploration and evaluation
assets while sufficient and continued progress is made in assessing the
commerciality of the hydrocarbons. All such costs are subject to technical,
commercial and management review as well as review for impairment indicators at
each period end to confirm the continued intent to develop or otherwise extract
value from the discovery. When this is no longer the case, the costs are written
off. When proved and probable reserves of oil are determined and development is
sanctioned, the relevant expenditure is transferred to oil and gas properties
after impairment is assessed and any resulting impairment loss is recognized.
e) Property, plant and equipment
Property, plant and equipment are stated at cost, less accumulated depreciation
and accumulated impairment losses.
The initial cost of an asset comprises its purchase price or construction cost,
any costs directly attributable to bringing the asset into operation, the
initial estimate of the decommissioning obligations and borrowing costs for
qualifying assets. Expenditures on the construction, installation or completion
of infrastructure facilities such as platforms, pipelines and the drilling and
completion of development wells, including unsuccessful development or
delineation wells, is capitalized within property, plant and equipment. The
purchase price or construction cost is the aggregate amount paid and the fair
value of any other consideration given to acquire the asset. The capitalized
value of a finance lease is also included within property, plant and equipment.
Depletion and depreciation
Oil and gas assets within property, plant and equipment are depleted on a
unit-of-production basis over the proved and probable reserves of the field
concerned. The unit-of-production rate for the amortization of field development
costs takes into account expenditures incurred to date, together with sanctioned
future development expenditure.
Other property, plant and equipment are generally depreciated on a straight-line
basis over its estimated useful lives, as follows:
Office equipment 5 years
Computer hardware and software 3 years
f) Impairment of non-financial assets
The Company assesses at each reporting date whether there is an indication that
an asset may be impaired. If any indication exists the Company estimates the
asset's recoverable amount. An asset's recoverable amount is the higher of an
asset's or CGU's fair value less costs to sell and its value-in-use and is
determined for an individual asset, unless the asset does not generate cash
inflows that are largely independent of those from other assets or groups of
assets. If the carrying amount of an asset or CGU exceeds its recoverable
amount, the asset or CGU is considered impaired and is written down to its
recoverable amount. In assessing value-in-use, the estimated future cash flows
are discounted to their present value using a pre-tax discount rate that
reflects current market assessments of the time value of money and the risks
specific to the asset. In determining fair value less costs to sell, recent
market transactions are taken into account, if available. If no such
transactions can be identified, an appropriate valuation model is used. These
calculations are corroborated by valuation multiples or other available fair
value indicators.
Impairment losses are recognized in the consolidated statement of loss and
comprehensive loss.
An assessment is made at each reporting date as to whether there is any
indication that previously recognized impairment losses may no longer exist or
may have decreased. If such indication exists, the Company estimates the asset's
or cash-generating unit's recoverable amount. A previously recognized impairment
loss is reversed only if there has been a change in the assumptions used to
determine the asset's recoverable amount since the last impairment loss was
recognized.
The reversal is limited so that the carrying amount of the asset does not exceed
its recoverable amount, nor exceed the carrying amount that would have been
determined, net of depreciation, had no impairment loss been recognized for the
asset in prior years.
g) Financial assets
Financial assets are measured at fair value on the balance sheet upon initial
recognition of the instrument. Subsequent measurement and changes in fair value
will depend on initial classification, as follows:
i. fair value through profit or loss financial assets and liabilities,
classified as held for trading or designated as fair value through
profit or loss, are measured at fair value and subsequent changes in
fair value are recognized in income;
ii. loans and receivables are non-derivative financial assets with fixed or
determinable payments that are not quoted in an active market;
iii.available-for-sale financial instruments are measured at fair value with
changes in fair value recorded in equity until the instrument or a
portion thereof is derecognized or impaired at which time the amounts
would be recognized in income; and
iv. held to maturity financial assets and loans and receivables are
initially measured at fair value with subsequent measurement at
amortized cost using the effective interest rate method. The effective
interest rate method calculates the amortized cost of a financial asset
and allocates interest income or expense over the applicable period. The
rate used discounts the estimated future cash flows over either the
expected life of the financial asset or liability or a shorter time-
frame if it's deemed appropriate.
Antrim's current classifications are as follows:
i. cash and cash equivalents are designated as loans and receivables,
ii. restricted cash is designated as loans and receivables; and
iii.accounts receivable are designated as loans and receivables.
h) Financial liabilities
Financial liabilities within the scope of IAS 39 Financial Instruments:
Recognition and Measurement ("IAS 39") are classified as financial liabilities
at fair value through profit or loss or as other financial liabilities at
amortized cost, as appropriate. The Company determines the classification of its
financial liabilities at initial recognition.
All financial liabilities are recognized initially at fair value and in the case
of loans and borrowings, plus directly attributable transaction costs. The
Company's financial liabilities include accounts payables and contingent
consideration.
Derecognition
A financial liability is derecognized when the obligation under the liability is
discharged, cancelled or expires.
i) Cash and cash equivalents
Cash and cash equivalents include cash on hand, deposits held with banks, and
other short-term highly liquid investments with original maturities of three
months or less.
j) Inventories
Inventories are stated at the lower of cost and net realizable value. The cost
of crude oil is the cost to produce, including the appropriate proportion of
depletion and depreciation and overheads, including all costs incurred in the
normal course of business in bringing each product to its present location and
condition, and is accounted on a weighted average basis. Net realizable value of
crude oil and refined products is based on estimated selling price in the
ordinary course of business less any expected selling costs.
k) Assets held for sale
Non-current assets, or disposal groups consisting of assets and liabilities, are
classified as held for sale if their carrying amounts will be recovered through
a sale transaction rather than through continuing use. This condition is met
when the sale is highly probably and the asset is available for immediate sale
in its present condition.
Non-current assets classified as held for sale are measured at the lower of the
carrying amount and fair value less costs to sell, with impairments recognized
in net earnings in the period measured.
Non-current assets and disposal groups held for sale are presented in current
assets and liabilities within the consolidated balance sheet. Assets held for
sale are not depreciated, depleted or amortized.
l) Provisions
General
Provisions are recognized when the Company has a present obligation (legal or
constructive) as a result of a past event, it is probable that an outflow of
resources embodying economic benefits will be required to settle the obligation
and a reliable estimate can be made of the amount of the obligation. Where the
Company expects some or all of a provision to be reimbursed, for example, under
an insurance contract, the reimbursement is recognized as a separate asset but
only when the reimbursement is virtually certain. The expense relating to any
provision is presented in the income statement net of any reimbursement. If the
effect of the time value of money is material, provisions are discounted using a
current pre-tax rate that reflects, where appropriate, the risks specific to the
liability. Where discounting is used, the increase in the provision due to the
passage of time is recognized as a finance cost.
Decommissioning obligations
Decommissioning obligations are recognized when the Company has a present legal
or constructive obligation as a result of past events, it is probable that an
outflow of resources will be required to settle the obligation and a reliable
estimate of the amount of obligation can be made. A corresponding amount
equivalent to the provision is also recognized as part of the cost of the
relevant asset category to which they relate. The amount recognized is the
estimated cost of decommissioning, discounted to its present value using a
risk-free interest rate.
Changes in the estimated timing or cost of decommissioning are dealt with
prospectively by recording an adjustment to the provision, and a corresponding
adjustment to the relevant asset category. The unwinding of the discount on the
decommissioning obligations is included as a finance cost.
m) Taxes
Current income tax
Current income tax assets and liabilities are measured at the amount expected to
be recovered from or paid to the taxation authorities. The tax rates and tax
laws used to compute the amount are those that are enacted or substantively
enacted, by the reporting date, in the countries where the Company operates and
generates taxable income.
Current income tax relating to items recognized directly in equity is recognized
in equity and not in the income statement. Management periodically evaluates
positions taken in the tax returns with respect to situations in which
applicable tax regulations are subject to interpretation and establishes
provisions where appropriate.
Deferred tax
The Company follows the liability method of accounting for income taxes. Under
this method, income tax assets and liabilities are recognized for the estimated
tax consequences attributable to differences between the amounts reported in the
financial statements and their respective tax bases, using enacted or
substantially enacted tax rates expected to apply when the asset is realized or
the liability settled. Deferred tax assets are only recognized to the extent it
is more likely than not that sufficient future taxable income will be available
to allow the future income tax asset to be realized.
n) Revenue recognition
Revenue is recognized when it is probable that the economic benefits associated
with a transaction will flow to the Company and the amount of the revenue can be
measured reliably and collectability is reasonably assured. In particular,
revenue from the production and sale of crude oil is recognized when the title
has been transferred to customers, which is when risk and rewards pass to the
customer. This occurs when product is physically transferred into a shipping
vessel.
Deferred revenue is recognized when cash is received and no crude oil has been
lifted from the terminal therefore title and risk has not been transferred to
the buyer.
For all financial instruments measured at amortized cost and interest bearing
financial assets classified as available-for-sale, interest income or expense is
recorded using the effective interest rate, which is the rate that exactly
discounts the estimated future cash payments or receipts through the expected
life of the financial instrument or a shorter period, where appropriate, to the
net carrying amount of the financial asset or liability. Interest income is
included in finance income in the income statement.
o) Share-based compensation
Equity-settled share-based compensation to directors, employees and others
providing similar services are measured at the fair value of the equity
instruments at the grant date.
The fair value determined at the grant date of the equity-settled share-based
compensation is expensed on a graded basis over the vesting period, based on the
Company's estimate of equity instruments that will eventually vest. At the end
of each reporting period, the Company revises its estimate of the number of
equity instruments expected to vest. The impact of the revision of the original
estimates, if any, is recognized in profit or loss such that the cumulative
expense reflects the revised estimate, with a corresponding adjustment to
contributed surplus.
p) Earnings (loss) per share
Basic earnings (loss) per share is computed by dividing the net earnings (loss)
available to common shareholders by the weighted average number of shares
outstanding during the reporting year. Diluted earnings (loss) per share is
computed in a similar way to basic earnings (loss) per share except that the
weighted average shares outstanding are increased to include additional shares
for the assumed exercise of stock options and warrants, if dilutive. The number
of additional shares is calculated by assuming that outstanding stock options
were exercised and that the proceeds from such exercises were used to acquire
common stock at the average market price during the reporting periods.
q) Share capital
Common shares are classified as equity. Incremental costs directly attributable
to the issuance of shares are recognized as a deduction from equity.
r) Standards issued but not yet effective
The following pronouncements and amendments are effective for annual periods
beginning on or after January 1, 2013 unless otherwise stated. Adopting these
standards is expected to have minimal or no impact on the consolidated financial
statements.
IFRS 10 - Consolidation replaces SIC-12 Consolidation - Special Purpose Entities
and parts of IAS 27 Consolidated and Separate Financial Statements and requires
an entity to consolidate an investee when it is exposed, or has rights, to
variable returns from its involvement with the investee and has the ability to
affect those returns through its power over the investee.
IFRS 11 - Joint Arrangements requires a venturer to classify its interest in a
joint arrangement as a joint venture or joint operation. Joint ventures will be
accounted for using the equity method of accounting whereas joint operations,
the venturer will recognize its share of the assets, liabilities, revenue and
expenses of the joint operation. IFRS 11 supersedes IAS 31 Interests in Joint
Ventures, and SIC-13 Jointly Controlled Entities - Non-monetary Contributions by
Venturers.
IFRS 12 - Disclosure of Interest in Other Entities establishes disclosure
requirements for interests in other entities, such as joint arrangements,
associates, and special purpose vehicles and off balance sheet vehicles. The
standard carries forward existing disclosures and also introduces additional
disclosures addressing the nature of, and risks associated with, an entity's
interests in other entities.
IFRS 13 - Fair Value Measurement is a comprehensive standard that defines fair
value, requires disclosure about fair value measurement and provides a framework
for measuring fair value when it is required or permitted within the IFRS
standards.
IAS 27 - Separate Financial Statement addresses accounting for subsidiaries,
jointly controlled entities and associates in non-consolidated financial
statements.
IAS 28 - Investments in Associates and Joint Ventures has been amended to
include joint ventures in its scope and to address the changes in IFRS 10 - 13.
IAS 1 - Presentation of Financial Statements amendment requires components of
other comprehensive income to be separately presented between those that may be
reclassified to income and those that will not. The amendments are effective for
annual periods beginning on or after July 1, 2012.
IAS 32 - Financial Instruments: Presentation amendment provides clarification on
the application of offsetting rules. The amendments are effective for annual
periods beginning on or after January 1, 2014.
4) Discontinued operations
The Company entered into an agreement on March 23, 2012 to sell all of its
interest in its wholly owned subsidiary Antrim Argentina S.A. to Crown Point
Energy Inc. ("Crown Point") (formerly known as Crown Point Ventures Ltd.) by way
of a plan of arrangement (the "Arrangement"). The consideration consisted of Cdn
$10,262 in cash (subject to certain adjustments) and 35,761,290 common shares of
Crown Point ("Crown Point Shares"). Pursuant to the Arrangement, Antrim would
distribute the Crown Point Shares to its shareholders.
On May 28, 2012, Antrim completed the sale of Antrim Argentina S.A. to Crown
Point. Under the terms of the Arrangement, the Company received a cash payment
of $9,976 (Cdn $10,262) and 35,761,290 Crown Point Shares. The actual cash
payment received was netted against adjustments of $1,015 (Cdn $1,016) which
have been recognized as sale transaction costs. These sale transaction costs,
along with costs of $1,886 incurred by the Company, have been offset against
income from discontinued operations.
Details of the disposition are as follows:
2012
--------
Consideration received:
Cash 9,976
Crown Point Shares (based on a May 28, 2012 share price of Cdn
$0.80) 27,811
--------
37,787
Carrying value of assets and liabilities disposed:
Working capital 9,388
Property, plant and equipment 19,886
Exploration and evaluation assets 719
Other non-current assets 1,189
Decommissioning obligations (2,502)
--------
Total carrying value of assets and liabilities disposed 28,680
--------
Gain on disposal excluding foreign currency translation adjustment 9,107
Foreign currency translation adjustment relating to disposal (3,213)
--------
Gain on disposal after foreign currency translation adjustment 5,894
--------
--------
Antrim distributed the Crown Point Shares to its shareholders on June 7, 2012
(the "Distribution Date"). On the Distribution Date, Crown Point's closing share
price on the TSX Venture Exchange was Cdn $0.51 which had decreased from the May
28, 2012 closing share price of Cdn $0.80. This reduction in Crown Point's share
price resulted in the Company recognizing a capital loss on the Crown Point
Shares of $10,040. This amount has been recognized on the consolidated statement
of comprehensive loss as a reduction in the fair value of financial assets. A
capital distribution of $17,657 has been recorded in deficit on the statement of
changes in equity.
The combined results of the discontinued operations have been included in the
consolidated statement of comprehensive loss. The comparative period income and
cash flows from discontinued operations have been reclassified to include those
operations classified as discontinued in the current year.
The year ended December 31, 2012 discontinued financial and operating results
include only those results up to May 28, 2012 (the date of sale of the Argentina
operations).
December 31 December 31
2012 2011
------------------------------
Discontinued operations
Revenue, net of royalties 4,764 10,197
Direct production and operating expenditures (1,906) (4,710)
Depletion and depreciation (147) (4,004)
General and administrative expenses (768) (1,292)
Sale transaction costs (1,886) -
Exploration and evaluation expenditures (26) (45)
Other income 935 2,183
Export taxes (88) (247)
Write down of non-current assets (568) -
Finance income 88 311
Finance costs (130) (272)
Foreign exchange gain 47 19
------------------------------
Income from discontinued operations 315 2,140
------------------------------
------------------------------
December 31 December 31
2012 2011
------------------------------
Cash flow from discontinued operations
Net cash flow used in operating activities (365) (1,204)
Net cash flow used in investing activities (1,121) (2,372)
------------------------------
Net cash flow used in discontinued operations (1,486) (3,576)
------------------------------
------------------------------
5) Restricted cash
December 31 December 31
2012 2011
------------------------------
Restricted cash 808 17,249
------------------------------
808 17,249
------------------------------
------------------------------
Restricted cash of $808 at December 31, 2012 relates to a British pounds
sterling standby letter of credit issued to the Sullom Voe Terminal as part of
the operations of Causeway.
Restricted cash of $17,249 at December 31, 2011 relates to US dollar and British
pounds sterling standby letters of credit issued with respect to the Company's
drilling program in the UK North Sea.
6) Inventory and prepaid expenses
December 31 December 31
2012 2011
------------------------------
Crude oil inventory 4,498 -
Prepaids 1,379 240
------------------------------
5,877 240
------------------------------
------------------------------
Inventory with a carrying amount of $4,498 (2011 - nil) represents linefill and
oil stocks available for sale as at December 31, 2012. Included within this
balance is depletion of $3,372.
7) Property, plant and equipment
December 31 December 31
2012 2011
------------------------------
Opening balance 15,207 26,129
Additions 58,250 2,161
Depletion and depreciation (3,466) (191)
Depletion and depreciation relating to assets
held for sale - (4,004)
Changes in decommissioning estimate 158 370
Impairment - (3,184)
Transferred from exploration and evaluation
assets 9,347 15,005
Reclassified to assets held for sale - (19,536)
Foreign currency translation 1,573 (1,543)
------------------------------
Ending balance 81,069 15,207
------------------------------
------------------------------
In November 2012, the Field Development Plan ("FDP") for the Cormorant East
Field was approved by the Department of Energy and Climate Change ("DECC"). As a
result, $9,347 of accumulated exploration and evaluation costs were transferred
to property, plant and equipment.
During the year, the Company capitalized $152 (2011 - $23) of general and
administrative and $61 (2011 - $20) of share-based compensation related to
development activity.
At December 31, 2012, the Company assessed the carrying amount of its property,
plant and equipment assets for indicators of impairment such as changes in
reserves and lower production rates. Impairment tests were completed using an
after-tax discount rate of 10 percent. The following table outlines benchmark
prices at December 31, 2012 used in the impairment test:
Brent crude oil Exchange rate Exchange rate
(US$/barrel) (US$/C$) (US$/GBPGBP )
---------------------------------------------
2013 107.50 1.00 1.60
2014 102.50 1.00 1.60
2015 101.40 1.00 1.60
2016 100.80 1.00 1.60
2017 100.10 1.00 1.60
Thereafter +2.0% 1.00 1.60
---------------------------------------------
No impairment existed at December 31, 2012 relating to the capitalized costs of
property, plant and equipment assets.
8) Exploration and evaluation assets
December 31 December 31
2012 2011
------------------------------
Opening balance 122,431 171,850
Additions 9,219 38,494
Changes in decommissioning estimate(1) 1,850 (288)
Disposals - (22,035)
Impairment (122,698) (45,917)
Transferred to property, plant and equipment (9,347) (15,005)
Reclassified to assets held for sale - (608)
Foreign currency translation 5,476 (4,060)
------------------------------
Ending balance 6,931 122,431
------------------------------
------------------------------
(1) Changes in decommissioning obligation estimate are offset by
decommissioning obligation dispositions of $1,362
During the year, the Company capitalized $425 (2011 - $558) of general and
administrative costs and $137 (2011 - $391) of share-based compensation related
to exploration and evaluation activity.
In January 2013, the Company elected not to participate in further development
work on the Fionn Field. As a result, an impairment charge of $50,358 in 2012
was recognized, representing the full carrying value relating to the Fionn Field
CGU. Antrim retains a 35.5% interest in the remainder of Licence P201 Block
211/22a South East Area.
Licence P1625 Block 21/24b ("West Teal") is nearing the end of its initial
exploration term and based on an evaluation performed by management the licence
is not considered economically viable to continue with. As a result the Company
recognized an impairment charge of $1,841 million in 2012, relating to the full
carrying value of this licence.
In December 2012, the Company announced that the Cyclone exploration well in UK
Block 21/7b was plugged and abandoned. As a result, an impairment charge of
$5,939 was recognized in 2012 representing the full carrying value relating to
this licence.
In October 2012, DECC agreed to waive the seismic and contingent well
obligations on Licence P1563 Blocks 21/28b & 21/29c ("Carra") which allowed the
Company to relinquish the licence in its entirety. The Company recognized an
impairment charge of $2,304 in 2012 representing the full carrying value of this
licence.
As at March 31, 2012, in accordance with IFRS, management performed an
impairment assessment on the carrying value of the Fyne Licence CGU as there
were indications that the recoverable value may be impaired. The facts and
circumstances considered included the abandonment of the East Fyne appraisal
well, the expectation that the gross Fyne Field reserves would likely decline by
approximately 36%, the withdrawal of Premier Oil UK Limited ("Premier") and
First Oil Expro Limited ("First Oil") from the Joint Operating Agreement
("JOA"), the risk that Antrim may not obtain approval of an FDP from DECC, the
risk of Antrim not finding partners and the challenge in securing funding for
the project in a difficult market. In light of these events management
determined that the carrying value of the Fyne Licence CGU was impaired. The
carrying value of the Fyne Licence was written down to a $nil value with the
Company incurring a $60,112 impairment charge in the first quarter of 2012.
Costs incurred subsequent to March 31, 2012 of $7,343 relating to this licence
have been expensed as exploration and evaluation expenditures on the statement
of comprehensive loss.
The Company recognized an impairment charge in 2012 of $2,144 relating to the
Erne discovery well 21/29d-11 and the sidetrack well 21/29d-11Z. Post-well
analysis of these two wells by the Company's independent reserve evaluation
engineers did not result in any reserves being assigned at this time. The
impairment charge is in addition to an impairment charge of $10,312 recognized
in the fourth quarter of 2011.
With the sale of the Company's subsidiary Antrim Causeway (N.I.) Limited
("Antrim Causeway") to Valiant Petroleum plc ("Valiant") in October 2011, an
impairment charge of $35,605 to exploration and evaluation assets was recognized
in 2011.
9) Deferred revenue
December 31 December 31
2012 2011
------------------------------
Deferred revenue 1,089 -
------------------------------
------------------------------
Deferred revenue of $1,089 (2011 - $nil) relates to oil sales which have been
invoiced during the year but have not been lifted from the terminal therefore
title and risk has not been transferred to the buyer (see Note 15).
10) Decommissioning obligations
December 31 December 31
2012 2011
------------------------------
Opening balance 3,595 7,380
Additions 4,259 579
Accretion 145 209
Accretion relating to asset held for sale - 30
Change in estimate 3,370 82
Dispositions (1,362) (1,561)
Reclassified to liabilities held for sale - (2,529)
Foreign currency translation 263 (595)
------------------------------
Ending balance 10,270 3,595
------------------------------
------------------------------
At December 31, 2012, the estimated undiscounted decommissioning obligations are
$11,218 (2011 - $5,794). The Company expects the undiscounted obligations to be
payable between 2016 and 2020.
In January 2013, the Company elected not to participate in further development
work on the Fionn Field. As a result of Antrim's withdrawal of its 35.5% working
interest, $1,362 of abandonment liability was disposed of.
The change in estimate in 2012 is primarily related to increased costs estimates
for the reclamation of suspended wells, changes in working interest and revision
to the timing of future decommissioning obligation cash flows.
The present value of the decommissioning obligations has been calculated using a
risk-free interest rate of 1.6% (2011 - 3.8%) and an inflation rate of 2.0%
(2011 - 2.0%).
11) Contingent consideration
December 31 December 31
2012 2011
------------------------------
Opening balance 7,000 8,000
Revision to estimate (7,000) (1,000)
------------------------------
Ending balance - 7,000
------------------------------
------------------------------
Contingent consideration of $10,000 on the acquisition of the Fyne Field is
payable to the seller upon approval of an FDP by DECC. As at March 31, 2012, a
fair value of $nil for the contingent consideration was determined based on the
impairment assessment performed with respect to the Fyne Licence (See Note 8).
12) Share capital
Authorized
Unlimited number of common voting shares
Common shares issued Number of Amount
Shares $
------------------------------
Balance, December 31, 2010 135,571,542 312,062
Issuance of common shares 48,191,700 52,297
Exercise of stock options 352,836 134
Transfer from contributed surplus - 92
Share issuance costs - (2,998)
------------------------------
Balance, December 31, 2011 184,116,078 361,587
Exercise of stock options 614,998 186
Transfer from contributed surplus - 149
------------------------------
Balance, December 31, 2012 184,731,076 361,922
------------------------------
------------------------------
13) Share-based compensation
The Company has a program whereby it may grant options to its directors,
officers and employees to purchase up to 10% of the issued and outstanding
number of common shares. The exercise price of each option is no less than the
market price of the Company's stock on the date of grant. Stock option terms are
determined by the Company's Board of Directors but options typically vest evenly
over a period of three years from the date of grant and expire five years after
the date of grant.
Share-based compensation for the year was $1,196 (2011 - $1,294) of which $998
(2011 - $883) was expensed and $198 (2011 - $411) was capitalized.
The following table illustrates the number and weighted average exercise prices
of and movements in share options under the option program during the year.
2012 2011
--------------------------------------------------
Weighted Weighted
average average
exercise exercise
price price
# of Options Cdn $ # of Options Cdn $
--------------------------------------------------
Outstanding at January 1 9,168,063 2.12 13,247,898 2.20
Granted 6,985,000 0.60 - -
Forfeited/expired (3,188,000) 3.45 (3,726,999) 2.59
Exercised (614,998) 0.30 (352,836) 0.37
--------------------------------------------------
Outstanding at December 31 12,350,065 0.98 9,168,063 2.12
--------------------------------------------------
--------------------------------------------------
Exercisable at December 31 4,581,742 1.56 6,858,083 2.49
--------------------------------------------------
--------------------------------------------------
The weighted average share price on the exercise date for share options
exercised in 2012 was $0.77 (2011 - $1.19).
The range of exercise prices of the outstanding options is as follows:
Options outstanding
----------------------------------------------------------------------------
Weighted-
Weighted- Number average
Range average outstanding years
of exercise exercise at remaining
prices price December contractual
Cdn $ Cdn $ 31, 2012 life
----------------------------------------------------------------------------
0.27 - 1.00 0.55 8,485,065 3.91
1.01 - 2.00 1.02 2,340,000 2.72
2.01 - 3.00 2.49 600,000 0.60
3.01 - 3.92 3.87 925,000 0.37
--------------------
12,350,065
--------------------
--------------------
Options Options exercisable
outstanding
----------------------------------------------------------------------------
Weighted-
Weighted- Number average
Range average outstanding years
of exercise exercise at remaining
prices price December contractual
Cdn $ Cdn $ 31, 2012 life
----------------------------------------------------------------------------
0.27 - 1.00 0.31 1,470,066 1.08
1.01 - 2.00 1.02 1,586,676 2.71
2.01 - 3.00 2.49 600,000 0.60
3.01 - 3.92 3.87 925,000 0.37
--------------------
4,581,742
--------------------
--------------------
The fair values of options granted during the year were calculated using a Black
Scholes valuation model. The principal inputs to the option valuation model
were:
2012 2011
--------------------
Weighted average share price 0.60 -
Weighted average exercise price 0.60 -
Weighted average expected volatility 80.54% -
Option life 4.5 years -
Dividend yield Nil -
Weighted average risk-free interest rate 1.19% -
Forfeiture rate 10% -
Expected volatility was determined by calculating the historical volatility of
the Company's share price over a period commensurate with the expected lifetime
of the options.
On July 26, 2012, as a result of the completion of the Arrangement for the sale
of Antrim Argentina S.A. and in accordance with the terms of the Company's stock
option plan, the Company received all necessary approvals to make a four cent
reduction to the exercise price of the Antrim options outstanding at the time of
the Arrangement, so that Antrim option plan participants were neither favoured
nor penalized by the impact of the reduction of stated capital of Antrim's
common shares. The modification of the exercise price resulted in an increase of
$51 on the fair value of the stock options outstanding. This incremental fair
value has been recognized in share-based compensation.
14) Earnings per share
2012 2011
------------------------------
Loss used in the calculation from continuing
operations 134,859 55,110
Income used in the calculation from
discontinued operations (315) (2,140)
------------------------------
Net loss for the year 134,544 52,970
------------------------------
------------------------------
Basic earnings per share was calculated as follows:
2012 2011
------------------------------
Weighted average number of common shares:
Issued common shares 184,116,078 135,571,542
Effects of share options exercised 272,074 268,446
Effects of shares issued - 38,157,264
------------------------------
Weighted average number of common shares -
basic 184,388,152 173,997,252
------------------------------
------------------------------
Diluted earnings per share was calculated as follows:
2012 2011
------------------------------
Weighted average number of common shares:
Weighted average number of common shares -
basic 184,388,152 173,997,252
Effect of outstanding options 1,140,005 1,415,216
------------------------------
Weighted average number of common shares -
diluted 185,528,157 175,412,468
------------------------------
------------------------------
There have been no other transactions involving ordinary shares or potential
ordinary shares between the reporting date and the date of completion of these
financial statements.
2012 2011
--------------------
Basic and diluted loss (earnings) per common share
From continuing operations 0.73 0.32
From discontinued operations (0.00) (0.01)
--------------------
Total basic and diluted loss per share 0.73 0.31
--------------------
--------------------
For the years ended December 31, 2012 and 2011, all stock options were
anti-dilutive and were not included in the diluted common share calculation.
15) Revenue
2012 2011
--------------------
Sales invoiced 1,089 -
Deferred revenue at the end of the year (1,089) -
--------------------
Sales recognized as revenue - -
--------------------
--------------------
Revenue is recognized when title and risk transfer to the purchaser, which is at
the time of lifting of the oil into the tanker at the Sullom Voe terminal. All
sales are made under contract to one UK customer. Under the contract with the
purchaser, Antrim invoices and receives payment for its oil in the month after
production; however, the purchaser retains certain rights impacting the timing
of liftings which may result in no sales in a particular month resulting in
deferred revenue.
16) General and administrative expenses
2012 2011
--------------------
Wages and salaries 3,770 3,338
Occupancy 467 468
Administrative 2,253 1,699
Travel 315 370
Overhead recovery (962) (871)
--------------------
5,843 5,004
--------------------
--------------------
Total employee benefits expenses, including share-based compensation for the
year ended December 31, 2012 were $4,966 (2011 - $4,632).
17) Finance income
2012 2011
--------------------
Interest income 276 706
--------------------
--------------------
18) Finance costs
2012 2011
--------------------
Accretion of decommissioning obligations 145 209
Interest expense - 172
Bank charges 68 205
--------------------
213 586
--------------------
--------------------
19) Supplemental cash flow information
2012 2011
--------------------
(Increase) / decrease of assets:
Trade and other receivables 4,962 (1,764)
Inventory and prepaid expenses (2,284) 487
Increase / (decrease) of liabilities:
Trade and other payables 950 13,965
Deferred revenue 1,089 -
--------------------
4,717 12,688
--------------------
--------------------
Cash and cash equivalents are comprised of: 2012 2011
--------------------
Cash in bank 1,503 19,921
Short-term deposits - 27,184
--------------------
1,503 47,105
--------------------
--------------------
20) Income taxes
The differences between the expected income tax provision and the reported
income tax provision are summarized as follows:
2012 2011
--------------------
Loss from continuing operations before income taxes 134,859 55,110
Statutory income tax rate 25% 26.5%
--------------------
Expected recovery 33,715 14,604
Increase (decrease) in taxes resulting from:
Non-deductible expenses (16,692) (9,575)
Effect of different tax rates in foreign jurisdictions (10,767) 2,635
Changes in statutory rate changes in the year 412 104
Benefit of tax losses not recognized (6,668) (7,768)
--------------------
- -
--------------------
--------------------
The statutory tax rate was 25% in 2012 (2011 - 26.5%). The decrease from 2011 to
2012 was as a result of previously enacted reductions in the federal corporate
income tax rates.
There was no income tax expense relating to discontinued operations.
Deferred income tax
The deferred income tax assets are comprised of the following:
December 31 December 31
2012 2011
------------------------------
Property, plant and equipment (25,083) (39,139)
Decommissioning obligations 3,081 1,078
Non-capital losses 94,165 63,995
Capital losses 1,447 -
Share issuance and financing costs 1,103 755
Other 249 149
Unrecognized deferred tax asset (74,962) (26,838)
------------------------------
- -
------------------------------
------------------------------
The Company has unused non-capital tax losses of $310,676 (2011 - $220,754) to
carry forward against future taxable income of subsidiaries in which the losses
arose. Some of these deferred tax assets were recognized in the current period
as the Company anticipates being able to use them to offset taxable profits in
its operations in the United Kingdom.
At December 31, 2012, the Company had the following available tax loss
carryforwards:
Expiry Dates $
------------------------
Loss carryforwards attributable to continuing
operations:
Canada 2014-2031 26,809
United Kingdom No Expiry 283,841
Ireland No Expiry 26
----------
310,676
----------
----------
21) Commitments and contingencies
The Company has commitments in respect of its petroleum and natural gas
properties and operating leases as follows:
2013 2014 2015 2016 2017 Thereafter
----------------------------------------------------------------------------
United Kingdom
Causeway(1) 16,079 7,073 27 29 31 31
Cormorant East 654 8 8 8 8 8
Fyne and Dandy(2) 2,913 33 33 33 33 33
Cyclone - Typhoon(3) 13 12 - - - -
West Teal(4) - - - - - -
Carra(5) - - - - - -
Erne 13 13 - - - -
Ireland 69 - - - - -
Office leases 358 359 372 372 350 10
----------------------------------------------------------------------------
Total 20,099 7,498 440 442 422 82
----------------------------------------------------------------------------
(1) Relates to Antrim's 35.5% interest in the Causeway Licences.
(2) In 2012, Antrim signed a Heads of Term's Agreement for an option to
lease an FPSO for use in the development of the Fyne Field. As the
Company decided not to proceed with the development of the Fyne Field,
there is a $2.8 million obligation related to front end engineering
design work. This obligation is included on the consolidated balance
sheet as at December 31, 2012 under accounts payables and accrued
liabilities.
(3) The Company has a $6.2 million contingent drilling commitment on this
licence for the Typhoon prospect in 2014. Due to the results of the
Cyclone well, the Company has asked DECC to accept this well as a
fulfillment of the drilling obligation. Contingent on DECC acceptance,
there are no remaining obligations for the initial term of the licence.
(4) The Company has a $24.0 million contingent drilling commitment on this
licence for the West Teal prospect in 2013. Due to the Company being
unable to identify a commercially viable export route a request was made
to DECC to waive the contingent well requirement and, with DECC's
consent, allow the licence to be relinquished (see Note 8).
(5) In October 2012, DECC waived all commitments related to the Licence
P1563 Blocks 21/28b & 21/29c. In February 2013, the licence and all
commitments were officially relinquished.
Contingencies
In 2011, the Company entered into a variation to an existing contract for
drilling management services in the UK North Sea which required the drilling of
two wells, estimated to take 50 days in a letter of intent preceding the
contract variation. The Company contends that it met its contractual obligations
under this variation through the drilling of the Erne pilot well (21/29d-11) and
the Erne sidetrack well (21/29d-11Z). The drilling of these two wells took place
over a period of 58 days. Subsequent to releasing the rig, the Company received
an invoice from the drilling management services contractor charging the Company
for approximately $5 million in additional costs as the contractor claims all
conditions of the contract had not yet been satisfied. In July 2012, the
drilling management services contractor filed a claim against the Company for
the additional invoice costs plus interest and lost management time, in the High
Court of England and Wales. In August 2012, the Company filed a defence against
this claim in the High Court of England and Wales. A case management conference
where the Court will set the timetable for the claim going forward has been
listed for April 12, 2013. The Company is disputing the additional costs and
believes it is more likely than not that it will not have to pay. As a result, a
contingent liability has not been recorded.
In January 2013, the Company elected not to participate in further development
work on the Fionn Field. Subject to all necessary approvals from DECC, Antrim
intends to withdraw from the Fionn Field subarea and will not incur any further
liabilities. In accordance with the Fionn Field Supplemental Agreement, signed
in January 2012, the Company is of the position that there are no further
obligations with respect to the decommissioning or well abandonment liabilities
of the three currently suspended wells in the Fionn Field subarea. The operator
contends this position in regards to two of the three currently suspended wells.
The Company believes it is more likely than not that Antrim will be released of
these obligations. Accordingly, no amounts have been recorded in decommissioning
obligations in relation to the Fionn Field (see Note 10).
Operating lease arrangements
2012 2011
--------------------
Minimum lease payments under operating leases recognized
as an expense in the year 470 -
--------------------
--------------------
At the balance sheet date, the Company had outstanding commitments for future
minimum lease payments under non-cancellable operating leases, which fall due as
follows:
2012 2011
--------------------
Within one year 358 -
In the second to fifth years inclusive 1,464 -
--------------------
1,822 -
--------------------
--------------------
Operating lease payments represent net rentals payable by the Company for its
office properties. Current lease arrangements expire at the end of December
2017.
22) Financial instruments and financial risks
Financial instruments
Financial assets and financial liabilities are initially recognized at fair
value and are subsequently accounted for based on their classification. The
classification categories, which depend on the purpose for which the financial
instruments were acquired and their characteristics, include held-for-trading,
available-for-sale, held-to-maturity, loans and receivables, investments, and
other liabilities.
Except in very limited circumstances, the classification is not changed
subsequent to initial recognition.
The Company's financial instruments consist of cash, cash equivalents,
restricted cash, accounts receivable, other non-current assets, accounts payable
and contingent consideration. Cash and cash equivalents, restricted cash, and
accounts receivable are classified as loans and receivables and are accounted
for at amortized cost. Accounts payable are classified as other liabilities and
are accounted for at amortized cost. Due to the short-term maturity of the
Company's financial instruments, fair values approximate carrying amounts.
Financial risks
The Company is exposed to financial risks encountered during the normal course
of its business. These financial risks are composed of credit risk, liquidity
risk and market risk including commodity price and foreign currency exchange
risks.
a) Credit risk
The Company is exposed to the risk that its counterparties will fail to
discharge their obligations to the Company on its cash, cash equivalents,
accounts receivable and certain non-current assets.
Cash and cash equivalents and restricted cash are on deposit with reputable
Canadian and international banks, and therefore the Company does not believe
these financial instruments are subject to material credit risk. The Company
sells all of its production to one oil and natural gas marketer and therefore is
subject to concentration risk. Management does not believe that this
concentration of credit risk will result in any loss to the Company based on
past payment experience and its investment grade credit rating as established by
independent credit rating agencies.
The Company's sales from discontinued operations are approximately 40% to a
single customer and three customers who each have sales of greater than 10%.
Factors included in the assessment of accounts receivable for impairment are the
relationship between the purchaser and the Company and the age of the
receivable. As at December 31, 2012, the Company has provided for an allowance
for doubtful accounts of $nil (2011 - $nil).
The extent of the Company's credit risk exposure is identified in the following
table:
December 31 December 31
2012 2011
------------------------------
Current
Cash and cash equivalents 1,503 47,105
Restricted cash 808 17,249
Accounts receivable 332 5,294
Assets held for sale(1) - 8,200
------------------------------
2,643 77,848
------------------------------
------------------------------
(1) Relates to cash and cash equivalents classified as assets held for sale
as at December 31, 2011 and the non-interest bearing promissory note and
interest bearing bond which were classified as non-current as at
December 31, 2011.
(b) Liquidity risk
The Company is exposed to liquidity risk from the possibility that it will
encounter difficulty meeting its financial obligations. The Company manages this
risk by forecasting cash flows in an effort to identify future liabilities and
arrange financing, if necessary. It may take many years and substantial cash
expenditures to pursue exploration and development activities on all of the
Company's existing undeveloped properties. Accordingly, the Company will need to
raise additional funds from outside sources in order to explore and develop its
properties. There is no assurance that adequate funds from debt and equity
markets will be available to the Company in a timely manner.
At December 31, 2012, the Company had a working capital deficiency of $10,734,
compared to working capital of $52,674 at December 31, 2011. In January 2013 the
Company entered into a $30 million Payment Swap transaction described in Note
24. The Payment Swap provides the Company with sufficient funding to meet its
commitments for cost overruns on the completion of the production well in the
Causeway Field and future costs related to the Causeway development program. The
contractual maturities of the Company's financial liabilities at December 31,
2012 are all less than one year.
(c) Market risk
Market risk consists of commodity price risk and foreign currency exchange risk.
Commodity price risk
Currently all of the Company's production is from one property in the UK.
Commodity price risk related to crude oil production represents a significant
market risk exposure. Crude oil prices and quality differentials can be
influenced by global supply and demand factors as well as political events,
quotas imposed on members of the Organization of Petroleum Exporting Countries
(OPEC) and weather. In January 2013, Antrim entered into a Brent Oil Price
Commodity Swap which reduced its exposure to commodity price risk (see Note 24).
Foreign currency exchange risk
The Company is exposed to fluctuations in foreign currency exchange rates as
many of the Company's financial instruments are denominated in United States
dollars and British pounds sterling ("GBP "). As a result, fluctuations in the
United States dollar and British pounds sterling against the Canadian dollar
could result in unanticipated fluctuations in the Company's financial results.
The Company seeks to minimize foreign exchange risk by holding cash and cash
equivalents in Canadian dollars when not required in support of current
operations. A 1% change in the Cdn$/US$ and Cdn$/GBP exchange rate at December
31, 2012 would impact comprehensive income by approximately $1,123 and $739,
respectively.
Capital management
The Company's objective when managing its capital is to maintain adequate levels
of funding to support its exploration and development program and provide
flexibility in the future development of its business. Historically the Company
raised all of its capital requirements from internally generated cash flow and
the issuance of common shares and securities exchangeable for common shares. In
the fourth quarter of 2012, the Company incurred unexpected cost overruns on the
development of Causeway resulting in a working capital deficiency as at December
31, 2012.
The Company's capital structure at December 31, 2012 consisted of cash and cash
equivalents and shareholders' equity. Shareholders' equity includes
shareholders' capital, contributed surplus, and accumulated other comprehensive
loss and deficit. The Company had no bank debt at December 31, 2012; however, it
assumed debt obligations in January 2013 when it entered into a Payment Swap
transaction (see Note 24).
The capital structure of the Company consists of:
December 31 December 31
2012 2011
------------------------------
Cash and cash equivalents 1,503 47,105
Shareholders' equity (66,996) (207,188)
------------------------------
(65,493) (160,083)
------------------------------
------------------------------
Current restrictions on the availability of credit may limit the Company's
ability to access debt or equity financing for its development projects. The
Company forecasts cash flows against a range of macroeconomic and financing
market scenarios in an effort to identify future liabilities and arrange
financing, if necessary. Although the Company may need to raise additional funds
from outside sources, if available, in order to develop its oil and gas
properties, the Company maintains flexibility to manage financial commitments on
these assets.
Methods employed to adjust the Company's capital structure could include any,
all or a combination of the following activities:
i. Issue new shares through a public offering or private placement;
ii. Issue equity linked or convertible debt;
iii.Raise fixed or floating rate debt;
iv. Sell or farmout existing exploration, development and producing assets.
23) Related party transactions
The financial statements include the financial statements of Antrim and the
subsidiaries listed in the following table:
Equity interest in %
Country of
Subsidiary Incorporation 2012 2011
----------------------------------------------------------------------------
Antrim Argentina S.A. Argentina - 100
Antrim Energy Ltd. Bahamas 100 100
Antrim Exploration (Ireland) Limited Ireland 100 100
Antrim Resources (N.I.) Limited United Kingdom 100 100
Netherfield Corporation(1) British Virgin - 100
Islands
(1) - This entity was amalgamated with Antrim Energy Inc. as part of the
plan of arrangement discussed in Note 4.
Compensation of key management personnel of the Company
Key management personnel include directors and executives of the Company. The
compensation paid or payable to key management personnel is as follows:
2012 2011
--------------------
Short-term employee benefits 2,190 1,643
Share-based compensation 792 753
--------------------
Total compensation paid to key management personnel 2,982 2,396
--------------------
--------------------
Other related party transactions
The Company may from time to time enter into arrangements with related parties
which are accounted for at the exchange amount. In 2012, the Company incurred
fees of $422 (2011 - $267) payable to Burstall Winger LLP, a law firm in which a
director of the Company is a partner.
24) Subsequent events
In January 2013, the Company elected not to participate in further development
work on the Fionn Field. Subject to all necessary approvals from DECC, Antrim
intends to withdraw from the Fionn Field subarea and will not incur any further
liabilities, including remaining decommissioning or well abandonment
liabilities. As a result of its withdrawal, the Company recorded a $50,358
impairment charge as at December 31, 2012.
On January 23, 2013, Antrim announced that it entered into a $30 million Payment
Swap transaction with a major financial institution. Under the terms of the
Payment Swap, the Company received $30 million which is repayable in 29
instalments commencing September 2013 and concluding January 2016. The interest
rate under the Payment Swap is fixed at 5.1%. Antrim also entered into a Brent
Oil Price Commodity Swap to forward sell 657,350 barrels of Brent crude oil at a
fixed price of $89.37 covering the period from February 2013 to December 2015.
On March 26, 2013 the Company discontinued development of the Fyne Field. Until
very recently, estimated costs indicated that the planned Fyne development
satisfied the Company's economic threshold and contingent on timing of the
redeployment of the FPSO from its current location was on track for a late 2014
start-up. However, projected capital costs have recently increased
substantially, and in the Company's view now make the project uneconomic.
DIRECTORS
Stephen Greer
President and Chief Executive Officer,
Antrim Energy Inc.
Colin Maclean (2) (3) (4) (5)
Independent Director
Dr. Gerry Orbell (1) (3) (4) (5)
Chairman,
Antrim Energy Inc.
Erik Mielke
Independent Director
Jim Perry (1) (3) (4) (5)
President and CEO,
Alternative Fuel Systems (2004) Inc.
Jim Smith (1) (2) (5)
Independent Director
Jay Zammit (2) (5)
Partner,
Burstall Winger LLP
1. Member of the Audit Committee
2. Member of the Compensation Committee
3. Member of the Reserves Committee
4. Member of the Exploration Committee
5. Member of the Corporate Governance Committee
OFFICERS
Stephen Greer
President and Chief Executive Officer
Anthony Potter
Chief Financial Officer
Kerry Fulton
Vice President, Operations
Terry Lederhouse
Vice President, Commercial
Martin Dashwood
Vice President, Exploration
Adrian Harvey
Corporate Secretary
STOCK EXCHANGE LISTINGS
Toronto Stock Exchange: Trading Symbol "AEN"
London Stock Exchange (AIM): Trading Symbol "AEY"
HEAD OFFICE
610, 301 8th Avenue SW
Calgary, Alberta
Canada T2P 1C5
Main: +1 403 264 5111
Fax: + 1 403 264 5113
info@antrimenergy.com
http://www.antrimenergy.com/
The Company's website is not incorporated by reference in and does not form
a part of this annual report.
LONDON OFFICE
Ashbourne House, The Guildway
Old Portsmouth Road, Artington
Guildford, Surrey
United Kingdom GU3 1LR
Main: +44 (0) 1483-307 530
Fax: +44 (0) 1483-307 531
INTERNATIONAL SUBSIDIARIES
Antrim Energy Ltd.
Antrim Exploration (Ireland) Limited
Antrim Resources (N.I.) Limited
LEGAL COUNSEL
Burstall Winger LLP
Calgary, Alberta
BANKERS
Toronto-Dominion Bank of Canada
AUDITORS
PricewaterhouseCoopers LLP
Calgary, Alberta
INDEPENDENT ENGINEERS
McDaniel & Associates Consultants Ltd.
REGISTRAR AND TRANSFER AGENT
Inquiries regarding change of address, registered shareholdings, stock
transfers or lost certificates should be direct to:
CIBC Mellon Trust Company
Calgary, Alberta
FOR FURTHER INFORMATION PLEASE CONTACT:
Antrim Energy Inc.
Stephen Greer
President & CEO
403-264-5111
403-264-5113 (FAX)
greer@antrimenergy.com
Antrim Energy Inc.
Anthony Potter
Chief Financial Officer
403-264-5111
403-264-5113 (FAX)
potter@antrimenergy.com
www.antrimenergy.com
Nominated Advisor
Royal Bank of Canada Europe Limited
Martin Eales
+44 20 7029 7881
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