Bellatrix Exploration Ltd. Announces Year End 2012 Financial Results
Bellatrix Exploration Ltd. Announces Year End 2012 Financial Results
PR Newswire
CALGARY, March 7, 2013
TSX, NYSE MKT: BXE
CALGARY, March 7, 2013 /PRNewswire/ - Bellatrix Exploration Ltd. ("Bellatrix"
or the "Company") (TSX, NYSE MKT: BXE) announces its financial and operating
results for the year ended December 31, 2012.
Forward-Looking Statements
This press release, including the report to shareholders, contains
forward-looking statements. Please refer to our cautionary language on
forward-looking statements and the other matters set forth at the beginning of
the management's discussion and analysis (the "MD&A") attached to this press
release.
HIGHLIGHTS
Years ended December 31,
2012 2011
FINANCIAL (unaudited)
(CDN$000s except share and per share amounts)
Revenue (before royalties and risk management ^(1)) 219,314 202,318
Funds flow from operations ^(2) 111,038 94,237
Per basic share ^(6) $1.03 $0.91
Per diluted share ^(6) $0.96 $0.84
Cash flow from operating activities 109,328 98,192
Per basic share ^(6) $1.02 $0.95
Per diluted share ^(6) $0.95 $0.87
Net profit before certain non-cash items ^(5) 21,746 17,105
Per basic share ^(6) $0.20 $0.16
Per diluted share ^(6) $0.20 $0.16
Net profit (loss) 27,771 (5,949)
Per basic share ^(6) $0.26 ($0.06)
Per diluted share ^(6) $0.25 ($0.06)
Exploration and development 164,187 175,495
Corporate and property acquisitions 21,160 4,066
Capital expenditures - cash 185,348 179,561
Property dispositions - cash (6,660) (4,203)
Non-cash items 25,875 10,575
Total capital expenditures - net 204,563 185,933
Long-term debt 133,047 56,701
Convertible debentures ^(7) 50,687 49,076
Adjusted working capital deficiency ^ (3) 5,843 13,473
Total net debt ^(3) 189,577 119,250
Total assets 681,421 580,422
Shareholders' equity 381,106 348,405
OPERATING Years ended December 31,
2012 2011
Average daily sales volumes
Crude oil, condensate and NGLs (bbls/d) 5,717 4,540
Natural gas (mcf/d) 65,812 44,484
Total oil equivalent (boe/d) 16,686 11,954
Average prices
Light crude oil and condensate ($/bbl) 86.47 92.51
NGLs (excluding condensate) ($/bbl) 38.88 53.54
Heavy oil ($/bbl) 68.51 68.23
Crude oil, condensate and NGLs ($/bbl) 73.59 83.89
Crude oil, condensate and NGLs
(including risk
management ^(1)) ($/bbl) 72.65 81.47
Natural gas ($/mcf) 2.62 3.77
Natural gas (including risk
management ^ (1)) ($/mcf) 3.17 4.05
Total oil equivalent ($/boe) 35.56 45.88
Total oil equivalent (including
risk management ^ (1)) ($/boe) 37.40 46.01
Statistics
Operating netback ^(4) ($/boe) 19.66 25.09
Operating netback ^(4) (including
risk management ^ (1)) ($/boe) 21.51 25.22
Transportation ($/boe) 0.82 1.31
Production expenses ($/boe) 8.73 11.53
General & administrative ($/boe) 2.34 2.83
Royalties as a % of sales after
Transportation 18% 18%
COMMON SHARES
Common shares outstanding 107,868,774 107,407,241
Share options outstanding 9,420,451 7,985,320
Shares issuable on conversion of
convertible debentures ^(7) 9,821,429 9,821,429
Diluted common shares outstanding 127,110,654 125,213,990
Diluted weighted average shares - net
profit (loss) ^(6) 109,125,094 103,857,689
Diluted weighted average shares - funds
flow from
operations and cash flow from operating
activities ^(2) (6) 118,946,523 116,046,595
SHARE TRADING STATISTICS
TSX and Other ^(8) (CDN$, except
volumes) based on intra-day trading
High 5.67 6.19
Low 2.45 3.15
Close 4.27 4.91
Average daily volume 1,127,281 1,152,846
NYSE MKT ^(9) (US$, except volumes)
based on intra-day trading
High 4.54 -
Low 3.69 -
Close 4.28 -
Average daily volume 37,924 -
^(1) The Company has entered into various commodity price risk management
contracts which are considered to be economic hedges. Per unit metrics
after risk management include only the realized portion of gains or
losses on commodity contracts.
The Company does not apply hedge accounting to these contracts. As such,
these contracts are revalued to fair value at the end of each reporting
date. This results in recognition of unrealized gains or losses over the
term of these contracts which is reflected each reporting period until
these contracts are settled, at which time realized gains or losses are
recorded. These unrealized gains or losses on commodity contracts are
not included for purposes of per unit metrics calculations disclosed.
^(2) The highlights section contains the term "funds flow from operations"
which should not be considered an alternative to, or more meaningful than
cash flow from operating activities as determined in accordance with
generally accepted accounting principles ("GAAP") as an indicator of the
Company's performance. Therefore reference to the additional GAAP
measures of funds flow from operations, or funds flow from operations per
share may not be comparable with the calculation of similar measures for
other entities. Management uses funds flow from operations to analyze
operating performance and leverage and considers funds flow from
operations to be a key measure as it demonstrates the Company's ability
to generate the cash necessary to fund future capital investments and to
repay debt. The reconciliation between cash flow from operating
activities and funds flow from operations can be found in the MD&A.
Funds flow from operations per share is calculated using the weighted
average number of common shares for the period.
^(3) Net debt and total net debt are considered additional GAAP measures. The
Company's calculation of total net debt includes the liability component
of convertible debentures and excludes deferred liabilities, long-term
commodity contract liabilities, decommissioning liabilities, long-term
finance lease obligations and the deferred tax liability. Net debt and
total net debt include the net working capital deficiency (excess) before
short-term commodity contract assets and liabilities and current finance
lease obligations. Net debt also excludes the liability component of
convertible debentures. A reconciliation between total liabilities under
GAAP and total net debt and net debt as calculated by the Company is
found in the MD&A.
^(4) Operating netbacks is considered a non-GAAP term. Operating netbacks are
calculated by subtracting royalties, transportation, and operating costs
from revenues before other income.
^(5) Net profit before certain non-cash items is considered a non-GAAP term.
Net profit before certain non-cash items is calculated as net profit
(loss) per the Consolidated Statement of Comprehensive Income, excluding
the non-cash impairment loss, unrealized gain or loss on commodity
contracts, gain property acquisition, and gain or loss on property
dispositions, net of the deferred tax impact on these adjustments. The
Company's reconciliation between net profit (loss) and net profit before
certain non-cash items is found in the MD&A.
^(6) Basic weighted average shares for the year ended December 31, 2012 were
107,543,811 (2011: 103,857,689).
In computing weighted average diluted earnings and weighted average
diluted net profit before certain non-cash items per share for the year
ended December 31, 2012, a total of 1,581,283 (2011: 2,367,477) common
shares, were added to the denominator as a consequence of applying the
treasury stock method to the Company's outstanding share options as they
were dilutive, and a total of 9,821,429 (2011: 9,821,429) common shares
issuable on conversion of convertible debentures were excluded from the
denominator as they were not dilutive, resulting in diluted weighted
average shares of 109,125,094 (2011: 106,225.166).
In computing weighted average diluted cash flow from operating activities
and funds flow from operations per share for the year ended December 31,
2012, a total of 1,581,283 (2011: 2,367,477) common shares were added to
the denominator as a consequence of applying the treasury stock method to
the Company's outstanding share options and a total of 9,821,429 (2011:
9,821,429) common shares issuable on conversion of convertible debentures
were also added to the denominator as they were dilutive, resulting in
diluted weighted average common shares of 118,946,523 (2011:
116,046,595). As a consequence, a total of $3.2 million (2011: $3.0
million) for interest accretion expense (net of income tax effect) were
added to the numerator.
^(7) Shares issuable on conversion of convertible debentures are calculated by
dividing the $55.0 million principal amount of the convertible debentures
by the conversion price of $5.60 per share.
^(8) TSX and Other includes the trading statistics for the Toronto Stock
Exchange and other Canadian trading markets.
^(9) The Company's common shares commenced trading on the NYSE MKT on
September 24, 2012.
REPORT TO SHAREHOLDERS
Bellatrix's corporate strategy encompasses effective execution of a defined
exploitation oriented growth plan in the Western Canadian Sedimentary Basin
complemented with opportunistic tuck in acquisitions. In 2012 the Company
excelled as a "drill bit driven growth" story defined by;
* An experienced innovative management team with a long history and proven
track record
* A highly technical/creative staff
* Being a low cost producer/operator/finder
* Preserving a strong balance sheet with hedging and debt maintenance
* Possessing and expanding a top tier asset base
* Exceptional industry leading well results on the core Cardium and
Notikewin resource plays
* Large inventory of high IRR opportunities (692 net locations in the
Cardium and 401 net locations in the Notikewin/Falher totaling net capital
development opportunity of $4.34 billion)
* Near term catalysts with forecast 2013 exit rate of 30,000 to 31,000
boe/d.
Despite average oil & gas prices softening in 2012 when compared to 2011 by
10.8% and 30.5%, respectively, Bellatrix posted its fourth consecutive year of
industry leading drill bit growth. Since converting to an exploration company
in November of 2009 the Company has grown production by 155%, liquids
production by 235%, reserves per share by 191% and cash flow per share by
164%. Fiscal year 2012 proved to be an exceptional year punctuated by the
following;
* Record production levels of 6.1 million boe
* Achieving Company average annual guidance of 16,686 boe/d and exit
production guidance of 19,500 boe/d
* Reducing lease operating expenses to $8.73/boe
* Establishing industry leading 2P FD&A including FDC of $6.95/boe
* Posting a 2P excluding FDC Recycle Ratio of 5.02 times
* Increased 2P reserves by 54% to 104 million barrels with a 10% NPV of
$1.07 billion and a net asset value of $9.90 per basic share.
* At December 31, 2012, the Company had approximately $87 million or 40% was
undrawn under the existing $220 million credit facility.
Currently the Company is focusing on developing its two core resource plays,
the Cardium and the Notikewin/Falher intervals in Western Canada. The
Notikewin/Falher in Alberta's deep basin boasts abundant, liquids-rich natural
gas with compelling economics. The Cardium is a highly economic investment
that we believe has the potential to add substantial reserves, production and
long term economic value for our shareholders. Both plays have thick resource
rich reservoirs with exceptional subsurface control which have proven to be
predictable and repeatable with the application of modern drilling and
completion techniques. To date the Company has drilled 111 Cardium wells and
24 Notikewin/Falher wells posting a 100% success rate.
To accelerate the development of the aforementioned 24 year drilling inventory
on the Company's key plays while maintaining a strong balance sheet and
minimizing the issuing of equity Bellatrix entered into a joint venture
agreement with a Seoul Korea based company ("JV Partner"), to accelerate
development of Bellatrix's extensive undeveloped Cardium land holdings in
west-central Alberta. Under the terms of the agreement, the JV Partner will
contribute 50%, or CDN$150 million, to a $300 million joint venture (the
"Joint Venture") to participate in an expected 83 Cardium well program. Under
the agreement, the JV Partner will earn 33% of Bellatrix's working interest in
the Cardium well program until payout (being recovery of the JV Partner's
capital investment plus an 8% return on investment) on the total program,
which is expected to occur prior to a maximum of 7 years, reverting to a 20%
working interest after payout. The effective date of the agreement is April
1, 2013 but with the ability of the JV Partner to elect to invest in the wells
drilled between January 1 and up to April 30, 2013. Certain conditions
precedent are expected to be satisfied or waived by April 22, 2013 which is
expected to enable closing to occur on or before April 30, 2013. Bellatrix
will be required to provide a guarantee of the return of the JV Partner's
capital investment of up to $30 million if not recovered within 7 years.
Operational highlights for the three months and year ended December 31, 2012
include:
* During the 2012 year, Bellatrix posted a 100% success rate drilling and/or
participating in 34 gross (26.32 net) wells, resulting in 28 gross (21.32
net) Cardium oil wells, 2 gross (2.0 net) Cardium condensate-rich gas
wells, 1 gross (1.0 net) Duvernay gas well, and 3 gross (2.0 net)
Notikewin/Falher liquids-rich gas wells. In the fourth quarter of 2012,
Bellatrix drilled or participated in 10 gross wells (6.17 net), all of
which were Cardium light oil horizontal wells.
* During fiscal 2012 the Company operated 24 gross Cardium wells of the 28
gross wells reported. The following average initial production ("IP")
rates for the first 7 days ("IP7"), for the first 15 days ("IP15") and the
first 30 days ("IP30") were achieved:
Time # of wells Boe/d
IP 7 24 769
IP 15 24 715
IP 30 24 656
* Q4 2012 sales volumes averaged 18,763 boe/d (weighted 31% to oil,
condensate and NGLs and 69% to natural gas). This represents a 32%
increase from the fourth quarter 2011 average sales volumes of 14,209
boe/d and a 21% increase from third quarter 2012 average sales volumes of
15,503 boe/d.
* 2012 annual sales volumes averaged 16,686 boe/d (weighted 34% to oil,
condensate and NGLs and 66% to natural gas). This represents a 40%
increase from 2011 average sales volumes of 11,954 boe/d.
* In the fourth quarter of 2012 the Company spent $53.0 million on capital
projects, including $21.0 on a tuck in acquisition in the Willesden Green
area, compared to $47.3 million during the fourth quarter of 2011.
* On December 14, 2012, Bellatrix acquired an additional 11 gross and net
sections of highly prospective Cardium and Notikewin/Falher lands in the
Ferrier area of west-central Alberta. This acquisition is anticipated to
provide an additional 37 net drilling locations in the Cardium, 9 net
locations in the Notikewin/Falher and an additional 66 net locations in
the Duvernay formation.
* As at December 31, 2012, Bellatrix had approximately 206,638 net
undeveloped acres of land in Alberta, British Columbia and Saskatchewan.
* Effective November 1, 2012, Bellatrix acquired additional highly
prospective Cardium and Notikewin/Falher lands and production in the
Willesden Green area of Alberta with 500 boe/d of production, 16 gross
(11.95 net) sections of Cardium and Mannville prospective lands, 25 net
Cardium development locations, 4 net Notikewin/Falher development
locations and a 25% working interest in an operated compressor station and
gathering system. The purchase price of $21 million was funded using the
Company's existing credit facility.
* During Q3 2012, Bellatrix closed on the disposition of a minor non-core
property interest in the Wainwright Alberta area for $4.3 million after
adjustments.
* During Q2 2012, Bellatrix closed on the disposition of the Girouxville
property in Alberta, a minor non-core interest, for $0.6 million after
adjustments.
* During Q2 2012, Bellatrix closed on the disposition of a non-core property
interest in Cypress-Chowade in British Columbia for $1.4 million after
adjustments.
* Bellatrix continued with its 2 year crusade toward inviolable sovereignty
of the infrastructure in its core areas of Brazeau and Ferrier. In 2012
and 2013 the Company is connecting to over half a BCF of daily capacity in
third party operated gas plants in close proximity. In 2012 and Q1 2013
the Company has installed a total of 7.5 km of 6" pipeline, 64 km of 8"
pipeline, 47.4 km of 10" pipeline and 25 km of 12" pipeline providing
unfettered access to the aforementioned facilities. In addition Bellatrix
commissioned a 3,300 HP compressor station in Ferrier and is currently
constructing an additional 3,300 HP compressor station in the Ferrier
area.
Financial highlights for the three months and year ended December 31, 2012
include:
* Q4 2012 revenue was $62.3 million, 5% higher than the $59.2 million
recorded in Q4 2011. Revenue for the year ended December 31, 2012 was
$219.3 million, up 8% from $202.3 million in 2011. The increase in
revenues is a result of higher sales volumes between periods, offset
partially by reduced liquids and natural gas prices experienced in the
2012 periods.
* Funds flow from operations for Q4 2012 was $29.9 million ($0.28 per basic
share), up 12% from $26.6 million ($0.25 per basic share) in Q3 2012 and
down 1% from $30.1 million ($0.28 per basic share) in Q4 2012. Funds flow
from operations for the year ended December 31, 2012 was $111.0 million
($1.03 per basic share), up 18% from $94.2 million ($0.91 per basic share)
in 2011.
* For the three and twelve months ended December 31, 2012, net profit before
non-cash impairment loss, unrealized gain (loss) on commodity contracts,
gain on property acquisition, and gain (loss) on property dispositions,
net of associated deferred tax impacts, was $7.3 million and $21.7
million, compared to $7.9 million and $17.1 million in 2011 periods,
respectively.
* The net profit for Q4 2012 was $9.3 million, compared to a net loss of
$13.6 million in Q4 2011.
* The net profit for the year ended December 31, 2012 was $27.8 million,
compared to a net loss of $5.9 million in 2011.
* Crude oil, condensate and NGLs produced 60% and 71% of petroleum and
natural gas sales revenue for the three and twelve month periods ended
December 31, 2012, respectively.
* Production expenses for Q4 2012 were $8.91/boe ($15.4 million), compared
to $10.78/boe ($14.1 million) for Q4 2011. Production expenses for the
year ended December 31, 2012 were $8.73/boe ($53.3 million) compared to
$11.53/boe ($50.3 million) in 2011. The decrease was due to increased
production volumes which is a result of 2011 and 2012 drilling in areas
with lower production expenses, as well as reduced processing fees in
certain areas and continued field optimization projects.
* Operating netbacks after including risk management for Q4 2012 were
$20.83/boe, down from $26.38/boe in Q4 2011. Operating netbacks before
risk management for Q4 2012 were $19.20/boe, down from $26.00/boe in Q4
2011 and up from $18.29/boe in Q3 2012. The decreased netback for Q4 2012
compared to Q4 2011 was primarily the result of reduced commodity prices
and slightly higher royalties, despite a reduction in transportation and
production expenses. The Q4 2012 netback reflects slightly increased
overall commodity prices, despite slightly increased expenses compared to
Q3 2012.
* Operating netbacks before risk management for the year ended December 31,
2012 were $19.66/boe, down from $25.09/boe in 2011.
* Bellatrix spent $53.0 million on capital projects during Q4 2012 compared
to $47.3 million in Q4 2011. For the year ended December 31, 2012,
Bellatrix spent $185.3 million on capital projects compared to $179.6
million in 2011.
* Proceeds from property dispositions were $6.7 million for the year ended
December 31, 2012, compared to $4.2 million for 2011.
* G&A expenses for Q4 2012 decreased to $2.54/boe ($4.4 million), compared
to $2.88/boe ($3.8 million) for Q4 2011. G&A expenses for the year ended
December 31, 2012 were $2.34/boe ($14.3 million), compared to $2.83/boe
($12.4 million) in 2011.
* On September 20, 2012, Bellatrix received approval for listing of its
common shares on the NYSE MKT, and its common shares commenced trading on
September 24, 2012 under the symbol "BXE".
* A syndicate of banks led by National Bank of Canada recently completed its
semi-annual borrowing base determination for November 30, 2012. Effective
December 13, 2012, the Company's borrowing base was increased by $20
million to $220 million, through to the next redetermination date of May
31, 2013.
* As at December 31, 2012, Bellatrix had $87.0 million drawn on its total
$220 million credit facility.
* Total net debt as of December 31, 2012 was $189.6 million, including the
liability component of convertible debentures.
* As at December 31, 2012, Bellatrix has approximately $584 million in tax
pools available for deduction against future income.
RESERVES
Highlights from Bellatrix's December 31, 2012 reserves include:
Total proved plus probable company interest reserves, including all royalties
receivable but before deducting royalty burdens, as evaluated by Sproule
Associates Limited. ("Sproule") at December 31, 2012 were 104,258 mboe (gas
converted 6:1). This represents a 54% increase from the 67,550 mboe of 2P
reserves as at December 31, 2011. By commodity type, natural gas makes up
67%, oil and natural gas liquids 33% of total reserves. At December 31, 2012,
the Company's total proved company interest reserves were 55,490 mboe, an
increase of 33% compared to 41,818 mboe at December 31, 2011.
* Including properties which were disposed in 2012, proved and probable
company interest reserve additions in 2012 replaced 702% of total
production.
* The net present value of future net revenue of working interest reserves
(which does not represent fair market value) at a 10% discount rate
improved to $1,106.9 million up from $722.5 million posted in 2011
representing an increase of 53%.
* Bellatrix's net asset value, as at December 31, 2012, based on the Sproule
evaluation at a 10% discount rate, internal estimates of the value of
undeveloped lands and seismic, and 107.9 million common shares
outstanding, equates to $9.90 per basic share outstanding and is $13.77
per basic share outstanding at a 5% discount rate.
* The Company's reserve life index has improved to 8.6 years for total
company interest proved reserves up from 8.0 years in 2011 with total
company interest proved and probable reserve life index of 12.4 years
compared to 10.0 years presented in 2011. These 2012 indices were based
on first year production as set forth in Sproule Report with 2012 company
interest production of 17,655 boe/d and 22,888 boe/d for total company
interest proved reserves and proved and probable reserves, respectively.
* 2012 finding, development and acquisition costs ("FD&A") including changes
to future development capital ("FDC") for total proved plus probable
reserves were $6.95/boe. The three year average FD&A including FDC is
$9.04/boe.
* 2012 FD&A including changes to FDC for proved reserves equated to
$11.77/boe.
* At year end, 2012, Sproule had evaluated certain future development
opportunities on Company lands including 161 gross (112.7 net) future
undrilled Cardium horizontal locations and 56 gross (23.3 net) evaluated
future undrilled Notikewin/Falher horizontal locations. Of the 161
Cardium locations, 104 were assigned proved and probable reserves, with 57
assigned probable reserves only. Of the 56 Notikewin/Falher locations, 41
were assigned proved and probable reserves, with the remaining 15 assigned
probable reserves only.
* The Company established recycle ratios, after commodity price risk
management contracts and excluding future development costs of 2.35 times
on a proved basis and 5.02 times on a proved and probable basis.
The Company recorded all-in annual FD&A cost of $9.16 per boe in 2012 before
consideration of FDC for proved reserves category. The three year average
FD&A cost is $8.69 per boe for the proved category before FDC; for the proved
category including FDC, the three year average FD&A cost is $13.22 per boe.
In addition to the information disclosed herein, more detailed information on
the Company's reserves will be included in the Company's Annual Information
Form and SEC Annual Report on Form 40-F. For additional information please
refer to the reserves news release dated February 21, 2013 (posted on
www.sedar.com and filed with the SEC at www.sec.gov).
COMMODITY PRICE RISK MANAGEMENT
In January 2013, Bellatrix reset the fixed prices on two of its commodity
price risk management contracts for natural gas fixed price swaps. The first
existing swap contract for 20,000 GJ/d for the period April 1, 2013 to October
31, 2013 was reset from a price of CDN$4.0875/GJ to $3.05/GJ (CDN$3.51/mcf)
for a net payment to Bellatrix of $4.3 million. The second existing swap
contract for 10,000 GJ/d for the period April 1, 2013 to October 31, 2013 was
reset from a price of CDN $4.15/GJ to CDN$3.095/GJ (CDN$3.56/mcf) for a net
payment to Bellatrix of $2.2 million. Bellatrix now has 55,000 GJ/d (47.8
mmcf/d) for the period April 1, 2013 through to October 31, 2013 hedged at an
average fixed price of $3.058/GJ ($3.52/mcf). By resetting the fixed prices
on the natural gas commodity price risk management contracts for the period
from April 1, 2013 through to October 31, 2013, the Company has crystalized
and realized $6.5 million in cash proceeds while continuing to have put in
place ongoing down side price protection on the existing 55,000 GJ/d (47.8
mmcf/d) if natural gas prices were to move lower than the fixed price of
$3.058/GJ ($3.52/mcf).
As of March 6, 2013, the Company has entered into the following commodity
price risk management arrangements:
Type Period Volume Price Price Index
Floor Ceiling
Crude oil January 1, 1,500 $ $ WTI
fixed ^(1) 2013 to Dec. bbl/d 94.50 CDN 94.50 CDN
31, 2013
Crude oil January 1, 3,000 - $ 110.00 WTI
call option 2013 to Dec. bbl/d US
31, 2013
Crude oil January 1, 3,000 - $ 105.00 US WTI
call option 2014 to Dec. bbl/d
31, 2014
Natural gas April 1, 2013 20,000 $ $ AECO
fixed to Oct. 31, GJ/d 3.05 CDN 3.05 CDN
2013
Natural gas April 1, 2013 10,000 $ $ AECO
fixed to Oct. 31, GJ/d 3.095 CDN 3.095 CDN
2013
Natural gas Feb. 1, 2013 10,000 $ $ AECO
fixed to Dec. 31, GJ/d 3.05 CDN 3.05 CDN
2013
Natural gas April 1, 2013 15,000 $ $ AECO
fixed to June 30, GJ/d 3.05 CDN 3.05 CDN
2014
^(1) A call has been placed on 3,000 bbl/d at $110 US/bbl for the year 2013
and at $105 US/bbl for the calendar year 2014.
OUTLOOK
As a result of the recently announced joint venture with a Seoul Korea based
company, Bellatrix's 2013 capital expenditure budget has been increased to
between $230 and $240 million. A total capital program of $365 million is
anticipated including the capital expected to be invested by the JV partner.
Based on the timing of proposed expenditures, downtime for scheduled and
unscheduled plant turnarounds, completion of required infrastructure, and
normal production declines, execution of the 2013 capital expenditure plan is
expected to provide average daily production of approximately 24,000 boe/d to
25,000 boe/d, and an exit rate of approximately 30,000 boe/d to 31,000 boe/d.
The Company has initiated the 2013 program by instituting drilling of multiple
horizontal wells from single surface locations. Pad drilling enhances the
opportunity to efficiently develop the resource while minimizing the
environmental footprint and improving our cost and on-stream efficiencies.
Pad drilling also facilitates drilling through the spring breakup months of
Q2. As a result the Company plans to run 3 rigs throughout the second quarter
ramping up to 7 or 8 rigs for the second half of 2013.
The key operational strategy Bellatrix employs is to focus on full cycle
profitability, indifferent to product type, with every investment decision.
As always the Company's priority is to bring together the technical,
operational and financial talent required to create long term value growth for
our shareholders.
Raymond G. Smith, P. Eng.
President and CEO
March 6, 2013
Note:
A conference call to discuss Bellatrix's annual financial and reserves results
will be held on March 7, 2013 at [11:00 am MDT/1:00 pm EDT]. To participate,
please call toll-free 1-888-231-8191 or 647-427-7450. The conference call will
also be recorded and available by calling 1-855-859-2056 or 403-451-9481 and
entering passcode 16291676 followed by the pound sign.
Bellatrix's annual meeting is scheduled for 3:00 pm on May 22, 2013 in the
Devonian Room at the Calgary Petroleum Club.
MANAGEMENT'S DISCUSSION AND ANALYSIS
March 6, 2013 - The following Management's Discussion and Analysis of
financial results ("MD&A") as provided by the management of Bellatrix
Exploration Ltd. ("Bellatrix" or the "Company") should be read in conjunction
with the audited consolidated financial statements of the Company for the
years ended December 31, 2012 and 2011. This commentary is based on
information available to, and is dated as of, March 6, 2013. The financial
data presented is in Canadian dollars, except where indicated otherwise.
CONVERSION: The term barrels of oil equivalent ("boe") may be misleading,
particularly if used in isolation. A boe conversion ratio of six thousand
cubic feet of natural gas to one barrel of oil equivalent (6 mcf/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. Given that the
value ratio based on the current price of crude oil as compared to natural gas
is significantly different from the energy equivalency of 6:1, utilizing a
conversion on a 6:1 basis may be misleading as an indication of value. All boe
conversions in this report are derived from converting gas to oil in the ratio
of six thousand cubic feet of gas to one barrel of oil.
INITIAL PRODUCTION RATES: Initial production rates disclosed herein may not
necessarily be indicative of long-term performance or ultimate recovery.
ADDITIONAL GAAP MEASURES: This Management's Discussion and Analysis and the
accompanying report to shareholders and financial statements contain the term
"funds flow from operations" which should not be considered an alternative to,
or more meaningful than "cash flow from operating activities" as determined in
accordance with generally accepted accounting principles ("GAAP") as an
indicator of the Company's performance. Therefore reference to funds flow from
operations or funds flow from operations per share may not be comparable with
the calculation of similar measures for other entities. Management uses funds
flow from operations to analyze operating performance and leverage and
considers funds flow from operations to be a key measure as it demonstrates
the Company's ability to generate the cash necessary to fund future capital
investments and to repay debt. The reconciliation between cash flow from
operating activities and funds flow from operations can be found in this
Management's Discussion and Analysis. Funds flow from operations per share is
calculated using the weighted average number of shares for the period.
This Management's Discussion and Analysis and the accompanying report to
shareholders and financial statements contain the term total net debt and net
debt. Total net debt is calculated as long-term debt plus the liability
component of the convertible debentures and the net working capital deficiency
(excess) before short-term commodity contract assets and liabilities and
current finance lease obligations. Management believes these measures are
useful supplementary measures of the total amount of current and long-term
debt.
NON-GAAP MEASURES: This Management's Discussion and Analysis and the
accompanying report to shareholders also contains other terms such as net
profit before certain non-cash items and operating netbacks, which are not
recognized measures under GAAP. Net profit before certain non-cash items is
calculated as net profit (loss) per the Consolidated Statement of
Comprehensive Income, excluding the non-cash impairment loss, net unrealized
gain or loss on commodity contracts, gain on property acquisition, and gain or
loss on property dispositions net of the deferred tax impact on these
adjustments. Net debt is calculated as long-term debt plus the net working
capital deficiency (excess) before short-term commodity contract assets and
liabilities and current finance lease obligations. Operating netbacks are
calculated by subtracting royalties, transportation, and operating expenses
from revenues before other income. Management believes these measures are
useful supplemental measures of firstly, the amount of net profit before
certain non-cash items, and secondly, the amount of revenues received after
transportation, royalties and operating expenses. Readers are cautioned,
however, that these measures should not be construed as an alternative to net
income determined in accordance with GAAP as measures of performance.
Bellatrix's method of calculating these measures may differ from other
entities, and accordingly, may not be comparable to measures used by other
companies.
Additional information relating to the Company, including the Bellatrix's
Annual Information Form, is available on SEDAR at www.sedar.com.
FORWARD LOOKING STATEMENTS: Certain information contained herein and in the
accompanying report to shareholders may contain forward looking statements
including management's assessment of future plans and operations, drilling
plans and the timing thereof, commodity price risk management strategies, 2013
capital expenditure budget, the nature of expenditures and the method of
financing thereof, expected 2013 average production and exit rate, anticipated
liquidity of the Company and various matters that may impact such liquidity,
expected 2013 operating expenses and general and administrative expenses,
expected costs to satisfy drilling commitments and method of funding drilling
commitments, commodity prices and expected volatility thereof, estimated
amount and timing of incurring decommissioning liabilities, plans to utilize
pad drilling and effect thereof, use of funds from property dispositions,
timing of closing of joint venture agreement, the effect of certain
acquisitions, and plans for facility construction may constitute
forward-looking statements under applicable securities laws and necessarily
involve risks including, without limitation, risks associated with oil and gas
exploration, development, exploitation, production, marketing and
transportation, loss of markets, volatility of commodity prices, currency
fluctuations, risks related to satisfaction of conditions precedent to closing
of joint venture agreement, imprecision of reserve estimates, environmental
risks, competition from other producers, inability to retain drilling rigs and
other services, incorrect assessment of the value of acquisitions, failure to
realize the anticipated benefits of acquisitions, delays resulting from or
inability to obtain required regulatory approvals and ability to access
sufficient capital from internal and external sources. Events or
circumstances may cause actual results to differ materially from those
predicted, as a result of the risk factors set out and other known and unknown
risks, uncertainties, and other factors, many of which are beyond the control
of Bellatrix. In addition, forward-looking statements or information are based
on a number of factors and assumptions which have been used to develop such
statements and information but which may prove to be incorrect and which have
been used to develop such statements and information in order to provide
shareholders with a more complete perspective on Bellatrix's future
operations. Such information may prove to be incorrect and readers are
cautioned that the information may not be appropriate for other purposes.
Although the Company believes that the expectations reflected in such
forward-looking statements or information are reasonable, undue reliance
should not be placed on forward-looking statements because the Company can
give no assurance that such expectations will prove to be correct. In
addition to other factors and assumptions which may be identified herein,
assumptions have been made regarding, among other things: the impact of
increasing competition; the general stability of the economic and political
environment in which the Company operates; the timely receipt of any required
regulatory approvals; the ability of the Company to obtain qualified staff,
equipment and services in a timely and cost efficient manner; drilling
results; the ability of the operator of the projects which the Company has an
interest in to operate the field in a safe, efficient and effective manner;
the ability of the Company to obtain financing on acceptable terms; field
production rates and decline rates; the ability to replace and expand oil and
natural gas reserves through acquisition, development of exploration; the
timing and costs of pipeline, storage and facility construction and expansion
and the ability of the Company to secure adequate product transportation;
future commodity prices; currency, exchange and interest rates; the regulatory
framework regarding royalties, taxes and environmental matters in the
jurisdictions in which the Company operates; and the ability of the Company to
successfully market its oil and natural gas products. Readers are cautioned
that the foregoing list is not exhaustive of all factors and assumptions which
have been used. As a consequence, actual results may differ materially from
those anticipated in the forward-looking statements. Additional information
on these and other factors that could effect Bellatrix's operations and
financial results are included in reports on file with Canadian and US
securities regulatory authorities and may be accessed through the SEDAR
website (www.sedar.com, and at Bellatrix's website
www.bellatrixexploration.com). Furthermore, the forward-looking statements
contained herein are made as at the date hereof and Bellatrix does not
undertake any obligation to update publicly or to revise any of the included
forward-looking statements, whether as a result of new information, future
events or otherwise, except as may be required by applicable securities laws.
The reader is further cautioned that the preparation of financial statements
in accordance with GAAP requires management to make certain judgments and
estimates that affect the reported amounts of assets, liabilities, revenues
and expenses. Estimating reserves is also critical to several accounting
estimates and requires judgments and decisions based upon available
geological, geophysical, engineering and economic data. These estimates may
change, having either a negative or positive effect on net earnings as further
information becomes available, and as the economic environment changes.
Overview and Description of the Business
Bellatrix Exploration Ltd. ("Bellatrix" or the "Company") is a Western
Canadian based growth oriented oil and gas company engaged in the exploration
for, and the acquisition, development and production of oil and natural gas
reserves in the provinces of Alberta, British Columbia and Saskatchewan.
Bellatrix's common shares and convertible debentures are listed on the Toronto
Stock Exchange under the symbols BXE and BXE.DB.A, respectively, and the
common shares of Bellatrix trade on the NYSE MKT under the symbol BXE.
Cardium Joint Venture
Bellatrix has entered into a joint venture agreement with a Seoul Korea based
company ("JV Partner"), to accelerate development of Bellatrix's extensive
undeveloped Cardium land holdings in west-central Alberta. Under the terms of
the agreement, the JV Partner will contribute 50%, or CDN$150 million, to a
$300 million joint venture (the "Joint Venture") to participate in an expected
83 Cardium well program. Under the agreement, the JV Partner will earn 33% of
Bellatrix's working interest in the Cardium well program until payout (being
recovery of the JV Partner's capital investment plus an 8% return on
investment) on the total program, which is expected to occur prior to a
maximum of 7 years, reverting to a 20% working interest after payout. The
effective date of the agreement is April 1, 2013 but with the ability of the
JV Partner to elect to invest in the wells drilled between January 1 and up to
April 30, 2013. Certain conditions precedent are expected to be satisfied or
waived by April 22, 2013 which is expected to enable closing to occur on or
before April 30, 2013. Bellatrix will be required to provide a guarantee of
the return of the JV Partner's capital investment of up to $30 million if not
recovered within 7 years.
Fourth Quarter 2012
HIGHLIGHTS Three months ended December 31,
(CDN$000s except share and
per share amounts) 2012 2011
FINANCIAL
Revenue (before royalties and
risk management ^(1)) 62,283 59,194
Funds flow from operations
^(2) 29,865 30,120
Per basic share ^(6) $0.28 $0.28
Per diluted share ^(6) $0.26 $0.26
Cash flow from operating
activities 32,007 30,626
Per basic share ^(6) $0.30 $0.28
Per diluted share ^(6) $0.28 $0.26
Net profit before certain
non-cash items ^(5) 7,299 7,938
Per basic share ^(6) $0.07 $0.07
Per diluted share ^(6) $0.07 $0.07
Net profit (loss) ^ 9,251 (13,597)
Per basic share ^(6) $0.09 ($0.13)
Per diluted share ^(6) $0.08 ($0.13)
Exploration and development 32,083 47,141
Corporate and property
acquisitions 20,965 121
Capital expenditures - cash 53,048 47,262
Property dispositions - cash 10 (22)
Non-cash items 27,487 6,165
Total capital expenditures -
net 80,545 53,405
Three months ended December
31,
(CDN$000s except share and
per share amounts) 2012 2011
OPERATING
Average daily sales volumes
Crude oil, condensate and (bbls/d)
NGLs 5,730 5,420
Natural gas (mcf/d) 78,195 52,734
Total oil equivalent (boe/d) 18,763 14,209
Average prices
Light crude oil and ($/bbl)
condensate 82.58 95.18
NGLs (excluding ($/bbl)
condensate) 38.84 54.31
Heavy oil ($/bbl) 65.30 74.30
Crude oil, condensate and ($/bbl)
NGLs 69.55 85.09
Crude oil, condensate and ($/bbl)
NGLs (including risk
management ^(1)) 72.11 82.90
Natural gas ($/mcf) 3.46 3.30
Natural gas (including ($/mcf)
risk management ^(1)) 3.67 3.62
Total oil equivalent ($/boe) 35.67 44.69
Total oil equivalent ($/boe)
(including risk
management ^ (1)) 37.30 45.07
Statistics
Operating netback ^(4) ($/boe) 19.20 26.00
Operating netback ^(4) ($/boe)
(including risk
management ^(1)) 20.83 26.38
Transportation ($/boe) 0.70 1.21
Production expenses ($/boe) 8.91 10.78
General & administrative ($/boe) 2.54 2.88
Royalties as a % of sales
after transportation 20% 15%
DILUTED WEIGHTED AVERAGE
SHARES
Diluted weighted average
shares - net profit (loss)
^(6) 118,931,047 109,349,045
Diluted weighted average
shares - funds flow from
operations and cash flow from
operating activities ^(2) (6) 118,931,047 119,170,474
SHARE TRADING STATISTICS
TSX and Other ^(7) (CDN$,
except volumes) based on
intra-day trading
High 4.47 5.05
Low 3.59 3.15
Close 4.27 4.91
Average daily volume 842,840 928,836
NYSE MKT ^(8) (US$, except
volumes) based on intra-day
trading
High 4.54 -
Low 3.69 -
Close 4.28 -
Average daily volume 39,079 -
^(1) The Company has entered into various commodity price risk management
contracts which are considered to be economic hedges. Per unit metrics
after risk management includes only the realized portion of gains or
losses on commodity contracts.
The Company does not apply hedge accounting to these contracts. As
such, these contracts are revalued to fair value at the end of each
reporting date. This results in recognition of unrealized gains or
losses over the term of these contracts which is reflected each
reporting period until these contracts are settled, at which time
realized gains or losses are recorded. These unrealized gains or losses
on commodity contracts are not included for purposes of per share
metrics calculations disclosed.
^(2) The highlights section contains the term "funds flow from operations"
which should not be considered an alternative to, or more meaningful
than cash flow from operating activities as determined in accordance
with generally accepted accounting principles ("GAAP") as an indicator
of the Company's performance. Therefore reference to additional GAAP
terms of diluted funds flow from operations or funds flow from
operations per share may not be comparable with the calculation of
similar measures for other entities. Management uses funds flow from
operations to analyze operating performance and leverage and considers
funds flow from operations to be a key measure as it demonstrates the
Company's ability to generate the cash necessary to fund future capital
investments and to repay debt. The reconciliation between cash flow
from operating activities and funds flow from operations can be found
further in the MD&A. Funds flow from operations per share is calculated
using the weighted average number of common shares for the period.
^(3) Net debt and total net debt are considered additional GAAP terms. The
Company's calculation of total net debt includes the liability component
of convertible debentures and excludes deferred liabilities, long-term
commodity contract liabilities, decommissioning liabilities, long-term
finance lease obligations and the deferred tax liability. Net debt and
total net debt include the net working capital deficiency (excess)
before short-term commodity contract assets and liabilities and current
finance lease obligations. Net debt also excludes the liability
component of convertible debentures. A reconciliation between total
liabilities under GAAP and total net debt and net debt as calculated by
the Company is found further in the MD&A.
^(4) Operating netbacks is considered a non-GAAP term. Operating netbacks
are calculated by subtracting royalties, transportation, and operating
costs from revenues before other income.
^(5) Net profit before certain non-cash items is considered a non-GAAP term.
Net profit before certain non-cash items is calculated as net profit
(loss) per the Consolidated Statement of Comprehensive Income, excluding
the impairment loss (reversal) on property, plant and equipment, the
unrealized gain or loss on commodity contracts, the gain on property
acquisition, and the gain or loss on property dispositions, net of
deferred tax impacts on each item. The Company's reconciliation between
the net profit and net profit before certain non-cash items is found in
this MD&A.
^(6) Basic weighted average shares for the three months ended December 31,
2012 were 107,734,134 (2011: 107,397,265).
In computing weighted average diluted earnings per share for the three
months ended December 31, 2012, a total of 1,375,484 common shares were
added to the denominator as a consequence of applying the treasury stock
method to the Company's outstanding share options and a total of
9,821,429 common shares issuable on conversion of convertible debentures
were also added to the denominator as they were dilutive, resulting in
diluted weighted average common shares of 118,931,047. In computing
weighted average diluted earnings per share for the three months ended
December 31, 2011, a total of 1,951,780 common shares were added to the
denominator as a consequence of applying the treasury stock method to
the Company's outstanding share options and a total of 9,821,429 common
shares issuable on conversion of convertible debentures were excluded
from the denominator as they were not dilutive, resulting in diluted
weighted average common shares of 107,397,265.
In computing weighted average diluted net profit before certain items
per share for the three months ended December 31, 2012, a total of
1,375,484 (2011: 1,951,780) common shares were added to the denominator
as a consequence of applying the treasury stock method to the Company's
outstanding share options as they were dilutive, and a total of
9,821,429 (2011: 9,821,429) common shares issuable on conversion of
convertible debentures were excluded from the denominator as they were
not dilutive, resulting in diluted weighted average common shares of
109,109,618 (2011:109,349,045).
In computing weighted average diluted cash flow from operating
activities and funds flow from operations per share for the three months
ended December 31, 2012, a total of 1,375,484 (2011: 1,951,780) common
shares were added to the denominator as a consequence of applying the
treasury stock method to the Company's outstanding share options and a
total of 9,821,429 (2011: 9,821,429) common shares issuable on
conversion of convertible debentures were also added to the denominator
as they were dilutive, resulting in diluted weighted average common
shares of 118,931,047 (2011: 119,170,474). As a consequence, a total of
$0.8 million (2011: $0.8 million) for interest accretion expense (net of
income tax effect) was added to the numerator.
^(7) TSX and Other includes the trading statistics for the Toronto Stock
Exchange and other Canadian trading markets.
^(8) The Company's common shares commenced trading on the NYSE MKT on
September 24, 2012.
As detailed previously in this Management's Discussion and Analysis, funds
flow from operations is a term that does not have any standardized meaning
under GAAP. Funds flow from operations is calculated as cash flow from
operating activities before asset retirement costs incurred and changes in
non-cash working capital incurred.
Reconciliation of Cash Flow from Operating Activities to Funds Flow from
Operations
Three months ended December 31,
($000s) 2012 2011
Cash flow from operating activities 32,007 30,626
Decommissioning costs incurred 76 186
Change in non-cash working capital (2,218) (692)
Funds flow from operations 29,865 30,120
Funds flow from operations during the fourth quarter of 2012 was $29.9
million, a decrease of 0.9% compared to $30.1 million for the fourth quarter
of 2011. The decrease in funds flow from operations between the periods was
due primarily to lower pricing for light and heavy oil, condensate, and NGL's,
largely offset by higher production volumes and slightly higher natural gas
prices in the 2012 fourth quarter. Fluctuations in oil and gas prices during
the fourth quarter of 2012 resulted in an increase in net realized gains on
commodity risk management contracts by approximately $2.3 million compared to
the fourth quarter of 2011. Cash flow from operating activities during the
fourth quarter of 2012 was $32.0 million, compared to $30.6 million for the
fourth quarter of 2011. The increase in cash flow from operating activities
between the periods was reflective of an increase in cash from changes in
working capital, and a minor decrease in decommissioning costs incurred.
In the fourth quarter of 2012, Bellatrix realized a net profit of $9.3 million
compared to a net loss of $13.6 million in the fourth quarter of 2011. The
net profit recorded in the fourth quarter of 2012 compared to the net loss in
the fourth quarter of 2011 is primarily a consequence of a $1.3 million
non-cash unrealized gain on commodity risk management compared to a $17.7
million loss in the 2011 period, and a $16.2 million non-cash gain on property
acquisition recognized in the 2012 fourth quarter, offset by a higher non-cash
impairment loss on oil and gas properties, slightly increased depletion and
depreciation expenses, and a deferred income tax expense of $3.3 million in
the 2012 fourth quarter compared to a $4.0 million recovery in the 2011
period.
As previously noted in this MD&A, net profit before certain non-cash items is
a non-GAAP measure. A reconciliation between this measure and net profit per
the Consolidated Statement of Comprehensive Income is provided below.
For the fourth quarter of 2012, net profit before certain non-cash items, net
of associated deferred tax impacts, was $7.3 million compared to $7.9 million
in 2011.
Reconciliation of Net Profit (Loss) to Net Profit Before Certain Non-Cash
Items
Three months ended December 31,
($000s) 2012 2011
Net profit (loss) per financial statements 9,251 (13,597)
Items subject to reversal
Impairment loss on property, plant and equipment 14,820 11,018
Unrealized (gain) loss on commodity contracts (1,313) 17,676
Gain on property acquisition (16,160) -
Loss on property dispositions 50 20
Deferred tax impact of above items 651 (7,179)
Net profit before certain non-cash items 7,299 7,938
Sales Volumes
Three months ended December 31,
2012 2011
Light oil and condensate (bbls/d) 3,910 3,925
NGLs (excluding condensate) (bbls/d) 1,631 1,173
Heavy oil (bbls/d) 189 322
Total crude oil, condensate and (bbls/d) 5,730 5,420
NGLs
Natural gas (mcf/d) 78,195 52,734
Total boe/d (6:1) 18,763 14,209
Sales volumes for the three months ended December 31, 2012 averaged 18,763
boe/d, an increase of 32% from the 14,209 boe/d sold in the fourth quarter of
2011. The weighting toward crude oil, condensate and NGLs sales volumes
decreased to 31% in the 2012 fourth quarter, compared to 38% in the
corresponding period in 2011. Fourth quarter 2012 natural gas, NGL, and total
overall sales volumes were higher than the same period in 2011 primarily due
to the continued success achieved from the Company's liquids rich drilling
program.
Natural gas sales averaged 78.2 Mmcf/d during the fourth quarter of 2012,
compared to 52.7 Mmcf/d in the fourth quarter of 2011. The weighting toward
natural gas sales volumes averaged 69% in the fourth quarter of 2012, an
increase over the 62% weighting realized in the corresponding period in 2011.
Crude oil, condensate and NGL sales volumes increased to 5,730 bbls/d in the
fourth quarter of 2012 compared to 5,420 bbls/d during the same period of
2011.
Revenue
Three months ended December 31,
($000s) 2012 2011
Light crude oil and condensate 29,702 34,366
NGLs (excluding condensate) 5,829 5,862
Heavy oil 1,136 2,204
Crude oil and NGLs 36,667 42,432
Natural gas 24,904 15,995
Total revenue before other 61,571 58,247
Other ^(1) 712 767
Total revenue before royalties and risk
management 62,283 59,194
^1) Other revenue primarily consists of processing and other third party
income.
Revenue before other income, royalties and commodity price risk management
contracts for the fourth quarter of 2012 was $61.6 million, an increase of 6%
from $58.2 million in the fourth quarter of 2011. The increase in revenues
between the periods was due to increased sales volumes and slightly higher
natural gas prices in the 2012 period, partially offset by lower crude oil,
condensate, and NGL prices.
Light oil and condensate revenues for the fourth quarter of 2012 were down 14%
from the same period in 2011 due to lower prices. For light oil and
condensate, Bellatrix recorded an average $82.58/bbl before commodity price
risk management contracts during the fourth quarter of 2012, 13% lower than
the average price of $95.18/bbl received in the comparative 2011 period. In
comparison, the Edmonton par price decreased by 14% over the same period.
The average WTI crude oil benchmark price decreased by 6% in fourth quarter of
2012 compared to the same period in 2011. The average US$/CDN$ foreign
exchange rate was 1.0093 for the three months ended December 31, 2012, an
increase of 3% compared to an average rate of 0.9773 in the same period in
2011.
NGL revenues for the fourth quarter of 2012 were comparable to the 2011 period
as a result of higher sales volumes offset by lower prices. For NGLs
(excluding condensate), Bellatrix recorded an average $38.84/bbl during the
fourth quarter of 2012, a 28% decrease from the $54.31/bbl received in the
comparative 2011 period. The decrease in NGL pricing between the 2012 and
2011 periods is largely attributable to changes in NGL market supply
conditions between the periods.
The decrease in heavy oil revenue from the fourth quarter of 2011 to the same
period in 2012 is reflective of lower sales volumes and reduced prices.
Bellatrix sold its Wainwright heavy oil property, with 59 bbls/d of current
production, in the third quarter of 2012. For heavy crude oil, Bellatrix
received an average price before commodity risk management contracts of
$65.30/bbl in the 2012 fourth quarter, a decrease of 12% from the $74.30/bbl
realized in the fourth quarter of 2011. In comparison, the Bow River
reference price decreased by 19%, and the Hardisty Heavy reference price
decreased by 21% between the fourth quarter of 2011 and the fourth quarter of
2012. The majority of Bellatrix's heavy crude oil density ranges between 11
and 16 degrees API, consistent with the Hardisty Heavy reference price.
Natural gas revenues in the fourth quarter of 2012 were up 56% from the same
period in 2011 as a result of a 48% increase in sales volumes and a slight
increase in natural gas prices between the periods. Bellatrix's natural gas
sales are priced with reference to the daily or monthly AECO indices.
Bellatrix's natural gas sold has a higher heat content than the industry
average, which results in slightly higher prices per mcf than the daily AECO
index. During the fourth quarter of 2012, the AECO daily reference price
increased by 1%, and the AECO monthly reference price decreased by
approximately 12% compared to the fourth quarter of 2011. Bellatrix's natural
gas average sales price before commodity price risk management contracts for
the fourth quarter of 2012 increased by 5% to $3.46/mcf compared to the
$3.30/mcf realized in the same period in 2011. The more significant increase
in Bellatrix's realized natural gas prices compared to the daily AECO index
between the periods was primarily due to the weighting of sales volumes
realized at increased prices during the fourth quarter of 2012. Bellatrix's
natural gas average price after including commodity price risk management
contracts for the three months ended December 31, 2012 was $3.67/mcf, compared
to $3.62/mcf for the three months ended December 31, 2011.
In the fourth quarter of 2012, average sales volumes increased 21% from the
third quarter 2012 average volumes of 15,503 boe/d. The increase was due to
the success achieved from the Company's drilling program in 2012.
During the fourth quarter of 2012, Bellatrix spent $32.1 million on capital
projects, excluding corporate and asset acquisitions and dispositions,
compared to $47.1 million in 2011. In the fourth quarter of 2012, Bellatrix
drilled or participated in 10 gross wells (6.17 net), all of which were
Cardium light oil horizontal wells. In the fourth quarter of 2011, Bellatrix
drilled or participated in 12 (7.64 net) wells including 8 gross (6.68 net)
oil wells, 3 gross (0.95 net) natural gas wells, and participated in 1 gross
(0.007 net) dry hole that was drilled in a non-operated oil unit.
In the fourth quarter of 2012, the Company paid $11.8 million in royalties,
compared to $8.8 million in the same period in 2011. As a percentage of
pre-commodity price risk management sales (after transportation costs),
royalties were 20% in the fourth quarter of 2012 compared to 15% in the same
period in 2011. Royalties for the fourth quarter of 2011 were reduced by $1.5
million in adjustments relating to previous quarter estimates, primarily for
wells under the recent Alberta royalty programs. Excluding these adjustments,
the average royalty rate percentage for the fourth quarter of 2011 would be
18%. Certain light oil wells are now incurring higher royalty rates as they
come off the initial royalty incentive rates. The Company's heavy oil
properties are minor, and consist of principally the Frog Lake Alberta assets
which are subject to high crown royalty rates. The Company's royalty
percentage for natural gas royalties continues to decline due to increased
production from recently drilled wells which take advantage of Alberta royalty
incentive programs.
In the fourth quarter of 2012, operating costs totaled $15.4 million, compared
to $14.1 million recorded in the same period of 2011. During the fourth
quarter of 2012, operating costs averaged $8.91/boe, down from the $10.78/boe
incurred during the fourth quarter of 2011. The decrease was primarily due to
increased production from recent drilling in areas with lower production
expenses and the Company's continued efforts to streamline operations and
field optimization projects. In comparison, operating costs for the third
quarter of 2012 averaged $7.96/boe. The increase between the third and fourth
quarters of 2012 was primarily due to additional chemical well treating,
compressor rentals, and other maintenance expenses.
During the fourth quarter of 2012, the Company's field operating netbacks
before commodity risk management contracts decreased by 26% to $19.20/boe
compared to $26.00/boe in the comparative 2011 period, driven primarily by a
20% decrease in overall commodity prices and a slight 2% increase in
royalties, partially offset by a 17% reduction in production expenses and a
41% reduction in transportation costs. In comparison, the Company's field
operating netback before commodity risk management contracts for the third
quarter of 2012 was $18.29/boe.
Field operating netbacks for natural gas before commodity price risk
management contracts during the fourth quarter of 2012 of $1.85/mcf were 52%
higher than the $1.22/mcf recorded in the same period in 2011. The increase
was primarily a result of slightly higher gas prices, as well as lower
transportation, royalties, and production expenses. In comparison, the field
operating netback for natural gas before commodity risk management contracts
for the third quarter of 2012 was $1.12/mcf.
Field operating netbacks before commodity price risk management contracts for
crude oil, condensate and NGLs during the fourth quarter of 2012 averaged
$37.60/bbl, a decrease of 33% from the $56.26/bbl realized during the fourth
quarter of 2011. The decrease between the periods was primarily as a result of
weaker commodity prices and increased royalties, offset partially by decreases
in production and transportation expenses. In comparison, the field operating
netback for crude oil, condensate and NGLs for the third quarter of 2012 was
$41.12/bbl.
In the fourth quarter of 2012, general and administrative expenses ("G&A"),
net of capitalized G&A and recoveries, were $4.4 million, compared to $3.8
million in the comparable 2011 period. The increase to net G&A was primarily
attributable to increases in staffing costs between the periods. The overall
increase in G&A expenses was offset slightly by higher capitalized G&A and
recoveries as a result of the increase in capital activity in the fourth
quarter of 2012 compared to the fourth quarter of 2011.
Depletion, depreciation and accretion expense for the fourth quarter of 2012
was $18.6 million ($10.77/boe), compared to $17.6 million ($13.48/boe) in
2011. The increase in depletion, depreciation and accretion expense from the
2011 fourth quarter to that in 2012 is reflective of the 32% increase in sales
volumes between the same comparative periods, offset by the additional
reserves achieved through the Company's drilling success.
2012 Annual Financial and Operational Results
Acquisition and Dispositions
Effective November 1, 2012, Bellatrix acquired Cardium and Notikewin/Falher
lands and production in the Willesden Green area adjacent to Bellatrix's core
area in the Ferrier/Willesden Green Cardium light oil resource play in West
Central Alberta. The assets acquired included then current production
capability of approximately 500 boe/d (32% oil and liquids and 68% natural
gas), 16 gross (11.95 net) sections of Cardium and Mannville prospective
lands, 25 net Cardium development locations, 4 net Notikewin/Falher
development locations, and a 25% working interest in an operated compressor
station and gathering system. Bellatrix acquired these assets for a net
purchase price of $21 million, which was funded using the Company's existing
credit facilities.
On December 14, 2012, Bellatrix acquired an additional 11 gross and net
sections of highly prospective Cardium and Notikewin/Falher lands in the
Ferrier area of west-central Alberta, subject to the receipt of land permits
anticipated in Q1 2013. This acquisition is anticipated to provide an
additional 37 net drilling locations in the Cardium, 9 net locations in the
Notikewin/Falher, and an additional 66 net locations in the Duvernay
formation. The Company continues to focus on adding Cardium and Notikewin
prospective lands.
During the third quarter of 2012, Bellatrix closed on the disposition of a
minor non-core property interest in the Wainwright area, Alberta for $4.25
million after adjustments. This non-operated unit heavy oil property had
production of approximately 59 boe/d. The net proceeds from the disposition
were initially used to reduce the Company's bank indebtedness, and ultimately
were directed towards the development of the Company's Cardium oil resource
program.
During the second quarter of 2012, Bellatrix closed on the disposition of the
Girouxville property in Alberta, a minor non-core property interest. The
property was sold for $0.6 million after adjustments.
Additionally, in the second quarter of 2012, Bellatrix closed on the
disposition of the Cypress-Chowade property in British Columbia, a minor
non-core property interest. The property was sold for $1.4 million after
adjustments. There was no current production from the Cypress-Chowade
property.
Bellatrix had other minor property dispositions in 2012 resulting in total
cumulative property dispositions of $6.7 million.
Sales Volumes
Sales volumes for the year ended December 31, 2012 averaged 16,686 boe/d
compared to 11,954 boe/d for the 2011 year, representing a 40% increase.
Total crude oil, condensate and NGLs averaged approximately 34% of sales
volumes for the year ended December 31, 2012, compared to 38% of sales volumes
in the 2011 year. The increase in sales was primarily a result of a year
over year increased capital program and the associated drilling success
achieved in the Cardium and Notikewin resource plays. Capital expenditures
for the year ended December 31, 2012 were $185.3 million, compared to $179.6
million for the 2011 year.
Sales Volumes
Years ended December 31,
2012 2011
Light oil and condensate (bbls/d) 3,996 3,416
NGLs (excluding condensate) (bbls/d) 1,441 808
Heavy oil (bbls/d) 280 316
Total crude oil, condensate and NGLs (bbls/d) 5,717 4,540
Natural gas (mcf/d) 65,812 44,484
Total boe/d (6:1) 16,686 11,954
During the 2012 year, Bellatrix posted a 100% success rate drilling and/or
participating in 34 gross (26.32 net) wells, resulting in 28 gross (21.32 net)
Cardium oil wells, 2 gross (2.0 net) Cardium condensate-rich gas wells, 1
gross (1.0 net) Duvernay gas well, and 3 gross (2.0 net) Notikewin/Falher
liquids-rich gas wells.
By comparison, Bellatrix drilled or participated in 54 gross (34.84 net) wells
during the 2011 year, including 39 gross (29.04 net) oil wells, 14 gross (5.79
net) liquids-rich natural gas wells, and 1 gross (0.007 net) dry hole that was
drilled in a non-operated oil unit.
For the year ended December 31, 2012, crude oil, condensate and NGL sales
volumes increased by approximately 26%, averaging 5,717 bbl/d compared to
4,540 bbl/d in the 2011 year. For the year ended December 31, 2012, sales
volumes for crude oil, condensate and NGLs averaged approximately 34% of total
sales volumes compared to approximately 38% of total sales volumes in the 2011
year. The reduction in liquids weighting between the years was a direct
result of adding the dry gas producing Duvernay well during the second quarter
of 2012, as well as bringing on several other high-productivity gas wells
throughout the 2012 year.
Sales of natural gas averaged 65.8 Mmcf/d for the year ended December 31,
2012, compared to 44.5 Mmcf/d in the 2011 year, an increase of approximately
48%. The weighting towards natural gas sales volumes averaged approximately
66% for the year ended December 31, 2012, compared to 62% in the 2011 year.
For 2013, Bellatrix will utilize pad drilling, involving the drilling of
multiple horizontal wells from single surface locations, enhancing resource
development efficiency, minimizing the Company's environmental footprint, and
improving cost and on-stream efficiencies. An initial capital expenditure
budget of between $230 to $240 million has been set for fiscal 2013. Based on
the timing of proposed expenditures, downtime for scheduled and unscheduled
plant turnarounds, completion of required infrastructure, and normal
production declines, execution of the 2013 capital expenditure plan is
anticipated to provide average daily production of approximately 24,000 to
25,000 boe/d and an exit rate of approximately 30,000 boe/d to 31,000 boe/d.
Commodity Prices
Average Commodity Prices
Years ended December 31,
2012 2011 % Change
Average exchange rate (US$/Cdn$) 1.0009 1.0111 (1)
Crude oil:
WTI (US$/bbl) 94.14 95.12 (1)
Edmonton par - light oil ($/bbl) 86.53 95.16 (9)
Bow River - medium/heavy oil ($/bbl) 74.30 78.30 (5)
Hardisty Heavy - heavy oil ($/bbl) 64.99 69.10 (6)
Bellatrix's average prices ($/bbl)
Light crude oil and condensate 86.47 92.51 (7)
NGLs (excluding condensate) 38.88 53.54 (27)
Heavy crude oil 68.51 68.23 -
Total crude oil and NGLs 73.59 83.89 (12)
Total crude oil and NGLs (including risk 72.65 81.47 (11)
management ^(1))
Natural gas:
NYMEX (US$/mmbtu) 2.83 4.03 (30)
AECO daily index (CDN$/mcf) 2.39 3.62 (34)
AECO monthly index (CDN$/mcf) 2.40 3.67 (35)
Bellatrix's average price ($/mcf) 2.62 3.77 (31)
Bellatrix's average price (including risk 3.17 4.05 (22)
management ^(1)) ($/mcf)
^(1) Per unit metrics including risk management include realized gains or
losses on commodity contracts and exclude unrealized gains or losses on
commodity contracts.
During 2012, the differential between West Texas Intermediate ("WTI") and
Edmonton par price widened, whereas for 2011 the differential was nearly
non-existent. North America has seen significant increases in light oil
production as a result of the rapid pace of development in the shale oil
reservoirs. These volumes have displaced Canadian production resulting in
lower demand for Edmonton light oil. This factor, along with higher
incidences of refinery maintenance in 2012 and continued refinery conversions
to run heavier streams, has resulted in the widening of the price differential
between WTI and Edmonton par. For light oil and condensate, Bellatrix
recorded an average $86.47/bbl before commodity price risk management
contracts during the year ended December 31, 2012, 7% lower than the average
price received in the 2012 year. In comparison, the Edmonton par price
decreased by 9% over the same period. The average WTI crude oil benchmark
price decreased by 1% in the year ended December 31, 2012 compared to the 2011
year. The average US$/CDN$ foreign exchange rate was 1.0009 for the year
ended December 31, 2012, a decrease of 1% compared to an average rate of
1.0111 in the 2011 year.
For NGLs (excluding condensate), Bellatrix recorded an average $38.88/bbl
during the year ended December 31, 2012, a 27% decrease from the $53.54/bbl
received in the 2011 year. The decrease in NGL pricing between the 2012 and
2011 years is largely attributable to changes in NGL market supply conditions
between the years.
For heavy crude oil, Bellatrix received an average price before commodity risk
management contracts of $68.51/bbl in the 2012 year, consistent with the
average price of $68.23/bbl realized in the 2011 year. In comparison, the Bow
River reference price decreased by 5%, and the Hardisty Heavy reference price
decreased by 6% between the 2012 and 2011 years. The majority of Bellatrix's
heavy crude oil density ranges between 11 and 16 degrees API, consistent with
the Hardisty Heavy reference price.
Bellatrix's natural gas sales are priced with reference to the daily or
monthly AECO indices. Bellatrix's natural gas sold has a higher heat content
than the industry average, which results in slightly higher prices per mcf
than the daily AECO index. During the 2012 year, the AECO daily reference
price decreased by 34%, and the AECO monthly reference price decreased by
approximately 35% compared to the 2011 year. Bellatrix's natural gas average
sales price before commodity price risk management contracts for the 2012 year
decreased by 31% to $2.62/mcf compared to $3.77/mcf in the 2011 year. The
lower decrease in Bellatrix's realized natural gas prices compared to the
daily AECO index between the years was primarily due to the weighting of
additional sales volumes realized at increasing prices throughout the 2012
year. Bellatrix's natural gas average price after including commodity price
risk management contracts for the year ended December 31, 2012 was $3.17/mcf,
compared to $4.05/mcf for the year ended December 31, 2011.
Revenue
Revenue before other income, royalties and commodity price risk management
contracts for the year ended December 31, 2012 was $217.1 million, 8% higher
than the $200.2 million in the 2011 year. The increase in revenues between the
years was due to increased sales volumes between the years, partially offset
by reduced liquids and natural gas prices experienced in the 2012 year.
Revenue before other income, royalties and commodity price risk management
contracts for crude oil and NGLs for the year ended December 31, 2012
increased by 11% from the 2011 year, resulting from higher sales volumes,
partially offset by lower light crude oil, condensate and NGL prices when
compared to the 2011 year. In the 2012 year, total crude oil, condensate and
NGL revenues contributed 71% of total revenue (before other) compared to 69%
in the 2011 year. Light crude oil, condensate and NGL revenues in the year
ended December 31, 2012 comprised 95% of total crude oil, condensate and NGL
revenues (before other) for those periods, compared to 94% in the 2011 year.
Natural gas revenue before other income, royalties and commodity price risk
management contracts for the year ended December 31, 2012 increased by
approximately 3% compared to the 2011 year as a result of an approximate 48%
increase in sales volumes between the years, largely offset by a 31% decrease
in realized gas prices before risk management.
Years ended December 31,
($000s) 2012 2011
Light crude oil and condensate 126,468 115,353
NGLs (excluding condensate) 20,504 15,782
Heavy oil 7,023 7,866
Crude oil and NGLs 153,995 139,001
Natural gas 63,143 61,186
Total revenue before other 217,138 200,187
Other ^(1) 2,176 2,131
Total revenue before royalties and risk 219,314 202,318
management
^(1) Other revenue primarily consists of processing and other third party
income.
Commodity Price Risk Management
The Company has a formal commodity price risk management policy which permits
management to use specified price risk management strategies including fixed
price contracts, collars and the purchase of floor price options and other
derivative financial instruments and physical delivery sales contracts to
reduce the impact of price volatility for a maximum of eighteen months beyond
the transaction date. The program is designed to provide price protection on a
portion of the Company's future production in the event of adverse commodity
price movement, while retaining significant exposure to upside price
movements. By doing this, the Company seeks to provide a measure of stability
to funds flow from operations, as well as to ensure Bellatrix realizes
positive economic returns from its capital development and acquisition
activities. The Company plans to continue its commodity price risk management
strategies focusing on maintaining sufficient cash flow to fund Bellatrix's
capital expenditure program. Any remaining production is realized at market
prices.
A summary of the financial commodity price risk management volumes and average
prices by quarter currently outstanding as of March 6, 2013 is shown in the
following tables:
Natural gas
Average Volumes (GJ/d)
Q1 2013 Q2 2013 Q3 2013 Q4
2013
Fixed 6,556 55,000 55,000 35,109
Q1 2014 Q2 2014 Q3 2014 Q4
2014
Fixed 15,000 15,000 - -
Average Price ($/GJ
AECO C)
Q1 2013 Q2 2013 Q3 2013 Q4 2013
Fixed 3.05 3.06 3.06 3.05
Q1 2014 Q2 2014 Q3 2014 Q4 2014
Fixed 3.05 3.05 - -
Crude oil and liquids
Average Volumes
(bbls/d)
Q1 2013 Q2 2013 Q3 2013 Q4 2013
Call option 3,000 3,000 3,000 3,000
Fixed 1,500 1,500 1,500 1,500
Total bbls/d 4,500 4,500 4,500 4,500
Q1 2014 Q2 2014 Q3 2014 Q4 2014
Call option 3,000 3,000 3,000 3,000
Average Price ($/bbl
WTI)
Q1 2013 Q2 2013 Q3 2013 Q4 2013
Call option (ceiling 110.00 110.00 110.00 110.00
price) (US$/bbl)
Fixed price (CDN$/bbl) 94.50 94.50 94.50 94.50
Q1 2014 Q2 2014 Q3 2014 Q4 2014
Call option (ceiling 105.00 105.00 105.00 105.00
price) (US$/bbl)
As of December 31, 2012, the fair value of Bellatrix's outstanding commodity
contracts is a net unrealized asset of $0.2 million as reflected in the
financial statements. The fair value or mark-to-market value of these
contracts is based on the estimated amount that would have been received or
paid to settle the contracts as at December 31, 2012 and will be different
from what will eventually be realized. Changes in the fair value of the
commodity contracts are recognized in the Consolidated Statements of
Comprehensive Income within the financial statements.
The following is a summary of the gain (loss) on commodity contracts for the
years ended December 31, 2012 and 2011 as reflected in the Consolidated
Statements of Comprehensive Income in the financial statements:
Commodity contracts
Crude Oil Natural 2012
($000s) & Liquids Gas Total
Realized cash gain (loss) on contracts (1,976) 13,245 11,269
Unrealized gain on contracts ^(1) 6,267 4,539 10,806
Total gain on commodity contracts 4,291 17,784 22,075
Commodity contracts
Crude Oil Natural 2011
($000s) & Liquids Gas Total
Realized cash gain (loss) on contracts (4,015) 4,582 567
Unrealized gain (loss) on contracts ^(1) (9,879) 2,979 (6,900)
Total gain (loss) on commodity contracts (13,894) 7,561 (6,333)
Unrealized gain (loss) on commodity contracts represents non-cash
^(1) adjustments for changes in the fair value of these contracts during the
period.
Royalties
For the year ended December 31, 2012, total royalties were $38.8 million
compared to $34.7 million incurred in the 2011 year. Overall royalties as a
percentage of revenue (after transportation costs) in the 2012 year were 18%,
compared with 18% in the 2011 year.
Certain light oil wells are now incurring higher royalty rates as they come
off the initial royalty incentive rates. The Company's heavy oil properties
are minor, and consist of principally the Frog Lake Alberta assets which are
subject to high crown royalty rates. The Company's royalty percentage for
natural gas royalties continues to decline due to increased production from
recently drilled wells which take advantage of Alberta royalty incentive
programs. Natural gas royalties and total royalties recognized in 2012 were
reduced by $1.5 million and $1.7 million, respectively, in adjustments
relating to prior period estimates, primarily for Ferrier area wells for
Indian Oil and Gas Canada royalties under recent royalty incentive programs.
Excluding these adjustments, the average natural gas and overall corporate
royalty rate percentages for 2012 would be 6% and 19%, respectively.
Royalties by Commodity Type Years ended December 31,
($000s, except where noted) 2012 2011
Light crude oil, condensate and NGLs 33,607 23,065
$/bbl 16.89 14.96
Average light crude oil, condensate and
NGLs royalty rate (%) 23 18
Heavy Oil 3,496 3,538
$/bbl 34.11 30.69
Average heavy oil royalty rate (%) 52 46
Natural Gas 1,653 8,095
$/mcf 0.07 0.50
Average natural gas royalty rate (%) 3 14
Total 38,756 34,698
$/boe 6.35 7.95
Average total royalty rate (%) 18 18
Royalties, by Type
Years ended December 31,
($000s) 2012 2011
Crown royalties 11,518 12,264
Indian Oil and Gas Canada royalties 8,038 8,346
Freehold & GORR 19,200 14,088
Total 38,756 34,698
Expenses
Years ended December 31,
($000s) 2012 2011
Production 53,316 50,313
Transportation 4,978 5,715
General and administrative 14,272 12,358
Interest and financing charges ^ (1) 9,834 7,041
Share-based compensation 3,219 2,939
^(1) Does not include financing charges in relation to the Company's accretion
of decommissioning liabilities.
Expenses per boe
Years ended December 31,
($ per boe) 2012 2011
Production 8.73 11.53
Transportation 0.82 1.31
General and administrative 2.34 2.83
Interest and financing charges 1.61 1.61
Share-based compensation 0.53 0.67
Production Expenses
For the year ended December 31, 2012, production expenses totaled $53.3
million ($8.73/boe), compared to $50.3 million ($11.53/boe) in the 2011 year.
For the year ended December 31, 2012, production expenses increased overall,
while decreasing on a per boe basis when compared to the 2011 year. The
decrease in production expenses on a boe basis in the 2012 year was primarily
due to increased production, which is a result of drilling in both 2011 and
2012 in areas with lower production expenses, as well as reduced processing
fees in certain areas and continued field optimization projects.
Bellatrix is targeting operating costs of approximately $73.6 million
($8.00/boe) in the 2013 year, which is a reduction from the $8.73/boe
operating costs incurred for the 2012 year. This is based upon assumptions of
estimated 2013 average production of approximately 24,000 boe/d to 25,000
boe/d, continued field optimization work and planned capital expenditures in
producing areas which are anticipated to have lower operating costs.
Production Expenses, by Commodity Type
Years ended December
31,
($000s, except where noted) 2012 2011
Light crude oil, condensate and NGLs 21,840 20,536
$/bbl 10.97 13.32
Heavy oil 1,555 2,587
$/bbl 15.17 22.44
Natural gas 29,921 27,190
$/mcf 1.24 1.67
Total 53,316 50,313
$/boe 8.73 11.53
Total 53,316 50,313
Processing and other third party income ^(1) (2,176) (2,131)
Total after deducting processing and other third 51,140 48,182
party income
$/boe 8.37 11.04
^(1) Processing and other third party income is included within petroleum and
natural gas sales on the Consolidated Statements of Comprehensive
Income.
Transportation
Transportation expenses for the year ended December 31, 2012 were $5.0 million
($0.82/boe), compared to $5.7 million ($1.31/boe) in the 2011 year. The
decrease in overall and per boe costs is reflective of a higher volume of oil
production being shipped through pipelines rather than through trucking at a
higher cost, as well as reduced gas transportation fees resulting from the
acquisition of an ownership interest in certain gathering and processing
facilities in the first half of 2011.
Operating Netback
Field Operating Netback - Corporate
(before risk management)
For the years ended December 31,
($/boe) 2012 2011
Sales 35.56 45.88
Transportation (0.82) (1.31)
Royalties (6.35) (7.95)
Production expense (8.73) (11.53)
Field operating netback 19.66 25.09
For the year ended December 31, 2012, the corporate field operating netback
(before commodity price risk management contracts) was $19.66/boe compared to
$25.09/boe in the 2011 year. The reduced netback was primarily the result of
reduced commodity prices, offset by reduced transportation, royalty and
production expenses. After including commodity price risk management
contracts, the corporate field operating netback for the 2012 year was
$21.51/boe compared to $25.22/boe in the 2011 year. Per unit metrics including
risk management include realized gains or losses on commodity contracts and
exclude unrealized gains or losses on commodity contracts.
Field Operating Netback - Crude Oil, Condensate and
NGLs (before risk management)
Years ended December 31,
($/bbl) 2012 2011
Sales 73.59 83.89
Transportation (0.98) (1.86)
Royalties (17.73) (16.06)
Production expense (11.18) (13.96)
Field operating netback 43.70 52.01
Field operating netback for crude oil, condensate and NGLs averaged $43.70/bbl
for the year ended December 31, 2012, a decrease of 16% from $52.01/bbl
realized in the 2011 year. In the 2012 year, Bellatrix's combined crude oil
and NGLs average price (before risk management) decreased by approximately 12%
compared to the 2011 year. The commodity price decrease in conjunction with a
slight increase in royalties was partially offset by reductions in production
and transportation expenses, resulting in the overall decrease to the field
operating netback for crude oil, condensate and NGLs. After including
commodity price risk management contracts, field operating netback for crude
oil and NGLs for the year ended December 31, 2012 decreased to $42.76/boe
compared to $49.58/boe in the 2011 year.
Field Operating Netback - Natural Gas (before risk
management)
Years ended December 31,
($/mcf) 2012 2011
Sales 2.62 3.77
Transportation (0.12) (0.16)
Royalties (0.07) (0.50)
Production expense (1.24) (1.67)
Field operating netback 1.19 1.44
Field operating netback for natural gas in the year ended December 31, 2012
year decreased by 17% to $1.19/mcf, compared to $1.44/mcf realized in the 2011
year, reflecting depressed natural gas prices, offset somewhat by lower
production, transportation and royalty expenses. After including commodity
price risk management contracts, field operating netback for natural gas for
the year ended December 31, 2012 increased to $1.74/mcf, which compared to
$1.72/mcf in the 2011 year.
General and Administrative
General and administrative ("G&A") expenses (after capitalized G&A and
recoveries) for the year ended December 31, 2012 were $14.3 million
($2.34/boe), compared to $12.4 million ($2.83/boe) for the 2011 year. G&A
expenses in the 2012 year were higher in comparison to the 2011 year, which is
reflective of higher compensation costs and slightly reduced recoveries,
offset partially by higher capitalized G&A. On a boe basis, G&A for the year
ended December 31, 2012 decreased by approximately 17% when compared to the
2011 year. The decrease was primarily as a result of higher average sales
volumes in the 2012 year, despite higher overall costs.
For 2013, the Company is anticipating G&A expenses after capitalization to be
approximately $23.0 million ($2.50/boe) based on estimated 2013 average
production volumes of approximately 24,000 boe/d to 25,000 boe/d.
General and Administrative Expenses
Years ended December 31,
($000s, except where noted) 2012 2011
Gross expenses 21,170 18,582
Capitalized (4,335) (3,553)
Recoveries (2,563) (2,671)
G&A expenses 14,272 12,358
G&A expenses, per unit ($/boe) 2.34 2.83
Interest and Financing Charges
Bellatrix recorded $9.8 million ($1.61/boe) of interest and financing charges
related to bank debt and its debentures for the year ended December 31, 2012,
compared to $7.0 million ($1.61/boe) in the 2011 year. The overall increase in
interest and financing charges between the years was primarily due to greater
interest and accretion charges in relation to the Company's outstanding
debentures in conjunction with higher interest charges related to the
Company's long-term debt as the Company carried a higher average debt balance
in the 2012 year compared to the 2011 year. Bellatrix's total net debt at
December 31, 2012 of $189.6 million includes the $50.7 million liability
portion of its $55 million principal amount of 4.75% convertible unsecured
subordinated debentures (the "4.75% Debentures"), $133.0 million of bank debt
and the net balance of the working capital deficiency. The 4.75% Debentures
have a maturity date of April 30, 2015.
Debt to Funds Flow from Operations Ratio
Years ended December 31,
($000s, except where noted) 2012 2011
Shareholders' equity 381,106 348,405
Long-term debt 133,047 56,701
Convertible debentures (liability component) 50,687 49,076
Working capital deficiency ^(2) 5,843 13,473
Total net debt ^(2) at year end 189,577 119,250
Debt to funds flow from operations ^(1) ratio
(annualized) ^(3)
Funds flow from operations ^(1) (annualized) 119,460 120,480
Total net debt ^(2) at year end 189,577 119,250
Total net debt to periods funds flow from
operations ratio
(annualized) ^(3) 1.6x 1.0x
Net debt ^(2) (excluding convertible debentures)
at year end 138,890 70,174
Net debt to periods funds flow from operations
ratio (annualized) ^(3) 1.2x 0.6x
Debt to funds flow from operations ^(1) ratio
Funds flow from operations ^(1) for the year 111,038 94,237
Total net debt ^(2) to funds flow from operations
for the year 1.7x 1.3x
Net debt ^(2) (excluding convertible debentures)
to funds flow
from operations for the year 1.3x 0.7x
^(1) As detailed previously in this Management's Discussion and Analysis,
funds flow from operations is a term that does not have any standardized
meaning under GAAP. Funds flow from operations is calculated as cash
flow from operating activities, less decommissioning costs incurred and
changes in non-cash working capital incurred. Refer to the
reconciliation of cash flow from operating activities to funds flow from
operations appearing elsewhere herein.
^(2) Net debt and total net debt are considered additional GAAP measures. The
Company's calculation of total net debt includes the liability component
of convertible debentures and excludes deferred liabilities, long-term
commodity contract liabilities, decommissioning liabilities, long-term
finance lease obligation and the deferred tax liability. Net debt and
total net debt include the net working capital deficiency (excess) before
short-term commodity contract assets and liabilities and current finance
lease obligation. Net debt also excludes the liability component of
convertible debentures. Total net debt and net debt are additional GAAP
measures; refer to the following reconciliation of total liabilities to
total net debt and net debt.
^(3) Total net debt and net debt to periods funds flow from operations ratio
(annualized) is calculated based upon fourth quarter funds flow from
operations annualized.
Reconciliation of Total Liabilities to Total Net Debt
and Net Debt
As at December 31,
($000s) 2012 2011
Total liabilities per financial statements 300,315 232,017
Current liabilities included within working capital (53,327) (73,578)
calculation
Commodity contract liability (6,214) (2,944)
Decommissioning liabilities (43,909) (45,091)
Finance lease obligation (13,131) (4,627)
Working Capital
Current assets (52,447) (51,927)
Current liabilities 53,327 73,578
Current portion of finance lease (1,425) (490)
Net commodity contract asset (liability) 6,388 (7,688)
5,843 13,473
Total net debt 189,577 119,250
Convertible debentures (50,687) (49,076)
Net debt 138,890 70,174
Share-Based Compensation
Non-cash share-based compensation expense for the year ended December 31, 2012
was an expense of $3.2 million compared to $2.9 million in the 2011 year. The
overall increase in non-cash share-based compensation expense between the
years is primarily a result of a larger number of outstanding share options
expensed during the year and greater Deferred Share Unit Plan expenses of $1.0
million (2011: $0.8 million), offset partially by higher capitalized
share-based compensation of $1.6 million (2011: $1.4 million).
Depletion and Depreciation
Depletion and depreciation expense for the year ended December 31, 2012 was
$75.7 million ($12.40/boe), compared to $63.4 million ($14.53/boe) recognized
in the 2011 year. The decrease in depletion and depreciation expense between
the years, on a per boe basis, was primarily a result of an increase in the
reserve base used for the depletion calculation, partially offset by a higher
cost base and increased future development costs.
For the year ended December 31, 2012 Bellatrix has included a total of $524.6
million (2011: $376.8 million) for future development costs in the depletion
calculation and excluded from the depletion calculation a total of $37.2
million (2011: $35.1 million) for estimated salvage.
Depletion and Depreciation
Years ended December 31,
($000s, except where noted) 2012 2011
Depletion and Depreciation 75,720 63,384
Per unit ($/boe) 12.40 14.53
Property Acquisition
Effective November 1, 2012, Bellatrix acquired production and working interest
in certain facilities, as well as undeveloped land in the Willesden Green area
of Alberta for a cash purchase price of $20.9 million after adjustments. In
accordance with IFRS, a property acquisition is accounted for as a business
combination when certain criteria are met, such as the acquisition of inputs
and processes to convert those inputs into beneficial outputs. Bellatrix
assessed the property acquisition and determined that it constitutes a
business combination under IFRS. In a business combination, acquired assets
and liabilities are recognized by the acquirer at their fair market value at
the time of purchase. Any variance between the determined fair value of the
assets and liabilities and the purchase price is recognized as either a gain
or loss in the statement of comprehensive income in the period of acquisition.
The estimated fair value of the property, plant and equipment acquired was
determined using both internal estimates and an independent reserve
evaluation. The decommissioning liabilities assumed were determined using the
timing and estimated costs associated with the abandonment, restoration and
reclamation of the wells and facilities acquired. A summary of the acquired
property is provided below:
($000s)
Estimated fair value of acquisition:
Oil and natural gas properties 29,530
Exploration and evaluation assets 8,525
Decommissioning liabilities (973)
37,082
Cash consideration 20,922
Gain on property acquisition 16,160
Impairment of Assets
In accordance with IFRS, the Company calculates an impairment test when there
are indicators of impairment. The impairment test is performed at the asset
or cash generating unit ("CGU") level. IAS 36 - "Impairment of Assets" ("IAS
36") is a one step process for testing and measuring impairment of assets.
Under IAS 36, the asset or CGU's carrying value is compared to the higher of:
value-in-use and fair value less costs to sell. Value in use is defined as
the present value of the future cash flows expected to be derived from the
asset or CGU.
When performed, the impairment test is based upon the higher of value-in-use
and estimated fair market values for the Company's properties, including but
not limited to an updated external reserve engineering report which
incorporates a full evaluation of reserves on an annual basis or internal
reserve updates at quarterly periods, and the latest commodity pricing deck.
Estimating reserves is very complex, requiring many judgments based on
available geological, geophysical, engineering and economic data. Changes in
these judgments could have a material impact on the estimated reserves. These
estimates may change, having either a negative or positive effect on net
earnings as further information becomes available and as the economic
environment changes.
2012 Impairment
Bellatrix engaged an external reserve evaluator to prepare an updated company
reserve report effective December 31, 2012. Overall corporate proved and
probable reserve volumes increased significantly at December 31, 2012 compared
to evaluated reserves at December 31, 2011. However, the fair values of two
largely natural gas-weighted CGUs and one CGU with significant natural gas and
heavy oil weightings were reduced, largely as a result of suppressed commodity
prices.
As at December 31, 2012, Bellatrix performed an impairment test using VIU
values in accordance with IAS 36, resulting in an excess of the carrying value
of three CGUs over their recoverable amount, resulting in a non-cash $14.8
million impairment loss. In performing the test, future cash flows at between
a 10% and 20% discount rate were used for the Company's largely gas weighted
North East Alberta, South East Alberta, and British Columbia CGUs. The
Company's core West Central Alberta CGU had no indicators of impairment.
Discounted salvage values and discounted future associated general and
administrative costs were also incorporated into the VIU calculation. The
$14.8 million impairment loss was comprised of $11.4 million recognized in the
Company's North East Alberta CGU, $2.9 million in the South East Alberta CGU,
and $0.5 million in the British Columbia CGU. The reduction in the fair
values of these CGUs between December 31, 2011 and December 31, 2012 was
predominantly due to weak natural gas prices.
2011 Impairment
During the year ended December 31, 2011, Bellatrix performed an impairment
test in accordance with IAS 36 resulting in an excess of the carrying value of
three CGUs over their recoverable amount, resulting in a non-cash $25.6
million impairment loss.
IAS 36 requires impairment losses to be reversed when there has been a
subsequent increase in the recoverable amount. In the case of an impairment
loss reversal, the carrying amount of the asset or CGU is limited to the
original carrying amount less depreciation, depletion and amortization as if
no impairment had been recognized for the asset or CGU for prior periods. In
2011, a partial reversal of impairment was recognized relating to a previous
impairment for the Company`s South East Alberta CGU. As a result of the
reversal, impairment expense for the 2011 year was reduced by $2.7 million.
The impairment test is based upon fair market values for the Company's
properties, including but not limited to an updated external reserve
engineering report which incorporates a full evaluation of reserves on an
annual basis or internal reserve updates at quarterly periods, and the latest
commodity pricing deck. Estimating reserves is very complex, requiring many
judgments based upon available geological, geophysical, engineering and
economic data. Changes in these judgments could have a material impact on the
Company's estimated reserves. These estimates may change, having either a
negative or positive impact on net earnings as further information becomes
available and as the economic environment changes.
Income Taxes
Deferred income taxes arise from differences between the accounting and tax
basis of the Company's assets and liabilities. For the year ended December
31, 2012, the Company recognized a deferred income tax expense of $10.1
million compared to $0.8 million in the 2011 year.
At December 31, 2012, the Company had a total deferred tax asset balance of
$1.0 million. IFRS requires that a deferred tax asset be recorded when the
tax pools exceeds the book value of assets, to the extent the amount is
probable to be realized.
At December 31, 2012, Bellatrix had approximately $584 million in tax pools
available for deduction against future income as follows:
($000s) Rate % 2012 2011
Intangible resource pools:
Canadian exploration expenses 100 56,200 47,600
Canadian development expenses 30 358,700 326,900
Canadian oil and gas property expenses 10 40,400 25,100
Foreign resource expenses 10 800 800
Attributed Canadian Royalty Income (Alberta) 100 16,100 16,100
Undepreciated capital cost ^(1) 6 - 55 98,000 83,100
Non-capital losses (expire through 2027) 100 10,000 10,000
Financing costs 20 S.L. 3,300 4,700
583,500 514,300
^(1) Approximately $91 million of undepreciated capital cost pools are class
41, which is claimed at a 25% rate.
Cash Flow from Operating Activities, Funds Flow from Operations and Net Profit
(Loss)
As detailed previously in this MD&A, funds flow from operations is a term that
does not have any standardized meaning under GAAP. Funds flow from operations
is calculated as cash flow from operating activities before decommissioning
costs incurred and changes in non-cash working capital incurred.
Reconciliation of Cash Flow from Operating Activities
and Funds Flow from Operations
Years ended December 31,
($000s) 2012 2011
Cash flow from operating activities 109,328 98,192
Decommissioning costs incurred 635 569
Change in non-cash working capital 1,075 (4,524)
Funds flow from operations 111,038 94,237
Bellatrix's cash flow from operating activities of $109.3 million ($1.02 per
basic share and $0.95 per diluted share) for the year ended December 31, 2012
increased approximately 11% from the $98.2 million ($0.95 per basic share and
$0.87 per diluted share) generated in the 2011 year. Bellatrix generated
funds flow from operations of $111.0 million ($1.03 per basic share and $0.96
per diluted share) for the year ended December 31, 2012, an increase of 18%
from $94.2 million ($0.91 per basic share and $0.84 per diluted share) for the
2011 year.
The increase in funds flow from operations between the 2012 and 2011 years was
principally due to higher funds from operating netbacks, despite significantly
reduced commodity prices, as well as higher net realized gains on the
Company's commodity risk management contracts, and offset partially by
increased financing expenses and slightly higher general and administrative
expenses in 2012 compared to 2011.
Bellatrix maintains a commodity price risk management program to provide a
measure of stability to funds flow from operations. Unrealized mark-to-market
gains or losses are non-cash adjustments to the current fair market value of
the contract over its entire term and are included in the calculation of net
profit.
As previously noted in this MD&A, net profit before certain non-cash items is
a non-GAAP measure. A reconciliation between this measure and net loss per the
Consolidated Statement of Comprehensive Income is provided below.
For the year ended December 31, 2012, net profit before certain non-cash
items, net of associated deferred tax impacts, was $21.7 million compared to a
net profit of $17.1 million in the 2011 year.
Reconciliation of Net Profit (Loss) to Net Profit
Before Certain Non-Cash Items
Years ended December 31,
($000s) 2012 2011
Net profit (loss) per financial statements 27,771 (5,949)
Items subject to reversal
Impairment loss on property, plant and 14,820 25,569
equipment
Unrealized (gain) loss on commodity (10,806) 6,900
contracts
Loss (gain) on property dispositions 4,113 (1,730)
Gain on property acquisition (16,160) -
Deferred tax impact of above items 2,008 (7,685)
Net profit before certain non-cash items 21,746 17,105
A net profit of $27.8 million ($0.26 per basic share and $0.25 per diluted
share) was recognized for the year ended December 31, 2012, compared to a net
loss of $5.9 million ($0.06 per basic share and $0.06 per diluted share) in
the 2011 year. The net profit recorded in the year ended December 31, 2012
compared to the net loss recorded in the 2011 year is primarily a consequence
of higher cash flows as noted above, a $16.2 million gain on property
acquisition recognized in 2012, a net unrealized gain on commodity contracts
in the 2012 year compared to a loss in 2011, and a lower non-cash impairment
loss on oil and gas properties, offset somewhat by a higher depletion and
depreciation expense, a total net loss on property dispositions compared to a
minor gain on property dispositions in the comparative 2011 year, and a higher
deferred tax expense.
Cash Flow from Operating Activities, Funds Flow from Operations and Net Profit
(Loss)
Years ended December 31,
($000s, except per share amounts) 2012 2011
Cash flow from operating activities 109,328 98,192
Basic ($/share) 1.02 0.95
Diluted ($/share) 0.95 0.87
Funds flow from operations 111,038 94,237
Basic ($/share) 1.03 0.91
Diluted ($/share) 0.96 0.84
Net profit (loss) 27,771 (5,949)
Basic ($/share) 0.26 (0.06)
Diluted ($/share) 0.25 (0.06)
Capital Expenditures
Bellatrix invested $185.3 million in capital expenditures, including a $21.0
million property acquisition, during the year ended December 31, 2012,
compared to $179.6 million in the 2011 year.
Capital Expenditures
Years ended December 31,
($000s) 2012 2011
Lease acquisitions and retention 8,303 16,367
Geological and geophysical 290 433
Drilling and completion costs 118,783 141,051
Facilities and equipment 36,811 18,471
164,187 176,322
Drilling incentive credits - (827)
Exploration and development ^(1) 164,187 175,495
Corporate ^(2) 195 268
Property acquisition 20,966 3,798
Total capital expenditures - cash 185,348 179,561
Property dispositions - cash (6,660) (4,203)
Total net capital expenditures - cash 178,688 175,358
Capital lease additions - non-cash 10,000 3,700
Adjustment on property acquisition - non-cash 16,160 -
Other - non-cash ^(3) (285) 6,875
Total non-cash 25,875 10,575
Total net capital expenditures 204,563 185,933
(1) Excludes capitalized costs related to decommissioning liabilities
expenditures incurred during the year.
(2) Corporate includes office furniture, fixtures and equipment.
(3) Other includes non-cash adjustments for the current year's
decommissioning liabilities and share based compensation.
During the 2012 year, Bellatrix posted a 100% success rate drilling and/or
participating in 34 gross (26.32 net) wells, resulting in 28 gross (21.32 net)
Cardium oil wells, 2 gross (2.0 net) Cardium condensate-rich gas wells, 1
gross (1.0 net) Duvernay gas well, and 3 gross (2.0 net) Notikewin/Falher
liquids-rich gas wells.
By comparison, Bellatrix drilled or participated in 54 gross (34.84 net) wells
during the year ended December 31, 2011, including 39 gross (29.04 net) oil
wells, 14 gross (5.79 net) liquids-rich natural gas wells, and 1 gross (0.007
net) dry hole that was drilled in a non-operated oil unit.
The $185.3 million capital program for the year ended December 31, 2012 was
financed from funds flow from operations and bank debt.
Based on the current economic conditions and Bellatrix's operating forecast
for 2013, the Company budgets a capital program between $230 to $240 million
funded from the Company's cash flows and to the extent necessary, bank
indebtedness. The 2013 capital budget is expected to be directed primarily
towards horizontal drilling and completions activities in the Cardium and
Notikewin areas.
Decommissioning Liabilities
At December 31, 2012, Bellatrix has recorded decommissioning liabilities of
$43.9 million, compared to $45.1 million at December 31, 2011, for future
abandonment and reclamation of the Company's properties. For the year ended
December 31, 2012, decommissioning liabilities decreased by a net $1.2 million
as a result of a reduction of $3.0 million for liabilities reversed on
dispositions, a $0.7 million decrease for changes in estimates, and a $0.6
million decrease for liabilities settled during the year, offset by $2.4
million incurred on property acquisitions and development activities, and $0.7
million as a result of charges for the unwinding of the discount rates used
for fair valuing the liabilities. The $0.7 million decrease as a result of
changes in estimates is primarily due to a discount rate variations at
December 31, 2012 compared to 2011, in addition to other abandonment liability
revisions.
Liquidity and Capital Resources
As an oil and gas business, Bellatrix has a declining asset base and therefore
relies on ongoing development and acquisitions to replace production and add
additional reserves. Future oil and natural gas production and reserves are
highly dependent on the success of exploiting the Company's existing asset
base and in acquiring additional reserves. To the extent Bellatrix is
successful or unsuccessful in these activities, cash flow could be increased
or reduced.
Bellatrix is focused on growing oil and natural gas production from its
diversified portfolio of existing and emerging resource plays in Western
Canada. Bellatrix remains highly focused on key business objectives of
maintaining financial strength, optimizing capital investments - attained
through a disciplined approach to capital spending, a flexible investment
program and financial stewardship. Natural gas prices are primarily driven by
North American supply and demand, with weather being the key factor in the
short term. Bellatrix believes that natural gas represents an abundant,
secure, long-term supply of energy to meet North American needs. Bellatrix's
results are affected by external market and risk factors, such as fluctuations
in the prices of crude oil and natural gas, movements in foreign currency
exchange rates and inflationary pressures on service costs. Market conditions
have resulted in Bellatrix experiencing primarily downward trends in crude oil
pricing for 2012 compared to 2011, and a more significant downward trend in
natural gas pricing, although natural gas prices started to recover in the
second half of 2012.
Liquidity risk is the risk that Bellatrix will not be able to meet its
financial obligations as they become due. Bellatrix actively manages its
liquidity through daily and longer-term cash, debt and equity management
strategies. Such strategies encompass, among other factors: having adequate
sources of financing available through its bank credit facilities, estimating
future cash generated from operations based on reasonable production and
pricing assumptions, analysis of economic risk management opportunities, and
maintaining sufficient cash flows for compliance with operating debt
covenants. Bellatrix is fully compliant with all of its operating debt
covenants.
Bellatrix generally relies on operating cash flows and its credit facilities
to fund capital requirements and provide liquidity. Future liquidity depends
primarily on cash flow generated from operations, existing credit facilities
and the ability to access debt and equity markets. From time to time, the
Company accesses capital markets to meet its additional financing needs and to
maintain flexibility in funding its capital programs. There can be no
assurance that future debt or equity financing, or cash generated by
operations will be available or sufficient to meet these requirements or for
other corporate purposes or, if debt or equity financing is available, that it
will be on terms acceptable to Bellatrix.
Credit risk is the risk of financial loss to Bellatrix if a customer or
counterparty to a financial instrument fails to meet its contractual
obligations, and arises principally from Bellatrix's trade receivables from
joint venture partners, petroleum and natural gas marketers, and financial
derivative counterparties.
A substantial portion of Bellatrix's accounts receivable are with customers
and joint interest partners in the petroleum and natural gas industry and are
subject to normal industry credit risks. Bellatrix sells substantially all of
its production to seven primary purchasers under standard industry sale and
payment terms. The most significant 60 day exposure to a single counterparty
is currently approximately $12.6 million. Purchasers of Bellatrix's natural
gas, crude oil and natural gas liquids are subject to a periodic internal
credit review to minimize the risk of non-payment. Bellatrix has continued to
closely monitor and reassess the creditworthiness of its counterparties,
including financial institutions. This has resulted in Bellatrix reducing or
mitigating its exposures to certain counterparties where it is deemed
warranted and permitted under contractual terms.
Bellatrix may be exposed to third party credit risk through its contractual
arrangements with its current or future joint venture partners, marketers of
its petroleum and natural gas production, derivative counterparties and other
parties. In the event such entities fail to meet their contractual
obligations to Bellatrix, such failures may have a material adverse effect on
the Company's business, financial condition, results of operations and
prospects. In addition, poor credit conditions in the industry and of joint
venture partners may impact a joint venture partner's willingness to
participate in Bellatrix's ongoing capital program, potentially delaying the
program and the results of such program until Bellatrix finds a suitable
alternative partner.
Total net debt levels of $189.6 million at December 31, 2012 have increased by
$70.3 million from $119.3 million at December 31, 2011, primarily as a
consequence of an increase in a working capital deficiency and bank debt as
the Company executed its 2012 capital program. Total net debt includes the
liability component of the 4.75% Debentures and excludes unrealized commodity
contract assets and liabilities, deferred taxes, finance lease obligations,
deferred liabilities and decommissioning liabilities.
Funds flow from operations represents 60% of the funding requirements for
Bellatrix's capital expenditures for the year ended December 31, 2012.
Effective December 13, 2012, the Company's borrowing base was increased from
$200 million to $220 million through to the next scheduled borrowing base
determination to be completed on or before May 31, 2013. Effective May 31,
2012, the revolving period of the credit facility was extended from June 26,
2012 to June 25, 2013. The Company's credit facilities consist of a $25
million demand operating facility provided by a Canadian bank and a $195
million extendible revolving term credit facility provided by two Canadian
banks and a Canadian financial institution. Amounts borrowed under the credit
facility bear interest at a floating rate based on the applicable Canadian
prime rate, U.S. base rate, the LIBOR margin rate, or the bankers' acceptance
stamping fee, plus between 1.00% and 3.50%, depending on the type of borrowing
and the Company's debt to cash flow ratio. The credit facilities are secured
by a $400 million debenture containing a first ranking charge and security
interest. Bellatrix has provided a negative pledge and undertaking to provide
fixed charges over its properties in certain circumstances. A standby fee is
charged of between 0.50% and 0.875% on the undrawn portion of the credit
facilities, depending on the Company's debt to cash flow ratio.
The revolving period for the revolving term credit facility will end on June
25, 2013, unless extended for a further 364 day period. Should the facility
not be extended it will convert to a non-revolving term facility with the full
amount outstanding due 366 days after the last day of the revolving period of
June 25, 2013. The borrowing base will be subject to re-determination on May
31 and November 30 in each year prior to maturity, with the next semi-annual
redetermination occurring on May 31, 2013.
As at December 31, 2012, approximately $87.0 million or 40% of unused and
available bank credit under its credit facilities was available to fund
Bellatrix's ongoing capital spending and operational requirements.
Bellatrix currently has commitments associated with its credit facilities
outlined above and the commitments outlined under the "Commitments" section.
Bellatrix continually monitors its capital spending program in light of the
recent volatility with respect to commodity prices and Canadian dollar
exchange rates with the aim of ensuring the Company will be able to meet
future anticipated obligations incurred from normal ongoing operations with
funds flow from operations and draws on Bellatrix's credit facility, as
necessary. Bellatrix has the ability to fund its 2013 capital program of $230
to $240 million by utilizing cash flow, and to the extent necessary, bank
indebtedness.
As at February 25, 2013, Bellatrix had outstanding a total of 9,334,894
options exercisable at an average exercise price of $3.45 per share, $55.0
million principal amount of 4.75% Debentures convertible into common shares
(at a conversion price of $5.60 per share) and 107,880,996 common shares.
Related Party Transactions
Previous to 2012, the Company entered into agreements to obtain financing in
the amount of $5.3 million for the construction of certain facilities.
Members of the Company's management team and entities affiliated with them
provided financing of $900,000. The terms of the transactions with those
related parties were the same as those with arms-length participants.
Commitments
As at December 31, 2012, Bellatrix committed to drill 3 gross (1.7 net) wells
pursuant to farm-in agreements. Bellatrix expects to satisfy these drilling
commitments at an estimated cost of approximately $6.5 million.
In addition, Bellatrix entered into two joint venture agreements during the
2011 year and an additional joint venture agreement during 2012. The
agreements include a minimum commitment for the Company to drill a specified
number of wells each year over the term of the individual agreements. The
details of these agreements are provided in the table below:
Joint Venture Agreement Feb. 1, 2011 Aug. 4, 2011 Dec. 14, 2012
Agreement Term 2011 to 2015 2011 to 2016 2014 to 2018
Minimum wells per year (gross 3 5 to 10 2
and net)
Minimum total wells (gross and 15 40 10
net)
Estimated total cost ($000s) $52.5 $140.0 $35.0
Remaining wells to drill at 8 32 10
December 31, 2012
Remaining estimated total cost $28.0 $112.0 $35.0
($000s)
The Company has the following liabilities as at December 31, 2012:
More
Liabilities < 1 than
($000s) Total Year 1-3 Years 4-5 Years 5 years
Accounts payable $ $ $
and accrued $ $
liabilities ^(1) 50,771 50,771 - - -
Long-term debt -
principal ^(2) 133,047 - 133,047 - -
Convertible
debentures -
principal 55,000 - 55,000 - -
Convertible
debentures -
interest ^(3) 6,085 2,613 3,472 - -
Commodity
contract
liability 7,345 1,131 6,214 - -
Decommissioning
liabilities ^(4) 43,909 - 7,187 5,796 30,926
Finance lease
obligation 14,556 1,425 3,069 3,172 6,890
$ $ $
Total 310,713 55,940 $ 207,989 $ 8,968 37,816
^(1) Includes $0.4 million of accrued coupon interest payable in relation to
the 4.75% Debentures and $0.2 million of accrued interest payable in
relation to the credit facilities is included in Accounts Payable and
Accrued Liabilities.
^(2) Bank debt is based on a revolving term which is reviewed annually and
converts to a 366 day non-revolving facility if not renewed. Interest
due on the bank credit facility is calculated based upon floating rates.
^(3) The 4.75% Debentures outstanding at December 31, 2012 bear interest at a
coupon rate of 4.75%, which currently requires total annual interest
payments of $2.6 million.
^(4) Amounts represent the inflated, discounted future abandonment and
reclamation expenditures anticipated to be incurred over the life of the
Company's properties (between 2013 and 2053).
Bellatrix will also have drilling commitments associated with its recently
announced joint venture agreement in January, 2013 with a South Korean based
company. Closing of this agreement is expected to occur on or before April 30,
2013. Refer to the details discussed earlier herein.
Off-Balance Sheet Arrangements
The Company has certain fixed term lease agreements, including primarily
office space leases, which were entered into in the normal course of
operations. All leases have been treated as operating leases whereby the
lease payments are included in operating expenses or G&A expenses depending on
the nature of the lease. The lease agreements do not currently provide for
early termination. No asset or liability value has been assigned to these
leases in the balance sheet as of December 31, 2012.
The Company is committed to payments under fixed term operating leases which
do not currently provide for early termination. The Company's commitment for
office space as at December 31, 2012 is as follows:
($000s) Gross Expected
Year Amount Recoveries Net amount
2013 $ 2,254 $ 947 $ 1,307
2014 1,520 641 879
Subsequent to year end, Bellatrix entered into a fixed term operating lease
agreement for corporate office space in a new location, commencing September
1, 2013. Bellatrix is currently pursuing subleasing options for the remaining
term of its existing corporate office space. A summary of the Company's
commitment for the new office space is as follows:
($000s)
Year Total amount
2013 $ 388
2014 2,153
2015 2,243
2016 2,243
2017 2,243
More than 5 years 14,449
Business Prospects and 2013 Year Outlook
Bellatrix continues to develop its core assets and conduct exploration
programs utilizing its large inventory of geological prospects. As at
December 31, 2012, Bellatrix has approximately 206,638 net undeveloped acres
and including all opportunities has in excess of 1,700 net exploration
drilling opportunities identified.
As a result of the recently announced joint venture with a Seoul Korea based
company, Bellatrix's 2013 capital expenditure budget has been increased to
between $230 and $240 million. A total capital program of $365 million is
anticipated including the capital expected to be invested by the joint venture
partner. Based on the timing of proposed expenditures, downtime for scheduled
and unscheduled plant turnarounds, completion of required infrastructure, and
normal production declines, execution of the 2013 capital expenditure plan is
expected to provide average daily production of approximately 24,000 boe/d to
25,000 boe/d, and an exit rate of approximately 30,000 boe/d to 31,000 boe/d.
The Company has initiated the 2013 program by instituting drilling of multiple
horizontal wells from single surface locations. Pad drilling enhances the
opportunity to efficiently develop the resource while minimizing the
environmental footprint and improving our cost and on-stream efficiencies.
Pad drilling also facilitates drilling through the spring breakup months of
Q2. As a result the Company plans to run 3 rigs throughout the second quarter
ramping up to 7 or 8 rigs for the second half of 2013.
Financial Reporting Update
Future Accounting Pronouncements
The following pronouncements from the IASB are applicable to Bellatrix and
will become effective for future reporting periods, but have not yet been
adopted:
IFRS 9 - "Financial Instruments", which is the result of the first phase of
the IASB's project to replace IAS 39, "Financial Instruments: Recognition and
Measurement". The new standard replaces the current multiple classification
and measurement models for financial assets and liabilities with a single
model that has only two classification categories: amortized cost and fair
value. This standard is effective for annual periods beginning on or after
January 1, 2015 with different transitional arrangements depending on the date
of initial application. The extent of the impact of the adoption of IFRS 9 has
not yet been determined.
IFRS 10 - "Consolidated Financial Statements" ("IFRS 10"), which 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. Under existing IFRS,
consolidation is required when an entity has the power to govern the financial
and operating policies of an entity so as to obtain benefits from its
activities. This standard replaces SIC-12 - "Consolidation—Special Purpose
Entities" and parts of IAS 27 - "Consolidated and Separate Financial
Statements." Bellatrix intends to adopt IFRS 10, including the amendments
issued in June 2012, in its financial statements for the annual period
beginning on January 1, 2013. The adoption of IFRS 10 is currently not
anticipated to impact the Company's financial statements.
IFRS 11 - "Joint Arrangements" ("IFRS 11"), requires a venturer to classify
its interest in a joint arrangement as a joint venture or joint operation,
each having its own accounting model. Joint ventures will be accounted for
using the equity method of accounting, whereas for a joint operation the
venture will recognize its share of the assets, liabilities, revenue and
expenses of the joint operation. The standard provides for a more substance
based reflection of joint arrangements by focusing on the rights and
obligations of the arrangement, rather than its legal form. IFRS 11 replaces
IAS 31 - "Interests in Joint Ventures" and SIC-13 - "Jointly Controlled
Entities—Non-monetary Contributions by Venturers" and establishes principles
for accounting for all joint arrangements. Bellatrix intends to adopt IFRS
11, including the amendments issued in June 2012, in its financial statements
for the annual period beginning on January 1, 2013. The adoption of IFRS 11
is currently not anticipated to have a significant impact on the Company's
financial statements.
IFRS 12 - "Disclosure of Interests in Other Entities" ("IFRS 12"), establishes
disclosure requirements for interests in other entities, such as joint
arrangements, associates, special purpose vehicles and off balance sheet
vehicles. The standard carries forward existing disclosures and also
introduces significant additional disclosure requirements that address the
nature of, and risks associated with, an entity's interests in other
entities. Bellatrix intends to adopt IFRS 12, including the amendments issued
in June 2012, in its financial statements for the annual period beginning on
January 1, 2013. The adoption of IFRS 12 is currently not anticipated to have
a significant impact on the Company's financial statements.
IFRS 13 - "Fair Value Measurement" ("IFRS 13"), is a comprehensive standard
for fair value measurement and disclosure requirements for use across all
IFRSs. The new standard clarifies that fair value is the price that would be
received to sell an asset, or paid to transfer a liability in an orderly
transaction between market participants, at the measurement date. It also
establishes disclosures about fair value measurement. Under existing IFRS,
guidance on measuring and disclosing fair value is dispersed among the
specific standards requiring fair value measurements and in many cases does
not reflect a clear measurement basis or consistent disclosures. IFRS 13 is
effective for annual periods beginning on or after January 1, 2013 and applies
prospectively from the beginning of the annual period in which the standard is
adopted. The extent of the impact of the adoption of IFRS 13 on the
Company's financial statements has not yet been determined.
In June 2011, the IASB issued an amendment to IAS 1 - "Presentation of
Financial Statements" ("IAS 1") requiring companies to group items presented
within Other Comprehensive Income based on whether they may be subsequently
reclassified to profit or loss. This amendment to IAS 1 is effective for
annual periods beginning on or after July 1, 2012 with full retrospective
application. Early adoption is permitted. Bellatrix intends to adopt the
amendments in its financial statements for the annual period beginning on
January 1, 2013. The extent of the impact of the amendments on the financial
statements has not yet been determined.
Business Risks and Uncertainties
General
Bellatrix's production and exploration activities are concentrated in the
Western Canadian Sedimentary Basin, where activity is highly competitive and
includes a variety of different sized companies ranging from smaller junior
producers to the much larger integrated petroleum companies.
Bellatrix is subject to the various types of business risks and uncertainties
including:
* Finding and developing oil and natural gas reserves at economic costs;
* Production of oil and natural gas in commercial quantities; and
* Marketability of oil and natural gas produced.
In order to reduce exploration risk, the Company strives to employ highly
qualified and motivated professional employees with a demonstrated ability to
generate quality proprietary geological and geophysical prospects. To help
maximize drilling success, Bellatrix combines exploration in areas that afford
multi-zone prospect potential, targeting a range of low to moderate risk
prospects with some exposure to select high-risk with high-reward
opportunities. Bellatrix also explores in areas where the Company has
significant drilling experience.
The Company mitigates its risk related to producing hydrocarbons through the
utilization of the most appropriate technology and information systems managed
by qualified personnel. In addition, Bellatrix seeks to maintain operational
control of the majority of its prospects.
Oil and gas exploration and production can involve environmental risks such as
pollution of the environment and destruction of natural habitat, as well as
safety risks such as personal injury. In order to mitigate such risks,
Bellatrix conducts its operations at high standards and follows safety
procedures intended to reduce the potential for personal injury to employees,
contractors and the public at large. The Company maintains current insurance
coverage for general and comprehensive liability as well as limited pollution
liability. The amount and terms of this insurance are reviewed on an ongoing
basis and adjusted as necessary to reflect changing corporate requirements, as
well as industry standards and government regulations. Bellatrix may
periodically use financial or physical delivery contracts to reduce its
exposure against the potential adverse impact of commodity price volatility,
as governed by formal policies approved by senior management subject to
controls established by the Board.
Pricing and Marketing
Oil
The producers of oil are entitled to negotiate sales contracts directly with
oil purchasers, with the result that the market determines the price of oil.
Worldwide supply and demand primarily determines oil prices. The specific
price depends in part on oil quality, prices of competing fuels, distance to
market, the availability of transportation, the value of refined products, the
supply/demand balance and contractual terms of sale. Oil exporters are also
entitled to enter into export contracts with terms not exceeding one year in
the case of light crude oil and two years in the case of heavy crude oil,
provided that an order approving such export has been obtained from the
National Energy Board of Canada (the "NEB"). Any oil export to be made
pursuant to a contract of longer duration (to a maximum of 25 years) requires
an exporter to obtain an export licence from the NEB. The NEB is currently
undergoing a consultation process to update the current regulations governing
the issuance of export licences. The updating process is necessary to meet the
criteria set out in the federal Jobs, Growth and Long-term Prosperity Act
which received Royal Assent on June 29, 2012 (the "Prosperity Act"). In this
transitory period, the NEB has issued, and is currently following an "Interim
Memorandum of Guidance concerning Oil and Gas Export Applications and Gas
Import Applications under Part VI of the National Energy Board Act".
Natural Gas
Alberta's natural gas market has been deregulated since 1985. Supply and
demand determine the price of natural gas and price is calculated at the sale
point, being the wellhead, the outlet of a gas processing plant, on a gas
transmission system such as the Alberta "NIT" (Nova Inventory Transfer), at a
storage facility, at the inlet to a utility system or at the point of receipt
by the consumer. Accordingly, the price for natural gas is dependent upon
such producer's own arrangements (whether long or short term contracts and the
specific point of sale). As natural gas is also traded on trading platforms
such as the Natural Gas Exchange (NGX) or the New York Mercantile Exchange
(NYMEX) in the United States, spot and future prices can be set by such supply
and demand. Natural gas exported from Canada is subject to regulation by the
NEB and the Government of Canada. Exporters are free to negotiate prices and
other terms with purchasers, provided that the export contracts must continue
to meet certain other criteria prescribed by the NEB and the Government of
Canada. Natural gas (other than propane, butane and ethane) exports for a
term of less than two years or for a term of two to 20 years (in quantities of
not more than 30,000 m3/day) must be made pursuant to an NEB order. Any
natural gas export to be made pursuant to a contract of longer duration (to a
maximum of 25 years) or for a larger quantity requires an exporter to obtain
an export licence from the NEB.
Royalties and Incentives - General
In addition to federal regulation, each province has legislation and
regulations which govern royalties, production rates and other matters. The
royalty regime in a given province is a significant factor in the
profitability of oil sands projects, crude oil, natural gas liquids, sulphur
and natural gas production. Royalties payable on production from lands other
than Crown lands are determined by negotiation between the mineral freehold
owner and the lessee, although production from such lands is subject to
certain provincial taxes and royalties. Royalties from production on Crown
lands are determined by governmental regulation and are generally calculated
as a percentage of the value of gross production. The rate of royalties
payable generally depends in part on prescribed reference prices, well
productivity, geographical location, field discovery date, method of recovery
and the type or quality of the petroleum product produced. Other royalties
and royalty like interests are carved out of the working interest owner's
interest, from time to time, through non public transactions. These are often
referred to as overriding royalties, gross overriding royalties, net profits
interests, or net carried interests.
Occasionally the governments of the western Canadian provinces create
incentive programs for exploration and development. Such programs often
provide for royalty rate reductions, royalty holidays or royalty tax credits
and are generally introduced when commodity prices are low to encourage
exploration and development activity by improving earnings and cash flow
within the industry.
Land Tenure
The respective provincial governments predominantly own crude oil and natural
gas located in the western provinces. Provincial governments grant rights to
explore for and produce oil and natural gas pursuant to leases, licences, and
permits for varying terms, and on conditions set forth in provincial
legislation including requirements to perform specific work or make payments.
Private ownership of oil and natural gas also exists in such provinces and
rights to explore for and produce such oil and natural gas are granted by
lease on such terms and conditions as may be negotiated.
Each of the provinces of Alberta, British Columbia and Saskatchewan has
implemented legislation providing for the reversion to the Crown of mineral
rights to deep, non-productive geological formations at the conclusion of the
primary term of a lease or license. On March 29, 2007, British Columbia
expanded its policy of deep rights reversion for new leases to provide for the
reversion of both shallow and deep formations that cannot be shown to be
capable of production at the end of their primary term.
Alberta also has a policy of "shallow rights reversion" which provides for the
reversion to the Crown of mineral rights to shallow, non-productive geological
formations for all leases and licenses. For leases and licenses issued
subsequent to January 1, 2009, shallow rights reversion will be applied at the
conclusion of the primary term of the lease or license. Holders of leases or
licences that have been continued indefinitely prior to January 1, 2009 will
receive a notice regarding the reversion of the shallow rights, which will be
implemented three years from the date of the notice. Leases and licences
granted prior to January 1, 2009, but continued after that date, are not
subject to shallow rights reversion until they continue past their primary
term (at which time the application of deep rights reversion occurs).
Afterwards, the holders of such agreements will be served with shallow rights
reversion notices based on vintage and location similar to leases and licences
that were already continued as of January 1, 2009. The order in which these
agreements will receive reversion notices will depend on their vintage and
location.
Environmental Regulation
The oil and natural gas industry is currently subject to environmental
regulations pursuant to a variety of provincial and federal legislation, all
of which is subject to governmental review and revision from time to time.
Such legislation provides for restrictions and prohibitions on the release or
emission of various substances produced in association with certain oil and
gas industry operations, such as sulphur dioxide and nitrous oxide. In
addition, such legislation sets out the requirements for the satisfactory
abandonment and reclamation of well and facility sites. Compliance with such
legislation can require significant expenditures and a breach of such
requirements may result in suspension or revocation of necessary licenses and
authorizations, civil liability for pollution damage, and the imposition of
material fines and penalties. Implementation of strategies for reducing
greenhouse gases could have a material impact on the nature of oil and gas
operations, including those of the Company. Given the evolving nature of the
debate related to climate change and the control of greenhouse gases and
resulting requirements, it is not possible to predict either the nature of
those requirements or the impact on the Company and its operations and
financial condition.
Global Financial Crisis
Recent market events and conditions, including disruptions in the
international credit markets and other financial systems and the American and
European sovereign debt levels have caused significant volatility in commodity
prices. These events and conditions have caused a decrease in confidence in
the broader U.S. and global credit and financial markets and have created a
climate of greater volatility, less liquidity, widening of credit spreads, a
lack of price transparency, increased credit losses and tighter credit
conditions. Notwithstanding various actions by governments, concerns about
the general condition of the capital markets, financial instruments, banks,
investment banks, insurers and other financial institutions caused the broader
credit markets to further deteriorate and stock markets to decline
substantially. While there are signs of economic recovery, these factors have
negatively impacted company valuations and are likely to continue to impact
the performance of the global economy going forward. Petroleum prices are
expected to remain volatile for the near future as a result of market
uncertainties over the supply and demand of these commodities due to the
current state of the world economies, actions taken by OPEC and the ongoing
global credit and liquidity concerns. This volatility may in the future affect
the Company's ability to obtain equity or debt financing on acceptable terms.
Substantial Capital Requirements
The Company anticipates making substantial capital expenditures for the
acquisition, exploration, development and production of oil and natural gas
reserves in the future. As future capital expenditures will be financed out
of cash generated from operations, borrowings and possible future equity
offerings, the Company's ability to do so is dependent on, among other
factors, the overall state of the capital markets, the Company's credit rating
(if applicable), interest rates, royalty rates, tax burden due to current and
future tax laws, and investor appetite for investments in the energy industry
and the Company's securities in particular. Further, if the Company's
revenues or reserves decline, it may not have access to the capital necessary
to undertake or complete future drilling programs. There can be no assurance
that debt or equity financing, or cash generated by operations will be
available or sufficient to meet these requirements or for other corporate
purposes or, if debt or equity financing is available, that it will be on
terms acceptable to the Company. The inability of the Company to access
sufficient capital for its operations could have a material adverse effect on
the Company's business financial condition, results of operations and
prospects.
Third Party Credit Risk
The Company may be exposed to third party credit risk through its contractual
arrangements with its current or future joint venture partners, marketers of
its petroleum and natural gas production and other parties. In the event such
entities fail to meet their contractual obligations to the Company, such
failures may have a material adverse effect on the Company's business,
financial condition, results of operations and prospects. In addition, poor
credit conditions in the industry and of joint venture partners may impact a
joint venture partner's willingness to participate in the Company's ongoing
capital program, potentially delaying the program and the results of such
program until the Company finds a suitable alternative partner.
Critical Accounting Estimates
The reader is advised that the critical accounting estimates, policies, and
practices as described herein continue to be critical in determining
Bellatrix's financial results.
The reader is cautioned that the preparation of financial statements in
accordance with GAAP requires management to make certain judgments and
estimates that affect the reported amounts of assets, liabilities, revenues
and expenses. The following discussion outlines accounting policies and
practices that are critical to determining Bellatrix's financial results.
Derivatives
The fair value of commodity contracts is estimated, whenever possible, based
on published market prices, and if not available, on estimates from third
party brokers, as at the balance sheet date and may differ from what will
eventually be realized.
Oil and gas reserves
Reserves and resources are used in the units of production calculation for
depreciation, depletion and amortization and the impairment analysis which
affect net profit. There are numerous uncertainties inherent in estimating
oil and gas reserves. Estimating reserves is very complex, requiring many
judgments based on geological, geophysical, engineering and economic data.
Changes in these judgments could have a material impact on the estimated
reserves. These estimates may change, having either a negative or positive
effect on net profit as further information becomes available and as the
economic environment changes.
Depreciation and depletion
Depletion of petroleum and natural gas properties is provided using the
unit-of-production method based on production volumes before royalties in
relation to total estimated proved and probable reserves as determined
annually by independent engineers and internal reserve evaluations on a
quarterly basis determined in accordance with National Instrument 51-101.
Natural gas reserves and production are converted at the energy equivalent of
six thousand cubic feet to one barrel of oil.
Calculations for depletion and depreciation of production equipment are based
on total capitalized costs plus estimated future development costs of proved
and probable undeveloped reserves less the estimated net realizable value of
production equipment and facilities after the proved reserves are fully
produced. The costs of acquiring and evaluating unproved properties are
excluded from depletion calculations.
Recoverability of asset carrying values
The Company assesses its oil and gas properties, including exploration and
evaluation assets, for possible impairment if there are events or changes in
circumstances that indicate that carrying values of the assets may not be
recoverable, or at least at every reporting date.
The assessment of any impairment of property, plant and equipment is dependent
upon estimates of recoverable amount that take into account factors such as
reserves, economic and market conditions, timing of cash flows, the useful
lives of assets and their related salvage values.
Bellatrix's assets are aggregated into CGUs, for the purpose of calculating
impairment, based on their ability to generate largely independent cash flows,
geography, geology, production profile and infrastructure of its assets. By
their nature, these estimates and assumptions are subject to measurement
uncertainty and may impact the carrying value of the Company's assets in
future periods.
Decommissioning obligations
Provisions for decommissioning obligations associated with the Company's
drilling operations are based on current legal and constructive requirements,
technology, price levels and expected plans for remediation. Actual costs and
cash outflows can differ from estimates because of changes in laws and
regulations, public expectations, prices, discovery and analysis of site
conditions and changes in clean up technology.
Share-based compensation
The fair value of stock options granted is measured using a Black Scholes
model. Measurement inputs include share price on measurement date, exercise
price of the option, expected volatility, expected life of the options,
expected dividends and the risk-free rate. The Company estimates volatility
based on the historical share price. The expected life of the options is
based on historical experience and general option holder behavior. Dividends
were not taken into consideration as the Company does not expect to pay
dividends. Management also makes an estimate of the number of options that
will be forfeited and the rate is adjusted to reflect the actual number of
options that actually vest.
Income taxes
Related assets and liabilities are recognized for the estimated tax
consequences between amounts included in the financial statements and their
tax base using substantively enacted future income tax rates. Timing of
future revenue streams and future capital spending changes can affect the
timing of any temporary differences, and accordingly affect the amount of the
deferred tax asset or liability calculated at a point in time. These
differences could materially impact earnings.
Business combinations
Business combinations are accounted for using the acquisition method of
accounting. The determination of fair value often requires management to make
assumptions and estimates about future events. The assumptions and estimates
with respect to determining the fair value of property, plant, and equipment,
and exploration and evaluation assets acquired generally require the most
judgment and include estimates of reserves acquired, forecast benchmark
commodity prices, and discount rates. Changes in any of the assumptions or
estimates used in determining the fair value of acquired assets and
liabilities could impact the amounts assigned to assets, liabilities in the
purchase price allocation, and any resulting gain or loss. Future net earnings
can be affected as a result of changes in future depletion, depreciation and
accretion, and asset impairments.
Legal, Environmental Remediation and Other Contingent Matters
The Company is involved in various claims and litigation arising in the normal
course of business. While the outcome of these matters is uncertain and there
can be no assurance that such matters will be resolved in the Company's favor,
the Company does not currently believe that the outcome of adverse decisions
in any pending or threatened proceeding related to these and other matters or
any amount which it may be required to pay by reason thereof would have a
material adverse impact on its financial position or results of operations.
The Company reviews legal, environmental remediation and other contingent
matters to both determine whether a loss is probable based on judgment and
interpretation of laws and regulations and determine that the loss can
reasonably be estimated. When the loss is determined, it is charged to
earnings. The Company's management monitor known and potential contingent
matters and make appropriate provisions by charges to earnings when warranted
by the circumstances.
With the above risks and uncertainties the reader is cautioned that future
events and results may vary substantially from that which Bellatrix currently
foresees.
Controls and Procedures
Disclosure Controls and Procedures
The Company's Chief Executive Officer and Chief Financial Officer have
designed, or caused to be designed under their supervision, disclosure
controls and procedures to provide reasonable assurance that: (i) material
information relating to the Company is made known to the Company's Chief
Executive Officer and Chief Financial Officer by others, particularly during
the period in which the annual and interim filings are being prepared; and
(ii) information required to be disclosed by the Company in its annual
filings, interim filings or other reports filed or submitted by it under
securities legislation is recorded, processed, summarized and reported within
the time period specified in securities legislation. Such officers have
evaluated, or caused to be evaluated under their supervision, the
effectiveness of the Company's disclosure controls and procedures at the
financial year end of the Company and have concluded that the Company's
disclosure controls and procedures are effective at the financial year end of
the Company for the foregoing purposes.
Internal Control over Financial Reporting
The Company's Chief Executive Officer and Chief Financial Officer have
designed, or caused to be designed under their supervision, internal control
over financial reporting to provide reasonable assurance regarding the
reliability of the Company's financial reporting and the preparation of
financial statements for external purposes in accordance with GAAP. Such
officers have evaluated, or caused to be evaluated under their supervision,
the effectiveness of the Company's internal control over financial reporting
at the financial year end of the Company and concluded that the Company's
internal control over financial reporting is effective at the financial year
end of the Company for the foregoing purpose.
The Company is required to disclose herein any change in the Company's
internal control over financial reporting that occurred during the period
beginning on October 1, 2012 and ended on December 31, 2012 that has
materially affected, or is reasonably likely to materially affect, the
Company's internal control over financial reporting. No material changes in
the Company's internal control over financial reporting were identified during
such period that has materially affected, or are reasonably likely to
materially affect, the Company's internal control over financial reporting.
It should be noted that a control system, including the Company's disclosure
and internal controls and procedures, no matter how well conceived, can
provide only reasonable, but not absolute, assurance that the objectives of
the control system will be met and it should not be expected that the
disclosure and internal controls and procedures will prevent all errors or
fraud.
Sensitivity Analysis
The table below shows sensitivities to funds flow from operations as a result
of product price, exchange rate, and interest rate changes. This is based on
actual average prices received for the fourth quarter of 2012 and average
production volumes of 18,763 boe/d during that period, as well as the same
level of debt outstanding at December 31, 2012. Diluted weighted average
shares are based upon the fourth quarter of 2012. These sensitivities are
approximations only, and not necessarily valid under other significantly
different production levels or product mixes. Commodity price risk management
activities can significantly affect these sensitivities. Changes in any of
these parameters will affect funds flow as shown in the table below:
Funds Flow from Funds Flow from
Operations ^(1) Operations ^ (1)
(annualized) Per Diluted Share
Sensitivity Analysis ($000s) ($)
Change of US $1/bbl WTI 1,500 0.01
Change of $0.10/ mcf 2,600 0.02
Change of US $0.01 CDN/ US 1,100 0.01
exchange rate
Change in prime of 1% 1,300 0.01
(1) The term "funds flow from operations" should not be considered an
alternative to, or more meaningful than cash flow from operating
activities as determined in accordance with GAAP as an indicator of the
Company's performance. Therefore reference to additional GAAP measures of
diluted funds flow from operations or funds flow from operations per share
may not be comparable with the calculation of similar measures for other
entities. Management uses funds flow from operations to analyze operating
performance and leverage and considers funds flow from operations to be a
key measure as it demonstrates the Company's ability to generate the cash
necessary to fund future capital investments and to repay debt. The
reconciliation between cash flow from operating activities and funds flow
from operations can be found elsewhere herein. Funds flow from operations
per share is calculated using the weighted average number of common shares
for the period.
Selected Quarterly Consolidated Information
The following table sets forth selected consolidated financial information of
the Company for the quarters in 2012 and 2011.
2012 - Quarter ended (unaudited)
($000s, except per share amounts) March 31 June 30 Sept. 30 Dec. 31
Revenues before royalties and risk
management 58,191 50,714 48,126 62,283
Cash flow from operating activities 24,056 28,458 24,807 32,007
Cash flow from operating activities
per share
Basic $0.22 $0.24 $0.23 $0.30
Diluted $0.21 $0.22 $0.22 $0.28
Funds flow from operations ^(1) 29,194 25,366 26,613 29,865
Funds flow from operations per
share ^(1)
Basic $0.27 $0.24 $0.25 $0.28
Diluted $0.25 $0.22 $0.23 $0.26
Net profit (loss) 9,172 9,963 (615) 9,251
Net profit (loss) per share
Basic $0.09 $0.09 ($0.01) $0.09
Diluted $0.08 $0.09 ($0.01) $0.08
Net capital expenditures (cash) 73,831 16,284 35,515 64,383
2011 - Quarter ended (unaudited)
($000s, except per share amounts) March 31 June 30 Sept. 30 Dec. 31
Revenues before royalties and risk
management 40,535 53,444 49,145 59,194
Cash flow from operating activities 15,718 23,825 28,023 30,626
Cash flow from operating activities
per share
Basic $0.16 $0.23 $0.26 $0.28
Diluted $0.15 $0.22 $0.24 $0.26
Funds flow from operations ^(1) 17,027 23,126 23,964 30,120
Funds flow from operations per
share ^(1)
Basic $0.17 $0.22 $0.22 $0.28
Diluted $0.16 $0.21 $0.21 $0.26
Net profit (loss) (5,487) 12,315 820 (13,597)
Net profit (loss) per share
Basic ($0.06) $0.12 $0.01 ($0.13)
Diluted ($0.06) $0.11 $0.01 ($0.13)
Net capital expenditures (cash) 59,247 28,784 40,087 47,240
^(1) Refer to "Additonal GAAP Measures" in respect of the term "funds flow
from operations" and "funds flow from operations per share".
The quarterly results for 2012 compared to 2011 were positively impacted by
increased production resulting from the expansion of Bellatrix's 2011 and 2012
drilling programs, offset somewhat by lower overall commodity prices realized
in the 2012 quarters compared to the 2011 quarters.
During the first quarter of 2012, the Company spent $74.1 million in capital
expenditures, compared to $59.1 million in the first quarter of 2011. The
Company drilled or participated in 13 gross (10.72 net) wells in the first
quarter of 2012, compared to 21 gross (12.07 net) wells in the comparative
2011 quarter. Higher sales volumes of 15,900 boe/d in the 2012 first quarter
compared to 10,084 boe/d in the 2011 period, in conjunction with stronger
crude oil and NGL pricing and offset slightly by depressed natural gas prices,
resulted in increased revenue of $58.2 million in the first quarter of 2012,
compared to $40.5 million in the 2011 first quarter.
In the second quarter of 2012, the Company closed on the disposition of two
minor non-core properties for total proceeds of $2.0 million after
adjustments. In the 2012 second quarter, the Company spent $18.3 million
(2011: $29.0 million) in capital expenditures, and drilled 2 gross (1.72 net)
wells, compared to 2 gross (1.71 net) wells in the same period in 2011. Due
primarily to Bellatrix's 2012 drilling program executed in the first and
second quarters, sales volumes increased by 42% to 16,569 boe/d in the second
quarter of 2012, compared to 11,643 boe/d in the second quarter of 2011.
During the third quarter of 2012, the Company closed on the disposition of a
minor non-core property interest in the Wainwright area for proceeds of $4.3
million after adjustments. In the third quarter of 2012, the Company spent
$39.8 million on capital expenditures compared to $44.2 million in the third
quarter of 2011. In the third quarter of 2012, Bellatrix drilled 9 gross (7.71
net) wells, compared to 19 gross (13.41 net) wells in the third quarter of
2011.
Fourth quarter of 2012 results are compared in detail to fourth quarter 2011
results throughout this MD&A.
Overall, the success and execution of the Company's 2012 drilling program
resulted in increased sales volumes and cash flows, despite weaker commodity
prices experienced during most of the 2012 year.
Selected Annual Consolidated Information
The following table sets forth selected consolidated financial information of
the Company for the most recently completed year ending December 31, 2012 and
for comparative 2011 and 2010 years. The adoption date of IFRS of January 1,
2011 required restatement for comparative purposes, of the Company's opening
balance sheet as at January 1, 2010, all interim quarterly periods in 2010 and
for its year ended December 31, 2010.
Years ended December 31,
($000s, except per share amounts) 2012 2011 2010
Revenues (before royalties and risk
management) 219,314 202,318 117,673
Funds flow from operations ^(1) 111,038 94,237 53,042
Funds flow from operations per share ^(1)
Basic $1.03 $0.91 $0.57
Diluted $0.96 $0.87 $0.54
Cash flow from operating activities
Cash flow from operating activities per
share 109,328 98,192 44,272
Basic $1.02 $0.95 $0.47
Diluted $0.95 $0.87 $0.46
Net profit (loss) 27,771 (5,949) (4,985)
Net profit (loss) per share
Basic $0.26 ($0.06) ($0.05)
Diluted $0.25 ($0.06) ($0.05)
Net capital expenditures (cash) (178,688) (175,358) (92,181)
Total assets 681,421 580,422 477,054
Total net debt ^(1) (2) 189,577 119,250 87,444
Non-current financial liabilities
Future income taxes - - -
Decommissioning liabilities 43,909 45,091 38,710
Sales volumes (boe/d) 16,775 11,954 8,519
Distributions declared - - -
Distributions per share/unit - - -
^(1) Refer to " Additional GAAP Measures" in respect of the terms "funds
flow from operations," "funds flow from operations per share," "net
debt" and "total net debt."
^(2) Net debt includes the net working capital deficiency before short-term
commodity contract assets and liabilities, current finance lease
obligations and short-term future income tax assets and liabilities.
Total net debt also includes the liability component of convertible
debentures and excludes finance lease obligations, decommissioning
liabilities and future income tax liabilities.
2012 annual results are compared in detail to 2011 annual results throughout
this MD&A.
The annual results for 2011 compared to 2010 were most notably impacted by an
expanded drilling program resulting in increased sales volumes. Revenues and
cash flows were impacted by increased sales volumes, higher crude oil,
condensate and NGL prices and lower natural gas prices realized, as well as
lower operating costs per boe between the years.
Bellatrix's capital expenditures totaled $179.6 million in 2011, compared to
$106.7 million in 2010. Due in large part to the expanded capital program in
2011, total sales volumes increased by 40% to 11,954 boe/d in 2011, compared
to 8,519 boe/d in 2010. Primarily due to the significant increase in sales
volumes between the years, revenues before royalties and risk management
increased to $202.3 million in 2011, compared to $117.7 million realized in
2010, despite reductions in commodity prices between the years.
BELLATRIX EXPLORATION LTD.
CONSOLIDATED BALANCE SHEETS
As at December 31,
(expressed in Canadian dollars)
($000s) 2012 2011
ASSETS
Current assets
Accounts receivable (note 21) $ $
40,792 45,322
Deposits and prepaid expenses 4,136 3,626
Commodity contract asset (note 21) 7,519 2,979
52,447 51,927
Exploration and evaluation assets (note 6) 38,177 33,089
Property, plant and equipment (note 7) 589,759 484,301
Deferred taxes (note 15) 1,038 11,105
Total assets $ $
681,421 580,422
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities $ $
50,771 62,421
Current portion of finance lease obligation (note 10) 1,425 490
Commodity contract liability (note 21) 1,131 10,667
53,327 73,578
Commodity contract liability (note 21) 6,214 2,944
Long-term debt (note 8) 133,047 56,701
Convertible debentures (note 9) 50,687 49,076
Finance lease obligation (note 10) 13,131 4,627
Decommissioning liabilities (note 11) 43,909 45,091
Total liabilities 300,315 232,017
SHAREHOLDERS' EQUITY
Shareholders' capital (note 12) 371,576 370,048
Equity component of convertible debentures (note 9) 4,378 4,378
Contributed surplus 37,284 33,882
Deficit (32,132) (59,903)
Total shareholders' equity 381,106 348,405
Total liabilities and shareholders' equity $ $
681,421 580,422
COMMITMENTS (note 20)
SUBSEQUENT EVENT (note 22)
See accompanying notes to the consolidated financial statements.
BELLATRIX EXPLORATION LTD.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the years ended December 31,
(expressed in Canadian dollars)
($000s) 2012 2011
REVENUES
Petroleum and natural gas sales $ 217,138 $ 200,187
Other income 2,176 2,131
Royalties (38,756) (34,698)
Total revenues 180,558 167,620
Realized gain on commodity contracts 11,269 567
Unrealized gain (loss) on commodity contracts 10,806 (6,900)
202,633 161,287
EXPENSES
Production 53,316 50,313
Transportation 4,978 5,715
General and administrative (note 17) 14,272 12,358
Share-based compensation (note 13) 3,219 2,939
Depletion and depreciation (note 7) 75,720 63,384
Gain on property acquisition (note 7) (16,160) -
Loss (gain) on property dispositions (note 7) 4,113 (1,730)
Impairment loss on property, plant and equipment 14,820 25,569
(note 7)
154,278 158,548
NET PROFIT BEFORE FINANCE AND TAXES 48,355 2,739
Finance expenses (note 16) 10,517 7,920
NET PROFIT (LOSS) BEFORE TAXES 37,838 (5,181)
TAXES
Deferred tax expense (note 15) 10,067 768
NET PROFIT (LOSS) AND COMPREHENSIVE INCOME 27,771 (5,949)
Net profit (loss) per share (note 19)
Basic $0.26 ($0.06)
Diluted $0.25 ($0.06)
See accompanying notes to the consolidated financial statements.
BELLATRIX EXPLORATION LTD.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
For the years ended December 31,
(expressed in Canadian dollars)
($000s) 2012 2011
SHAREHOLDERS' CAPITAL (note 12)
Common shares
Balance, beginning of year $ 370,048 $ 316,779
Issued for cash, net of transaction costs - 52,734
Issued on exercise of share options 1,093 381
Contributed surplus transferred on 435 154
exercised options
Balance, end of year 371,576 370,048
EQUITY COMPONENT OF CONVERTIBLE DEBENTURES (note
9)
Balance, beginning and end of year 4,378 4,378
CONTRIBUTED SURPLUS (note 13)
Balance, beginning of year 33,882 30,489
Share-based compensation expense 4,024 3,632
Adjustment of share-based compensation (187) (85)
expense for forfeitures of unvested share
options
Transfer to share capital for exercised (435) (154)
options
Balance, end of year 37,284 33,882
DEFICIT
Balance, beginning of year (59,903) (53,954)
Net profit (loss) 27,771 (5,949)
Balance, end of year (32,132) (59,903)
TOTAL SHAREHOLDERS' EQUITY $ 381,106 $ 348,405
See accompanying notes to the consolidated financial statements.
BELLATRIX EXPLORATION LTD.
CONSOLIDATED STATEMENTS OF CASH
FLOWS
For the years ended December 31,
(expressed in Canadian dollars)
($000s) 2012 2011
Cash provided by (used in):
CASH FLOW FROM OPERATING ACTIVITIES
Net profit (loss) $ 27,771 $ (5,949)
Adjustments for:
Depletion and 75,720 63,384
depreciation
Finance expenses (note 2,294 2,356
16)
Share-based compensation 3,219 2,939
(note 13)
Unrealized (gain) loss on (10,806) 6,900
commodity contracts
Gain on property (16,160) -
acquisition (note 7)
Loss (gain) on property 4,113 (1,730)
dispositions
Impairment loss on 14,820 25,569
property, plant and
equipment
Deferred tax expense 10,067 768
(note 15)
Decommissioning costs (635) (569)
incurred
Change in non-cash (1,075) 4,524
working capital (note 14)
109,328 98,192
CASH FLOW FROM (USED IN) FINANCING
ACTIVITIES
Issuance of share capital 1,093 55,385
Issue costs on share - (3,088)
capital
Advances from loans and 528,529 372,141
borrowings
Repayment of loans and (452,183) (356,612)
borrowings
Obligations under finance (560) (172)
lease (note 10)
76,879 67,654
Change in non-cash (55) 136
working capital (note 14)
76,824 67,790
CASH FLOW FROM (USED IN) INVESTING
ACTIVITIES
Expenditure on (17,118) (16,839)
exploration and
evaluation assets
Additions to property, (168,230) (162,722)
plant and equipment
Proceeds on sale of 6,660 4,203
property, plant and
equipment
(178,688) (175,358)
Change in non-cash (7,464) 9,376
working capital (note 14)
(186,152) (165,982)
Change in cash - -
Cash, beginning of year - -
Cash, end of year $ - $ -
Cash paid:
Interest $ 5,676 $ 4,738
Taxes - -
See accompanying notes to the
consolidated financial statements.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(expressed in Canadian dollars)
1. CORPORATE INFORMATION
Bellatrix Exploration Ltd. (the "Company" or "Bellatrix") is a growth
oriented, public exploration and production company.
2. BASIS OF PREPARATION
a. Statement of compliance
These consolidated financial statements ("financial statements") were
authorized by the Board of Directors on March 6, 2013. The Company prepared
these financial statements in accordance with International Financial
Reporting Standards as issued by the International Accounting Standards Board
("IFRS").
b. Basis of measurement
The consolidated financial statements are presented in Canadian dollars, the
Company's functional currency, and have been prepared on the historical cost
basis except for derivative financial instruments and liabilities for
cash-settled share-based payment arrangements measured at fair value. The
consolidated financial statements have, in management's opinion, been properly
prepared using careful judgment and reasonable limits of materiality and
within the framework of the significant policies summarized in note 3. The
areas involving a higher degree of judgment or complexity, or areas where
assumptions and estimates are significant to the financial statements are
disclosed in note 4.
3. SIGNIFICANT ACCOUNTING POLICIES
a. Principles of Consolidation
The consolidated financial statements include the accounts of the Company and
its subsidiary. Any reference to the "Company" throughout these consolidated
financial statements refers to the Company and its subsidiary. All
inter-entity transactions have been eliminated.
b. Revenue Recognition
Revenues from the sale of petroleum and natural gas are recorded when title to
the products transfers to the purchasers based on volumes delivered and
contracted delivery points and prices. Royalty income is recognized as it
accrues in accordance with the terms of the overriding royalty agreements and
is included with petroleum and natural gas sales.
Processing charges to other entities for use of facilities owned by the
Company are recognized as revenue as they accrue in accordance with the terms
of the service agreements and are presented as other income.
c. Joint Interests
A significant portion of the Company's exploration and development activities
are conducted jointly with others. The financial statements reflect only the
Company's proportionate share of the assets, liabilities, revenues, expenses
and cash flows from these activities.
d. Property, Plant and Equipment and Exploration and Evaluation Assets
I. Pre-exploration expenditures
Expenditures made by the Company before acquiring the legal right
to explore in a specific area do not meet the definition of an
asset and therefore are expensed by the Company as incurred.
II. Exploration and evaluation expenditures
Costs incurred once the legal right to explore has been acquired
are capitalized as exploration and evaluation assets. These costs
include, but are not limited to, exploration license expenditures,
leasehold property acquisition costs, evaluation costs, including
drilling costs directly attributable to an identifiable well and
directly attributable general and administrative costs. These
costs are accumulated in cost centres by property and are not
subject to depletion until technical feasibility and commercial
viability have been determined.
Exploration and evaluation assets are assessed for impairment if
sufficient data exists to determine technical feasibility and
commercial viability, or if facts and circumstances suggest that
the carrying amount is unlikely to be recovered.
III. Developing and production costs
Items of property, plant and equipment, which include oil and gas
development and production assets, are measured at cost less
accumulated depletion and depreciation and accumulated impairment
losses.
Gains and losses on disposal of an item of property, plant and
equipment, including oil and natural gas interests, are determined
by comparing the proceeds from disposal with the carrying amount
of property, plant and equipment, and are recognized within the
Consolidated Statements of Comprehensive Income.
IV. Subsequent costs
Costs incurred subsequent to the determination of technical
feasibility and commercial viability and the costs of replacing
parts of property, plant and equipment are recognized as oil and
natural gas interests only when they increase the future economic
benefits embodied in the specific asset to which they relate. All
other expenditures are recognized in profit or loss as incurred.
Such capitalized oil and natural gas interests generally represent
costs incurred in developing proved and/or probable reserves and
bringing in or enhancing production from such reserves, and are
accumulated on a well, field or geotechnical area basis. The
carrying amount of any replaced or sold component is derecognized.
The costs of the day-to-day servicing of property, plant and
equipment are recognized in profit or loss as incurred.
V. Depletion and depreciation
Depletion of petroleum and natural gas properties is provided
using the unit-of-production method based on production volumes in
relation to total estimated proven and probable reserves as
determined annually by independent engineers and determined in
accordance with National Instrument 51-101. Natural gas reserves
and production are converted at the energy equivalent of six
thousand cubic feet to one barrel of oil.
Calculations for depletion and depreciation of production
equipment are based on total capitalized costs plus estimated
future development costs of proven and probable undeveloped
reserves less the estimated net realizable value of production
equipment and facilities after the proved and probable reserves
are fully produced.
Depreciation of office furniture and equipment is provided for on
a 20% declining balance basis. Depreciation methods, useful lives
and residual values are reviewed at each reporting date.
e. Impairment
I. Financial assets
A financial asset is assessed at each reporting date to determine
whether there is any objective evidence that it is impaired. A
financial asset is considered to be impaired if objective evidence
indicates that one or more events have had a negative effect on the
estimated future cash flows of that asset.
An impairment loss in respect of a financial asset measured at
amortized cost is calculated as the difference between its carrying
amount and the present value of the estimated future cash flows
discounted at the original effective interest rate. All impairment
losses are recognized in profit or loss.
II. Non-financial assets
For the purpose of impairment testing, assets are grouped together
into the smallest group of assets that generates cash inflows from
continuing use that are largely independent of the cash inflows of
other assets or groups of assets (the "cash-generating unit" or
"CGU"). Developing and producing assets are assessed for impairment
if facts and circumstances suggest that the carrying amount exceeds
the recoverable amount.
The recoverable amount of an asset or a CGU is the greater of its
value in use and its fair value less costs to sell. Fair value less
costs to sell is determined to be the amount for which the asset
could be sold in an arm's length transaction. Fair value less costs
to sell can be determined by using an observable market metric or by
using discounted future net cash flows of proved and probable
reserves using forecasted prices and costs. Value in use is
determined by estimating the present value of the future net cash
flows expected to be derived from the continued use of the asset or
cash generating unit.
An impairment loss is recognized if the carrying amount of an asset
or its CGU exceeds its estimated recoverable amount. Impairment
losses are recognized in profit or loss. Impairment losses
recognized in respect of CGU's are allocated first to reduce the
carrying amount of goodwill, if any, allocated to the units and then
to reduce the carrying amounts of the other assets in the unit
(group of units) on a pro rata basis.
Impairment losses recognized in prior years are assessed at each
reporting date for any indications that the loss has decreased or no
longer exists. An impairment loss is reversed if there has been a
change in the estimates used to determine the recoverable amount. An
impairment loss is reversed only to the extent that the asset's
carrying amount does not exceed the carrying amount that would have
been determined, net of depletion and depreciation or amortization,
if no impairment loss had been recognized.
Exploration and evaluation assets are grouped together with the
Company's CGU's when they are assessed for impairment, both at the
time of any triggering facts and circumstances as well as upon their
eventual reclassification to producing assets (oil and natural gas
interests in property, plant and equipment).
f. Provisions
Provisions are recognized when the Company has a present legal or constructive
obligation as a result of a past event, it is probable that an outflow of
economic benefits will be required to settle the obligation and a reliable
estimate can be made of the amount of the obligation. Provisions are
determined by discounting the expected cash flows at a pre-tax rate that
reflects current market assessments of the time value of money and the risks
specific to the liability if the risks have not been incorporated into the
estimate of cash flows. The increase in the provision due to the passage of
time is recognized within finance costs.
I. Decommissioning obligations
The Company's activities give rise to dismantling, decommissioning
and site disturbance re-mediation activities. A provision is made
for the estimated cost of site restoration and capitalized in the
relevant asset category.
Decommissioning obligations are measured at the present value of
management's best estimate of the expenditure required to settle
the present obligation at the balance sheet date. Changes in the
present value of the estimated expenditure are reflected as an
adjustment to the provision and the relevant asset. The unwinding
of the discount on the decommissioning provision is recognized as a
finance cost. Actual costs incurred upon settlement of the
decommissioning liabilities are charged against the provision to
the extent the provision was recognized.
II. Environmental Liabilities
The Company records liabilities on an undiscounted basis for
environmental remediation efforts that are likely to occur and
where the cost can be reasonably estimated. The estimates,
including associated legal costs, are based on available
information using existing technology and enacted laws and
regulations. The estimates are subject to revision in future
periods based on actual costs incurred or new circumstances. Any
amounts expected to be recovered from other parties, including
insurers, are recorded as an asset separate from the associated
liability.
g. Share-based Payments
I. Equity-settled transactions
Bellatrix accounts for options issued under the Company's share
option plan to employees, directors, officers, consultants and
other service providers by reference to the fair value of the
equity instruments granted. The fair value of each share option is
estimated on the date of the grant using the Black-Scholes options
pricing model and charged to earnings over the vesting period with
a corresponding increase to contributed surplus. The Company
estimates a forfeiture rate on the grant date and the rate is
adjusted to reflect the actual number of options that actually
vest. The expected life of the options granted is adjusted, based
on the Company's best estimate, for the effects of
non-transferability, exercise restrictions and behavioural
considerations.
II. Cash-settled transactions
The Company's Deferred Share Unit Plan (the "Plan") is accounted
for as a cash settled share based payment plan in accordance with
IFRS 2 - "Share-based Payments" in which the fair value of the
amount payable under the Plan is recognized as an expense with a
corresponding increase in liabilities. The liability is re-measured
at each reporting date and at settlement date. Any changes in the
fair value of the liability are recognized in profit or loss.
h. Income Taxes
Income tax expense is comprised of current and deferred tax. Income tax
expense is recognized in profit or loss except to the extent that it relates
to items recognized directly in equity, in which case it is recognized in
equity.
I. Current income tax
Current income tax assets and liabilities for the current and prior
periods 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 date of the statement of financial position.
II. Deferred income tax
Deferred tax is recognized using the balance sheet method,
providing for temporary differences between the carrying amounts of
assets and liabilities for financial reporting purposes and the
amounts used for taxation purposes. Deferred tax is not recognized
on the initial recognition of assets or liabilities in a
transaction that is not a business combination. In addition,
deferred tax is not recognized for taxable temporary differences
arising on the initial recognition of goodwill. Deferred tax is
measured at the tax rates that are expected to be applied to
temporary differences when they reverse, based on the laws that
have been enacted or substantively enacted by the reporting date.
Deferred tax assets and liabilities are offset if there is a
legally enforceable right to offset, and they relate to income
taxes levied by the same tax authority on the same taxable entity,
or on different tax entities, but they intend to settle current tax
liabilities and assets on a net basis or their tax assets and
liabilities will be realized simultaneously.
A deferred tax asset is recognized to the extent that it is
probable that future taxable profits will be available against
which the temporary difference can be utilized. Deferred tax assets
are reviewed at each reporting date and are reduced to the extent
that it is no longer probable that the related tax benefit will be
realized.
i. Financial Instruments
All financial instruments, including all derivatives, are recognized on the
balance sheet initially at fair value. Subsequent measurement of all
financial assets and liabilities except those held-for-trading and available
for sale are measured at amortized cost determined using the effective
interest rate method. Held-for-trading financial assets are measured at fair
value with changes in fair value recognized in income. Available-for-sale
financial assets are measured at fair value with changes in fair value
recognized in comprehensive income and reclassified to income when
derecognized or impaired. The Company has the following classifications:
Financial Assets and Category Subsequent Measurement
Liabilities
Cash and cash equivalents Held-for-trading Fair value through profit
or loss
Accounts receivable Loans and receivables Amortized cost
Deposits and prepaid expenses Other assets Amortized cost
Commodity risk management Held-for-trading Fair value through profit
contracts or loss
Accounts payable and accrued Other liabilities Amortized cost
liabilities
Long-term debt Other liabilities Amortized cost
Convertible debentures Other liabilities Amortized cost
Finance lease obligation Other liabilities Amortized cost
Transaction costs attributable to financial instruments classified as other
than held-for-trading are included in the recognized amount of the related
financial instrument and recognized over the life of the resulting financial
instrument using the effective interest rate method.
The Company utilizes financial derivatives and commodity sales contracts
requiring physical delivery, to manage the price risk attributable to
anticipated sale of petroleum and natural gas production and foreign exchange
exposures. The Company does not enter into derivative financial instruments
for trading or speculative purposes. The Company has not designated its
financial derivative contracts as effective accounting hedges, and thus not
applied hedge accounting, even though the Company considers all commodity
contracts to be economic hedges. As a result, financial derivatives are
classified as fair value through profit or loss and are recorded on the
balance sheet at fair value.
The derivative financial instruments are initiated within the guidelines of
the Company's commodity price risk management policy. This includes linking
all derivatives to specific assets and liabilities on the balance sheet or to
specific firm commitments or forecasted transactions.
The Company accounts for its commodity sales and purchase contracts, which
were entered into and continue to be held for the purpose of receipt or
delivery of non-financial items in accordance with its expected purchase, sale
or usage requirements as executory contracts. As such, physical sales and
purchase contracts are not recorded at fair value on the balance sheet.
Settlements on these physical sales contracts are recognized in petroleum and
natural gas sales.
Financial instruments measured at fair value on the balance sheet require
classification into one of the following levels of the fair value hierarchy:
Level 1 - Quoted prices (unadjusted) in active markets for identical assets or
liabilities
Level 2 - Inputs other than quoted prices included in level 1 that are
observable for the asset or liability, either directly or indirectly.
Level 3 - inputs for the asset or liability that are not based on observable
market data.
The fair value hierarchy level at which a fair value measurement is
categorized is determined on the basis of the lowest level input that is
significant to the fair value measurement in its entirety. The Company has
categorized its financial instruments that are fair valued on the balance
sheet according to the fair value hierarchy.
j. Compound Financial Instruments
The Company's compound financial instruments comprise of its convertible
debentures that can be converted to common shares at the option of the holder,
and the number of shares to be issued does not vary with changes in fair
value.
The liability component of the convertible debentures is recognized initially
at the fair value of a similar liability that does not have an equity
conversion option. The equity component is recognized initially as the
difference between the fair value of the convertible debenture and the fair
value of the liability component. Any directly attributable transaction costs
are allocated to the liability and equity components in proportion to their
initial carrying amounts.
Subsequent to initial recognition, the liability component of the convertible
debentures is measured at amortized cost using the effective interest method.
The equity component of the convertible debentures is not re-measured
subsequent to initial recognition.
k. Finance Lease Obligation
Leases which effectively transfer substantially all of the risks and rewards
of ownership to the Company are classified as finance leases and are accounted
for as an acquisition of an asset and an assumption of an obligation at the
inception of the lease, measured as the present value of minimum lease
payments to a maximum of the asset's fair value. The asset is amortized in
accordance with the Company's depletion and depreciation policy. The
obligations recorded under finance lease payments are reduced by the lease
payments made.
l. Basic and Diluted per Share Calculations
Basic per share amounts are calculated using the weighted average number of
shares outstanding during the period. The Company uses the treasury share
method to determine the dilutive effect of share options. Under the treasury
share method, only "in the money" dilutive instruments impact the diluted
calculations in computing diluted per share amounts. The Company uses the
"if-converted" method to determine the dilutive effect of convertible
debentures.
m. Finance Income and Expenses
Finance income is recognized as it accrues in profit or loss, using the
effective interest method. Finance expense comprises interest expense on
borrowings, amortization of deferred charges, accretion of the discount rate
on provisions, accretion of the liability component of the convertible
debentures and impairment losses recognized on financial assets.
n. Borrowing Costs
Borrowing costs incurred for the construction of qualifying assets are
capitalized during the period of time that is required to complete and prepare
the assets for their intended use or sale. Qualifying assets are assets that
necessarily take a substantial period of time to get ready for their intended
use. All other borrowing costs are recognized in profit or loss using the
effective interest method. The capitalization rate used to determine the
amount of borrowing costs to be capitalized is the weighted average interest
rate applicable to the Company's outstanding borrowings during the period.
o. Cash and Cash Equivalents
Cash and cash equivalents include cash and short-term investments with
original maturities of three months or less.
p. Business Combinations
Business combinations are accounted for using the acquisition method. The
identifiable assets acquired and liabilities and contingent liabilities
assumed are measured at their fair values at the acquisition date. The cost
of an acquisition is measured as the aggregate consideration transferred,
measured at the acquisition date fair value. If the cost of the acquisition is
less than the fair value of the net assets acquired, the difference is
recognized immediately in net income. Acquisition costs incurred are expensed.
4. CRITICAL JUDGMENTS AND ACCOUNTING ESTIMATES
The consolidated financial statements of the Company have been prepared by
management in accordance with IFRS. The preparation of consolidated financial
statements in conformity with IFRS requires management to make judgment,
estimates and assumptions that affect the reported amounts of assets,
liabilities, and contingent liabilities at the date of the consolidated
financial statements and reported amounts of revenues and expenses during the
reporting period and accompanying notes. By their nature, these estimates are
subject to measurement uncertainty and the effect on the financial statements
of changes in such estimates in future periods could be material. Revisions
to accounting estimates are recognized in the period in which the estimates
are revised and in any future periods affected.
I. Derivatives
The fair value of commodity contracts is estimated, whenever
possible, based on published market prices, and if not available,
on estimates from third party brokers, as at the balance sheet
date and may differ from what will eventually be realized.
II. Oil and gas reserves
Reserves and resources are used in the units of production
calculation for depreciation, depletion and amortization and the
impairment analysis which affect net profit. There are numerous
uncertainties inherent in estimating oil and gas reserves.
Estimating reserves is very complex, requiring many judgments
based on geological, geophysical, engineering and economic data.
Changes in these judgments could have a material impact on the
estimated reserves. These estimates may change, having either a
negative or positive effect on net profit as further information
becomes available and as the economic environment changes.
III. Depreciation and depletion
Depletion of petroleum and natural gas properties is provided
using the unit-of-production method based on production volumes
before royalties in relation to total estimated proved and
probable reserves as determined annually by independent engineers
and internal reserve evaluations on a quarterly basis determined
in accordance with National Instrument 51-101. Natural gas
reserves and production are converted at the energy equivalent of
six thousand cubic feet to one barrel of oil.
Calculations for depletion and depreciation of production
equipment are based on total capitalized costs plus estimated
future development costs of proved and probable undeveloped
reserves less the estimated net realizable value of production
equipment and facilities after the proved reserves are fully
produced. The costs of acquiring and evaluating unproved
properties are excluded from depletion calculations.
IV. Recoverability of asset carrying values
The Company assesses its oil and gas properties, including
exploration and evaluation assets, for possible impairment if
there are events or changes in circumstances that indicate that
carrying values of the assets may not be recoverable, or at least
at every reporting date.
The assessment of any impairment of property, plant and equipment
is dependent upon estimates of recoverable amount that take into
account factors such as reserves, economic and market conditions,
timing of cash flows, the useful lives of assets and their
related salvage values.
Bellatrix's assets are aggregated into CGUs, for the purpose of
calculating impairment, based on their ability to generate
largely independent cash flows, geography, geology, production
profile and infrastructure of its assets. By their nature, these
estimates and assumptions are subject to measurement uncertainty
and may impact the carrying value of the Company's assets in
future periods.
V. Decommissioning obligations
Provisions for decommissioning obligations associated with the
Company's drilling operations are based on current legal and
constructive requirements, technology, price levels and expected
plans for remediation. Actual costs and cash outflows can differ
from estimates because of changes in laws and regulations, public
expectations, prices, discovery and analysis of site conditions
and changes in clean up technology.
VI. Share-based compensation
The fair value of stock options granted is measured using a Black
Scholes model. Measurement inputs include share price on
measurement date, exercise price of the option, expected
volatility, expected life of the options, expected dividends and
the risk-free rate. The Company estimates volatility based on
the historical share price. The expected life of the options is
based on historical experience and general option holder
behavior. Dividends were not taken into consideration as the
Company does not expect to pay dividends. Management also makes
an estimate of the number of options that will be forfeited and
the rate is adjusted to reflect the actual number of options that
actually vest.
VII. Income taxes
Related assets and liabilities are recognized for the estimated
tax consequences between amounts included in the financial
statements and their tax base using substantively enacted future
income tax rates. Timing of future revenue streams and future
capital spending changes can affect the timing of any temporary
differences, and accordingly affect the amount of the deferred
tax asset or liability calculated at a point in time. These
differences could materially impact earnings.
VIII. Business combinations
Business combinations are accounted for using the acquisition
method of accounting. The determination of fair value often
requires management to make assumptions and estimates about
future events. The assumptions and estimates with respect to
determining the fair value of property, plant, and equipment, and
exploration and evaluation assets acquired generally require the
most judgment and include estimates of reserves acquired,
forecast benchmark commodity prices, and discount rates. Changes
in any of the assumptions or estimates used in determining the
fair value of acquired assets and liabilities could impact the
amounts assigned to assets, liabilities in the purchase price
allocation, and any resulting gain or loss. Future net earnings
can be affected as a result of changes in future depletion,
depreciation and accretion, and asset impairments.
5. NEW STANDARDS AND INTERPRETATIONS NOT YET ADOPTED
The following pronouncements from the IASB are applicable to Bellatrix and
will become effective for future reporting periods, but have not yet been
adopted:
IFRS 9 - "Financial Instruments", which is the result of the first phase of
the IASB's project to replace IAS 39, "Financial Instruments: Recognition and
Measurement". The new standard replaces the current multiple classification
and measurement models for financial assets and liabilities with a single
model that has only two classification categories: amortized cost and fair
value. This standard is effective for annual periods beginning on or after
January 1, 2015 with different transitional arrangements depending on the date
of initial application. The extent of the impact of the adoption of IFRS 9 has
not yet been determined.
IFRS 10 - "Consolidated Financial Statements" ("IFRS 10"), which 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. Under existing IFRS,
consolidation is required when an entity has the power to govern the financial
and operating policies of an entity so as to obtain benefits from its
activities. This standard replaces SIC-12 - "Consolidation—Special Purpose
Entities" and parts of IAS 27 - "Consolidated and Separate Financial
Statements." Bellatrix intends to adopt IFRS 10, including the amendments
issued in June 2012, in its financial statements for the annual period
beginning on January 1, 2013. The adoption of IFRS 10 is currently not
anticipated to impact the Company's financial statements.
IFRS 11 - "Joint Arrangements" ("IFRS 11"), requires a venturer to classify
its interest in a joint arrangement as a joint venture or joint operation,
each having its own accounting model. Joint ventures will be accounted for
using the equity method of accounting, whereas for a joint operation the
venture will recognize its share of the assets, liabilities, revenue and
expenses of the joint operation. The standard provides for a more substance
based reflection of joint arrangements by focusing on the rights and
obligations of the arrangement, rather than its legal form. IFRS 11 replaces
IAS 31 - "Interests in Joint Ventures" and SIC-13 - "Jointly Controlled
Entities—Non-monetary Contributions by Venturers" and establishes principles
for accounting for all joint arrangements. Bellatrix intends to adopt IFRS
11, including the amendments issued in June 2012, in its financial statements
for the annual period beginning on January 1, 2013. The adoption of IFRS 11
is currently not anticipated to have a significant impact on the Company's
financial statements.
IFRS 12 - "Disclosure of Interests in Other Entities" ("IFRS 12"), establishes
disclosure requirements for interests in other entities, such as joint
arrangements, associates, special purpose vehicles and off balance sheet
vehicles. The standard carries forward existing disclosures and also
introduces significant additional disclosure requirements that address the
nature of, and risks associated with, an entity's interests in other
entities. Bellatrix intends to adopt IFRS 12, including the amendments issued
in June 2012, in its financial statements for the annual period beginning on
January 1, 2013. The adoption of IFRS 12 is currently not anticipated to have
a significant impact on the Company's financial statements.
IFRS 13 - "Fair Value Measurement" ("IFRS 13"), is a comprehensive standard
for fair value measurement and disclosure requirements for use across all
IFRSs. The new standard clarifies that fair value is the price that would be
received to sell an asset, or paid to transfer a liability in an orderly
transaction between market participants, at the measurement date. It also
establishes disclosures about fair value measurement. Under existing IFRS,
guidance on measuring and disclosing fair value is dispersed among the
specific standards requiring fair value measurements and in many cases does
not reflect a clear measurement basis or consistent disclosures. IFRS 13 is
effective for annual periods beginning on or after January 1, 2013 and applies
prospectively from the beginning of the annual period in which the standard is
adopted. The extent of the impact of the adoption of IFRS 13 on the
Company's financial statements has not yet been determined.
In June 2011, the IASB issued an amendment to IAS 1 - "Presentation of
Financial Statements" ("IAS 1") requiring companies to group items presented
within Other Comprehensive Income based on whether they may be subsequently
reclassified to profit or loss. This amendment to IAS 1 is effective for
annual periods beginning on or after July 1, 2012 with full retrospective
application. Early adoption is permitted. Bellatrix intends to adopt the
amendments in its financial statements for the annual period beginning on
January 1, 2013. The extent of the impact of the amendments on the financial
statements has not yet been determined.
6. EXPLORATION AND EVALUATION ASSETS
($000s)
Cost
Balance, December 31, 2010 $ 18,535
Additions 16,839
Transfer to oil and natural gas properties (1,817)
Disposals ^ (1) (468)
Balance, December 31, 2011 33,089
Additions 17,118
Transfer to oil and natural gas properties (10,301)
Disposals ^ (1) (1,729)
Balance, December 31, 2012 $ 38,177
^(1) Disposals include swaps.
7. PROPERTY, PLANT AND EQUIPMENT
($000s)
Oil and Office
natural gas furniture and
properties equipment Total
Cost
Balance, December 31, $ 484,600 $ 2,236 $ 486,836
2010
Additions 173,595 267 173,862
Transfer from 1,817 - 1,817
exploration and
evaluation assets
Disposals ^ (1) (2,697) - (2,697)
Balance, December 31, 657,315 2,503 659,818
2011
Additions 194,442 299 194,741
Transfer from 10,301 - 10,301
exploration and
evaluation assets
Disposals ^ (1) (10,950) - (10,950)
Balance, December 31, $ 851,108 $ 2,802 $ 853,910
2012
Accumulated Depletion,
Depreciation and
Impairment losses
Balance, December 31, $ 86,482 $ 774 $ 87,256
2010
Charge for time period 63,085 299 63,384
Impairment loss 28,039 194 28,233
Impairment reversal (2,664) - (2,664)
Disposals ^ (1) (692) - (692)
Balance, December 31, $ 174,250 $ 1,267 $ 175,517
2011
Charge for time period 75,466 254 75,720
Impairment loss 14,760 60 14,820
Disposals ^ (1) (1,906) - (1,906)
Balance, December 31, $ 262,570 $ 1,581 $ 264,151
2012
^(1) Disposals include
swaps.
Carrying amounts
At December 31, 2011 $ 483,065 $ $ 484,301
1,236
At December 31, 2012 $ 588,538 $ 1,221 $ 589,759
Bellatrix has included $524.6 million (2011: $376.8 million) for future
development costs and excluded $37.2 million (2011: $35.1 million) for
estimated salvage from the depletion calculation for the three months ended
December 31, 2012.
For the year ended December 31, 2012, the Company capitalized $4.3 million
(2011: $3.6 million) of general and administrative expenses and $1.6 million
(2011: $1.4 million) of share-based compensation expense directly related to
exploration and development activities.
Bellatrix's credit facilities are secured against all of the assets of the
Corporation by a $400 million debenture containing a first ranking floating
charge and security interest. The Corporation has provided a negative pledge
and undertaking to provide fixed charges over major petroleum and natural gas
reserves in certain circumstances.
Property Acquisition
Effective November 1, 2012, Bellatrix acquired production and working interest
in certain facilities, as well as undeveloped land in the Willesden Green area
of Alberta for a cash purchase price of $20.9 million after adjustments. In
accordance with IFRS, a property acquisition is accounted for as a business
combination when certain criteria are met, such as the acquisition of inputs
and processes to convert those inputs into beneficial outputs. Bellatrix
assessed the property acquisition and determined that it constitutes a
business combination under IFRS. In a business combination, acquired assets
and liabilities are recognized by the acquirer at their fair market value at
the time of purchase. Any variance between the determined fair value of the
assets and liabilities and the purchase price is recognized as either a gain
or loss in the statement of comprehensive income in the period of acquisition.
The estimated fair value of the property, plant and equipment acquired was
determined using both internal estimates and an independent reserve
evaluation. The decommissioning liabilities assumed were determined using the
timing and estimated costs associated with the abandonment, restoration and
reclamation of the wells and facilities acquired. A summary of the acquired
property is provided below:
($000s)
Estimated fair value of acquisition:
Oil and natural gas properties 29,530
Exploration and evaluation assets 8,525
Decommissioning liabilities (973)
37,082
Cash consideration 20,922
Gain on property acquisition 16,160
Included in the Company's deferred tax expense for the year was a $4.0 million
expense relating to the gain recognized on the property acquisition. If the
acquisition had been effective January 1, 2012, the Company would have
realized an estimated additional $5.6 million (unaudited) of production
revenue and an estimated additional $2.1 million (unaudited) of profit before
tax. Between the acquisition date and December 31, 2012, approximately $0.6
million of production revenue and $0.1 million of profit before tax was
recognized relating to the acquired properties.
Impairment
Bellatrix assesses the recoverability of the carrying values of its oil and
natural gas properties on a CGU basis. The composition of each CGU is
determined based on factors such as common processing facilities, sales
points, and commonalities in the geological and geophysical structure of
individual areas.
In accordance with IFRS, the recoverability of a CGU's carrying value is
determined by calculating and using the greater of its Value in Use ("VIU") or
Fair Value Less Costs to Sell ("FVLCS"). VIU is determined by estimating the
present value of the future net cash flows expected to be derived from the
continued use of the assets in the CGU. FVLCS is determined to be the amount
for which the assets in the CGU could be sold in an arm's length transaction.
FVLCS is calculated for each CGU based on independently available data on
recent industry acquisition transactions ("transaction metrics") applicable to
the CGU based on similarities in assets involved in the transactions. These
transaction metrics are determined as a dollar-value per boe for proved plus
probable reserves. The per-boe value for each CGU is applied to the estimated
boe proved plus probable reserves remaining in that CGU as determined at least
annually by independent reserve engineers. The recoverable amount is compared
to the carrying value of that CGU in order to determine if impairment exists.
Impairment is recognized as an expense included in the Company's consolidated
statement of comprehensive income in the period in which it occurs.
A 1% increase to the discount rates applied in 2012 year-end impairment
calculations would result in an increase in impairment expense of $0.8
million. Identical decreases would result from a 1% decrease to the discount
rates applied.
2012 Impairment
Bellatrix engaged an external reserve evaluator to prepare an updated company
reserve report effective December 31, 2012. Overall corporate proved and
probable reserve volumes increased significantly at December 31, 2012 compared
to evaluated reserves at December 31, 2011. However, the fair values of two
largely natural gas-weighted CGUs and one CGU with significant natural gas and
heavy oil weightings were reduced, largely as a result of suppressed commodity
prices.
As at December 31, 2012, Bellatrix performed an impairment test using VIU
values in accordance with IAS 36, resulting in an excess of the carrying value
of three CGUs over their recoverable amount, resulting in a non-cash $14.8
million impairment loss. In performing the test, future cash flows at between
a 10% and 20% discount rate were used for the Company's largely gas weighted
North East Alberta, South East Alberta, and British Columbia CGUs. The
Company's core West Central Alberta CGU had no indicators of impairment.
Discounted salvage values and discounted future associated general and
administrative costs were also incorporated into the VIU calculation.
2011 Impairment
During the year ended December 31, 2011, Bellatrix performed an impairment
test in accordance with IAS 36 resulting in an excess of the carrying value of
three CGUs over their recoverable amount, resulting in a non-cash $25.6
million impairment loss.
IAS 36 requires impairment losses to be reversed when there has been a
subsequent increase in the recoverable amount. In the case of an impairment
loss reversal, the carrying amount of the asset or CGU is limited to the
original carrying amount less depreciation, depletion and amortization as if
no impairment had been recognized for the asset or CGU for prior periods. In
2011, a partial reversal of impairment was recognized relating to a previous
impairment for the Company`s South East Alberta CGU. As a result of the
reversal, impairment expense for the 2011 year was reduced by $2.7 million.
8. LONG-TERM DEBT
($000s) 2012 2011
Operating facility $ 4,047 $ 5,701
Revolving term facility 129,000 51,000
Balance, end of year $ 133,047 $ 56,701
Effective December 13, 2012, the Company's borrowing base was increased from
$200 million to $220 million through to the next scheduled borrowing base
determination to be completed on or before May 31, 2013. Effective May 31,
2012, the revolving period of the credit facility was extended from June 26,
2012 to June 25, 2013. As of December 31, 2012, the Company's credit
facilities consist of a $25 million demand operating facility provided by a
Canadian bank and a $195 million extendible revolving term credit facility
provided by two Canadian banks and a Canadian financial institution. Amounts
borrowed under the credit facility will bear interest at a floating rate based
on the applicable Canadian prime rate, U.S. base rate, LIBOR margin rate, or
the bankers' acceptance stamping fee, plus between 1.00% and 3.50%, depending
on the type of borrowing and the Company's debt to cash flow ratio. The
credit facilities are secured by a $400 million debenture containing a first
ranking charge and security interest. Bellatrix has provided a negative
pledge and undertaking to provide fixed charges over its properties in certain
circumstances. A standby fee is charged of between 0.50% and 0.875% on the
undrawn portion of the credit facilities, depending on the Company's debt to
cash flow ratio.
The revolving period for the revolving term credit facility will end on June
25, 2013, unless extended for a further 364 day period. Should the facility
not be extended it will convert to a non-revolving term facility with the full
amount outstanding due 366 days after the last day of the revolving period of
June 25, 2013. The borrowing base will be subject to re-determination on May
31 and November 30 in each year prior to maturity, with the next semi-annual
redetermination occurring on May 31, 2013.
Principal payment will not be required under the revolving term facility for
more than 365 days from December 31, 2012 and as there is sufficient
availability under the revolving term credit facility to cover the operating
facility, the entire amounts owing on the credit facilities have been
classified as long-term.
Pursuant to Bellatrix's credit facilities, the Company is permitted to pay the
semi-annual interest payments on the debentures, and payments by the Company
to debenture holders in relation to the redemption of debentures and in
relation to debenture normal course issuer bids approved by the Toronto Stock
Exchange (the "TSX"), provided that the aggregate of all such normal course
issuer bids and redemptions do not exceed $10.0 million in any fiscal year.
As at December 31, 2012, the Company had outstanding letters of credit
totaling $0.6 million that reduce the amount otherwise available to be drawn
on the syndicated facility.
As at December 31, 2012, the Company had approximately $87.0 million, or 40%
of unused and available bank credit under its credit facilities. Bellatrix was
fully compliant with all of its operating debt covenants.
9. CONVERTIBLE DEBENTURES
The following table sets forth a reconciliation of the convertible debentures:
Convertible debentures
($000s except number of debentures) 4.75%
Number of Debentures
Balance, December 31, 2011 and 2012 55,000
Debt Component
Balance, December 31, 2010 $ 47,599
Accretion 1,477
Balance, December 31, 2011 $ 49,076
Accretion 1,611
Balance, December 31, 2012 $ 50,687
Equity Component
Balance, December 31, 2011 and 2012 $ 4,378
On April 20, 2010, Bellatrix issued $55 million of 4.75% convertible unsecured
subordinated debentures (the "4.75% Debentures") on a bought deal basis. The
4.75% Debentures have a face value of $1,000 each, bear interest at the rate
of 4.75% per annum payable semi-annually in arrears on the last day of April
and October of each year commencing on October 31, 2010 and mature on April
30, 2015 (the "Maturity Date"). The 4.75% Debentures are convertible at the
holder's option and at any time prior to the close of business on the earlier
of the close of business on the business day immediately preceding the
Maturity Date and the date specified by the Corporation for redemption of the
4.75% Debentures into common shares of the Corporation at a conversion price
of $5.60 per common share (the "Conversion Price"), subject to adjustment in
certain events. The 4.75% Debentures are not redeemable by the Corporation
before April 30, 2013. On and after April 30, 2013 and prior to April 30,
2014, the 4.75% Debentures are redeemable at the Corporation's option, in
whole or in part, at par plus accrued and unpaid interest if the weighted
average trading price of the common shares for the specified period is not
less than 125% of the Conversion Price. On and after April 30, 2014, the 4.75%
Debentures are redeemable at the Corporation's option, in whole or in part, at
any time at par plus accrued and unpaid interest. The 4.75% Debentures are
listed and posted for trading on the TSX under the symbol "BXE.DB.A".
As the 4.75% Debentures are convertible into common shares, the liability and
equity components are presented separately. The initial carrying amount of
the financial liability is determined by discounting the stream of future
payments of interest and principal and has been determined to be $48.8
million. A total of $2.2 million of issue costs has been allocated to the
liability component of the debentures. Using the residual method, the
carrying amount of the conversion feature is the difference between the
principal amount and the carrying value of the financial liability. Within
the Shareholder's Equity section of the consolidated financial statements,
$4.4 million has been recorded as the carrying amount of the conversion
feature of the debentures, net of $0.3 million of issue costs and $1.5 million
of deferred taxes. The 4.75% Debentures, net of the equity component and
issue costs is accreted using the effective interest rate method over the term
of the 4.75% Debentures such that the carrying amount of the financial
liability will equal the principal balance at maturity.
10. FINANCE LEASE OBLIGATION
The Company entered into separate agreements in December 2012, 2011, and 2010
to raise $10 million, $3.7 million, and $1.6 million, respectively, for the
Company's proportionate share of the construction of certain facilities in
each of the years.
The agreements resulted in the recognition of finance leases in 2012, 2011,
and 2010 for the use of the constructed facilities. The agreements will expire
in years 2030 to 2032, respectively, or earlier if certain circumstances are
met. At the end of the term of each agreement, the ownership of the
facilities is transferred to the Company. Assets under these finance leases at
December 31, 2012 totaled $15.3 million (2011: $5.3 million) with accumulated
depreciation of $1.4 million (2011: $0.4 million).
Multiple participants of the joint ventures were involved in the 2012, 2011,
and 2010 agreements. Although the majority of participants were fully external
to the Company, some related parties were involved in the 2011 and 2010
agreements. See note 18.
The following is a schedule of future minimum lease payments under the finance
lease obligations:
Year ending December 31, ($000s)
2013 $ 3,552
2014 3,399
2015 3,244
2016 3,059
2017 2,719
Thereafter 13,472
Total lease payments 29,445
Amount representing implicit interest at 15.28% (14,889)
14,556
Current portion of finance lease obligation (1,425)
Finance lease obligation $ 13,131
11. DECOMMISSIONING LIABILITIES
The Company's decommissioning liabilities result from net ownership interests
in petroleum and natural gas assets including well sites, gathering systems
and processing facilities. The Company estimates the total undiscounted
amount of cash flows required to settle its decommissioning liabilities is
approximately $51 million which will be incurred between 2013 and 2053. A
risk-free rate between 1.14% - 2.36% (2011: 0.95% - 2.49%) and an inflation
rate of 2.4% (2011: 2.4%) were used to calculate the fair value of the
decommissioning liabilities as at December 31, 2012.
($000s) 2012 2011
Balance, beginning of year $ 45,091 $ 38,710
Incurred on development activities 1,400 1,694
Acquired through business combinations 973 -
Revisions on estimates (648) 4,703
Reversed on dispositions (2,955) (326)
Settled during the year (635) (569)
Accretion expense 683 879
Balance, end of year $ 43,909 $ 45,091
12. SHAREHOLDERS' CAPITAL
Bellatrix is authorized to issue an unlimited number of common shares. All
shares issued are fully paid and have no par value. The common shareholders
are entitled to dividends declared by the Board of Directors; Bellatrix does
not anticipate paying dividends.
2012 2011
Amount Amount
Number ($000s) Number ($000s)
Common shares, opening $
balance 107,407,241 370,048 97,446,026 $ 316,779
Shares issued for cash,
net of
transaction costs and
tax effect of $0.8
million in 2011 - - 9,822,000 52,734
Shares issued on 1,093
exercise of options 461,533 139,215 381
Contributed surplus
transferred on
exercised options - 435 - 154
Balance, end of year $
107,868,774 371,576 107,407,241 $ 370,048
13. SHARE-BASED COMPENSATION PLANS
a. Share Option Plan
Bellatrix has a share option plan where the Company may grant share options to
its directors, officers, employees and service providers. Under this plan,
the exercise price of each share option is not less than the volume weighted
average trading price of the Company's share price for the five trading days
immediately preceding the date of grant. The maximum term of an option grant
is five years. Option grants are non-transferable or assignable except in
accordance with the share option plan and the holding of share options shall
not entitle a holder to any rights as a shareholder of Bellatrix. Share
options, entitling the holder to purchase common shares of the Company, have
been granted to directors, officers, employees and service providers of
Bellatrix. One third of the initial grant of share options normally vests on
each of the first, second, and third anniversary from the date of grant.
During the year ended December 31, 2012, Bellatrix granted 2,648,000 (2011:
2,544,000) share options. During the year ended December 31, 2012, the
Company recorded share-based compensation of $3.8 million (2011: $3.5 million)
related to its outstanding share options, net of forfeitures of $0.2 million
(2011: $0.1 million), of which $1.6 million (2011: $1.4 million) was
capitalized to property, plant and equipment. In addition, $1.0 million
(2011: $0.8 million) (note 13 b.) was expensed in relation to the Director's
Deferred Share Unit Plan, resulting in total net share-based compensation of
$3.2 million recognized as an expense for the 2012 year (2011: $2.9 million).
The fair values of all share options granted are estimated on the date of
grant using the Black-Scholes option-pricing model. The weighted average fair
market value of share options granted during the years ended December 31, 2012
and 2011, and the weighted average assumptions used in their determination are
as noted below:
2012 2011
Inputs:
Share price 3.60 5.21
Exercise price 3.60 5.21
Risk free interest rate (%) 1.1 1.8
Option life (years) 2.8 3.6
Option volatility (%) 53 65
Results:
Weighted average fair value of each share option 1.28 2.48
granted
Bellatrix calculates volatility based on historical share price. Bellatrix
incorporates an estimated forfeiture rate between 3% and 10% (2011: 3% to 10%)
for stock options that will not vest, and adjusts for actual forfeitures as
they occur.
The weighted average TSX share trading price for the year ended December 31,
2012 was $4.31 (2011: $5.01).
The following tables summarize information regarding Bellatrix's Share Option
Plan:
Share Options Continuity
Weighted Average
Exercise Price Number
Balance, December 31, 2010 $ 2.69 5,823,377
Granted $ 5.21 2,544,000
Exercised $ 2.74 (139,215)
Forfeited and cancelled $ 4.37 (242,842)
Balance, December 31, 2011 $ 3.44 7,985,320
Granted $ 3.61 2,648,000
Exercised $ 2.37 (461,533)
Forfeited and cancelled $ 4.50 (751,336)
Balance, December 31, 2012 $ 3.46 9,420,451
As of December 31, 2012, a total of 10,739,129 share options were reserved,
leaving an additional 1,318,678 available for future grants.
Share Options Outstanding, December
31, 2012
Outstanding Exercisable
Weighted
Weighted Average
At Average Remaining At
Exercise December, Exercise Contractual December Exercise
Price 2012 Price Life 31, 2012 Price
$ 0.65 - 1.3
$ 1.45 682,949 $ 1.02 682,949 $ 1.02
$ 1.46 - 1.2
$ 1.99 1,177,449 $ 1.65 1,177,449 $ 1.65
$ 2.00 - 2.2
$ 3.36 1,407,052 $ 2.41 973,718 $ 2.08
$ 3.37 - 4.3
$ 3.84 1,575,000 $ 3.42 84,665 $ 3.70
$ 3.85 - 2.8
$ 4.72 2,271,001 $ 3.95 1,172,313 $ 3.90
$ 4.73 - 3.5
$ 5.50 2,307,000 $ 5.28 723,975 $ 5.26
$ 0.65 - 2.8
$ 5.50 9,420,451 $ 3.46 4,815,069 $ 2.78
Share Options Outstanding, December
31, 2011
Outstanding Exercisable
Weighted
Weighted Average
At Average Remaining At
Exercise December, Exercise Contractual December Exercise
Price 2011 Price Life 31, 2011 Price
$ 0.65 - $ 1.01 $
$ 1.45 758,028 2.4 483,628 1.02
$ 1.46 - $ 1.66 $
$ 1.99 1,244,115 2.3 914,105 1.66
$ 2.00 - $ 2.15 $
$ 3.36 1,273,676 2.0 964,805 2.19
$ 3.37 - $ 3.66 $
$ 3.84 171,000 4.1 38,333 3.75
$ 3.85 - $ 3.93 $
$ 4.72 1,921,001 3.1 685,646 3.98
$ 4.73 - $ 5.25 $
$ 5.57 2,617,500 4.0 287,833 5.11
$ 0.65 - $ 3.44 $
$ 5.57 7,985,320 3.1 3,374,350 2.51
b. Deferred Share Unit Plan
On May 11, 2011, the Board of Directors of Bellatrix approved a Directors'
Deferred Share Unit Plan ("the Plan") where the Company may grant to
non-employee directors Deferred Share Units ("DSUs"), each DSU being a right
to receive, on a deferred payment basis, a cash payment equivalent to the
volume weighted average trading price of the Company's common shares for the
five trading days immediately preceding the redemption date of such DSU.
Participants of the Plan may also elect to receive their annual remuneration
in the form of DSUs. Subject to TSX and shareholder approval, Bellatrix may
elect to deliver common shares from treasury in satisfaction in whole or in
part of any payment to be made upon the redemption of the DSUs. The DSUs vest
immediately and must be redeemed by December 1^st of the calendar year
immediately following the year in which the participant ceases to hold all
positions with Bellatrix or earlier if the participant elects to have the DSUs
redeemed at an earlier date (provided that the DSUs may not be redeemed prior
to the date that the participant ceases to hold all positions with
Bellatrix). On a go forward basis, it is intended that in the event of a
share based award, non-employee directors would receive DSU grants instead of
share option grants.
During the year ended December 31, 2012, the Company granted 249,298 (2011:
159,226) DSUs and had 408,524 DSUs outstanding as at December 31, 2012 (2011:
159,226). For the year ended December 31, 2012, Bellatrix recorded
approximately $1.0 million (2011: $0.8 million) of share based compensation
expense and had a liability balance of $1.7 million (2011: $0.8 million)
relating to the Company's outstanding DSUs.
14. SUPPLEMENTAL CASH FLOW INFORMATION
Change in Non-cash Working Capital
($000s) 2012 2011
Changes in non-cash working capital
items:
Accounts receivable $ 4,530 $ (5,822)
Deposits and prepaid expenses (510) 993
Accounts payable and accrued (12,614) 18,865
liabilities
$ (8,594) $ 14,036
Changes related to:
Operating activities $ (1,075) $ 4,524
Financing activities (55) 136
Investing activities (7,464) 9,376
$ (8,594) $ 14,036
15. INCOME TAXES
Bellatrix is a corporation as defined under the Income Tax Act (Canada) and is
subject to Canadian federal and provincial taxes. Bellatrix is subject to
provincial taxes in Alberta, British Columbia and Saskatchewan as the Company
operates in those jurisdictions.
Deferred taxes reflect the tax effects of differences between the carrying
amounts of assets and liabilities for financial reporting purposes and the
amounts reported for tax purposes. As at December 31, 2012, Bellatrix had
approximately $584 million in tax pools available for deduction against future
income. Included in this tax basis are estimated non-capital loss carry
forwards of approximately $10 million that expire in years through 2027.
The provision for income taxes differs from the expected amount calculated by
applying the combined Federal and Provincial corporate income tax rate of
25.0% (2011: 26.5%) to loss before taxes. This difference results from the
following items:
($000s) 2012 2011
Expected income tax expense (recovery) $ 9,459 $ (1,373)
Share based compensation expense 564 576
Change in tax rates - (6)
Flow through shares - 1,537
Other 44 34
Deferred tax expense (recovery) $ 10,067 $ 768
The statutory tax rate decreased to 25.0% in 2012 from 26.5% in 2011 as a
result of tax legislation enacted in 2007.
The components of the net deferred tax asset at December 31 are as follows:
($000s) 2012 2011
Deferred income tax liabilities:
Equity component of 4.75% Debentures $ (799) $ (1,078)
Property, plant and equipment and exploration (17,737) (8,126)
and evaluation assets
Commodity contract asset (43) -
Deferred income tax assets:
Finance lease obligation 3,639 1,279
Property, plant and equipment and exploration - -
and evaluation assets
Commodity contract liability - 2,658
Decommissioning liabilities 10,977 11,273
Share issue costs 834 1,174
Non-capital losses 2,500 2,500
Attributed Canadian Royalty Income 1,209 1,209
Other 458 216
Deferred income tax asset $ 1,038 $ 11,105
The Company has recognized a net deferred tax asset based on the independently
evaluated reserve report as cash flows are expected to be sufficient to
realize the deferred tax asset.
A continuity of the net deferred income tax asset (liability) for 2012 and
2011 is provided below:
Movement of temporary differences during the year
Recognized
Balance, in Flow Balance,
Jan. 1, profit or Recognized through Dec. 31,
($000s) 2012 loss in equity shares 2012
Property, plant
and equipment
and
exploration
and evaluation
assets $ (8,126) $ (9,611) $ - $ - $ (17,737)
Decommissioning
liabilities 11,273 (296) - - 10,977
Commodity
contract
liability 2,658 (2,701) - - (43)
Share issue
costs 1,174 (340) - - 834
Non-capital
losses 2,500 - - - 2,500
Equity
component of
4.75%
debentures (1,078) 279 - - (799)
Finance lease
obligation 1,279 2,360 - - 3,639
Attributed
Canadian
Royalty Income 1,209 - - - 1,209
Other 216 242 - - 458
$ 11,105 $ (10,067) $ - $ - $ 1,038
Recognized
Balance, in Flow Balance,
Jan. 1, profit or Recognized through Dec. 31,
($000s) 2011 loss in equity shares 2011
Property, plant
and equipment
and
exploration
and evaluation
assets $ 2,991 $ (7,349) $ - $ (3,768) $ (8,126)
Decommissioning
liabilities 9,729 1,544 - - 11,273
Commodity
contract
liability 989 1,669 - - 2,658
Share issue
costs 752 (399) 821 - 1,174
Non-capital
losses 79 2,421 - - 2,500
Equity
component of
4.75%
debentures (1,354) 276 - - (1,078)
Finance lease
obligation 399 880 - - 1,279
Attributed
Canadian
Royalty Income 1,209 - - - 1,209
Other 26 190 - - 216
$ 14,820 $ (768) $ 821 $ (3,768) $ 11,105
16. FINANCE INCOME AND EXPENSES
($000s) 2012 2011
Finance expense
Interest on long-term debt $ 5,603 $ 2,952
Interest on convertible debentures 2,620 2,612
Accretion on convertible debentures 1,611 1,477
Accretion on decommissioning liabilities 683 879
2,294 2,356
Finance expense $ 10,517 $ 7,920
17. CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME PRESENTATION
A mixed presentation of nature and function was used for the Company`s
presentation of operating expenses in the consolidated statement of
comprehensive income for the current and comparative years. General and
administrative expenses are presented by their function. Other expenses,
including production, transportation, depletion and dispositions are presented
by their nature. Such presentation is in accordance with industry practice.
Total employee compensation costs included in total production and general
administrative expenses in the consolidated statements of comprehensive income
are detailed in the following table:
($000s) 2012 2011
Production 885 818
General and administrative ^(1) 8,292 6,497
Employee compensation $ 9,177 $ 7,315
^(1) Amount shown is net of capitalization
18. RELATED PARTY TRANSACTIONS
a. Finance lease agreements
Previous to 2012, the Company entered into agreements to obtain financing in
the amount of $5.3 million for the construction of certain facilities.
Members of the Company's management team and entities affiliated with them
provided financing of $900,000. The terms of the transactions with those
related parties were the same as those with arms-length participants.
b. Key Management Compensation
Key management includes senior officers and directors (executive and
non-executive) of the Company. The compensation paid or payable to key
management for employee services is shown below:
($000s) 2012 2011
Salaries and other short-term employee benefits $ 4,611 $ 3,960
Long-term incentive compensation 77 59
Share-based compensation ^ (1) 2,942 2,506
$ 7,630 $ 6,525
^(1) Share-based compensation include share options and DSUs.
19. PER SHARE AMOUNTS
The calculation of basic earnings per share for the year ended December 31,
2012 was based on a net profit of $27.8 million (2011: net loss of $5.9
million).
2012 2011
Basic common shares outstanding 107,868,774 107,407,241
Dilutive effect of:
Share options outstanding 9,420,451 7,985,320
Shares issuable for convertible 9,821,429 9,821,429
debentures
Diluted common shares outstanding 127,110,654 125,213,990
Weighted average shares outstanding 107,543,811 103,857,689
Dilutive effect of share options and -
convertible debentures ^(1) 1,581,283
Diluted weighted average shares outstanding 109,125,094 103,857,689
(1) For the year ended December 31, 2012, a total of 7,839,168 (2011:
7,985,320) share options and 9,821,429 (2011: 9,821,429) common shares
issuable pursuant to the conversion of the 4.75% Debentures were excluded
from the calculation as they were not dilutive.
20. COMMITMENTS
The Company is committed to payments under fixed term operating leases which
do not currently provide for early termination. The Company's commitment for
office space as at December 31, 2012 is as follows:
($000s) Gross Recoveries Net amount
Year Amount
2013 $ 2,254 $ 947 $ 1,307
2014 1,520 641 879
Subsequent to year end, Bellatrix entered into a fixed term operating lease
agreement for corporate office space in a new location, commencing September
1, 2013. Bellatrix is currently pursuing subleasing options for the remaining
term of its existing corporate office space. A summary of the Company's
commitment for the new office space is as follows:
($000s)
Year Total amount
2013 $ 388
2014 2,153
2015 2,243
2016 2,243
2017 2,243
More than 5 years 14,449
As at December 31, 2012, Bellatrix committed to drill 3 gross (1.7 net) wells
pursuant to farm-in agreements. Bellatrix expects to satisfy these drilling
commitments at an estimated cost of approximately $6.5 million.
In addition, Bellatrix entered into two joint venture agreements during the
2011 year and an additional joint venture agreement during 2012. The
agreements include a minimum commitment for the Company to drill a specified
number of wells each year over the term of the individual agreements. The
details of these agreements are provided in the table below:
Joint Venture Agreement F*Story too large*
[TRUNCATED]
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