1. business and industrial
2. company
3. joint venture

MANAGEMENT’S DISCUSSION AND ANALYSIS
March 11, 2015 – 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, 2014 and 2013. This commentary
is based on information available to, and is dated as of, March 11, 2015. 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.
FINDING, DEVELOPMENT AND ACQUISITION COSTS: Finding and development costs including acquisitions and
dispositions (“FD&A costs”) have been presented herein. While National Instrument 51-101 – Standards of Disclosure for
Oil and Gas Activities requires that the effects of acquisitions and dispositions be excluded, FD&A costs have been
presented because acquisitions and dispositions can have a significant impact on the Company's ongoing reserve
replacement costs and excluding these amounts could result in an inaccurate portrayal of the Company's cost structure.
The Company's finding and development costs, excluding the effects of acquisitions and dispositions, for 2014 were
$18.56/boe on a proved basis and $23.80/boe on a proved plus probable basis. The Company's finding and
development costs, excluding the effects of acquisitions and dispositions, for 2013 were $10.67/boe on a proved basis
and $9.65/boe on a proved plus probable basis. The Company's average finding and development costs for the last
three years, excluding the effects of acquisitions and dispositions, were $13.45/boe on a proved basis and $11.69/boe
on a proved plus probable basis. The aggregate of the exploration and development costs incurred in the most recent
financial year and the change during that year in estimated future development costs generally will not reflect total finding
and development costs related to reserves additions for that year.
ADDITIONAL GAAP MEASURES: This MD&A and the 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 MD&A. Funds flow from operations per share is calculated using the weighted average number of shares
for the period.
This MD&A and the financial statements also contain the terms total net debt and adjusted working capital deficiency
(excess), which also are not recognized measures under GAAP. Therefore reference to the additional GAAP measures
of total net debt or adjusted working capital deficiency (excess) may not be comparable with the calculation of similar
measures for other entities. The Company’s 2014 calculation of total net debt excludes deferred lease inducements,
decommissioning liabilities, the long-term finance lease obligation, and the deferred tax liability. Total net debt includes
the adjusted working capital deficiency (excess). The adjusted working capital deficiency (excess) is an additional GAAP
measure calculated as net working capital deficiency (excess) excluding current finance lease obligation and current
1
deferred lease inducements. Management believes these measures are useful supplementary measures of the total
amount of current and long-term debt.
NON-GAAP MEASURES: This MD&A and contains the terms of operating netbacks and total capital expenditures - net,
which are not recognized measures under GAAP. Operating netbacks are calculated by subtracting royalties,
transportation, and operating expenses from revenues before other income. Management believes this measure is a
useful supplemental measure of the amount of revenues received after transportation, royalties and operating expenses.
Readers are cautioned, however, that this measure should not be construed as an alternative to net profit or loss
determined in accordance with GAAP as a measure of performance. Bellatrix’s method of calculating this measure may
differ from other entities, and accordingly, may not be comparable to measures used by other companies. Total capital
expenditures - net includes the cash impact of capital expenditures and property dispositions, as well as the non-cash
capital impacts of corporate acquisitions, adjustments to the Company’s decommissioning liabilities, and share based
compensation.
DISCLOSURES: Due to immateriality, the Company has combined the previously separated disclosure of “Heavy Oil”
revenue, volumes, pricing, production expenses and royalties into “Crude Oil and condensate” revenue, volumes,
pricing, production expenses and royalties for the year ending December 31, 2014. Prior period comparative values
have been adjusted for comparative purposes.
JOINT ARRANGEMENTS: Bellatrix is a partner in the Grafton Joint Venture, the CNOR Joint Venture, the Daewoo and
Devonian Partnership, and the Troika Joint Venture (all as defined below), which have all been separately assessed and
classified under International Financial Reporting Standards (“IFRS”) as joint operations. This classification is on the
basis that the arrangement is not conducted through a separate legal entity and the partners are legally obligated to pay
their share of costs incurred and take their share of output produced from the various production areas, and all partners
have rights to the assets and obligations for the liabilities resulting from the joint operations. The Company considered
these factors as well as the terms of the individual agreements in determining the classification of a joint operation to be
appropriate for each arrangement. For purposes of disclosure throughout the MD&A and financial statements, Bellatrix
has referred to these arrangements by the common oil and gas industry term of joint ventures.
GRAFTON JOINT VENTURE – On April 10, 2014, Bellatrix announced that Grafton Energy Co I Ltd. (“Grafton”)
elected to exercise an option to increase committed capital investment to the joint venture (the “Grafton Joint
Venture”) with Grafton established during 2013 by an additional $50 million, for a total commitment of $250 million,
on the same terms and conditions as the previously announced Grafton Joint Venture. The Grafton Joint Venture
properties are in the Willesden Green and Brazeau areas of West-Central Alberta, whereby Grafton will contribute
82%, or $250 million, to the joint venture to participate in a Notikewin/Falher and Cardium well program. Under the
agreement, Grafton will earn 54% of Bellatrix’s working interest (“WI”) in each well drilled in the well program until
payout (being recovery of Grafton's capital investment plus an 8% internal rate of return) on the total program,
reverting to 33% of Bellatrix's WI after payout. At any time after payout of the entire program, Grafton shall have the
option to elect to convert all wells from the 33% WI to a 17.5% Gross Overriding Royalty (“GORR”) on Bellatrix’s preGrafton Joint Venture WI.
CNOR JOINT VENTURE - On September 30, 2014, Bellatrix announced that the Company and Canadian NonOperated Resources Corp. ("CNOR"), a non-operated oil and gas company managed by Grafton Asset
Management Inc., had completed the formation of a new multi-year joint venture arrangement (the “CNOR Joint
Venture”), pursuant to which CNOR has committed $250 million in capital towards future accelerated development
of a portion of Bellatrix's extensive undeveloped land holdings. Under the terms of the agreement, CNOR will pay
50% of the drilling, completion, equipping and tie-in capital expenditures associated with development plans to be
proposed by Bellatrix and approved by a management committee comprised of representatives of Bellatrix and
CNOR in order to earn 33% of Bellatrix's working interest before payout and automatically converting to a 10.67%
gross overriding royalty on Bellatrix's pre-joint venture working interest after payout (being recovery of CNOR’s
capital investment plus an 8% return on investment).
DAEWOO AND DEVONIAN PARTNERSHIP – Bellatrix has a joint venture arrangement (the “Daewoo and
Devonian Partnership”) with Canadian subsidiaries of two Korean entities, Daewoo International Corporation
(“Daewoo”) and Devonian Natural Resources Private Equity Fund (“Devonian”) in the Baptiste area of West-Central
2
Alberta, whereby Daewoo and Devonian own a combined 50% of Bellatrix’s WI share of producing assets, an
operated compressor station and gathering system and related land acreage.
TROIKA JOINT VENTURE – Bellatrix has a joint venture (the “Troika Joint Venture”) with TCA Energy Ltd. ("TCA")
in the Ferrier Cardium area of West-Central Alberta, whereby Troika will contribute 50% towards a capital program
for which they will receive a 35% WI until payout (being recovery of TCA's capital investment plus a 15% internal
rate of return) on the total program, and thereafter reverting to 25% of Bellatrix's WI.
Additional information relating to the Company, including the Bellatrix’s Annual Information Form, is available on SEDAR
at www.sedar.com and on the Company’s website at www.bellatrixexploration.com. The Company’s EDGAR filings and
forms are available through the U.S. Securities and Exchange Commission at www.sec.gov.
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, operations
and strategy, drilling plans and the timing thereof, commodity price risk management strategies, 2015 capital expenditure
budget, the expectation of management to revisit its capital budget on a continuous basis, the nature of expenditures and
the method of financing thereof, anticipated liquidity of the Company and various matters that may impact such liquidity,
expected 2015 production expenses, general and administrative expenses, royalty rates and operating costs, 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, estimated capital expenditures
and wells to be drilled under joint venture agreements, the ability to fund the 2015 capital expenditure program utilizing
various available sources of capital, expected 2015 production growth, average daily production and exit rate, plans to
continue commodity risk management strategies, timing of redetermination of borrowing base, plans for additional
facilities and infrastructure and timing and effects thereof, expected cost and timing for completion of the Bellatrix Alder
Flats Plant (as defined below), expected additional ability to grow production resulting from completing the Bellatrix Alder
Flats Plant, expectation that Phase I of the Bellatrix Alder Flats Plant will be completed on schedule and on budget, the
expectation that the addition of firm service capacity is anticipated to improve overall operational reliability and facilitate
the execution of the Company’s projected growth, timing of commissioning of new facilities, including the Bellatrix Alder
Flats Plant, and the impact and anticipated benefits of infrastructure investments, expected timing of expenditure of
funds under the CNOR Joint Venture (as defined below), the expectation that 2015 will represent a transformational year
for the Company given the strategic infrastructure investment made over the past several years, the expectation that the
Company’s differentiated joint venture strategy will provide additional insulation from weak commodity prices given, and
the expectation that reduced service costs may provide further benefits in 2015, may constitute forward-looking
statements under applicable securities laws. To the extent that any forward-looking information contained herein
constitute a financial outlook, they were approved by management on March 11, 2015 and are included herein to provide
readers with an understanding of the anticipated funds available to Bellatrix to fund its operations and readers are
cautioned that the information may not be appropriate for other purposes. Forward-looking statements 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,
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
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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 affect 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), through the SEC website (www.sec.gov), 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.
Common shares of Bellatrix trade on the Toronto Stock Exchange and, effective October 6, 2014, on the New York
Stock Exchange, under the symbol “BXE”.
2014 Transactions
Consolidation Efforts of Key Operating Area
During the fourth quarter of 2014, Bellatrix completed an acquisition of complementary assets within its core Alder Flats
area of west central Alberta (greater Ferrier region) for total cash consideration of $118.0 million. The strategic tuck-in
acquisition added approximately 2,200 boe/d of unrestricted production (80% natural gas, 20% liquids) and largely
represented the consolidation of working interest ownership from existing wellbores and Mannville formation rights. The
transaction included production from approximately 10 gross (5.7 net) sections of land at Alder Flats, representing largely
joint interest lands where Bellatrix maintained existing working interest rights. The acquired acreage is highly contiguous
with Bellatrix acreage and includes operatorship over the majority of the acquired sections. Estimated reserve additions
from the transaction totaled 10.9 mmboe of proved reserves and 3.7 mmboe of probable reserves. The effective date of
the transaction was November 1, 2014.
Bellatrix completed an additional transaction during the fourth quarter of 2014 for the acquisition of complementary
assets within its core Alder Flats area of west central Alberta (greater Ferrier region) for total adjusted cash consideration
of $33.0 million. Approximately 720 boe/d of unrestricted production (77% natural gas, 23% liquids) was acquired in the
transaction from approximately 33 gross (5 net) sections of land at Alder Flats, representing largely joint interest lands
where Bellatrix currently maintains existing working interest rights. Estimated reserve additions from the transaction
totaled 9.0 mmboe of proved reserves and 3.8 mmboe of probable reserves. Production is largely from the Mannville
formation, with minor contributions from the Belly River, Rock Creek and other formations. The effective date of the
transaction was September 1, 2014.
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Additionally, during the fourth quarter of 2014, Bellatrix entered into a farmin arrangement encompassing 12 gross (9.4
net) sections of Mannville rights and 6 gross (3.5 net) sections of Cardium rights in the Ferrier area of West Central
Alberta. Under the arrangement, Bellatrix has committed to drill a minimum of 6 Cardium wells and 6 Mannville wells.
In the third quarter of 2014, Bellatrix completed a tuck-in acquisition of working-interests in the Company’s core Ferrier
area in West Central Alberta, extending the Company’s Cardium resource play for a net purchase price of $13.9 million.
The acquired assets included low decline rate net production of approximately 300 boe/d (24% oil and liquids and 76%
natural gas). The acquisition included 8 gross (7.0 net) sections of Cardium mineral rights and 3 gross (1.2 net) sections
of Mannville prospective lands. The Company estimates the acquired acreage to contain 18 gross (16.1 net) low risk
Cardium development locations, which are adjacent to Bellatrix’s core land base in the Ferrier area.
Bellatrix Alder Flats Plant
Bellatrix continued the construction of the Bellatrix O'Chiese Nees-Ohpawganu'ck deep-cut gas plant (the “Bellatrix Alder
Flats Plant”) in the Alder Flats area of Alberta. The Bellatrix Alder Flats Plant will be developed in two phases with a total
sales gas design capacity of 220 mmcf/d. Phase I and Phase II of the Bellatrix Alder Flats Plant are both designed to
process up to 110 mmcf/d, thereby providing Bellatrix the ability to grow its net production to over 80,000 boe/d in 2017
by utilizing existing strategic and third party infrastructure. Phase I of the Bellatrix Alder Flats Plant remains on schedule
and on budget for a July 2015 start-up.
In the fourth quarter of 2014, Bellatrix completed the transfer at cost of minority interests totaling 40% in Phase I and
Phase II of the Plant and related pipeline infrastructure currently under construction to Keyera Partnership and O'Chiese
Gas Plant GP Inc. The transfer of minority interests in the Bellatrix Alder Flats Plant is consistent with the Company's
strategy to maintain operatorship and control of strategic facilities, while being a good steward of available capital. The
transaction aligns the Company's working interest processing capacity in the facilities with its forecasted average net
working interest volumes to be processed through the Bellatrix Alder Flats Plant going forward.
Securing Firm Processing Capacity
On April 2, 2014, Bellatrix announced the completion of a 1.6 km river bore and a 7 km pipeline in conjunction with Blaze
Energy Ltd. ("Blaze"), completing a 55 km pipeline to tie-in Bellatrix natural gas for processing in the Blaze gas plant
located at 4-31-48-12W5. Bellatrix has secured firm processing capacity of 100 mmcf/d in the plant. Bellatrix was
delivering up to 100 mmcf/d (including partner gas) at its peak to the Blaze plant in December 2014, following the
successful completion of the booster compression project.
During the fourth quarter of 2014, Bellatrix entered into an arrangement with Keyera whereby Bellatrix has immediately
secured 19 mmcf/d of firm processing capacity, increasing to 30 mmcf/d on April 1, 2016 at Keyera's Strachan deep-cut
gas plant. The Keyera Strachan plant is well connected to multiple gathering pipelines and has inlet compression, gas
dehydration, and deep-cut natural gas liquids recovery. The addition of firm service capacity is anticipated to improve
overall operational reliability and facilitate the execution of the Company’s projected growth from the area.
Grafton Additional Commitments
On April 10, 2014, Bellatrix announced that Grafton elected to exercise an option to increase committed capital
investment to the Grafton Joint Venture with Grafton established during 2013 by an additional $50 million, for a total
commitment of $250 million, on the same terms and conditions as the previously announced Grafton Joint Venture.
On September 30, 2014, Bellatrix announced that based upon the success of the first joint venture with Grafton, Bellatrix
has entered into the new multi-year CNOR Joint Venture arrangement with CNOR, a non-operated oil and gas company
managed by Grafton Asset Management Inc. pursuant to which CNOR has committed $250 million in capital towards
future accelerated development of a portion of Bellatrix's extensive undeveloped land holdings. The joint venture funding
is available immediately, however Bellatrix expects the funds to be spent primarily from 2016 through 2018. Between
Grafton and CNOR, a total of $500 million has been committed to the development of Bellatrix's lands.
5
Transfer of Listing from NYSE MKT to the New York Stock Exchange
On October 1, 2014, Bellatrix announced the transfer of the listing of its common shares from NYSE MKT to the New
York Stock Exchange (“NYSE”). Bellatrix’s common shares began trading on the NYSE on Monday, October 6, 2014,
under its current trading symbol “BXE”. The Company’s common shares continue to be listed for trading on the Toronto
Stock Exchange (“TSX”).
$750.0 Million Short Form Base Shelf Prospectus and $172.6 Million Bought Deal Financing
In May 2014, Bellatrix filed a short form base shelf prospectus (the “$750 million Shelf Prospectus”) of up to $750 million,
with the securities regulatory authorities in each of the provinces of Canada (other than Quebec) and a Registration
Statement with the United States Securities and Exchange Commission. The $750 million Shelf Prospectus allows
Bellatrix to offer and issue common shares, subscription receipts, warrants and units (comprising any combination of the
foregoing securities), by way of one or more prospectus supplements at any time during the 25-month period that the
$750 million Shelf Prospectus remains in place.
Pursuant to a prospectus supplement to the $750 million Shelf Prospectus, on June 5, 2014, Bellatrix closed a bought
deal offering of 18,170,000 common shares of the Company (the "Common Shares") at a price of $9.50 per Common
Share for aggregate gross proceeds of $172.6 million (the "Offering"), through a syndicate of underwriters. Net proceeds
of $165.5 million received from the Offering were utilized to temporarily reduce outstanding indebtedness under the
Company's credit facilities, thereby freeing up borrowing capacity that may be redrawn, from time to time, to fund the
Company's ongoing capital expenditure program and for general corporate purposes.
As at December 31, 2014, the Company has the ability to offer to sell up to an additional $577.4 million on the $750
million Shelf Prospectus.
Credit Facilities Increased to $725 million and Financial Covenants Amended
Bellatrix maintains extendible revolving reserves-based credit facilities with a syndicate of lenders that mature May 2017.
The credit facilities do not require any mandatory principal payments prior to maturity and can be further extended
beyond May 2017 with the consent of the lenders. As of December 31, 2014, the credit facilities are available on an
extendible revolving term basis and consisting of a $75 million operating facility provided by a Canadian chartered bank
and a $650 million syndicated facility provided by nine financial institutions. The available credit facilities and related
borrowing base are subject to semi-annual reviews in May and November of each year.
In the Company’s semi-annual borrowing base review for November 30, 2014, Bellatrix and its lenders agreed to
increase the borrowing base and credit facilities to $725 million from $625 million. The 16% increase of $100 million to
the borrowing base and credit facilities was the result of Bellatrix's strong 2014 drilling results during the first nine months
of 2014, combined with benefits derived from the first of two tuck-in acquisitions completed during the fourth quarter of
2014 (excluding the announced $118.0 million acquisition), cumulatively delivering significant reserves and production
growth. The increased credit facilities will be available to finance Bellatrix’s ongoing capital expenditures, working capital
requirements and for general corporate purposes.
The Company is required to comply with covenants under its credit facilities, which include certain financial ratio tests,
which from time to time either affect the availability, or price, of additional funding. As discussed herein, as a result of the
recent precipitous drop in crude oil prices and the concomitant reduction in the Company’s associated future cash flow
and EBITDA, the Company sought and obtained from its lenders temporary relaxation of certain of these financial
covenants under its credit facilities.
6
2014 Guidance and Results
In 2014, Bellatrix successfully completed the most active year in the Company’s history. Sales volumes for the year
ended December 31, 2014 increased by 74% to average 38,065 boe/d (weighted 67% natural gas and 33% crude oil,
condensate and NGLs) compared to 21,829 boe/d in 2013. Bellatrix invested $504.5 million on exploration and
development capital projects, excluding property acquisitions and dispositions, during the year ended December 31,
2014, compared to $281.0 million in 2013. Included in net capital expenditures made during 2014 was $36 million
relating to the Bellatrix Alder Flats Plant project. Earnings for the year ended December 31, 2014 were $163.1 million, up
128% over $71.7 million in 2013. Revenue before other income, royalties, and commodity price risk management
contracts for the year ended December 31, 2014 increased by 99% to $574.3 million, compared to $288.3 million
realized in 2013.
2014 Guidance
Average daily production (boe/d)
Average product mix
Crude oil, condensate and NGLs (%)
Natural gas (%)
(2)
Capital spending ($ millions)
Expenses ($/boe)
(3)
Production
(3)
General and administrative
2014 Revised
(1)
Forecast
38,500
2014
Results
38,065
Variance (%)
(1)
33
67
515
33
67
516
-
7.95
1.67
8.64
1.83
9
10
(1)
Revised forecast guidance based on outlook as at November 4, 2014. Primarily as a result of third party facility constraints that
began to affect Bellatrix and other producers operating in West Central Alberta in early 2014, the Company revised its original
2014 average daily production guidance in March and May of 2014. Also in March 2014, the Company increased its net capital
budget to $440 million. In each of May, August and October 2014, the Company increased its net capital budget, inclusive of
exploration and development capital, corporate assets and property acquisitions and dispositions, to $500 million, $515 million, and
$530 million, respectively. Also in October 2014, as a result of continued tightness in available processing capacity, the Company
reduced its 2014 average daily production guidance to 38,500 boe/d.
(2)
Capital spending includes exploration and development capital projects and corporate assets, and excludes property
acquisitions and dispositions.
(3)
Actual full year production expense varied from the revised forecast primarily due to one-time adjustments attributable to
turnarounds on third-party operated facilities as well as realized facility equalizations in the fourth quarter of 2014. Absolute G&A
expenses increased in 2014 given higher staffing and compensation costs required to manage increased activity through the year.
On a per boe basis, G&A expenses varied relative to the revised forecast given the increase in absolute costs divided by lower
than projected production volumes, which were impacted by third-party facility downtime and TransCanada system pressures.
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FOURTH QUARTER 2014 HIGHLIGHTS
Three months ended December 31,
2014
2013
SELECTED FINANCIAL RESULTS
(CDN$000s except share and per share amounts)
(1)
Revenue (before royalties and risk management )
(2)
Funds flow from operations
(5)
Per basic share
(5)
Per diluted share
Cash flow from operating activities
(5)
Per basic share
(5)
Per diluted share
Net profit
(5)
Per basic share
(5)
Per diluted share
Capital – exploration and development
Capital – corporate assets
Property acquisitions
Capital expenditures – cash
Property dispositions – cash
Total net capital expenditures – cash
Corporate acquisitions and other non-cash items
(4)
Total capital expenditures – net
Long-term debt
(3)
Adjusted working capital deficiency
(3)
Total net debt
Total assets
Total shareholders’ equity
130,160
61,757
$0.32
$0.32
90,459
$0.47
$0.47
54,830
$0.29
$0.29
81,873
3,346
148,857
234,076
(1,435)
232,641
64,612
297,253
549,792
87,934
637,726
2,213,485
1,248,317
8
83,455
39,349
$0.31
$0.30
38,025
$0.30
$0.29
22,195
$0.17
$0.17
101,232
4,282
10,385
115,899
(16,700)
99,199
607,727
706,926
287,092
108,390
395,482
1,555,180
903,874
SELECTED OPERATING RESULTS
Average daily sales volumes
Crude oil, condensate and NGLs
Natural gas
Total oil equivalent
Average realized prices
Crude oil and condensate
NGLs (excluding condensate)
Crude oil, condensate and NGLs
Crude oil, condensate and NGLs (including
(1)
risk management )
Natural gas
(1)
Natural gas (including risk management )
Total oil equivalent
Total oil equivalent (including risk
(1)
management )
Three months ended December 31,
2014
2013
(bbls/d)
(mcf/d)
(boe/d)
13,204
178,443
42,945
7,564
98,423
23,968
($/bbl)
($/bbl)
($/bbl)
71.92
31.26
50.17
82.46
46.20
66.75
($/bbl)
($/mcf)
($/mcf)
($/boe)
57.16
4.01
4.08
32.07
64.32
3.89
3.97
37.05
($/boe)
34.51
36.59
7.1
21.4
($/boe)
16.12
21.10
($/boe)
($/boe)
($/boe)
($/boe)
18.56
1.05
9.57
2.33
20.64
1.02
8.70
2.53
17%
17%
191,950,576
10,913,337
202,863,913
191,579,631
170,990,605
11,182,963
182,173,568
130,875,349
7.03
3.45
4.23
3,166,506
8.52
6.65
7.81
2,678,253
6.28
2.97
3.64
547,564
8.43
6.38
7.33
171,620
Net wells drilled
Selected Key Operating Statistics
(4)
Operating netback
(4)
Operating netback (including risk
(1)
management )
Transportation
Production expenses
General & administrative
Royalties as a % of sales (after
transportation)
COMMON SHARES
Common shares outstanding
Share options outstanding
Fully diluted common shares outstanding
(5)
Weighted average shares
SHARE TRADING STATISTICS
TSX and Other
(6)
(CDN$, except volumes) based on intra-day trading
High
Low
Close
Average daily volume
NYSE
(7)
(US$, except volumes) based on intra-day trading
High
Low
Close
Average daily volume
(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 GAAP as an indicator of the Company’s
9
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)
Total net debt is considered to be an additional GAAP measure. Therefore reference to the additional GAAP measure of total net debt
may not be comparable with the calculation of similar measures for other entities. The Company’s 2014 calculation of total net debt
excludes deferred lease inducements, decommissioning liabilities, the long-term finance lease obligation, deferred lease inducements,
and the deferred tax liability. Total net debt includes the adjusted working capital deficiency (excess). The adjusted working capital
deficiency (excess) is an additional GAAP measure calculated as net working capital deficiency (excess) excluding short-term
commodity contract assets and liabilities, current finance lease obligation, and deferred lease inducements. A reconciliation between
total liabilities under GAAP and total net debt as calculated by the Company is found in this MD&A.
(4)
Operating netbacks and total capital expenditures – net are considered non-GAAP measures. Operating netbacks are calculated by
subtracting royalties, transportation, and operating costs from revenues before other income. Total capital expenditures – net includes
the cash impact of capital expenditures and property dispositions, as well as the non-cash capital impacts of corporate acquisitions,
property acquisitions, adjustments to the Company’s decommissioning liabilities, and share based compensation. The detailed
calculations of operating netbacks are found in the MD&A.
(5)
Basic weighted average shares for the three months ended December 31, 2014 were 191,579,631 (2013: 127,489,592).
In computing weighted average diluted earnings per share and weighted average diluted cash flow from operating activities and funds
flow from operations per share for the three months ended December 31, 2014, a total of nil (2013: 3,385,757) common shares were
added to the denominator as a consequence of applying the treasury stock method to the Company’s outstanding share options,
resulting in diluted weighted average common shares of 191,579,631 (2013: 130,875,349).
(6)
TSX and Other includes the trading statistics for the TSX and other Canadian trading markets.
(7)
Effective October 6, 2014, Bellatrix transferred the listing of its common shares from NYSE MKT to the New York Stock Exchange
(“NYSE”). The common shares trade on the NYSE under the same ticker symbol, “BXE”, as was used on the NYSE MKT listing and is
currently used on the TSX listing.
Sales Volumes
Sales volumes for the three months ended December 31, 2014 averaged 42,945 boe/d, an increase of 79% from an
average of 23,968 boe/d realized in the fourth quarter of 2013. The increase in total sales volumes experienced between
the quarters was primarily a result of a $234.1 million increase in net cash capital expenditures including property
acquisitions of 2,920 boe/d during the fourth quarter of 2014, Bellatrix’s ongoing successful drilling activity in the Cardium
and Mannville resource plays, and additional sales volumes acquired through the acquisition of Angle Energy Inc.
(“Angle”) in December 2013. The increase in sales volumes between the periods was also attributable in part to the
Grafton Joint Venture, the Daewoo and Devonian Partnership entered into by the Company during the third quarter of
2013, and the Troika Joint Venture entered into by the Company during the fourth quarter of 2013 as Bellatrix was able
to accelerate and expand its drilling activity through these joint venture arrangements throughout 2014.
Sales Volumes
Crude oil and condensate
NGLs (excluding condensate)
Total crude oil, condensate and NGLs
Natural gas
Total sales volumes (6:1 conversion)
Three months ended December 31,
2014
2013
6,139
4,286
7,065
3,278
13,204
7,564
(bbls/d)
(bbls/d)
(bbls/d)
(mcf/d)
178,443
98,423
(boe/d)
42,945
23,968
Crude oil, condensate and NGL sales volumes increased by 75% in the fourth quarter of 2014, averaging 13,204 bbls/d
compared to 7,564 bbls/d in the same period in 2013. The weighting towards crude oil, condensate and NGLs for the
three months ended December 31, 2014 was 31%, compared to 32% in the fourth quarter of 2013.
Sales of natural gas averaged 178.4 mmcf/d during the three months ended December 31, 2014, compared to 98.4
mmcf/d in the same period in 2013, an increase of 81%.
10
Drilling Activity
Cardium oil
Spirit River liquids-rich natural gas
Cardium natural gas
Total
Three months ended
December 31, 2014
Success
Gross
Net
Rate
3
2.0
100%
7
3.8
100%
2
1.3
100%
12
7.1
100%
Three months ended
December 31, 2013
Success
Gross
Net
Rate
24
16.2
100%
10
4.4
100%
1
0.8
100%
35
21.4
100%
During the fourth quarter of 2014, Bellatrix drilled and/or participated in 12 gross (7.1 net) wells, consisting of 3 gross (2.0
net) Cardium oil wells, 7 gross (3.8 net) Spirit River liquids-rich gas wells, and 2 gross (1.3 net) Cardium gas wells.
Bellatrix’s fourth quarter 2014 drilling activity was weighted 25% towards oil wells, and 75% towards natural gas wells.
By comparison, during the fourth quarter of 2013, Bellatrix drilled and/or participated in 35 gross (21.4 net) wells,
consisting of 24 gross (16.2 net) Cardium light oil horizontal wells, and 10 gross (4.4 net) Spirit River liquids-rich gas
wells, and one gross (0.8 net) Cardium gas well. Bellatrix’s drilling activity in the fourth quarter of 2013 was weighted
69% towards oil wells, and 31% towards gas wells.
Average Commodity Prices
Three months ended December 31,
2014
2013
% Change
Exchange rate (US$/CDN$1.00)
Crude oil:
WTI (US$/bbl)
Edmonton par – light oil / Canadian Light crude blend ($/bbl) (1)
Bellatrix’s average realized prices ($/bbl)
Crude oil and condensate
NGLs (excluding condensate)
Total crude oil and NGLs
Total crude oil and NGLs (including risk management (2))
Natural gas:
NYMEX (US$/mmbtu)
AECO daily index (CDN$/mcf)
AECO monthly index (CDN$/mcf)
Bellatrix’s average realized price ($/mcf)
Bellatrix’s average realized price (including risk
management (2)) ($/mcf)
0.8802
0.9528
(8)
73.20
74.37
97.61
86.26
(25)
(14)
71.92
31.26
50.17
57.16
82.46
46.20
66.75
64.32
(13)
(32)
(25)
(11)
3.83
3.60
4.01
4.01
3.85
3.53
3.15
3.89
(1)
2
27
3
4.08
3.97
3
(1)
Edmonton par – light oil prices were discontinued as of May 1, 2014 and replaced by Canadian Light crude blend. 2014 prices reflect
the Canadian Light crude blend, while 2013 prices reflect the Edmonton par – light oil.
(2)
Per unit metrics including risk management include realized gains or losses on commodity contracts and exclude unrealized gains or
losses on commodity contracts.
In the fourth quarter of 2014 Bellatrix realized an average price of $71.92/bbl before commodity price risk management
contracts for crude oil and condensate, a decrease of 13% from the average price of $82.46/bbl received in the fourth
quarter of 2013. By comparison, the Edmonton par/Canadian Light price decreased by 14% and the average WTI crude
oil benchmark price decreased by 25% between the fourth quarters of 2014 and 2013.
The global oil markets late in 2014 reacted with a significant price deterioration to the over-supply created from continued
production growth from shale plays in the United States, slower than anticipated global demand growth, and sustained
production from the Organization of the Petroleum Exporting Countries (“OPEC”).
Bellatrix’s average realized price for NGLs (excluding condensate) decreased by 32% to $31.26/bbl during the fourth
quarter of 2014, compared to $46.20/bbl received in the 2013 period.
11
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 realized prices per mcf than the daily
AECO index. During the fourth quarter of 2014, the AECO daily reference price increased by 2% and the AECO monthly
reference price increased by approximately 27% compared to the fourth quarter of 2013. Bellatrix’s natural gas average
sales price before commodity price risk management contracts for the fourth quarter of 2014 increased by 3% to
$4.01/mcf compared to $3.89/mcf in the same period in 2013.
Natural gas prices pulled back during the fourth quarter of 2014 as the year-over-year storage levels continued to build
due to growing production and a warmer than average start to the winter heating season.
Revenue
Revenue before other income, royalties and commodity price risk management contracts increased by 55% to $126.7
million for the three months ended December 31, 2014, compared to $81.7 million realized in the fourth quarter of 2013.
The higher realized revenue before other income between the 2014 and 2013 fourth quarters was attributable to an
increase in sales volumes for all products resulting from drilling activity throughout the 2014 year as well as additional
production from wells acquired as part of the acquisition of Angle in December 2013, in conjunction with higher realized
natural gas prices which were partially offset by the impacts of reduced crude oil, condensate, and NGL prices
experienced in the fourth quarter of 2014.
Crude oil and NGLs revenue before other income, royalties and commodity price risk management contracts for the
three months ended December 31, 2014 increased by 31% from the same period in 2013, resulting from 75% higher
sales volumes partially offset by reduced realized crude oil, condensate, and NGL prices when compared to the fourth
quarter of 2013.
For the three months ended December 31, 2014, total crude oil, condensate and NGL revenues contributed 48% of total
revenue before other income, compared to 57% in the fourth quarter of 2013.
Natural gas revenue before other income, royalties and commodity price risk management contracts increased by 87%
in the fourth quarter of 2014 compared to the same period in 2013 as a result of a 3% increase in realized gas prices
before risk management in conjunction with an 81% increase in sales volumes between the periods.
Three months ended December 31,
2014
2013
($000s)
Crude oil and condensate
NGLs (excluding condensate)
Crude oil and NGLs
Natural gas
Total revenue (before other income)
(1)
Other income
Total revenue (before royalties and risk management)
(1)
40,621
20,319
60,940
65,756
126,696
3,464
130,160
32,522
13,934
46,456
35,252
81,708
1,747
83,455
Other income primarily consists of processing and other third party income.
Royalties
In the fourth quarter of 2014, the Company incurred $21.0 million in royalties, compared to $13.8 million in the fourth
quarter of 2013. As a percentage of revenue before other income, royalties and commodity price risk management
contracts (after transportation costs), royalties were 17% in the three months ended December 31, 2014 and 2013. The
Company’s light crude oil, condensate and NGLs, and natural gas royalties are impacted by lower royalties on more
recent wells in their early years of production under the Alberta royalty incentive program, offset by increased royalty
rates on other wells now coming off initial royalty incentive rates and as other wells are drilled on Ferrier lands with
higher combined Indian Oil and Gas Canada (“IOGC”) royalty and gross overriding royalty (“GORR”) rates.
12
Royalties
Three months ended
December 31,
2014
2013
21,049
13,755
5.33
6.23
17
17
($000s, except where noted)
Royalties
Royalties ($/boe)
Average royalty rate (%)
Production Expenses
In the three months ended December 31, 2014, production expenses totaled $37.8 million, compared to $19.2 million
recorded in the same period of 2013.
During the three months ended December 31, 2014, production expenses
averaged $9.57/boe, compared to $8.70/boe incurred during the fourth quarter of 2013. By comparison, production
expenses for the third quarter of 2014 averaged $8.85/boe. Production expenses increased on a per boe basis between
the fourth quarter of 2014 and the fourth quarter of 2013 due to one-time adjustments of $1.42/boe primarily attributable
to turnarounds on third party operated facilities as well as realized facility equalizations. Excluding these one-time
adjustments, production expenses per boe for the three months ended December 31, 2014 were $8.15/boe.
Production Expenses by Commodity Type
($000s, except where noted)
Crude oil, condensate and NGLs
$/bbl
Three months ended
December 31,
2014
2013
11,465
5,827
9.44
8.37
Natural gas
$/mcf
26,359
1.61
13,346
1.47
Total Production Expenses
Total $/boe
37,824
9.57
19,173
8.70
Total Production Expenses
(1)
Processing and other third party income
Total after deducting processing and other third party income
Total $/boe
37,824
(3,464)
34,360
8.70
19,173
(1,747)
17,426
7.90
(1)
Processing and other third party income is included as other income in the Consolidated Statements of Comprehensive Income.
Transportation
Transportation expenses for the three months ended December 31, 2014 were $4.1 million ($1.05/boe), compared to
$2.3 million ($1.02/boe) in the fourth quarter of 2013.
Operating Netback
Operating Netback – Corporate (before risk management)
Three months ended
December 31,
2014
2013
32.07
37.05
(9.57)
(8.70)
(1.05)
(1.02)
(5.33)
(6.23)
16.12
21.10
($/boe)
Sales
Production
Transportation
Royalties
Operating netback
During the three months ended December 31, 2014, the Company’s corporate operating netback before commodity risk
management contracts decreased by 24% to $16.12/boe compared to $21.10/boe in the fourth quarter of 2013, driven
primarily by a 13% decrease in overall commodity prices, a 3% increase in transportation expenses, and a 10% increase
13
in production expenses, partially offset by a 15% decrease in royalties. By comparison, the Company’s corporate
operating netback before commodity risk management contracts for the third quarter of 2014 was $21.57/boe.
Operating Netback – Crude Oil, Condensate, and NGLs (before risk management)
Three months ended
December 31,
2014
2013
50.17
66.76
(9.44)
(8.37)
(0.79)
(0.84)
(12.14)
(14.36)
27.80
43.19
($/boe)
Sales
Production
Transportation
Royalties
Operating netback
Operating netback before commodity price risk management contracts for crude oil, condensate and NGLs during the
fourth quarter of 2014 averaged $27.80/bbl, a decrease of 36% from the $43.19/bbl realized during the same period in
2013. The decrease between the periods was primarily as a result of weaker commodity prices. Between the periods,
the operating net back for crude oil, condensate and NGLs was also impacted by higher production expenses, which
were partially offset by lower royalties and reduced transportation expenses. By comparison, the operating netback for
crude oil, condensate and NGLs for the third quarter of 2014 was $40.50/bbl.
Operating Netback – Natural Gas (before risk management)
Three months ended
December 31,
2014
2013
4.01
3.89
(1.61)
(1.47)
(0.19)
(0.18)
(0.38)
(0.42)
1.83
1.82
($/mcf)
Sales
Production
Transportation
Royalties
Operating netback
The operating netback for natural gas before commodity price risk management contracts during the fourth quarter of
2014 of $1.83/mcf was 1% lower than the $1.82/mcf recorded in the same period in 2013. The increase was attributable
to higher natural gas prices and reduced royalties, partially offset by higher production and transportation expenses. By
comparison, the operating netback for natural gas before commodity risk management contracts for the third quarter of
2014 was $2.19/mcf.
Interest and Financing Charges
Interest and financing charges related to bank debt for the three months ended December 31, 2014, totaled $5.8 million
($1.47/boe), compared to $2.3 million ($1.06/boe) during the fourth quarter of 2013, which included amounts relating to
the 4.75% convertible debentures settled during September and October of 2013. The increase in interest and financing
charges between the 2013 and 2014 periods was primarily due to higher interest charges as the Company carried a
higher average debt balance during the 2014 period and is supported by the expansion of Bellatrix’s credit facility to
$725 million. The higher average debt balance carried during the 2014 period was the result of Bellatrix’s expanded net
capital program related to exploration and development projects and acquisitions during 2014 compared to the 2013
year.
General and Administrative
General and administrative expenses (after capitalized G&A and recoveries) for the three months ended December 31,
2014 were $9.2 million ($2.33/boe), compared to $5.6 million ($2.53/boe) in the same period in 2013. The overall
increase to net G&A was primarily attributable to increases in staffing and office costs between the periods related to
Bellatrix’s increased production and operation activities. These costs were offset by higher capitalized G&A and
recoveries from partners associated with higher capital spending. The increase in total net G&A expenses was more
than offset by higher sales volumes realized during the 2014 period, resulting in an overall decrease to G&A expenses
on a per boe basis.
14
General and Administrative Expenses
Three months ended
December 31,
2014
2013
16,187
9,220
(1,548)
(1,469)
(5,432)
(2,170)
9,207
5,581
2.33
2.53
($000s, except where noted)
Gross expenses
Capitalized
Recoveries
G&A expenses
G&A expenses, per unit ($/boe)
Share-Based Compensation
For the three months ended December 31, 2014, non-cash share-based compensation was a recovery of $1.5 million
($0.38/boe), compared to a $1.0 million expense ($0.43/boe) in the same period in 2013. The non-cash share-based
compensation recovery realized in the 2014 period was composed of a recovery of $1.8 million for Deferred Share Units
(“DSUs”) (2013: $0.1 million recovery), a recovery of $0.4 million (2013: $0.3 million expense) for Performance Awards
(“PAs”), and a recovery of $0.8 million (2013: $0.7 million expense) for Restricted Awards (“RAs”), partially offset by
lower capitalized share-based compensation of $0.3 million (2013: $0.6 million) and a higher expense for the Company’s
outstanding share options of $1.8 million (2013: $0.7 million). The recoveries recognized for DSUs, RAs, and PAs
recognized during the fourth quarter of 2014 was primarily due to the revaluation of DSUs, RAs, and PAs to a lower
weighted average share trading price at December 31, 2014 than September 30, 2014.
Depletion, Depreciation and Impairment
Depletion and depreciation expense (excluding impairment) for the fourth quarter of 2014 was $50.4 million
($12.76/boe), compared to $27.3 million ($12.38/boe) in the same period in 2013.
The increase in depletion and
depreciation between the fourth quarter of 2013 and the same period in 2014 is reflective of a 79% increase in sales
volumes and a higher depletable base between the quarters impacted by net facility capital expenditures of $149.1
million in 2014 which excludes $38.7 million of facilities under construction, partially offset by the additional reserves
achieved through the Company’s drilling success and property acquisitions. By comparison, depletion, depreciation and
accretion expense for the third quarter of 2014 was $43.1 million ($12.39/boe). Primarily as a result of declining crude oil
and natural gas forward commodity prices, the Company recognized an impairment expense of $10.8 million related to
five non-core Cash Generating Units (“CGUs”) during the three months ended December 31, 2014. No impairment was
recognized in relation to the Company’s core West Central Alberta CGU.
Cash Flow from Operating Activities and Funds Flow from Operations
Funds flow from operations is a term that does not have any standardized meaning under GAAP. Bellatrix’s method of
calculating funds flow from operations may differ from that of other companies, and accordingly, may not be comparable
to measures used by other companies. Funds flow from operations is calculated as cash flow from operating activities
before decommissioning costs incurred, changes in non-cash working capital incurred and transaction costs.
Reconciliation of Cash Flow from Operating Activities to Funds Flow from Operations
Three months ended December 31,
($000s)
2014
2013
Cash flow from operating activities
Decommissioning costs incurred
Transaction costs
90,459
38,025
727
223
-
5,344
Change in non-cash working capital
(29,429)
(4,243)
Funds flow from operations
61,757
39,349
Bellatrix’s cash flow from operating activities for the three months ended December 31, 2014 increased by 138% to
$90.5 million ($0.47 per basic share and $0.47 per diluted share) from $38.0 million ($0.30 per basic share and $0.29 per
15
diluted share) generated in the fourth quarter of 2013. Bellatrix generated funds flow from operations of $61.8 million
($0.32 per basic share and $0.32 per diluted share) in the fourth quarter of 2014, an increase of 57% from $39.3 million
($0.31 per basic share and $0.30 per diluted share) generated in the comparative 2013 period. The greater funds flow
from operations in the fourth quarter of 2014 compared to the fourth quarter of 2013 was principally due to a 79%
increase in production volumes, higher realized natural gas prices, a net realized gain on commodity contracts in the
2014 period compared to a net realized loss in the 2013 period, partially offset by reduced realized crude oil,
condensate, and NGL prices, in addition to increased general and administrative, production, transportation, royalty, and
finance expenses.
For the three months ended December 31, 2014, Bellatrix recognized a net profit of $54.8 million ($0.29 per basic share
and $0.29 per diluted share), compared to a net profit of $22.2 million ($0.17 per basic share and $0.17 per diluted
share) in the fourth quarter of 2013. The higher net profit recorded in the fourth quarter of 2014 compared to the same
period in 2013 was primarily the result of increased funds from operating activities as noted above, an unrealized gain on
commodity contracts in the 2014 fourth quarter compared to an unrealized loss in the comparative 2013 period, a net
stock-based compensation recovery in the 2014 period compared to a net stock-based compensation expense in the
fourth quarter of 2013, a gain on property acquisition recognized in the fourth quarter of 2014, and a higher gain on
dispositions in the 2014 period compared to the 2013 fourth quarter. These positive impacts to net profit were partially
offset by increased depletion and depreciation expense as well as an impairment expense recognized in the fourth
quarter of 2014 compared to the same period in 2013.
Cash Flow from Operating Activities, Funds Flow from Operations and Net Profit
Three months ended
December 31,
2014
2013
($000s, except per share amounts)
Cash flow from operating activities
Basic ($/share)
Diluted ($/share)
90,459
0.47
0.47
38,025
0.30
0.29
Funds flow from operations
Basic ($/share)
61,757
0.32
39,349
0.31
Diluted ($/share)
0.32
0.30
Net profit
Basic ($/share)
Diluted ($/share)
54,830
0.29
0.29
22,195
0.17
0.17
During the three months ended December 31, 2014, Bellatrix invested $81.9 million on capital projects, excluding
corporate and property acquisitions and dispositions, compared to $101.2 million in the same period in 2013.
16
Capital Expenditures
Three months ended
December 31,
2014
2013
2,878
3,225
(103)
47
70,980
81,756
41,039
16,204
(32,921)
81,873
101,232
3,346
4,282
148,857
10,385
234,076
115,899
(1,435)
(16,700)
232,641
99,199
595,891
56,845
7,767
11,836
64,612
607,727
297,253
706,926
($000s)
Lease acquisitions and retention
Geological and geophysical
Drilling and completion costs
Facilities and equipment
Property transfers – cash
(1)
Capital – exploration and development
(2)
Capital – corporate assets
Property acquisitions
Total capital expenditures – cash
Property dispositions – cash
Total net capital expenditures – cash
Corporate acquisition – non-cash
Property acquisitions – non-cash
(3)
Other – non-cash
Total non-cash
(4)
Total capital expenditures – net
(1)
Excludes capitalized costs related to decommissioning liabilities expenditures incurred during the period.
Capital - corporate assets includes office leasehold improvements, furniture, fixtures and equipment before recoveries realized
from landlord lease inducements.
(3)
Other includes non-cash adjustments for the current period’s decommissioning liabilities and share based compensation.
(4)
Total capital expenditures – net is considered to be a non-GAAP measure. Total capital expenditures – net includes the cash
impact of capital expenditures and property dispositions, as well as the non-cash capital impacts of corporate acquisitions,
property acquisitions, adjustments to the Company’s decommissioning liabilities, and share based compensation.
(2)
During the fourth quarter of 2014, Bellatrix continued the construction of the Bellatrix Alder Flats Plant. The Bellatrix
Alder Flats Plant will be developed in two phases with total sales gas design capacity of 220 mmcf/d. Phase I of the
Bellatrix Alder Flats Plant remains on schedule and on budget of $90 million for a July 2015 start-up, with $60.1 million
total (including partners share) spent to date.
In the fourth quarter of 2014, Bellatrix completed the transfer at cost of minority interests totaling 40% in the Bellatrix
Alder Flats Plant and related pipeline infrastructure currently under construction to Keyera Partnership and O'Chiese Gas
Plant GP Inc.
17
2014 HIGHLIGHTS
Year ended December 31,
2014
2013
SELECTED FINANCIAL RESULTS (unaudited)
(CDN$000s except share and per share amounts)
(1)
Revenue (before royalties and risk management )
(2)
Funds flow from operations
(5)
Per basic share
(5)
Per diluted share
Cash flow from operating activities
(5)
Per basic share
(5)
Per diluted share
Net profit
(5)
Per basic share
(5)
Per diluted share
Capital – exploration and development
Capital – corporate assets
Property acquisitions
Capital expenditures – cash
Property dispositions – cash
Total net capital expenditures – cash
Corporate acquisitions and other non-cash items
(4)
Total capital expenditures – net
Long-term debt
(3)
Adjusted working capital deficiency
(3)
Total net debt
Total assets
Total shareholders’ equity
583,467
270,753
$1.48
$1.46
294,828
$1.61
$1.59
163,123
$0.89
$0.88
504,467
11,163
176,428
692,058
(9,809)
682,249
88,616
770,865
549,792
87,934
637,726
2,213,485
1,248,317
18
291,891
143,459
$1.27
$1.24
128,458
$1.14
$1.11
71,675
$0.63
$0.62
281,009
9,270
13,386
303,665
(70,942)
232,723
608,078
840,801
287,092
108,390
395,482
1,555,180
903,874
SELECTED OPERATING RESULTS
Average daily sales volumes
Crude oil, condensate and NGLs
Natural gas
Total oil equivalent
Average realized prices
Crude oil and condensate
NGLs (excluding condensate)
Crude oil, condensate and NGLs
Crude oil, condensate and NGLs (including
(1)
risk management )
Natural gas
(1)
Natural gas (including risk management )
Total oil equivalent
Total oil equivalent (including risk
(1)
management )
Year ended December 31,
2014
2013
(bbls/d)
(mcf/d)
(boe/d)
12,469
153,575
38,065
6,489
92,042
21,829
($/bbl)
($/bbl)
($/bbl)
91.41
42.74
67.47
91.45
43.85
72.29
($/bbl)
($/mcf)
($/mcf)
($/boe)
65.14
4.77
4.39
41.33
69.82
3.49
3.71
36.18
($/boe)
39.03
36.42
59.1
52.8
($/boe)
24.34
20.76
($/boe)
($/boe)
($/boe)
($/boe)
22.04
1.17
8.64
1.83
20.99
0.88
8.74
2.03
18%
16%
191,950,576
10,913,337
202,863,913
184,947,822
170,990,605
11,182,963
182,173,568
115,768,436
11.65
3.45
4.23
2,683,578
8.52
4.03
7.81
1,336,726
10.70
2.97
3.64
384,007
8.43
4.10
7.33
99,851
Net wells drilled
Selected Key Operating Statistics
(4)
Operating netback
(4)
Operating netback (including risk
(1)
management )
Transportation
Production expenses
General & administrative
Royalties as a % of sales (after
transportation)
COMMON SHARES
Common shares outstanding
Share options outstanding
Fully diluted common shares outstanding
(5)
Weighted average shares
SHARE TRADING STATISTICS
TSX and Other
(6)
(CDN$, except volumes) based on intra-day trading
High
Low
Close
Average daily volume
NYSE
(7)
(US$, except volumes) based on intra-day trading
High
Low
Close
Average daily volume
(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.
19
(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 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)
Total net debt is considered to be an additional GAAP measures. Therefore reference to the additional GAAP measure of total net
debt may not be comparable with the calculation of similar measures for other entities. The Company’s 2014 calculation of total net
debt excludes deferred lease inducements, decommissioning liabilities, the long-term finance lease obligation, deferred lease
inducements, and the deferred tax liability. Total net debt includes the adjusted working capital deficiency (excess). The adjusted
working capital deficiency (excess) is an additional GAAP measure calculated as net working capital deficiency (excess) excluding
short-term commodity contract assets and liabilities, current finance lease obligation, and deferred lease inducements. A reconciliation
between total liabilities under GAAP and total net debt as calculated by the Company is found in the MD&A.
(4)
Operating netbacks and total capital expenditures – net are considered non-GAAP measures. Operating netbacks are calculated by
subtracting royalties, transportation, and operating costs from revenues before other income. Total capital expenditures – net includes
the cash impact of capital expenditures and property dispositions, as well as the non-cash capital impacts of corporate acquisitions,
property acquisitions, adjustments to the Company’s decommissioning liabilities, and share based compensation. The detailed
calculations of operating netbacks are found in the MD&A.
(5)
Basic weighted average shares for the year ended December 31, 2014 were 183,216,536 (2013: 112,927,251).
In computing weighted average diluted earnings per share and weighted average diluted cash flow from operating activities and funds
flow from operations per share for the year ended December 31, 2014, a total of 1,731,286 (2013: 2,841,185) common shares were
added to the denominator as a consequence of applying the treasury stock method to the Company’s outstanding share options,
resulting in diluted weighted average common shares of 184,947,822 (2013: 115,768,436).
(6)
TSX and Other includes the trading statistics for the TSX and other Canadian trading markets.
(7)
Effective October 6, 2014, Bellatrix transferred the listing of its common shares from NYSE MKT to the New York Stock Exchange
(“NYSE”). The common shares trade on the NYSE under the same ticker symbol, “BXE”, as was used on the NYSE MKT listing and is
currently used on the TSX listing.
2014 Annual Financial and Operational Results
Sales Volumes
Sales volumes for the year ended December 31, 2014 increased by 74% to an average of 38,065 boe/d compared to
21,829 boe/d in the 2013 year. Total crude oil, condensate and NGLs averaged approximately 33% of sales volumes for
2014, compared to 30% in 2013. The increase in total sales volumes between the years were primarily a result of
$298.3 million of net drilling and completion capital expenditures for the year ended December 31, 2014, Bellatrix’s
ongoing successful drilling activity in the Cardium and Mannville resource plays, and additional sales volumes acquired
through the acquisition of Angle in December, 2013. The increase in sales volumes between the periods was also
attributable in part to the Grafton Joint Venture, the Daewoo and Devonian Partnership entered into by the Company
during the third quarter of 2013, and the Troika Joint Venture entered into by the Company during the fourth quarter of
2013, as Bellatrix was able to accelerate and expand its drilling activity through these joint venture arrangements
throughout 2014.
During 2014 Bellatrix experienced tightness in available processing capacity in its core area as interruptible capacity
became congested due to both system constraints and the influx of new production in the area. These constraints
stemmed from significant drilling with the application of new horizontal drilling and multi-stage fracing technology by area
operators. The area plant throughputs were further impacted by fluctuations in the TransCanada system pressures
which were elevated to accommodate their maintenance programs.
In order to address these production constraints, Bellatrix completed a multitude of infrastructure projects in 2014. In
April 2014, Bellatrix completed a 1.6 km river bore and a 7 km pipeline in conjunction with Blaze Energy Ltd., completing
a 55 km pipeline to tie-in Bellatrix’s natural gas for processing in the Blaze gas plant located at 4-31-48-12W5. In
addition, Bellatrix has secured firm processing capacity of 100 mmcf/d in the plant.
20
Bellatrix has also entered into a separate arrangement with Keyera whereby Bellatrix has immediately secured 19
mmcf/d of firm processing capacity, increasing to 30 mmcf/d on April 1, 2016 at Keyera's Strachan deep-cut gas plant.
The Keyera Strachan plant is well connected to multiple gathering pipelines and has inlet compression, gas dehydration,
and deep-cut natural gas liquids recovery.
The addition of firm service capacity is anticipated to improve overall
operational reliability and facilitate the execution of the Company’s projected growth from the area.
Also, in the fourth quarter Bellatrix added booster compression at its 13-5 compressor station, and completed the
construction of the Twin Rivers pipeline. These projects in combination are expected to increase gross processing
capability of approximately 30 to 40 mmcf/d; representing potential increased processing capability net to Bellatrix of
approximately 3,000 to 4,000 boe/d, based on forecasted working interest volumes.
Additionally, the two phases of the Bellatrix Alder Flats Plant and construction and tie-in of new associated pipelines are
anticipated to add 110 mmcf/d capacity by July 2015, expanding to a total of 220 mmcf/d in 2017. In combination, these
strategic endeavors provide for potential volume growth and total processing capability net to Bellatrix’s working interest
of over 80,000 boe/d in 2017.
Sales Volumes
Crude oil and condensate
NGLs (excluding condensate)
Total crude oil, condensate and NGLs
Natural gas
Total sales volumes (6:1 conversion)
Year ended December 31,
2014
2013
6,336
3,877
6,133
2,612
12,469
6,489
153,575
92,042
38,065
21,829
(bbls/d)
(bbls/d)
(bbls/d)
(mcf/d)
(boe/d)
In the year ended December 31, 2014, Bellatrix posted a 100% success rate, drilling and/or participating in 110 gross
(59.1 net) wells, consisting of 63 gross (36.4 net) Cardium oil wells, 34 gross (16.2 net) Spirit River liquids-rich gas wells,
and 13 gross (6.5 net) Cardium gas wells. Bellatrix’s drilling activity in 2014 was weighted 57% towards oil wells, and
43% towards natural gas wells
By comparison, during the year ended December 31, 2013, Bellatrix drilled and/or participated in 80 gross (52.8 net)
wells, consisting of 57 gross (41.2 net) Cardium light oil horizontal wells, 22 gross (10.8 net) Spirit River liquids-rich gas
wells, and one gross (0.8 net) Cardium gas well. Bellatrix’s drilling activity in 2013 was weighted 71% towards oil wells,
and 29% towards gas wells.
Drilling Activity
Cardium oil
Spirit River liquids-rich natural gas
Cardium natural gas
Total
Year ended
December 31, 2013
Success
Gross
Net
Rate
57
41.2
100%
22
10.8
100%
1
0.8
100%
80
52.8
100%
Year ended
December 31, 2014
Success
Gross
Net
Rate
63
36.4
100%
34
16.2
100%
13
6.5
100%
110
59.1
100%
Crude oil, condensate and NGL sales volumes increased by 92% in the year ended December 31, 2014, averaging
12,469 bbls/d, compared to 6,489 bbls/d in the 2013 year. Sales volumes were weighted 33% towards crude oil,
condensate and NGLs for the year ended December 31, 2014, compared to 30% in 2013.
Sales of natural gas averaged 153.6 mmcf/d during the year ended December 31, 2014, an increase of 69% compared
to 92.0 mmcf/d in 2013.
A net capital budget to not exceed $200 million has been set for fiscal 2015.
Based on the timing of proposed
expenditures, downtime for anticipated plant turnarounds and normal production declines, execution of the $200 million
2015 net capital budget is anticipated to provide 2015 average daily production of approximately 43,000 to 44,000 boe/d.
21
Commodity Prices
Average Commodity Prices
Year ended December 31,
2014
2013 % Change
Exchange rate (US$/CDN$1.00)
Crude oil:
WTI (US$/bbl)
Edmonton par – light oil / Canadian Light crude blend ($/bbl) (1)
Bellatrix’s average realized prices ($/bbl)
Crude oil and condensate
NGLs (excluding condensate)
Total crude oil and NGLs
Total crude oil and NGLs (including risk management (2))
Natural gas:
NYMEX (US$/mmbtu)
AECO daily index (CDN$/mcf)
AECO monthly index (CDN$/mcf)
Bellatrix’s average realized price ($/mcf)
Bellatrix’s average realized price (including risk
management (2)) ($/mcf)
0.9054
0.9712
(7)
92.21
93.99
98.05
93.24
(6)
1
91.41
42.74
67.47
65.14
91.45
43.85
72.29
69.82
(3)
(7)
(7)
4.26
4.50
4.41
4.77
3.73
3.17
3.16
3.49
14
42
40
37
4.39
3.71
18
(1)
Edmonton par – light oil prices were discontinued as of May 1, 2014 and replaced by Canadian Light crude blend. 2014 prices
reflect the Canadian Light crude blend, while 2013 prices reflect the Edmonton par – light oil.
(2)
Per unit metrics including risk management include realized gains or losses on commodity contracts and exclude unrealized
gains or losses on commodity contracts.
For crude oil and condensate, Bellatrix realized an average price of $91.41/bbl before commodity price risk management
contracts during the year ended December 31, 2014, consistent with the average price of $91.45/bbl received in the
2013 year. By comparison, the Edmonton par/Canadian Light price increased by 1% and the average WTI crude oil
benchmark price decreased by 6% between the 2014 and 2013 years.
In the first nine months of 2014, strong North American crude oil and natural gas prices promoted significant drilling
activity in North America.
The elevated drilling activity levels in conjunction with technological enhancements in
horizontal drilling resulted in supply growth of both crude oil and natural gas. The increased supply led to a supplydemand imbalance in the markets, which resulted in price deterioration for both crude oil and natural gas markets late in
2014.
The over-supplied nature of the global oil market became more apparent late in 2014, with the continued production
growth from shale plays in the United States, slower than expected global demand growth, and sustained production
levels by OPEC. Bellatrix expects significantly reduced drilling activity from the cutback 2015 budgeted capital spending
in the energy sector, resulting in a decrease in supply growth and re-balancing of over-supplied markets. However, there
will be a lag between drilling activity levels and a decrease in global oil production due to the life cycle of well
completions and tie-ins. In addition to re-balancing supply and demand, it is expected that the decrease in drilling
activity will result in a meaningful decrease in oilfield service costs which should result in improved rates of return at
lower commodity prices.
The average US$/CDN$1.00 foreign exchange rate decreased by 7% to 0.9054 for the year ended December 31, 2014
from an average rate of 0.9712 in 2013.
Bellatrix’s average realized price for NGLs (excluding condensate) decreased by 3% to $42.74/bbl during the 2014 year,
compared to $43.85/bbl received in the 2013 year. The overall decrease in NGL pricing between the years was largely
attributable to changes in NGL market supply conditions between the years.
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 realized prices per mcf than the daily
22
AECO index. During the year ended December 31, 2014, the AECO daily reference price increased by 42% and the
AECO monthly reference price increased by approximately 40% compared to the 2013 year. Bellatrix’s natural gas
average sales price before commodity price risk management contracts for the 2014 year increased by 37% to $4.77/mcf
compared to $3.49/mcf in 2013. Bellatrix’s natural gas average price after including commodity price risk management
contracts for the year ended December 31, 2014 averaged $4.39/mcf compared to $3.71/mcf in 2013.
Revenue
Revenue before other income, royalties and commodity price risk management contracts was $574.3 million for the year
ended December 31, 2014, an increase of 99% compared to $288.3 million realized in the year ended December 31,
2013. In the 2014 year, Bellatrix realized higher light oil, condensate, natural gas, and NGL revenues due primarily to
increased sales volumes resulting from Bellatrix’s ongoing successful drilling activity throughout 2014, a 38% increase in
wells drilled between the 2013 and 2014 years, higher natural gas prices, and additional sales volumes realized from the
acquisition of Angle in December of 2013, which were partially offset by lower NGL prices realized during the 2014 year.
Crude oil and NGLs revenue before other income, royalties and commodity price risk management contracts for the
2014 year increased by 79% to $307.1 million from $171.2 million realized during 2013. The increase in revenue realized
between the years was the result of 92% higher sales volumes, partly offset by slightly lower realized NGL prices when
compared to 2013.
For the year ended December 31, 2014, total crude oil, condensate and NGL revenues contributed 53% of total revenue
before other income, compared to 59% in the 2013 year.
Natural gas revenue before other income, royalties and commodity price risk management contracts was $267.2 million
in the year ended December 31, 2014, an increase of 128% from $117.1 million realized in the 2013 year. The increase
in realized revenue was attributable to a 37% increase in realized gas prices before risk management in conjunction with
a 69% increase in sales volumes between the 2014 and 2013 years.
Year ended December 31,
2014
2013
($000s)
Crude oil and condensate
NGLs (excluding condensate)
Crude oil and NGLs
Natural gas
Total revenue (before other income)
(1)
Other income
Total revenue (before royalties and risk management)
(1)
211,395
95,673
307,068
267,185
574,253
9,214
583,467
129,412
41,804
171,216
117,094
288,310
3,581
291,891
Other income 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.
23
As at December 31, 2014, Bellatrix had no outstanding commodity price risk management contracts and carried no
unrealized assets or liabilities related to such contracts.
A summary of the financial commodity price risk management volumes and average prices by quarter outstanding as of
March 11, 2015 is shown in the following tables:
Natural gas
Average Volumes (GJ/d)
Fixed
Q1 2015
54,250
Q2 2015
180,000
Q3 2015
180,000
Q4 2015
98,777
Q1 2015
2.73
Q2 2015
2.55
Q3 2015
2.55
Q4 2015
2.56
Q1 2015
1,967
Q2 2015
3,000
Q3 2015
3,000
Q4 2015
3,000
Q1 2015
70.34
Q2 2015
70.34
Q3 2015
70.34
Q4 2015
70.34
Average Price ($/GJ AECO C)
Fixed price
Crude oil and liquids
Average Volumes (bbls/d)
Fixed (CDN$)
Average Price ($/bbl WTI)
Fixed price (CDN$/bbl)
When the Company has outstanding commodity price risk management contracts at a reporting date, the fair value, or
mark-to-market value, of these contracts reflected in its financial statements as an unrealized asset or liability is based
on the estimated amount that would have been received or paid to settle the contracts as at the reporting date and would
differ from what would 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 are summaries of the gain (loss) on commodity contracts for the years ended December 31, 2014 and
2013 as reflected in the Consolidated Statements of Comprehensive Income:
Commodity contracts
Year ended December 31, 2014
($000s)
(1)
Realized cash loss on contracts
(4)
Unrealized gain on contracts
Total gain (loss) on commodity contracts
Crude Oil
(10,620)
11,411
791
Natural Gas
(21,371)
5,522
(15,849)
Total
(31,991)
16,933
(15,058)
Commodity contracts
Year ended December 31, 2013
($000s)
(2) (3)
Realized cash gain (loss) on contracts
(4)
Unrealized loss on contracts
Total loss on commodity contracts
Crude Oil
(5,851)
(4,112)
(9,963)
Natural Gas
7,710
(13,015)
(5,305)
Total
1,859
(17,127)
(15,268)
(1)
In January 2014, the Company settled a 1,500 bbl/d $105.00 US crude call option for the term of February to December 31,
2014 for US $0.5 million.
(2)
In January 2013, the Company crystalized and realized $6.5 million in cash proceeds by resetting the fixed prices on natural
gas commodity price risk management contracts for the period from April 1, 2013 through to October 31, 2013.
(3)
In September 2013, the Company incurred $0.6 million of costs for the settlement of an oil call commodity price risk
management contract for the period from November 1, 2013 through to December 31, 2013.
(4)
Unrealized gain (loss) on commodity contracts represents non-cash adjustments for changes in the fair value of these contracts
during the period.
24
Royalties
For the year ended December 31, 2014, royalties incurred totaled $99.8 million, compared to $46.2 million incurred in the
2013 year. Overall royalties as a percentage of revenue (after transportation costs) in 2014 were 18% compared with
16% in 2013.
Royalties by Commodity Type
Year ended December 31,
2014
2013
($000s, except where noted)
Crude oil, condensate and NGLs
$/bbl
Average crude oil, condensate and NGLs royalty rate (%)
66,128
14.53
22
35,913
15.16
21
Natural Gas
$/mcf
Average natural gas royalty rate (%)
33,695
0.60
13
10,304
0.31
9
Total
Total $/boe
Average total royalty rate (%)
99,823
7.18
18
46,217
5.80
16
Royalties by Type
Year ended December 31,
2014
2013
35,507
15,051
18,699
10,473
45,617
20,693
99,823
46,217
($000s)
Crown royalties
IOGC royalties
Freehold & GORR
Total
The Company’s light crude oil, condensate and NGLs, and natural gas royalties are impacted by lower royalties on more
recent wells in their early years of production under the Alberta royalty incentive program. This is offset by increased
royalty rates on wells coming off initial royalty incentive rates and wells drilled on Ferrier lands with higher combined
IOGC and GORR royalty rates.
EXPENSES
Year ended December 31,
2014
2013
120,072
69,668
16,259
7,014
99,823
46,217
25,371
16,214
19,198
12,488
3,673
4,960
($000s)
Production
Transportation
Royalties
General and administrative
(1)
Interest and financing charges
Share-based compensation
(1)
Does not include financing charges in relation to the Company’s accretion of decommissioning liabilities.
Expenses per boe
Year ended December 31,
2014
2013
8.64
8.74
1.17
0.88
7.18
5.80
1.83
2.03
1.38
1.57
0.26
0.62
($ per boe)
Production
Transportation
Royalties
General and administrative
(1)
Interest and financing charges
Share-based compensation
(1)
Does not include financing charges in relation to the Company’s accretion of decommissioning liabilities.
25
Production Expenses
Production expenses totaled $120.1 million ($8.64/boe) for the year ended December 31, 2014, compared to $69.7
million ($8.74/boe) in the 2013 year. Production expenses increased overall between the years as a result of increased
sales volumes and related operational activities. On a per boe basis, production expenses decreased in 2014 as the
overall increase in production expenses was more than offset by continued field optimization projects and increased
production in areas of Ferrier and Harmattan with lower production expenses, as well as reduced natural gas gathering
fees due to lower rate contracts executed during 2014.
Bellatrix is targeting production expenses of approximately $131.0 million ($8.25/boe) in the 2015 year, which represents
a reduction on a per unit basis from the $8.64/boe production expenses incurred for the 2014 year. The lower per boe
target is based upon assumptions of estimated 2015 average production of approximately 43,000 to 44,000 boe/d,
continued field optimization work, the start-up of the Bellatrix Alder Flats Plant, and planned capital expenditures in
producing areas which are anticipated to lower production expenses.
Production Expenses by Commodity Type
Year ended December 31,
2014
2013
38,539
25,839
8.47
10.91
($000s, except where noted)
Crude oil, condensate and NGLs
$/bbl
Natural gas
$/mcf
81,533
1.45
43,829
1.30
Total Production Expenses
Total $/boe
120,072
8.64
69,668
8.74
Total Production Expenses
(1)
Processing and other third party income
Total after deducting processing and other third party income
Total $/boe
120,072
(9,214)
110,858
7.98
69,668
(3,581)
66,087
8.29
(1)
Processing and other third party income is included as other income in the Consolidated Statements of Comprehensive
Income.
Transportation
Transportation expenses for the year ended December 31, 2014 were $16.3 million ($1.17/boe), compared to $7.0
million ($0.88/boe) in the 2013 year. The increase in transportation costs per boe between 2013 and 2014 was due to
increased fuel costs resulting from higher natural gas pricing realized during 2014, as well as higher transporting costs
for crude oil and associated products produced from wells commencing production during 2014.
Operating Netback
Operating Netback – Corporate (before risk management)
Year ended December 31,
2014
2013
41.33
36.18
(8.64)
(8.74)
(1.17)
(0.88)
(7.18)
(5.80)
24.34
20.76
($/boe)
Sales
Production
Transportation
Royalties
Operating netback
For the year ended December 31, 2014, the corporate operating netback (before commodity risk management contracts)
was $24.34/boe, an increase of 17% compared to $20.76/boe in the 2013 year. The higher netback realized in 2014
was primarily the result of an increase in the average realized combined commodity prices and lower production
expenses, partially offset by increased royalty and transportation expenses. After including commodity risk management
contracts, the corporate operating netback for the year ended December 31, 2014 was $22.04/boe, compared to
26
$20.99/boe in 2013.
Per unit metrics including risk management include realized gains or losses on commodity
contracts and exclude unrealized gains or losses on commodity contracts.
Operating Netback – Crude Oil, Condensate, and NGLs (before risk management)
Year ended December 31,
2014
2013
67.47
72.29
(8.47)
(10.91)
(1.11)
(0.86)
(14.53)
(15.16)
43.36
45.36
($/boe)
Sales
Production
Transportation
Royalties
Operating netback
Operating netback for crude oil, condensate, and NGLs decreased by 4% to $43.36/bbl for the year ended December 31,
2014 from $45.36/bbl realized in the 2013 year. The lower netback was primarily attributable to lower NGL commodity
prices and higher transportation expenses, partially offset by reduced production expenses and royalties. After including
commodity price risk management contracts, operating netback for crude oil, condensate, and NGLs for the year ended
December 31, 2014 was $41.03/bbl, compared to $42.89/bbl in 2013.
Operating Netback – Natural Gas (before risk management)
Year ended December 31,
2014
2013
4.77
3.49
(1.45)
(1.30)
(0.20)
(0.15)
(0.60)
(0.31)
2.52
1.73
($/mcf)
Sales
Production
Transportation
Royalties
Operating netback
For the year ended December 31, 2014, operating netback for natural gas was $2.52/mcf, an increase of 46% from
$1.73/mcf realized in 2013. The higher netback between the years reflected higher natural gas prices, partially offset by
increased production, transportation, and royalty expenses.
After including commodity risk management contracts,
operating netback for natural gas for the year ended December 31, 2014 was $2.14/mcf, compared to $1.96/mcf in the
2013 year.
General and Administrative
General and administrative expenses (after capitalized G&A and recoveries) for the year ended December 31, 2014
were $25.4 million ($1.83/boe), compared to $16.2 million ($2.03/boe) in 2013. The higher G&A expenses in 2014 were
primarily reflective of higher compensation costs and related staffing costs as Bellatrix’s headcount has increased by
68% between the years to manage the increased activity resulting from the Angle acquisition and increased drilling
activity. These cost increases were partially offset by greater capitalization of G&A and recoveries from partners
associated with higher capital spending. On a per boe basis, G&A expenses for the year ended December 31, 2014
decreased by 10% compared to 2013 due to increased sales volumes and Bellatrix’s continued increased focus on
operational and administrative efficiencies.
General and Administrative Expenses
Year ended December 31,
2014
2013
55,600
29,145
(8,458)
(5,343)
(21,771)
(7,588)
25,371
16,214
1.83
2.03
($000s, except where noted)
Gross expenses
Capitalized
Recoveries
G&A expenses
G&A expenses, per unit ($/boe)
27
Interest and Financing Charges
For the year ended December 31, 2014, Bellatrix recorded $19.2 million ($1.38/boe) of interest and financing charges
related to bank debt, compared to $12.5 million ($1.57/boe) during the 2013 year, which included amounts relating to the
4.75% convertible debentures outstanding during the majority of 2013. Bellatrix’s convertible debentures were settled
during September and October of 2013.
The overall increase in interest and financing charges between 2013 and 2014 was primarily due to higher interest
charges as the Company carried a higher average debt balance during the 2014 year resulting from the increased 2014
net capital program and is supported by the expansion of the Bellatrix’s credit facility to $725M.
Bellatrix’s total net debt at December 31, 2014 of $637.7 million included $549.8 million of bank debt and an adjusted
working capital deficiency of $87.9 million.
Interest and Financing Charges
(1)
Year ended December 31,
2014
2013
19,198
12,488
1.38
1.57
($000s, except where noted)
Interest and financing charges
Interest and financing charges ($/boe)
(1)
Does not include financing charges in relation to the Company’s accretion of decommissioning liabilities.
Debt to Funds Flow from Operations Ratio
Year ended December 31,
2014
2013
1,248,317
903,874
($000s, except where noted)
Shareholders’ equity
Long-term debt
(2)
Adjusted working capital deficiency
(2)
Total net debt at year end
549,792
87,934
637,726
287,092
108,390
395,482
247,028
637,726
2.6x
157,396
395,482
2.5x
270,753
637,726
2.4x
143,459
395,482
2.8x
(1) (3)
Debt to funds flow from operations ratio (annualized)
(1)
Funds flow from operations (annualized)
(2)
Total net debt at year end
(3)
Total net debt to periods funds flow from operations ratio (annualized)
(1)
Debt to funds flow from operations ratio
(1)
Funds flow from operations for the year
(2)
Total net debt at year end
(2)
(1)
Total net debt to funds flow from operations ratio for the year
(1)
(2)
As detailed previously in this MD&A, funds flow from operations is a term that does not have any
standardized meaning or
definition under GAAP.
Funds flow from operations is calculated as cash flow from operating activities, excluding
decommissioning costs incurred, changes in non-cash working capital incurred and transaction costs. Refer to the reconciliation of
cash flow from operating activities to funds flow from operations appearing elsewhere herein.
Total net debt is considered to be an additional GAAP measure. Therefore reference to the additional GAAP measurer of total net
debt may not be comparable with the calculation of similar measures for other entities. The Company’s 2014 calculation of total
net debt excludes deferred lease inducements, decommissioning liabilities, the long-term finance lease obligation, deferred lease
inducements, and the deferred tax liability. Total net debt includes the adjusted working capital deficiency (excess). The adjusted
working capital deficiency (excess) is an additional GAAP measure calculated as net working capital deficiency (excess) excluding
short-term commodity contract assets and liabilities, current finance lease obligation, and deferred lease inducements. A
reconciliation between total liabilities under GAAP and total net debt as calculated by the Company is found in the MD&A.
(3)
For the years ended December 31, 2014 and 2013, total net debt to funds flow from operations ratio (annualized) is calculated
based upon fourth quarter funds flow from operations annualized.
28
Reconciliation of Total Liabilities to Total Net Debt
($000s)
Total liabilities per financial statements
Current liabilities (included within working capital calculation below)
Decommissioning liabilities
Finance lease obligation
Deferred lease inducements
Deferred taxes
Adjusted working capital
Current assets
Current liabilities
Current portion of finance lease
Current portion of deferred lease inducements
Current portion of commodity contract liability
As at December 31,
2014
2013
965,168
651,306
(232,396)
(255,903)
(88,605)
(67,075)
(10,063)
(11,637)
(2,727)
(2,565)
(81,585)
(27,034)
(142,548)
232,396
(1,574)
(340)
87,934
637,726
Total net debt
(128,800)
255,903
(1,495)
(285)
(16,933)
108,390
395,482
Share-Based Compensation
For the year ended December 31, 2014, non-cash share-based compensation expense was $3.7 million compared to
$5.0 million in the same period in 2013. The decrease in non-cash share-based compensation expense was composed
of a recovery of $1.3 million for Deferred Share Units (“DSUs”) (2013: $2.3 million expense), higher capitalized sharebased compensation of $3.4 million (2013: $1.7 million), and a lower expense of $0.9 million (2013: $1.0 million) for
Restricted Awards (“RAs”), partially offset by a higher expense for the Company’s outstanding share options of $6.9
million (2013: $2.9 million), and a higher expense of $0.6 million (2013: $0.5 million) for Performance Awards (“PAs”).
The $1.3 million recovery for DSUs and lower expense for RAs recognized during 2014 was primarily due to the
revaluation of DSUs and RAs to a lower weighted average share trading price at December 31, 2014 than December 31,
2013.
Depletion and Depreciation and Impairment
Depletion and depreciation expense (excluding impairment) for the year ended December 31, 2014 was $171.0 million
($12.31/boe), compared to $85.8 million ($10.77/boe) recognized in the 2013 year. The increase in depletion and
depreciation expense between the periods on a per boe basis was primarily a result of a higher cost base impacted by
net facility capital expenditures of $149.1 million in 2014, which excludes $38.7 million of facilities under construction,
and increased future development costs, which was only partially offset by an increase in the reserve base used for the
depletion calculation.
For the year ended December 31, 2014, Bellatrix has included a total of $1.34 billion (2013: $1.28 billion) for future
development costs in the depletion calculation and excluded from the depletion calculation a total of $80.3 million (2013:
$69.0 million) for estimated salvage.
Depletion and Depreciation
Year ended December 31,
2014
2013
($000s, except where noted)
Depletion and Depreciation
Per unit ($/boe)
170,967
12.31
85,829
10.77
Impairment
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 its recoverable amount, which is defined as the greater of its value-in-use and 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
29
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.
2014 Impairment
At December 31, 2014, Bellatrix performed an assessment of possible indicators of impairment on all of the Company’s
CGUs.
Primarily as a result of declining crude oil and natural gas forward commodity prices, Bellatrix completed
impairment tests for each of its CGUs.
The impairment amount was estimated using fair value less costs to sell
calculations based on expected future cash flows generated from proved and probable reserves, which incorporated
before-tax discount rates ranging from 10-15%. This impairment test resulted in an excess of the carrying value over
their recoverable amount in five non-core CGUs.
The total non-cash impairment loss recognized in depletion,
depreciation and impairment expense for the year ended December 31, 2014 was $10.8 million. No impairment was
recognized in relation to the Company’s core West Central Alberta CGU.
2013 Impairment
As at December 31, 2013, Bellatrix determined there were no impairment indicators requiring an impairment test to be
performed.
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, 2014, the Company recognized a deferred income tax expense of $56.5
million, compared to $19.5 million during 2013. The increase in deferred income tax expense between 2013 and 2014
was primarily attributable to the increase in net profit after adjusting for non-deductible tax items realized during the 2014
year.
At December 31, 2014, the Company had a total deferred tax liability balance of $81.6 million.
At December 31, 2014, Bellatrix had approximately $1.64 billion in tax pools available for deduction against future
income as follows:
($000s)
Intangible resource pools:
Canadian exploration expenses
Canadian development expenses
Canadian oil and gas property expenses
Foreign resource expenses
Alberta non-capital losses greater than
Federal non-capital losses
(1)
Undepreciated capital cost
Non-capital losses (expire through 2030)
Financing costs
(1)
Rate %
December 31,
2014
December 31,
2013
100
30
10
10
116,700
758,700
207,900
800
99,000
691,500
80,200
900
(Alberta) 100
6 – 55
100
20 S.L.
16,100
367,600
162,300
14,100
1,644,200
16,100
224,900
94,500
15,600
1,222,700
Approximately $355.0 million of undepreciated capital cost pools are class 41, which is claimed at a 25% rate.
30
Cash Flow from Operating Activities, Funds Flow from Operations and Net Profit
As detailed previously in this MD&A, funds flow from operations is an additional GAAP measure that does not have any
standardized meaning under GAAP. Bellatrix’s method of calculating funds flow from operations may differ from that of
other companies, and accordingly, may not be comparable to measures used by other companies. Funds flow from
operations is calculated as cash flow from operating activities before decommissioning costs incurred, changes in noncash working capital incurred, and transaction costs.
Reconciliation of Cash Flow from Operating Activities to Funds Flow from Operations
Year ended December 31,
2014
2013
294,828
128,458
1,743
1,057
5,344
(25,818)
8,600
($000s)
Cash flow from operating activities
Decommissioning costs incurred
Transaction costs
Change in non-cash working capital
Funds flow from operations
270,753
143,459
Bellatrix’s cash flow from operating activities for the year ended December 31, 2014 increased by 130% to $294.8 million
($1.61 per basic share and $1.59 per diluted share) from $128.5 million ($1.14 per basic share and $1.11 per diluted
share) generated during the 2013 year. Bellatrix generated funds flow from operations of $270.8 million ($1.48 per basic
share and $1.46 per diluted share) in the year ended December 31, 2014, an increase of 89% from $143.5 million ($1.27
per basic share and $1.24 per diluted share) generated in 2013. The increase in funds flow from operations between
2013 and 2014 was principally due to an increase of 74% in production volumes and higher realized natural gas prices,
partially offset by reduced realized NGL prices, a net realized loss on commodity contracts in 2014 compared to a net
realized gain on commodity contracts in 2013, and increased general and administrative, production, transportation,
royalty, and finance expenses related to the increased operational activity.
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 fair market value of the
contract over its entire term and are included in the calculation of net profit.
For the year ended December 31, 2014, Bellatrix recognized a net profit of $163.1 million ($0.89 per basic share and
$0.88 per diluted share), compared to a net profit of $71.7 million ($0.63 per basic share and $0.62 per diluted share) in
2013. The higher net profit recorded in 2014 compared to 2013 was primarily the result of increased funds from
operating activities as noted above, an unrealized gain on commodity contracts in the 2014 year compared to an
unrealized loss in 2013, lower stock-based compensation expense, a gain on property acquisition recognized during
2014, and a higher gain on dispositions in 2014 compared to 2013. These positive impacts to net profit were partially
offset by increased depletion and depreciation expense, and an impairment expense recognized in the 2014 year
compared to 2013.
31
Cash Flow from Operating Activities, Funds Flow from Operations and Net Profit
Year ended December 31,
2014
2013
($000s, except per share amounts)
Cash flow from operating activities
Basic ($/share)
Diluted ($/share)
294,828
1.61
1.59
128,458
1.14
1.11
Funds flow from operations
Basic ($/share)
270,753
1.48
143,459
1.27
Diluted ($/share)
1.46
1.24
Net profit
Basic ($/share)
Diluted ($/share)
163,123
0.89
0.88
71,675
0.63
0.62
Capital Expenditures
Bellatrix invested $504.5 million on exploration and development capital projects, excluding property acquisitions and
dispositions during the year ended December 31, 2014, compared to $281.0 million in 2013.
Capital Expenditures
Year ended December 31,
2014
2013
16,701
11,190
1,601
140
298,313
211,912
220,773
57,767
(32,921)
504,467
281,009
11,163
9,270
176,428
13,386
692,058
303,665
(9,809)
(70,942)
682,249
232,723
595,891
68,616
20,000
12,187
88,616
608,078
770,865
840,801
($000s)
Lease acquisitions and retention
Geological and geophysical
Drilling and completion costs
Facilities and equipment
Property transfers – cash
(1)
Capital – exploration and development
(2)
Capital – corporate assets
Property acquisitions
Total capital expenditures – cash
Property dispositions – cash
Total net capital expenditures – cash
Corporate acquisition – non-cash
Property acquisitions – non-cash
(3)
Other – non-cash
Total non-cash
(4)
Total capital expenditures – net
(1)
Excludes capitalized costs related to decommissioning liabilities expenditures incurred during the period.
Capital - corporate assets includes office leasehold improvements, furniture, fixtures and equipment before recoveries realized
from landlord lease inducements.
(3)
Other includes non-cash adjustments for the current period’s decommissioning liabilities and share based compensation.
(4)
Total capital expenditures – net is considered to be a non-GAAP measure. Total capital expenditures – net includes the cash
impact of capital expenditures and property dispositions, as well as the non-cash capital impacts of corporate acquisitions,
property acquisitions, adjustments to the Company’s decommissioning liabilities, and share based compensation.
(2)
During the fourth quarter of 2014, Bellatrix continued the construction of the Bellatrix Alder Flats Plant. The Bellatrix
Alder Flats Plant will be developed in two phases with a total sales gas capacity of 220 mmcf/d. Phase I of the Bellatrix
Alder Flats Plant remains on schedule and on budget of $90 million for a July 2015 start-up, with $60.1 million total
(including partners’ share) spent to date.
In the fourth quarter of 2014, Bellatrix completed the transfer at cost as at the transfer date of minority interests totaling
40% in the Bellatrix Alder Flats Plant and related pipeline infrastructure currently under construction to Keyera
Partnership and O'Chiese Gas Plant GP Inc. The total value of the minority interests transferred related to the Bellatrix
Alder Flats Plant was $23.2 million, which reflected total actual costs incurred for the interest transferred as at the
transfer date. The remainder of the value transferred during 2014 related to recently constructed pipeline infrastructure.
32
Bellatrix’s $692.1 million capital program for the year ended December 31, 2014 was financed from a combination of
funds flow from operations, bank debt, and net proceeds of $165.5 million from the June 5, 2014 common share boughtdeal financing.
Based on the current economic conditions and Bellatrix’s operating forecast for 2015, the Company budgets a net capital
program to not exceed $200 million funded from the Company’s cash flows and to the extent necessary, bank
indebtedness. The 2015 capital budget is expected to be directed primarily towards horizontal drilling and completions
activities in the Cardium and Mannville formations and completion of Phase I of the Bellatrix Alder Flats Plant.
Business Combinations
Bellatrix completed multiple property acquisitions during 2014.
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 acquisitions individually and determined
each of them to constitute business combinations 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.
For each of the property acquisitions described below, the estimated fair value of the property, plant and equipment
acquired was determined using internal estimates and independent reserve evaluations. 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. The fair value of identifiable assets acquired and liabilities assumed is
final.
During the third quarter of 2014, Bellatrix closed an acquisition of production and working interests in certain facilities, as
well as undeveloped land in the Ferrier area of Alberta for a cash purchase price of $13.9 million after adjustments.
$27.0 million of oil and natural gas properties, the value of which was determined using the present value of associated
reserves, and $0.1 million of exploration and evaluation assets were acquired, in addition to $1.4 million of
decommissioning liabilities assumed as a result of the acquisition. A gain on property acquisition of $11.8 million was
recognized in relation to the acquisition. The effective date of the transaction was September 1, 2014.
During the fourth quarter of 2014, Bellatrix completed a transaction for the acquisition of complementary assets within its
core Alder Flats area of west central Alberta (greater Ferrier region) for total cash consideration of $118.0 million. The
acquired assets consisted entirely of oil and natural gas properties, the value of which was determined using the present
value of associated reserves. No gain or loss on property acquisition was recognized in relation to the acquisition. The
effective date of the transaction was November 1, 2014.
Bellatrix completed an additional transaction during the fourth quarter of 2014 for the acquisition of complementary
assets within its core Alder Flats area of west central Alberta (greater Ferrier region) for total adjusted cash consideration
of $33.0 million. $85.5 million of oil and natural gas properties, the value of which was determined using the present
value of associated reserves, and $4.5 million of exploration and evaluation assets were acquired in addition to $0.1
million of decommissioning liabilities assumed as a result of the acquisition. A gain on property acquisition of $56.8
million was recognized in relation to the acquisition. The effective date of the transaction was September 1, 2014.
Dispositions
In the year ended December 31, 2014, a total net gain on dispositions of $52.3 million (2013: $11.2 million) was
recognized relating to gains on wells drilled under the Grafton Joint Venture and the Troika Joint Venture which were
completed and tied-in during 2014. A gain on disposition for each well is recognized to account for the disposal of the
pre-payout working interest earned by the joint venture partner on the well, which results from the difference between the
percentage of all capital costs contributed for the drilling, completion, equipping and tie-in of the well by the joint venture
partner and the pre-payout working interest allocated to the joint venture partner by the Company. The gain on
disposition for a well is recognized during the quarter in which the well was completed and tied-in.
33
Under the Grafton Joint Venture, Grafton contributes 82% of the total capital costs required for each well and in return
earns 54% of Bellatrix’s WI in each well drilled in the well program until payout.
Under the Troika Joint Venture, Troika contributes 50% of the total capital costs required for each well and in return
earns 35% of Bellatrix’s WI in each well drilled in the well program until payout.
Decommissioning Liabilities
At December 31, 2014, Bellatrix has recorded decommissioning liabilities of $88.6 million, compared to $67.1 million at
December 31, 2013, for future abandonment and reclamation of the Company’s properties. During the year ended
December 31, 2014, decommissioning liabilities increased by a net $21.5 million as a result of $4.4 million incurred in
relation to development activities, $3.1 million related to corporate asset acquisitions, $12.4 million resulting from
changes in estimates, and $1.7 million as a result of charges for the unwinding of the discount rates used for assessing
liability fair values, partially offset by a $0.1 million decrease related to working interest dispositions during the year. The
$12.4 million increase as a result of changes in estimates was primarily due to reduced market interest rates which
resulted in decreases to discount rates applied to the valuation of liabilities between December 31, 2014 and December
31, 2013, as well as revisions to timing estimates of future decommissioning cash flows made to better reflect anticipated
abandonment timelines.
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 upon 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 decreased.
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 and optimizing capital investments – which it seeks to attain 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. 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.
Even though the Company experienced continual operational success in 2014, volatility in oil and gas prices has resulted
in a challenging environment for the energy sector. In response to this volatility and to preserve liquidity and capital
resources, Bellatrix announced a reduction to its 2015 net capital budget to not exceed $200 million on January 29,
2015. This represents a 71% reduction from actual 2014 capital spending. Bellatrix has the ability to fund its 2015 capital
program to not exceed $200 million by utilizing cash flow and to the extent necessary, bank indebtedness. Bellatrix
anticipates annual 2015 production growth of approximately 14% relative to estimated 2014 average production despite
this reduced capital spending program. Bellatrix continues to focus on management of all aspects of capital, operating
and general and administrative cost structures and commitment to ongoing risk management efforts to protect future
cash flows and capital programs.
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 its credit
34
facility financial covenants. Bellatrix was fully compliant with all of its credit facility financial covenants as at December
31, 2014.
Bellatrix generally relies upon its 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 currently sells substantially all of its
production to nine primary purchasers under standard industry sale and payment terms. The most significant 60 day
exposure to a single counterparty is approximately $16.6 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 mitigating its exposures to certain counterparties by obtaining financial assurances or reducing
credit 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 partners
and 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.
In May 2014, Bellatrix filed the $750 million Shelf Prospectus with the securities regulatory authorities in each of the
provinces of Canada (other than Quebec) and Registration Statement with the United States Securities and Exchange
Commission. The $750 million Shelf Prospectus allows Bellatrix to offer and issue common shares, subscription receipts,
warrants and units (comprising any combination of the foregoing securities), by way of one or more prospectus
supplements at any time during the 25-month period that the $750 million Shelf Prospectus remains in place.
Pursuant to a prospectus supplement to the $750 million Shelf Prospectus, on June 5, 2014, Bellatrix closed a bought
deal offering of 18,170,000 common shares of the Company at a price of $9.50 per common share for aggregate gross
proceeds of $172.6 million through a syndicate of underwriters. Net proceeds of $165.5 million received from the
offering were utilized to temporarily reduce outstanding indebtedness under the Company's credit facilities, thereby
freeing up borrowing capacity that may be redrawn, from time to time, to fund the Company's ongoing capital expenditure
program and for general corporate purposes.
As at December 31, 2014, the Company has the ability to offer to sell up to an additional $577.4 million on the $750
million Shelf Prospectus.
Total net debt levels of $637.7 million at December 31, 2014 increased by $242.2 million from $395.5 million at
December 31, 2013. The increase to total net debt was primarily due to capital expenditures for the year ended
December 31, 2014 made as the Company executed its $692.1 million 2014 capital program. Total net debt levels at
December 31, 2014 include the net balance of an adjusted working capital deficiency of $87.9 million, which incorporated
$76.4 million in advances from joint venture partners, the majority of which represents drilling obligations predominantly
under the Company’s joint venture obligations with TCA and Grafton, and under the Daewoo and Devonian Partnership.
35
Total net debt excludes unrealized commodity contract assets and liabilities, deferred taxes, finance lease obligations,
deferred lease inducements and decommissioning liabilities.
Funds flow from operations represents 39% of the funding requirements for Bellatrix’s net capital expenditures for the
year ended December 31, 2014.
As of December 31, 2014, the Company’s credit facilities are available on an extendible revolving term basis and consist
of a $75 million operating facility provided by a Canadian bank and a $650 million syndicated facility provided by nine
financial institutions, subject to a borrowing base test.
Amounts borrowed under the credit facilities will bear interest at a floating rate based on the applicable Canadian prime
rate, U.S. base rate, CDOR rate or LIBOR margin rate, plus between 0.8% to 3.75% (expanded to 4.75% in connection
with recent amendments described below), depending on the type of borrowing and the Company’s senior debt to
EBITDA ratio. A standby fee is charged of between 0.405% and 0.84375% (expanded to 1.06875% in connection with
recent amendments described below) on the undrawn portion of the credit facilities, depending on the Company’s senior
debt to EBITDA ratio. The credit facilities are secured by a $1 billion 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.
The revolving period for the revolving term credit facility will end on May 30, 2017, unless extended for a further period of
up to 3 years. Should the facility not be extended, the outstanding balance is due upon maturity. The borrowing base
will be subject to re-determination on or before May 31 and November 30 in each year prior to maturity, with the next
semi-annual redetermination occurring on or before May 31, 2015.
The Company’s credit facilities contain market standard terms and conditions, and include, for instance, restrictions on
asset dispositions and hedging. Generally, dispositions of properties to which the Company is given lending value in the
determination of the borrowing base require lender approval if the NPV 10% value attributed to all properties sold in a
fiscal year exceeds 5% of the borrowing base in effect at the time of such disposition. In addition, asset dispositions are
generally not permitted unless there would be no borrowing base shortfall as a result of such properties being sold.
Hedging transactions must not be done for speculative purposes, and the term of any hedging contract cannot exceed 3
years for commodity swaps, interest rate or exchange rate swaps. The aggregate amount hedged under all oil and gas
commodity swaps cannot exceed 70% of the Company’s average daily sales volume for the first year of a rolling 3 year
period, 60% for the second year of such period or 50% for the third year of such period, with the average daily sales
volume being based on our production for the previous fiscal quarter. The aggregate amount hedged under all interest
rate swaps cannot exceed the outstanding principal amount of any unsecured note debt or have a term exceeding the
remaining term of the unsecured note debt. For interest rate swaps unrelated to any unsecured note debt, the aggregate
amount hedged cannot exceed 60% of the amount of the commitment under the credit facilities or exceed a term of 3
years. The aggregate amount hedged under all exchange rate swaps cannot exceed the outstanding principal amount of
any unsecured note debt or have a term exceeding the remaining term of the unsecured note debt. For exchange rate
swaps unrelated to any unsecured note debt, the aggregate amount hedged cannot exceed 60% of Bellatrix’s US dollar
revenue over the previous 3 months or exceed a term of 3 years.
36
Bellatrix’s credit facilities are subject to a number of covenants, all of which were met as at December 31, 2014. Bellatrix
calculates its financial covenants quarterly. The calculation for each financial covenant is based on specific definitions,
are not in accordance with IFRS and cannot be readily replicated by referring to Bellatrix’s Consolidated Financial
Statements. As at December 31, 2014, the major financial covenants are:
Position at December 31, 2014
(1)
(2)
Total Debt must not exceed 3.5 times EBITDA for the last four fiscal quarters
(3)
Senior Debt must not exceed 3.0 times EBITDA for the last four fiscal quarters
EBITDA must not be less than 3.5 times interest expense for the last four fiscal quarters
2.08x
2.08x
14.97x
(1)
“Total Debt” is defined as the sum of the bank loan, the principal amount of long-term debt and certain other liabilities defined in
the agreement governing the credit facilities.
(2)
“EBITDA” refers to earnings before interest, taxes, depreciation and amortization. EBITDA is calculated based on terms and
definitions set out in the agreement governing the credit facilities which adjusts net income for financing costs, certain specific
unrealized and non-cash transactions, and acquisition and disposition activity and is calculated based on a trailing twelve month
basis.
(3)
“Senior Debt” is defined as Total Debt, excluding any unsecured or subordinated debt. Bellatrix currently does not have any
subordinated or unsecured debt.
In the event of a material acquisition, the Total Debt to EBITDA and Senior Debt to EBITDA covenants are relaxed for
two fiscal quarters after the close of the acquisition and must not exceed 4.0 and 3.5 times EBITDA, respectively. Due to
material acquisitions in the quarter ended December 31, 2014, the Total Debt to EBITDA and Senior Debt to EBITDA
covenants were temporarily increased until June 30, 2015 to not exceed 4.0 and 3.5 times, respectively.
Effective March 11, 2015, the Company’s banking syndicate agreed to amendments to certain of the financial covenants
in response to the recent decline in commodity prices. The Total Debt to EBITDA and Senior Debt to EBITDA financial
covenants have been revised such that they each must not exceed:
• 4.75 times for the fiscal quarters ending September 30, 2015, December 31, 2015, March 31, 2016 and June 30,
2016; and
•
4.0 times for the fiscal quarters ending September 30, 2016, December 31, 2016 and March 31, 2017.
During the periods in which these revised financial covenants are in place, the additional automatic relaxation of the debt
to EBITDA financial covenants following a material acquisition will not apply. Commencing with the second quarter of
2017, the maximum Senior Debt to EBITDA covenant will return to 3.0 times (3.5 times for the two fiscal quarters
immediately following a material acquisition) and the maximum Total Debt to EBITDA covenant will return to 3.5 times
(4.0 times for the two fiscal quarters immediately following a material acquisition).
The minimum EBITDA to interest expense ratio of 3.5 times remains unchanged.
As a corollary to these revised financial covenants, the applicable margin rate will range from 0.8% to 4.75%, depending
on the type of borrowing and the Company’s Senior Debt to EBITDA ratio and the standby fee will range from 0.405% to
1.06875% on the undrawn portion of the credit facilities, depending on the Company’s Senior Debt to EBITDA ratio.
Failing a financial covenant may result in cancellation of the credit facilities and/or all or any part of the outstanding loans
with all accrued and unpaid interest to be immediately due and payable. Including $0.7 million of outstanding letters of
credit that reduce the amount otherwise available to be drawn on the syndicated facility, as at December 31, 2014,
approximately $174.5 million or 24% 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.
As at February 28, 2015, Bellatrix had outstanding a total of 10,785,170 options exercisable at an average exercise price
of $6.29 per share and 191,957,243 common shares.
37
Commitments
As at December 31, 2014, Bellatrix committed to drill 10 gross (4.4 net) wells pursuant to farm-in agreements. Bellatrix
expects to satisfy these drilling commitments at an estimated net cost of approximately $16.7 million.
In addition, Bellatrix entered into two joint operating agreements during the 2011 year and an additional joint operating
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 Operating Agreement
Feb. 1, 2011
Aug. 4, 2011
Dec. 14, 2012
Commitment Term
2011 to 2015
2011 to 2016
2014 to 2018
3
5 to 10
2
15
40
10
$ 56.3
$ 150.0
$ 37.5
3
1
1
$ 11.3
$ 3.8
$ 3.8
Minimum wells per year (gross and net)
Minimum total wells (gross and net)
Estimated total cost ($millions)
Remaining wells to drill at December 31, 2014
Remaining estimated total cost ($millions)
Bellatrix also has certain drilling commitments relating to the Grafton Joint Venture, the Daewoo and Devonian
Partnership, and the Troika Joint Venture. In meeting the drilling commitments under these agreements, Bellatrix will
satisfy some of the drilling commitments under the joint operating agreements described above.
During September 2014, the CNOR Joint Venture was formed with CNOR a non-operated oil and gas company
managed by Grafton Asset Management Inc.. Through the joint venture, CNOR has committed $250 million in capital
towards future accelerated development of a portion of Bellatrix's undeveloped land holdings. Bellatrix is not currently
subject to any formal well or cost commitments in relation to the CNOR Joint Venture.
Daewoo and
(2)
Devonian
2013 to 2015
2013 to 2016
2013 to 2015
85
70
63
16.9
30.4
31.5
$ 305.0
$ 200.0
$ 240.0
$ 55.0
$ 100.0
$ 120.0
Remaining wells to drill at December 31, 2014 (gross)
38
23
7
Remaining wells to drill at December 31, 2014 (net)
7.7
11.7
3.5
$ 156.2
$ 94.9
$ 28.7
$ 31.3
$ 47.4
$ 14.4
Agreement
Grafton
Commitment Term
Minimum total wells (gross)
Minimum total wells (net)
(1)
(1)
Estimated total cost ($millions) (gross)
Estimated total cost ($millions) (net)
(1)
(1)
Remaining estimated total cost ($millions) (gross)
Remaining estimated total cost ($millions) (net)
(1)
(1)
Troika
(3)
(1)
Gross and net estimated total cost values and gross and net minimum estimated total wells for the Troika and Grafton Joint
Ventures represent Bellatrix’s total capital and well commitments pursuant to the Troika and Grafton joint venture agreements.
Gross and net minimum total wells for the Daewoo and Devonian Partnership represent Bellatrix’s total well commitments pursuant
to the Daewoo and Devonian Partnership agreement. Gross and net estimated total cost values for the Daewoo and Devonian
Partnership represent Bellatrix’s estimated cost associated with its well commitments under the Daewoo and Devonian Partnership
agreement. Remaining estimated total cost (gross) for the Daewoo and Devonian Partnership is based on initial Daewoo Devonian
Partnership gross capital divided by initial total gross capital including third parties.
(2)
During April 2014, Grafton elected to exercise an option to increase committed capital investment to the Grafton Joint Venture
established during 2013 by an additional $50 million, for a total commitment of $250 million, on the same terms and conditions as
the previously announced Grafton Joint Venture. Specific well commitments associated with the increase have been incorporated
into the commitments table.
(3)
The commitment term of the Troika Joint Venture has been extended to 2015 for the 7 gross (3.5 net) wells remaining to be
drilled.
38
More than
Liabilities ($000s)
Accounts payable and accrued liabilities
Advances from joint venture partners
Long-term debt – principal
(2)
Decommissioning liabilities
(3)
Finance lease obligation
(1)
Total
< 1 Year
$ 154,094
$ 154,094
76,388
76,388
-
-
-
549,792
-
549,792
-
-
88,605
-
776
3,653
84,176
11,637
1,574
3,172
1,645
5,246
3,067
340
680
680
1,367
$ 883,583
$ 232,396
$ 554,420
$ 5,978
$ 90,789
Deferred lease inducements
Total
1-3 Years
3-5 Years
$
$
-
-
5 years
$
-
(1)
Includes $0.8 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 three year facility, fully revolving until maturity, and extendable annually at the Company’s option
(subject to lender approval), provided that the term after any extension would not be more than three years. Interest due on the
bank credit facility is calculated based upon floating rates.
(3)
Amounts represent the inflated, discounted future abandonment and reclamation expenditures anticipated to be incurred over
the life of the Company’s properties (between 2018 and 2065).
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, 2014.
The Company’s commitment for office space as at December 31, 2014 is as follows:
($000s)
Year
Gross
Amount
Recoveries
Net amount
2015
6,238
(850)
5,388
2016
6,195
(904)
5,291
2017
6,185
(904)
5,281
2018
5,884
(828)
5,056
2019
More than 5 years
4,983
20,413
-
4,983
20,413
Business Prospects and 2015 Year Outlook
Bellatrix continues to develop its core assets and conduct exploration programs utilizing its large inventory of geological
prospects in conjunction with infrastructure investments made through 2014 and continuing into 2015.
Looking ahead, 2015 represents a transformational year for the Company given the strategic infrastructure investment
made over the past several years.
The decision to build, maintain, and control operatorship of key strategic
infrastructure remains critical to the Company’s long term sustainability and growth objectives. In response to continued
capricious behavior of oil and gas prices, Bellatrix announced on January 29, 2015 an updated 2015 net capital budget
to not exceed $200 million. Bellatrix will revisit its capital budget on a continuous basis, will strategically review all
sources and costs of capital available to the Company including monetization of assets, and will further curtail capital
spending, if necessary, in order to preserve its balance sheet until commodity prices firmly recover.
Despite current commodity price headwinds, the Company maintains focus on profitability for our shareholders. Drilling
and completion capital is focused principally on drilling Spirit River liquids rich natural gas wells that deliver superior rates
of return at current commodity prices. The Company’s differentiated joint venture strategy provides additional insulation
39
from weak commodity prices given the enhanced economic returns and improved capital efficiencies achieved from
spending under these funding transactions. Bellatrix expects to access up to $85 million of joint venture capital in 2015
pursuant to its existing joint venture arrangements.
The Company is also focused on the execution of Phase 1 of the Bellatrix Alder Flats Plant.
Phase 1 of the
aforementioned Bellatrix Alder Flats Plant is on budget and is anticipated to be on-stream on or before July 1, 2015.
Bellatrix anticipates significant benefits from our infrastructure investment including the ability to grow unfettered with
improved operational reliability, increased revenue from enhanced liquids extraction, and reduced operating costs.
With three year proved plus probable FD&A costs averaging $10.05/boe, Bellatrix continues to demonstrate its efficacy
as a low cost finder and producer of hydrocarbons. The Company continues to drive production down costs, reducing its
already low cost profile by 6% in 2014 to $8.23/boe after removing one-time adjustments, with further cost reductions
expected in 2015. Finally, Bellatrix recognized a 10% reduction in G&A costs in 2014 to $1.83/boe, and remains acutely
focused on continued cost containment in all areas of its business.
Despite the reduction in spending year over year, the Company is positioned to deliver full year annual average
production growth of 14% in 2015. Additionally, the Company has seen service cost reductions in its 2015 activities by
up to 15% in some areas, which provide further potential benefits not currently captured in our $200 million budget.
2015 Guidance
2015 Forecast
Average daily production (boe/d)
Low range
High range
Average product mix
Crude oil, condensate and NGLs (%)
Natural gas (%)
(1)
Capital spending ($ millions)
Expenses ($/boe)
Production
General and administrative (after capitalized G&A and recoveries)
(1)
43,000
44,000
33
67
200
8.25
1.50
Capital spending includes exploration and development capital projects and corporate assets, and excludes property
acquisitions and dispositions.
Financial Reporting Update
Future Accounting Pronouncements
The following pronouncements from the International Accounting Standards Board (“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, 2018 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 15 - “Revenue from Contracts with Customers”, which provides a five-step model to be applied to all contracts
formed with customers. The standard specifies when an entity will recognize revenue and provides guidance regarding
disclosures relating to revenue recognition. IFRS 15 will apply to annual reporting periods beginning on or after January
1, 2017. The extent of the impact of the adoption of IFRS 15 has not yet been determined.
40
Business Risks and Uncertainties
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:
•
financial risks, which includes commodity price risk and risks related to the Company's financing arrangements;
•
finding and developing oil and natural gas reserves at economic costs; and
•
operational risks such as risks related to health and safety, transportation and processing restrictions, project
execution and the environment.
A description of the risk factors and uncertainties affecting Bellatrix can be found under the heading "Forward Looking
Statements" and a full discussion of the material risk factors affecting Bellatrix can be found in our annual information
form for the year ended December 31, 2014, which may be accessed through the SEDAR website (www.sedar.com),
through the SEC website (www.sec.gov), and at Bellatrix's website (www.bellatrixexploration.com).
The following explains how material risks and uncertainties impact our business:
Prices, Markets and Marketing
Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of and
demand for oil and natural gas, market uncertainty and a variety of additional factors beyond the control of the Company.
These factors include economic conditions, in the United States, Canada and Europe, the actions of OPEC,
governmental regulation, political stability in the Middle East, Northern Africa and elsewhere, the foreign supply and
demand of oil and natural gas, risks of supply disruption, the price of foreign imports and the availability of alternative fuel
sources. Prices for oil and natural gas are also subject to the availability of foreign markets and the Company's ability to
access such markets. Oil prices are expected to remain volatile and may decline in the near future as a result of global
excess supply due to the increased growth of shale oil production in the United States, the decline in global demand for
exported crude oil commodities, and OPEC's recent decisions pertaining to the oil production of OPEC member
countries, among other factors. A material decline in prices could result in a reduction of the Company's net production
revenue. The economics of producing from some wells may change because of lower prices, which could result in
reduced production of oil or natural gas and a reduction in the volumes of the Company's reserves. The Company might
also elect not to produce from certain wells at lower prices.
All these factors could result in a material decrease in the Company's expected net production revenue and a reduction
in its oil and natural gas acquisition, development and exploration activities. Any substantial and extended decline in the
price of oil and natural gas would have an adverse effect on the Company's carrying value of its reserves, borrowing
capacity, revenues, profitability and cash flows from operations and may have a material adverse effect on the
Company's business, financial condition, results of operations and prospects.
Oil and natural gas prices are expected to remain volatile for the near future because of market uncertainties over the
supply and the demand of these commodities due to the current state of the world economies, OPEC actions, and
sanctions imposed on certain oil producing nations by other countries and ongoing credit and liquidity concerns. Volatile
oil and natural gas prices make it difficult to estimate the value of producing properties for acquisitions and often cause
disruption in the market for oil and natural gas producing properties, as buyers and sellers have difficulty agreeing on
such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and development
and exploitation projects.
Credit Facility Arrangements
The Company currently has a syndicated credit facility and the amount authorized thereunder is dependent on the
borrowing base determined by its lenders. The Company is required to comply with covenants under its credit facilities,
which include certain financial ratio tests, which from time to time either affect the availability, or price, of additional
41
funding. As discussed herein, as a result of the recent precipitous drop in crude oil prices and the concomitant reduction
in the Company’s associated future cash flow and EBITDA, the Company sought and obtained from its lenders
temporary relaxation of certain of these financial covenants under its credit facilities. In the event that the Company is not
able to comply with these covenants, as amended, the banking syndicate may not be willing to agree to a further
amendment to the financial covenants and as a result the Company's access to capital could be restricted or repayment
could be required.
Even if the Company is able to obtain new financing, it may not be on commercially reasonable terms or terms that are
acceptable to the Company. If the Company is unable to repay amounts owing under credit facilities, the lenders under
the credit facilities could proceed to foreclose or otherwise realize upon the collateral granted to them to secure the
indebtedness.
The acceleration of the Company's indebtedness under one agreement may permit acceleration of
indebtedness under other agreements that contain cross default or cross-acceleration provisions.
In addition, the
Company's credit facilities may impose operating and financial restrictions on the Company that could include restrictions
on, the payment of dividends, repurchase or making of other distributions with respect to the Company's securities,
incurring of additional indebtedness, the provision of guarantees, the assumption of loans, making of capital
expenditures, entering into of amalgamations, mergers, take-over bids or disposition of assets, among others.
The Company's lenders use the Company's reserves, commodity prices, applicable discount rate and other factors, to
periodically determine the Company's borrowing base. A further material decline in commodity prices could reduce the
Company's borrowing base, reducing the funds available to the Company under the credit facility. This could result in the
requirement to repay a portion, or all, of the Company's bank indebtedness.
Exploration, Development and Production Risks
Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful
evaluation may not be able to overcome. The long-term commercial success of the Company depends on its ability to
find, acquire, develop and commercially produce oil and natural gas reserves. Without the continual addition of new
reserves, the Company's existing reserves, and the production from them, will decline over time as the Company
produces from such reserves. A future increase in the Company's reserves will depend on both the ability of the
Company to explore and develop its existing properties and its ability to select and acquire suitable producing properties
or prospects. There is no assurance that the Company will be able continue to find satisfactory properties to acquire or
participate in.
Moreover, management of the Company may determine that current markets, terms of acquisition,
participation or pricing conditions make potential acquisitions or participations uneconomic. There is also no assurance
that the Company will discover or acquire further commercial quantities of oil and natural gas.
Future oil and natural gas exploration may involve unprofitable efforts from dry wells as well as from wells that are
productive but do not produce sufficient petroleum substances to return a profit after drilling, completing (including
hydraulic fracturing), operating and other costs. Completion of a well does not assure a profit on the investment or
recovery of drilling, completion and operating costs.
Drilling hazards, environmental damage and various field operating conditions could greatly increase the cost of
operations and adversely affect the production from successful wells. Field operating conditions include, but are not
limited to, delays in obtaining governmental approvals or consents, and shut-ins of connected wells resulting from
extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions.
While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over
time, it is not possible to eliminate production delays and declines from normal field operating conditions, which can
negatively affect revenue and cash flow levels to varying degrees.
Oil and natural gas exploration, development and production operations are subject to all the risks and hazards typically
associated with such operations, including, but not limited to, fire, explosion, blowouts, cratering, sour gas releases, spills
and other environmental hazards. These typical risks and hazards could result in substantial damage to oil and natural
gas wells, production facilities, other property, the environment and personal injury. Particularly, the Company may
explore for and produce sour natural gas in certain areas. An unintentional leak of sour natural gas could result in
42
personal injury, loss of life or damage to property and may necessitate an evacuation of populated areas, all of which
could result in liability to the Company.
Oil and natural gas production operations are also subject to all the risks typically associated with such operations,
including encountering unexpected formations or pressures, premature decline of reservoirs and the invasion of water
into producing formations. Losses resulting from the occurrence of any of these risks may have a material adverse effect
on the Company's business, financial condition, results of operations and prospects.
As is standard industry practice, the Company is not fully insured against all risks, nor are all risks insurable. Although
the Company maintains liability insurance in an amount that it considers consistent with industry practice, liabilities
associated with certain risks could exceed policy limits or not be covered. In either event the Company could incur
significant costs.
Gathering and Processing Facilities and Pipeline Systems
The Company delivers its products through gathering and processing facilities and pipeline systems some of which it
does not own. The amount of oil and natural gas that the Company can produce and sell is subject to the accessibility,
availability, proximity and capacity of these gathering and processing facilities and pipeline systems. In 2014, the
Company's production was constrained due to lack of processing facilities in the Company's area of operations. Although
the Company has taken steps to reduce the risk of constraints in production due to lack of processing capacity, further
constraints in production could be experienced. The lack of availability of capacity in any of the gathering and pipeline
systems, and in particular the processing facilities, could result in the Company's inability to realize the full economic
potential of its production or in a reduction of the price offered for the Company's production. Although pipeline
expansions are ongoing, the lack of firm pipeline capacity continues to affect the oil and natural gas industry and limit the
ability to produce and market oil and natural gas production. In addition, the pro-rationing of capacity on inter-provincial
pipeline systems continues to affect the ability to export oil and natural gas. Furthermore, producers are increasingly
turning to rail as an alternative means of transportation. In recent years, the volume of crude oil shipped by rail in North
America has increased dramatically and it is projected to continue in this upward trend. Any significant change in market
factors or other conditions affecting these infrastructure systems and facilities, as well as any delays in constructing new
infrastructure systems and facilities could harm the Company's business and, in turn, the Company's financial condition,
results of operations and cash flows.
A portion of the Company's production may, from time to time, be processed through facilities owned by third parties and
over which the Company does not have control. From time to time these facilities may discontinue or decrease
operations either as a result of normal servicing requirements or as a result of unexpected events. A discontinuation or
decrease of operations could have a materially adverse effect on the Company's ability to process its production and
deliver the same for sale.
Additional Funding Requirements
The Company's cash flow from its reserves may not be sufficient to fund its ongoing activities at all times and from time
to time, the Company may require additional financing in order to carry out its oil and natural gas acquisition, exploration
and development activities. There is risk that if the economy and banking industry experienced unexpected and/or
prolonged deterioration, the Company's access to additional financing may be affected.
Because of global economic volatility and the current volatility of oil and gas prices, the Company may from time to time
have restricted access to capital and increased borrowing costs. Failure to obtain such financing on a timely basis could
cause the Company to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce or
terminate its operations. If the Company's revenues from its reserves decrease as a result of lower oil and natural gas
prices or otherwise, it will affect the Company's ability to expend the necessary capital to replace its reserves or to
maintain its production. To the extent that external sources of capital become limited, unavailable or available on
onerous terms, the Company's ability to make capital investments and maintain existing assets may be impaired, and its
assets, liabilities, business, financial condition and results of operations may be affected materially and adversely as a
result. In addition, the future development of the Company's petroleum properties may require additional financing and
43
there are no assurances that such financing will be available or, if available, will be available upon acceptable terms.
Failure to obtain any financing necessary for the Company's capital expenditure plans may result in a delay in
development or production on the Company's properties.
Environmental
All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental
regulation pursuant to a variety of federal, provincial and local laws and regulations. Environmental legislation provides
for, among other things, restrictions and prohibitions on the spill, release or emission of various substances produced in
association with certain oil and gas industry operations. In addition, such legislation sets out the requirements with
respect to oilfield waste handling and storage, habitat protection and the satisfactory operation, maintenance,
abandonment and reclamation of well and facility sites.
Compliance with environmental legislation can require significant expenditures and a breach of applicable environmental
legislation may result in the imposition of fines and penalties, some of which may be material. Environmental legislation
is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially
increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil
or water may give rise to liabilities to governments and third parties and may require the Company to incur costs to
remedy such discharge. Although the Company believes that it will be in material compliance with current applicable
environmental legislation, no assurance can be given that environmental laws will not result in a curtailment of production
or a material increase in the costs of production, development or exploration activities or otherwise have a material
adverse effect on the Company's business, financial condition, results of operations and prospects.
Hedging
From time to time, the Company may enter into agreements to receive fixed prices on its oil and natural gas production
to offset the risk of revenue losses if commodity prices decline. However, to the extent that the Company engages in
price risk management activities to protect itself from commodity price declines, it may also be prevented from realizing
the full benefits of price increases above the levels of the derivative instruments used to manage price risk. In addition,
the Company's hedging arrangements may expose it to the risk of financial loss in certain circumstances, including
instances in which:
•
production falls short of the hedged volumes or prices fall significantly lower than projected;
•
there is a widening of price-basis differentials between delivery points for production and the delivery point
assumed in the hedge arrangement;
•
the counterparties to the hedging arrangements or other price risk management contracts fail to perform
under those arrangements; or
•
a sudden unexpected event materially impacts oil and natural gas prices.
Similarly, from time to time the Company may enter into agreements to fix the exchange rate of Canadian to United
States dollars or other currencies in order to offset the risk of revenue losses if the Canadian dollar increases in value
compared to other currencies. However, if the Canadian dollar declines in value compared to such fixed currencies, the
Company will not benefit from the fluctuating exchange rate.
Critical Judgments and 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.
44
Critical Accounting Judgments
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.
Identification of CGUs
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.
Impairment Indicators
Judgment is required to assess when impairment indicators exist and impairment testing is required. In determining the
recoverable amount of assets, in the absence of quoted market prices, impairment tests are based on estimate of
reserves, production rates, future oil and natural gas prices, future costs, discount rates, market value of land and other
relevant assumptions.
Joint Arrangements
Judgment is required to determine when the Company has joint control over an arrangement. In establishing joint
control, the Company considers whether unanimous consent is required to direct the activities that significantly affect the
returns of the arrangement, such as the capital and operating activities of the arrangement.
Once joint control has been established, judgment is also required to classify as a joint arrangement. The type of joint
arrangement is determined through analysis of the rights and obligations arising from the arrangement by considering its
structure, legal form, and terms agreed upon by the parties sharing control. An arrangement where the controlling
parties have rights to the assets and revenues and obligations for the liabilities and expenses is classified as a joint
operation.
Critical Estimates and Assumptions
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.
45
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 monitors 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 President and Chief Executive Officer (“CEO”) and Executive Vice President, Finance and Chief
Financial Officer (“CFO”) 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 ( as these terms are defined in National Instrument 52-109, Certification of Disclosure in Issuers’
Annual and Interim Filings (“NI 52-109”)) 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 as defined in Rules 13(a) - 15(e) and 15d – 15(e) under
the United States Securities Exchange Act of 1934, as amended (the “Exchange Act”), and National Instrument 52-109,
Certification of Disclosure in Issuer’s Annual and Interim Filings (“NI 52-109”), the effectiveness of the Company’s
disclosure controls and procedures at the financial year end of the Company. Based on the evaluation, the officers
concluded that Bellatrix’s disclosure controls and procedures were effective as at December 31, 2014.
46
Management’s Annual Report on Internal Control over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over the Company’s financial
reporting, as defined in Rules 13(a) – 15(f) and 15(d) – 15(f) under both the Securities Exchange Act of 1934 and NI 52109, as amended. Internal control over the Company’s financial reporting is a process designed by, or designed under
the supervision of, our President and CEO and our Executive Vice President, Finance and CFO, and effected by our
board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for the external purposes in accordance with GAAP.
Under the supervision and with the participation of management, including our CEO and our CFO, an evaluation of the
effectiveness of the Company’s internal control over financial reporting was conducted as of December 31, 2014 based
on the criteria described in “Internal Control – Integrated Framework (2013)” issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on this assessment, management determined that, as of December
31, 2014, the Company’s internal control over financial reporting was effective.
The Company is required to disclose herein any change in the Company’s internal control over financial reporting that
occurred during the year ended December 31, 2014 that has materially affected, or is reasonably likely to materially
affect, the Company’s internal control over financial reporting. Bellatrix acquired Angle on December 11, 2013. The
Company completed the integration of Angle’s operations during 2014, and expanded its internal controls over financial
reporting compliance program to incorporate those operations. With the exception of the integration of Angle there has
been no change in the Company’s internal control over financial reporting that occurred during the year ended December
31, 2014 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over
financial reporting.
The effectiveness of internal control over financial reporting as of December 31, 2014 was audited by KPMG LLP, an
independent registered public accounting firm, as stated in their Independent Auditors’ Report of Registered Public
Accounting Firm, which is included with the consolidated financial statements for the year ended December 31, 2014.
Limitations of the Effectiveness of Controls
It should be noted that a control system, 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 controls
and procedures and internal controls over financial reporting will prevent all errors or fraud.
CEO and CFO Certifications
The Company’s President and CEO and the Executive Vice President, Finance and CFO have attested to the quality of
the public disclosure in our fiscal 2014 reports filed with the Canadian securities regulators and the SEC, and have filed
certifications with them.
47
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 2014 and average production
volumes of 42,945 boe/d during that period, as well as the same level of debt outstanding as at December 31, 2014.
Diluted weighted average shares are based upon the fourth quarter of 2014. 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 Operations (1)
(annualized)
Sensitivity Analysis
($000s)
Change of US $1/bbl WTI
4,100
Change of $0.10/ mcf
5,900
Change of US $0.01 CDN/ US exchange rate
1,600
Change in prime of 1%
5,500
Funds Flow from Operations (1)
Per Diluted Share
($)
0.02
0.03
0.01
0.03
(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.
48
Selected Quarterly Consolidated Information
The following table sets forth selected consolidated financial information of the Company for the quarters in 2014 and
2013.
2014 – Quarter ended (unaudited)
($000s, except per share amounts)
Revenue (before royalties and risk management)
Cash flow from operating activities
Cash flow from operating activities per share
Basic
Diluted
(1)
Funds flow from operations
(1)
Funds flow from operations per share
Basic
Diluted
Net profit
Net profit per share
Basic
Diluted
Total net capital expenditures - cash
2013 – Quarter ended (unaudited)
($000s, except per share amounts)
Revenue (before royalties and risk management)
Cash flow from operating activities
Cash flow from operating activities per share
Basic
Diluted
(1)
Funds flow from operations
(1)
Funds flow from operations per share
Basic
Diluted
Net profit
Net profit per share
Basic
Diluted
Total net capital expenditures - cash
(1)
March 31
163,585
84,300
June 30
152,311
60,063
Sept. 30
137,411
60,006
Dec. 31
130,160
90,459
$0.49
$0.48
77,642
$0.34
$0.33
71,014
$0.31
$0.31
60,341
$0.47
$0.47
61,757
$0.45
$0.45
25,167
$0.40
$0.39
38,252
$0.32
$0.31
44,874
$0.32
$0.32
54,830
$0.15
$0.14
155,863
$0.22
$0.21
125,955
$0.23
$0.23
167,790
$0.29
$0.29
232,641
March 31
65,543
35,527
June 30
74,564
29,611
Sept. 30
68,329
25,295
Dec. 31
83,455
38,025
$0.33
$0.30
37,545
$0.27
$0.25
36,563
$0.23
$0.22
30,002
$0.30
$0.29
39,349
$0.35
$0.32
4,561
$0.34
$0.31
15,466
$0.28
$0.25
29,453
$0.31
$0.30
22,195
$0.04
$0.04
91,614
$0.14
$0.13
46,699
$0.27
$0.25
49,452
$0.17
$0.17
99,199
Refer to “Additional GAAP Measures” in respect of the terms “funds flow from operations,” “funds flow from operations per share,”
and “total net debt.”
Bellatrix’s 2014 quarterly results were positively impacted by an overall 74% increase in production resulting from the
success of Bellatrix’s 2014 drilling program, additional sales volumes realized through the December 2013 acquisition of
Angle, and higher natural gas prices realized during the 2014 quarters compared to the 2013 quarters.
Fourth quarter 2014 results are compared in detail to fourth quarter 2013 results throughout this MD&A.
During the third quarter of 2014, Bellatrix completed several asset acquisitions including a tuck-in acquisition of working
interests. In the third quarter of 2014, the Company incurred $167.8 million of net cash capital expenditures, compared
to $49.5 million in the third quarter of 2013, and drilled or participated in 35 gross (17.5 net) wells, compared to 19 gross
(8.6 net) wells in the third quarter of 2013. Bellatrix realized a 73% increase in sales volumes from 21,852 boe/d in the
third quarter of 2013 to 37,838 boe/d in the comparative 2014 period. Bellatrix’s revenue before other income, royalties
and commodity price risk management contracts increased by 99% to $134.6 million in the third quarter of 2014 from
$67.7 million in the comparative quarter in 2013 as a result of the increase in sales volumes between the quarters, in
conjunction with higher natural gas prices which were partially offset by reduced crude oil and NGL commodity prices
realized in the 2014 third quarter.
49
In the second quarter of 2014, Grafton elected to exercise an option to increase committed capital under the Grafton
Joint Venture by $50 million, resulting in a total commitment of $250 million at the end of that quarter. In addition to the
expansion of the Grafton Joint Venture, the Company experienced additional successes through the $172.6 million
bought deal financing, the expansion of its borrowing base and credit facilities to $625 million from $500 million, and the
commissioning of the Blaze Pipeline on April 1, 2014. Bellatrix’s net cash capital spending in the second quarter of 2014
totaled $134.6 million, compared to $46.7 million during the comparative 2013 period. During the second quarter of
2014, the Company drilled or participated in 19 gross (9.0 net) wells, compared to 5 gross (5.0 net) wells in the same
quarter of 2013 and realized a 64% increase in sales volumes to 36,342 boe/d in the second quarter of 2014 from 22,102
boe/d in the second quarter of 2013. The Company realized revenue before other income, royalties and commodity
price risk management contracts of $151.2 million in the second quarter of 2014, an increase of 104% from $74.0 million
in the comparative quarter in 2013. The increased revenue was the result of the increase in sales volumes between the
second quarters of 2013 and 2014, in conjunction with higher realized natural gas, crude oil and NGL prices realized in
the second quarter of 2014 compared to the second quarter of 2013.
During the first quarter of 2014, Bellatrix’s net cash capital expenditures totaled $155.6 million, compared to $91.6 million
in the first quarter of 2013. The Company drilled or participated in 44 gross (25.6 net) wells in the first quarter of 2014,
compared to 21 gross (17.1 net) wells in the comparative 2013 quarter. Sales volumes increased by 81% to 35,049
boe/d from 19,343 boe/d between the 2013 and 2014 first quarters. The Company’s revenue before other income,
royalties and commodity price risk management contracts increased by 149% to $161.7 million in the first quarter of
2014 from $64.9 million in the comparative quarter in 2013 as a result of the increase in sales volumes between the
quarters, in conjunction with higher realized crude oil, NGL, and natural gas commodity prices.
Overall, the Company’s cash flows were positively impacted primarily due to significantly increased sales volumes and
cash flows resulting from the success and execution of the Company’s 2014 drilling program in addition to volumes
realized from the December 2013 acquisition of Angle, and stronger natural gas prices.
50
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, 2014 and for comparative 2013 and 2012 years.
Years ended December 31,
($000s, except per share amounts)
Revenues (before royalties and risk management)
(1)
Funds flow from operations
(1)
Funds flow from operations per share
Basic
Diluted
Cash flow from operating activities
Cash flow from operating activities per share
Basic
Diluted
Net profit
Net profit per share
Basic
Diluted
Total net capital expenditures – cash
Total assets
(1)
Total net debt
Non-current financial liabilities
Future income taxes
Decommissioning liabilities
Sales volumes (boe/d)
(1)
2014
583,467
270,753
2013
291,891
143,459
2012
219,314
111,038
$1.48
$1.46
294,828
$1.27
$1.24
128,458
$1.03
$0.96
109,328
$1.61
$1.59
163,123
$1.14
$1.11
71,675
$1.02
$0.95
27,771
$0.89
$0.88
682,249
2,213,486
637,726
$0.63
$0.62
232,723
1,555,180
395,482
$0.26
$0.25
178,688
681,421
189,577
81,585
88,605
38,065
27,034
67,075
21,829
43,909
16,686
Refer to “Additional GAAP Measures” in respect of the terms “funds flow from operations,” “funds flow from operations per share,”
and “total net debt.”
Detailed discussions of 2014 annual results by comparison to 2013 annual results are contained throughout this MD&A.
Bellatrix expanded its operations significantly between 2012 and 2013 through the continued success of its internal
drilling program in conjunction with the completion of several major transactions. The Company closed the Grafton Joint
Venture, formed the Daewoo and Devonian Partnership, and closed the Troika Joint Venture during 2013.
On
November 5, 2013, Bellatrix closed a bought deal financing of 21,875,000 Bellatrix common shares at a price of $8.00
per Bellatrix Share for aggregate gross proceeds of $175.0 million (net proceeds of $165.7 million after transaction costs)
through a syndicate of underwriters.
On December 11, 2013, Bellatrix acquired all of the issued and outstanding
common shares of Angle for consideration consisting of $69.7 million in cash and approximately 30.2 million Bellatrix
common shares.
Bellatrix’s net cash capital expenditures increased to $840.8 million during 2013 compared to $204.6 million in 2012.
During 2013, Bellatrix drilled or participated in 80 gross (52.8 net) wells, compared to 34 gross (26.3 net) wells in 2012.
Sales volumes increased by 31% between the years to 21,829 boe/d in 2013 from 16,686 boe/d in 2012 due to the
transactions noted above as well as Bellatrix’s continued drilling success achieved throughout 2013. As a result of the
increase in sales volumes as well as higher realized prices for all commodities between the years, revenues before other
income, royalties and risk management increased to $288.3 million in 2013, compared to $217.1 million realized in 2012.
51
MANAGEMENT'S REPORT TO SHAREHOLDERS
Management’s Responsibility on Financial Statements
The management of Bellatrix Exploration Ltd. (“Bellatrix” or the “Company”) is responsible for the preparation and
integrity of the accompanying consolidated financial statements and all other information contained in this report. The
consolidated financial statements have been prepared in accordance with International Financial Reporting Standards as
issued by the International Accounting Standards Board and include amounts that are based on management's informed
judgments and estimates where necessary.
The Company has established internal accounting control systems which are designed to safeguard assets from loss or
unauthorized use and ensure the accuracy of the Company’s accounting records. The Board of Directors, through its
Audit Committee, monitors management's financial and accounting policies and practices and the preparation of these
consolidated financial statements. The Audit Committee meets periodically with the external auditors and management
to review the work of each and the propriety of the discharge of their responsibilities.
The Audit Committee reviews the consolidated financial statements of the Company with management and the external
auditors prior to submission to the Board of Directors for final approval. The external auditors have full and free access
to the Audit Committee to discuss auditing and financial reporting matters. The Audit Committee reviews the
independence of the external auditors and pre-approves audit and permitted non-audit services. The Shareholders have
appointed KPMG LLP as the external auditors of the Company. The Report of Independent Registered Public
Accounting Firm to the Board of Directors and Shareholders, which describe the scope of their examination and express
their opinion, are included with the consolidated financial statements for the year ended December 31, 2014.
Management’s Report on Internal Control over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined
in Rules 13(a) – 15(f) and 15(d) – 15(f) under both the Securities Exchange Act of 1934 and NI 52-109, as amended.
Internal control over financial reporting is designed by, or designed under the supervision of, our President and CEO and
our Executive Vice President, Finance and CFO, and effected by our Board of Directors, management and other
personnel, to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial
statements for external purposes in accordance with generally accepted accounting principles.
Under the supervision and with the participation of our management, including our President and CEO and our Executive
Vice President, Finance and CFO, an evaluation of the design and effectiveness of our internal control over financial
reporting was conducted as of December 31, 2014 based on the framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (“COSO”) in Internal Control – Integrated Framework (2013). Based on this
evaluation, management concluded that as of December 31, 2014 the Company did maintain effective internal control
over financial reporting.
The effectiveness of internal control over financial reporting as of December 31, 2014 was audited by KPMG LLP, an
independent registered public accounting firm, as stated in their Independent Auditors’ Report of Registered Public
Accounting Firm, which is included with the consolidated financial statements for the year ended December 31, 2014.
(signed) “Raymond G. Smith”
(signed) “Edward J. Brown”
Raymond G. Smith, P.Eng.
President and CEO
Edward J. Brown, C.A.
Executive Vice President, Finance and CFO
March 11, 2015
1
INDEPENDENT AUDITORS’ REPORT OF REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders of Bellatrix Exploration Ltd.
We have audited the accompanying consolidated financial statements of Bellatrix Exploration Ltd., which comprise the
consolidated balance sheets as at December 31, 2014 and December 31, 2013, the consolidated statements of
comprehensive income, shareholders’ equity and cash flows for the years then ended, and notes, comprising a summary
of significant accounting policies and other explanatory information.
Management’s Responsibility for the Consolidated Financial Statements
Management is responsible for the preparation and fair presentation of these consolidated financial statements in
accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board,
and for such internal control as management determines is necessary to enable the preparation of consolidated financial
statements that are free from material misstatement, whether due to fraud or error.
Auditors’ Responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We
conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the
Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical
requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial
statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated
financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material
misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments,
we consider internal control relevant to the entity’s preparation and fair presentation of the consolidated financial
statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes
evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by
management, as well as evaluating the overall presentation of the consolidated financial statements.
We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our
audit opinion.
Opinion
In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial
position of Bellatrix Exploration Ltd. as at December 31, 2014 and December 31, 2013, and its consolidated financial
performance and its consolidated cash flows for the years then ended in accordance with International Financial
Reporting Standards as issued by the International Accounting Standards Board.
Other Matter
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States), Bellatrix Exploration Ltd.’s internal control over financial reporting as of December 31, 2014, based on the
criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO), and our report dated March 11, 2015 expressed an unmodified
(unqualified) opinion on the effectiveness of Bellatrix Exploration Ltd.’s internal control over financial reporting.
(signed) “KPMG LLP”
Chartered Accountants
March 11, 2015
Calgary, Canada
2
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Bellatrix Exploration Ltd.
We have audited Bellatrix Exploration Ltd. (“the Corporation”) internal control over financial reporting as of December 31,
2014, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO). The Corporation’s management is responsible for
maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control
over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial
Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on
our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether
effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an
understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing
and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also
included performing such other procedures as we considered necessary in the circumstances. We believe that our audit
provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. A company’s internal control over financial reporting includes those policies
and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of
management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may
deteriorate.
In our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of
December 31, 2014, based on criteria established in Internal Control – Integrated Framework (2013) issued by the
Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with Canadian generally accepted auditing standards and the standards of the
Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Corporation as at
December 31, 2014 and December 31, 2013, and the related consolidated statements of comprehensive income,
shareholders’ equity and cash flows for the years then ended, and our report dated March 11, 2015 expressed an
unmodified (unqualified) opinion on those consolidated financial statements.
(signed) “KPMG LLP”
Chartered Accountants
March 11, 2015
Calgary, Canada
3
BELLATRIX EXPLORATION LTD.
CONSOLIDATED BALANCE SHEETS
(expressed in Canadian dollars)
As at December 31,
2014
($000s)
ASSETS
Current assets
Restricted cash
Accounts receivable (note 22)
Deposits and prepaid expenses
Current portion of commodity contract asset (note 22)
$
Exploration and evaluation assets (note 7)
Property, plant and equipment (note 8)
Total assets
LIABILITIES
Current liabilities
Accounts payable and accrued liabilities
Advances from joint venture partners
Current portion of finance lease obligation (note 11)
Current portion of deferred lease inducements
Current portion of commodity contract liability (note 22)
Long-term debt (note 9)
Finance lease obligation (note 11)
Deferred lease inducements
Decommissioning liabilities (note 12)
Deferred taxes (note 16)
Total liabilities
SHAREHOLDERS’ EQUITY
Shareholders’ capital (note 13)
Contributed surplus
Retained earnings
Total shareholders’ equity
Total liabilities and shareholders’ equity
COMMITMENTS (note 21)
See accompanying notes to the consolidated financial statements.
On behalf of the Board of Directors
(signed) “Doug Baker”
Doug Baker, FCA
Director, Chairman, Audit Committee
(signed) “W.C. (Mickey) Dunn”
W.C. (Mickey) Dunn
Director, Chairman of the Board
4
25,504
110,118
6,926
142,548
123,639
1,947,298
2013
$
38,148
80,306
10,001
345
128,800
132,971
1,293,409
$ 2,213,485
$ 1,555,180
$
$
154,094
76,388
1,574
340
232,396
137,465
99,380
1,495
285
17,278
255,903
549,792
10,063
2,727
88,605
81,585
965,168
287,092
11,637
2,565
67,075
27,034
651,306
1,000,041
44,302
203,974
1,248,317
824,065
38,958
40,851
903,874
$ 2,213,485
$ 1,555,180
BELLATRIX EXPLORATION LTD.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(expressed in Canadian dollars)
For the years ended December 31,
2014
($000s, except per share amounts)
REVENUES
Petroleum and natural gas sales
Other income
Royalties
Total revenues
2013
$ 574,253
9,214
(99,823)
483,644
$ 288,310
3,581
(46,217)
245,674
(31,991)
16,933
468,586
1,859
(17,127)
230,406
120,072
16,259
25,371
3,673
181,780
(68,616)
(50,526)
228,013
69,668
7,014
16,214
5,344
4,960
85,829
(42,494)
(20,630)
125,905
240,573
104,501
Finance expenses (note 17)
20,937
13,343
NET PROFIT BEFORE TAXES
219,636
91,158
56,513
19,483
$ 163,123
$ 71,675
$0.89
$0.88
$0.63
$0.62
Realized gain (loss) on commodity contracts
Unrealized gain (loss) on commodity contracts
EXPENSES
Production
Transportation
General and administrative
Transaction costs
Share-based compensation (note 14)
Depletion, depreciation, and impairment (note 8)
Gain on property acquisitions (note 6)
Gain on property dispositions and swaps (note 8)
Gain on corporate acquisition (note 6)
NET PROFIT BEFORE FINANCE AND TAXES
TAXES
Deferred tax expense (note 16)
NET PROFIT AND COMPREHENSIVE INCOME
Net profit per share (note 20)
Basic
Diluted
See accompanying notes to the consolidated financial statements.
5
BELLATRIX EXPLORATION LTD.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(expressed in Canadian dollars)
For the year ended December 31,
2014
($000s)
SHAREHOLDERS’ CAPITAL (note 13)
Common shares (note 13)
Balance, beginning of year
Issued for cash on exercise of share options
Issued for the Angle acquisition (note 6)
Share issue costs on the Angle acquisition, net of tax
Issued on settlement of convertible debentures
Issued for cash on equity issue, net of tax
Share issue costs on equity issue and shelf prospectus, net of tax
Contributed surplus transferred on exercised options
Balance, end of year
EQUITY COMPONENT OF CONVERTIBLE DEBENTURES (note 10)
Balance, beginning of year
Adjustment for settlement of convertible debentures
Balance, end of year
CONTRIBUTED SURPLUS (note 14)
Balance, beginning of year
Share-based compensation expense
Adjustment of share-based compensation expense
for forfeitures of unvested share options
Transfer to share capital for exercised options
Other
Balance, end of year
RETAINED EARNINGS (DEFICIT)
Balance, beginning of year
Adjustment for settlement of convertible debentures (note 10)
Net profit
Balance, end of year
$
824,065
6,931
172,615
(5,887)
2,317
1,000,041
-
6
4,378
(4,378)
-
37,284
3,045
(559)
(2,317)
774
44,302
(163)
(1,208)
38,958
$ 1,248,317
See accompanying notes to the consolidated financial statements.
$ 371,576
3,088
225,221
(576)
55,568
175,000
(7,020)
1,208
824,065
38,958
7,446
40,851
163,123
203,974
TOTAL SHAREHOLDERS’ EQUITY
2013
(32,132)
1,308
71,675
40,851
$ 903,874
BELLATRIX EXPLORATION LTD.
CONSOLIDATED STATEMENT OF CASH FLOWS
(expressed in Canadian dollars)
For the year ended December 31,
2014
($000s)
2013
Cash provided from (used in):
CASH FLOW FROM (USED IN) OPERATING ACTIVITIES
Net profit
Adjustments for:
Depletion, depreciation and impairment (note 8)
Finance expenses (note 17)
Interest paid on redemption of convertible debentures
Share-based compensation (note 14)
Unrealized (gain) loss on commodity contracts
Gain on property acquisitions (note 6)
Gain on property dispositions and swaps (note 8)
Gain on corporate acquisition
Deferred tax expense (note 16)
Decommissioning costs incurred
Change in non-cash working capital (note 15)
$ 163,123
CASH FLOW FROM (USED IN) FINANCING ACTIVITIES
Issuance of share capital (note 13)
Issue costs on share capital (note 13)
Settlement of restricted awards
Advances from loans and borrowings
Repayment of loans and borrowings
Repayment of Angle convertible debentures
Obligations under finance lease
Deferred lease inducements
Change in non-cash working capital (note 15)
$
71,675
181,780
1,739
3,673
(16,933)
(68,616)
(50,526)
56,513
(1,743)
25,818
294,828
85,829
2,151
14
4,960
17,127
(42,494)
(20,630)
19,483
(1,057)
(8,600)
128,458
180,320
(7,849)
(1,256)
2,813,950
(2,551,250)
(1,495)
218
149
432,787
178,088
(10,128)
1,022,835
(1,051,917)
(62,400)
(1,425)
2,565
(960)
76,658
(11,383)
(713,596)
42,730
(45,366)
(727,615)
(10,391)
(293,268)
70,936
(69,701)
97,308
(205,116)
CASH FLOW FROM (USED IN) INVESTING ACTIVITIES
Expenditure on exploration and evaluation assets
Additions to property, plant and equipment
Proceeds on sale of property, plant and equipment
Cash portion of Angle acquisition
Change in non-cash working capital (note 15)
Change in cash
-
-
Cash, beginning of year
-
-
Cash, end of year
$
Cash paid:
Interest
Taxes
See accompanying notes to the consolidated financial statements.
7
-
$
-
$ 15,349
-
$
7,609
-
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(expressed in Canadian dollars)
1.
CORPORATE INFORMATION
Bellatrix Exploration Ltd. (the “Company” or “Bellatrix”) is a growth oriented, publicly traded exploration and
production oil and gas company.
Bellatrix was incorporated in Canada and the Company’s registered office and principal place of business is located
th
at 1920, 800 – 5 Avenue SW, Calgary, Alberta, Canada T2P 3T6.
2.
BASIS OF PREPARATION
a.
Statement of compliance
These consolidated financial statements (“financial statements”) were authorized by the Board of Directors on March
11, 2015. The Company prepared these financial statements in accordance with International Financial Reporting
Standards as issued by the International Accounting Standards Board (“IFRS”).
b.
Change in accounting policies
IFRIC 21 - “Levies”, which establishes guidelines for the recognition and accounting treatment of a liability relating to
a levy imposed by a government. This standard is effective for annual periods beginning on or after January 1, 2014
and was adopted by Bellatrix effective January 1, 2014. The adoption of IFRIC 21 had no impact on Bellatrix.
Amendments to “Offsetting Financial Assets and Financial Liabilities” addressed within IAS 32 - “Financial
Instruments: Presentation”, which provides guidance regarding when it is appropriate and permissible for an entity to
disclose offsetting financial assets and financial liabilities on a net basis. The amendments to this standard are
effective for annual periods beginning on or after January 1, 2014 and were adopted by Bellatrix effective January 1,
2014. The adoption of IAS 32 amendments had no impact on Bellatrix.
c.
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 cashsettled 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.
8
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.
Bellatrix is a partner in the Grafton Joint Venture, the CNOR Joint Venture, the Daewoo and Devonian
Partnership, and the Troika Joint Venture (all as defined below), which have all been separately assessed and
classified under IFRS as joint operations.
This classification is on the basis that the arrangement is not
conducted through a separate legal entity and the partners are legally obligated to pay their share of costs
incurred and take their share of output produced from the various production areas, and all partners have rights
to the assets and obligations for the liabilities resulting from the joint operations. The Company considered
these factors as well as the terms of the individual agreements in determining the classification of a joint
operation to be appropriate for each arrangement.
For purposes of disclosure throughout the financial
statements, Bellatrix has referred to these arrangements by the common oil and gas industry term of joint
ventures.
Grafton Joint Venture – Bellatrix has a joint venture (the “Grafton Joint Venture”) with Grafton Energy
Co I Ltd. (“Grafton”) in the Willesden Green and Brazeau areas of West-Central Alberta, whereby
Grafton will contribute 82% to the joint venture. Under the agreement, Grafton will earn 54% of
Bellatrix’s working interest in each well drilled in the well program until payout (being recovery of
Grafton's capital investment plus an 8% internal rate of return) on the total program, reverting to 33%
of Bellatrix's working interest ("WI") after payout. At any time after payout of the entire program,
Grafton shall have the option to elect to convert all wells from the 33% WI to a 17.5% Gross Overriding
Royalty (“GORR”) on Bellatrix’s pre-Grafton Joint Venture WI.
CNOR Joint Venture - On September 30, 2014, Bellatrix announced that the Company and Canadian
Non-Operated Resources Corp. ("CNOR"), a non-operated oil and gas company managed by Grafton
Asset Management Inc., had completed the formation of a new multi-year joint venture arrangement
(the “CNOR Joint Venture”), pursuant to which CNOR will pay 50% of the drilling, completion,
equipping and tie-in capital expenditures associated with development plans to be proposed by
Bellatrix and approved by a management committee comprised of representatives of Bellatrix and
CNOR in order to earn 33% of Bellatrix's working interest before payout and automatically converting
to a 10.67% gross overriding royalty on Bellatrix's pre-joint venture working interest after payout (being
recovery of CNOR’s capital investment plus an 8% return on investment).
Daewoo and Devonian Partnership – Bellatrix has a joint venture arrangement (the “Daewoo and
Devonian Partnership”) with Canadian subsidiaries of two Korean entities, Daewoo International
Corporation (“Daewoo”) and Devonian Natural Resources Private Equity Fund (“Devonian”) in the
Baptiste area of West-Central Alberta, whereby Daewoo and Devonian own a combined 50% of
Bellatrix’s WI share of producing assets, an operated compressor station and gathering system and
related land acreage.
Troika Joint Venture – Bellatrix has a joint venture (the “Troika Joint Venture”) with TCA Energy Ltd.
("TCA") in the Ferrier Cardium area of West-Central Alberta, whereby Troika will contribute 50%
towards a capital program and will receive a 35% WI until payout (being recovery of TCA's capital
investment plus a 15% internal rate of return) on the total program, and thereafter reverting to 25% of
Bellatrix's WI.
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.
9
II.
Exploration and evaluation expenditures
Costs incurred once the legal right to explore has been acquired are capitalized as intangible 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.
Joint arrangements
The Company has entered into certain joint arrangements whereby the joint arrangement partner
(“partner”) will earn a working interest on certain properties through the payment of a pre-determined
portion of the costs of drilling, completing and equipping. A gain on disposition for each well is recognized
to account for the disposal of the pre-payout working interest earned by the partner on the well, which
results from the difference between the percentage of all capital costs contributed for the drilling,
completion, equipping and tie-in of the well by the partner, and the pre-payout working interest allocated to
the partner by the Company. The gain on disposition for a well is recognized during the quarter in which
the well was completed and tied-in, or upon the achievement of a different milestone as specified by the
relevant agreement with the partner. Bellatrix has both exploration and evaluation assets and property,
plant and equipment assets that are subject to these arrangements.
V.
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-today servicing of property, plant and equipment are recognized in profit or loss as incurred.
VI.
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 Standards of
Disclosure of Oil and Gas Activities. 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
10
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”).
reviews the composition and determination of its CGUs.
The Company regularly
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 CGU.
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 CGUs are allocated first to reduce the carrying amount of goodwill, if any,
allocated to the CGU and then to reduce the carrying amounts of the other assets in the CGU 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, 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).
11
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 expense.
I.
Decommissioning liabilities
The Company’s activities give rise to dismantling, decommissioning and site disturbance remediation
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 liability and the relevant asset.
The unwinding of the discount on the decommissioning provision is recognized as a finance expense.
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 BlackScholes 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 nontransferability, exercise restrictions and behavioural considerations.
II.
Cash-settled transactions
The Company’s Deferred Share Unit Plan (the “DSU Plan”) is accounted for as a cash settled share
based payment plan in which the fair value of the amount payable under the DSU Plan is recognized
as an expense with a corresponding increase in liabilities. The liability is remeasured at each reporting
date and at settlement date. Any changes in the fair value of the liability are recognized in profit or
loss.
The Company’s Restricted and Performance Award Plan (the “Incentive Plan”) is accounted for as a
cash settled share based payment plan in which the fair value of the amounts payable under the
Incentive Plan are recognized incrementally as an expense over the term of the corresponding grant,
with a corresponding change in liabilities.
12
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 tax
Current 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 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 Liabilities
Category
Cash and cash equivalents
Held-for-trading
Restricted cash
Accounts receivable
Deposits and prepaid expenses
Held-for-trading
Loans and receivables
Other assets
Commodity risk management contracts
Accounts payable and accrued liabilities
Held-for-trading
Other liabilities
Deferred share units
Other liabilities
Restricted awards
Other liabilities
Performance awards
Advances from joint venture partners
Long-term debt
Other liabilities
Other liabilities
Other liabilities
13
Subsequent Measurement
Fair value through profit or loss;
Level 1
Fair value through profit or loss;
Level 1
Amortized cost
Amortized cost
Fair value through profit or loss;
Level 2
Amortized cost
Fair value through profit or loss;
Level 1
Fair value through profit or loss;
Level 1
Fair value through profit or loss;
Level 2
Amortized cost
Amortized cost
Deferred lease inducements
Finance lease obligation
Other liabilities
Other liabilities
Amortized cost
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 fully settled its convertible debentures by October 21, 2013. As at December 31, 2013 and
December 31, 2014, the Company did not have any outstanding convertible debentures.
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.
14
k.
Lease Obligations
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.
Assets held under other leases are classified as operating leases and are not recognized in the balance sheet.
Payments made under operating leases are recognized in profit or loss on a straight-line basis over the term of
the lease. Lease incentives received from landlords are deferred and recognized as an integral part of the total
lease expense, over the term of the lease.
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.
Restricted Cash
Restricted cash represents funds advanced by a certain joint venture partner for specific future drilling projects.
These funds are released for general purposes and capital expenditures related to the joint venture as each
project reaches a predetermined progress point.
q.
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 profit. If the cost of the acquisition is more than the fair value of the net assets
acquired, the difference is recognized on the balance sheet as goodwill. Acquisition costs incurred are
expensed.
15
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.
a.
Critical Accounting Judgments
I.
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 or loss. 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.
II.
Identification of CGUs
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.
III. Impairment Indicators
Judgment is required to assess when impairment indicators exist and impairment testing is required. In
determining the recoverable amount of assets, in the absence of quoted market prices, impairment tests
are based on estimate of reserves, production rates, future oil and natural gas prices, future costs, discount
rates, market value of land and other relevant assumptions.
IV.
Joint Arrangements
Judgment is required to determine when the Company has joint control over an arrangement. In
establishing joint control, the Company considers whether unanimous consent is required to direct the
activities that significantly affect the returns of the arrangement, such as the capital and operating activities
of the arrangement. Additionally, the Company assesses the rights and obligations arising from the
arrangement by considering its governance structure, legal form, and terms agreed upon by the parties
sharing control, including the contractual rights of each partner, dispute resolution procedures, termination
provisions, and procedures for subsequent transactions in its determination of joint control.
Once joint control has been established, judgment is also required to classify the joint arrangement. The
type of joint arrangement is determined through analysis of the rights and obligations arising from the
arrangement by considering its legal structure, legal form. And terms agreed upon by the parties sharing
control. An arrangement that is not structured through a separate vehicle in which the controlling parties
have rights to the assets, revenues and substantially all of the economic benefits generated through the
arrangement, in addition to obligations for the liabilities and expenses, is classified as a joint operation. An
arrangement in which these criteria are not met is classified as a joint venture.
16
b.
Critical Estimates and Assumptions
I.
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. 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.
II.
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.
III. 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.
IV.
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
goodwill. 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 International Accounting Standards Board (“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, 2018 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 15 - “Revenue from Contracts with Customers”, which provides a five-step model to be applied to all contracts
formed with customers. The standard specifies when an entity will recognize revenue and provides guidance
regarding disclosures relating to revenue recognition. IFRS 15 will apply to annual reporting periods beginning on or
after January 1, 2017. The extent of the impact of the adoption of IFRS 15 has not yet been determined.
17
6.
ACQUISITIONS
a)
Business Combinations
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 acquisitions individually and determined each of them to constitute
business combinations 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.
During the year ended December 31, 2014, Bellatrix completed three major acquisitions of complementary
assets within its core Ferrier region.
These strategic tuck-in acquisitions added to the Company’s
production and largely represented the consolidation of working interest ownership from existing wellbores
and Mannville formation rights. Acreage acquired through the transactions is considered to be highly
contiguous with Bellatrix’s existing acreage, and includes operatorship over the majority of the acquired
sections.
For each of the property acquisitions, the estimated fair value of the property, plant and equipment
acquired was determined using internal estimates and independent reserve evaluations. 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.
The fair value of
identifiable assets acquired and liabilities assumed is final.
During the third quarter of 2014, Bellatrix closed an acquisition of production and working interest in certain
facilities, as well as undeveloped land in the Ferrier area of Alberta for a cash purchase price of $13.9
million after adjustments. The effective date of the transaction was September 1, 2014.
The fair values of the assets and liabilities acquired through the transaction were determined based on the
present value of the expected future cash flows associated with the acquired properties as determined by a
reserve report for oil and natural gas properties, as well through the examination of comparable market
transactions for parcels of land for exploration and evaluation assets. The total net fair value of the
acquired properties was greater than the cash consideration paid by the Company, resulting in the
recognition of a gain on property acquisition for the year ended December 31, 2014. The gain on this
property acquisition was the result of Bellatrix purchasing the assets from a counterparty that was looking
to exit operations within the acquisition area. A summary of the property acquired through this transaction
is provided below:
($000s)
Estimated fair value of acquisition:
Oil and natural gas properties
Exploration and evaluation assets
Decommissioning liabilities
$ 26,997
126
(1,444)
25,679
Cash consideration
Gain on property acquisition
13,909
$ 11,770
Included in the Company’s deferred tax expense for the year was a $2.9 million expense relating to the
gain recognized on the property acquisition.
During the three months ended December 31, 2014, the Company completed an acquisition of production
in the Ferrier area of Alberta for a total cash purchase price after adjustments of $118.0 million. The
effective date of the transaction was November 1, 2014.
18
The fair values of the assets and liabilities acquired through the transaction were determined based on the
present value of expected future cash flows associated with the acquired properties. The total net fair
value of the acquired properties was equal to the cash consideration paid by the Company. As a result, no
gain on property acquisition was recognized for the year ended December 31, 2014 relating to the
acquisition. A summary of the property acquired through this transaction is provided below:
A summary of the property acquired through this transaction is provided below:
($000s)
Estimated fair value of acquisition:
Oil and natural gas properties
$ 118,108
Decommissioning liabilities
(108)
118,000
Cash consideration
118,000
Gain on property acquisition
$
-
Had the $118.0 million property acquisition occurred with an effective date of January 1, 2014, the
Company would not have realized an additional 2,346 boe/d of average sales volumes, $24.4 million of
revenues, and an additional $14.6 million of after tax net profit.
During the three months ended December 31, 2014, the Company completed an additional acquisition of
production and working interest in certain facilities as well as undeveloped land in the Ferrier area of
Alberta for a total cash purchase price after adjustments of $33.0 million.
The effective date of the
transaction was September 1, 2014.
The fair values of the assets and liabilities acquired through the transaction were determined based on the
present value of the expected future cash flows associated with the acquired properties as determined by a
reserve report for the oil and natural gas properties. The total net fair value of the acquired properties was
greater than the cash consideration paid by the Company, resulting in the recognition of a gain on property
acquisitions for the year ended December 31, 2014. The gain for the acquired properties was the result of
Bellatrix purchasing the assets from a counterparty that was considering cessation of its operations within
the acquisition area and changes to the timing of the properties’ development plan. A summary of the
property acquired through this transaction is provided below:
($000s)
Estimated fair value of acquisition:
Oil and natural gas properties
$ 85,482
Exploration and evaluation assets
4,470
Decommissioning liabilities
(113)
89,839
Cash consideration
32,994
Gain on property acquisition
$ 56,845
Included in the Company’s deferred tax expense for the year was a $14.2 million expense relating to the
gain recognized on the property acquisition.
b)
Corporate acquisition of Angle Energy Inc. - 2013
On December 11, 2013, Bellatrix acquired all issued and outstanding shares of Angle Energy Inc. (“Angle”)
for the issuance of 30,230,998 Bellatrix common shares with a total value of $225.2 million, and cash
consideration of $69.7 million.
19
A summary of the acquired assets and liabilities is provided below:
($000s)
Estimated fair value of acquisition:
Accounts receivable
25,181
Deposits and prepaid expenses
3,526
Commodity contract asset
20
Exploration and evaluation assets
97,520
Property, plant and equipment
498,371
Accounts payable and accrued liabilities
(40,046)
Long-term debt
(183,127)
Convertible debentures
(62,400)
Decommissioning liabilities
(11,817)
Deferred taxes
(11,676)
315,552
Cost of acquisition:
Bellatrix shares issued (30,226,413 shares)
225,221
Cash consideration
69,701
294,922
Gain on corporate acquisition
20,630
A gain on corporate acquisition of $20.6 million was recognized for the Angle acquisition.
In the year ended December 31, 2013, Bellatrix incurred approximately $5.3 million of transaction costs
related to the corporate acquisition that are expensed on the Consolidated Statements of Comprehensive
Income.
7. EXPLORATION AND EVALUATION ASSETS
($000s)
Cost
Balance, December 31, 2012
Acquisitions through business combinations
Additions
Transfer to oil and natural gas properties
(1)
Disposals
Balance, December 31, 2013
Acquisitions through business combinations
Additions
Transfer to oil and natural gas properties
(1)
Disposals
Balance, December 31, 2014
(1)
Disposals include swaps.
20
$
38,177
97,520
10,391
(7,424)
(5,693)
132,971
4,596
6,788
(20,685)
(31)
$
123,639
8.
PROPERTY, PLANT AND EQUIPMENT
($000s)
Oil and
natural gas
properties
Cost
Balance, December 31, 2012
Acquisitions through business combinations
Additions
Transfer from exploration and evaluation assets
Joint venture wells
(1)
Disposals
$
Balance, December 31, 2013
Acquisitions through business combinations
Additions
Transfer from exploration and evaluation assets
Joint venture wells
Transfers
(1)
Disposals
$
1,629,027
230,366
563,015
20,685
53,169
(32,921)
(9,809)
Balance, December 31, 2014
2,802
9,270
(487)
Total
$
11,585
11,164
-
1,640,612
230,366
574,179
20,685
53,169
(32,921)
(9,809)
$
$
262,570
84,902
(2,510)
344,962
167,914
10,813
$
1,581
927
(267)
2,241
3,053
-
$
264,151
85,829
(2,777)
347,203
170,967
10,813
$
523,689
$
5,294
$
528,983
$ 1,284,065
$ 1,929,843
$
$
9,344
17,455
Balance, December 31, 2014
22,749
853,910
498,371
307,558
7,424
11,244
(37,895)
$ 2,453,532
Accumulated Depletion, Depreciation and Impairment losses
Balance, December 31, 2012
Charge for time period
(1)
Disposals
Balance, December 31, 2013
Charge for time period
Impairment loss
(1)
851,108
498,371
298,288
7,424
11,244
(37,408)
Office
furniture and
equipment
$ 2,476,281
Disposals include swaps.
Carrying amounts
At December 31, 2013
At December 31, 2014
$ 1,293,409
$ 1,947,298
Bellatrix has included $1.34 billion (2013: $1.28 billion) for future development costs and excluded $80.3 million
(2013: $69.0 million) for estimated salvage from the depletion calculation for the three months ended December 31,
2014. Facilities under construction associated capital of $38.7 million was excluded from the depletable base for the
depletion calculation for the three months ended December 31, 2014.
Dispositions
In the year ended December 31, 2014, a total net gain on dispositions of $52.3 million (2013: $11.2 million) was
recognized relating to gains on wells drilled under the Grafton Joint Venture and the Troika Joint Venture which were
completed and tied-in during 2014. A gain on disposition for each well is recognized to account for the disposal of
the pre-payout working interest earned by the joint venture partner on the well, which results from the difference
between the percentage of all capital costs contributed for the drilling, completion, equipping and tie-in of the well by
the joint venture partner and the pre-payout working interest allocated to the joint venture partner by the Company.
The gain on disposition for a well is recognized during the quarter in which the well was completed and tied-in.
Under the Grafton Joint Venture Agreement, Grafton contributes 82% of the total capital costs required for each well
under the Grafton Joint Venture Agreement, and in return earns 54% of Bellatrix’s WI in each well drilled until
payout.
Under the Troika Joint Venture Agreement, Troika contributes 50% of the total capital costs required for each well
under the Troika Joint Venture Agreement, and in return earns 35% of Bellatrix’s WI in each well until payout.
21
For the year ended December 31, 2014, the Company capitalized $8.5 million (2013: $5.3 million) of general and
administrative expenses and $3.4 million (2013: $1.7 million) of share-based compensation expense directly related
to exploration and development activities.
In the fourth quarter of 2014, Bellatrix completed the transfer of minority interests totaling 40% in its new Bellatrix
O'Chiese Nees-Ohpawganu'ck deep-cut gas plant at Alder Flats (the “Bellatrix Alder Flats Plant”) and related
pipeline infrastructure currently under construction to Keyera Partnership and O'Chiese Gas Plant GP Inc. The total
value of the minority interests transferred related to the Bellatrix Alder Flats Plant was $23.2 million, which reflected
the total actual costs incurred for the interest transferred as at the transfer date. The remainder of the value
transferred during 2014 related to recently constructed pipeline infrastructure transferred at cost at the transfer date.
The Company’s credit facilities are secured against all of its the assets by a $1 billion debenture containing a first
ranking floating charge and security interest. The Company has provided a negative pledge and undertaking to
provide fixed charges over major petroleum and natural gas reserves in certain circumstances.
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 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. The impairment test is a one step
process for testing and measuring impairment of assets. The recoverability of a CGU’s carrying value is determined
by calculating the recoverable amount of the CGU, which is defined as 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. 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.
Key input estimates used to determine the present value of expected future net cash flows include:
a)
Reserves - An external reserve engineering report which incorporates a full evaluation of reserves is
prepared on an annual basis with internal reserve updates completed at each quarterly period. Estimating
reserves is highly complex, requiring many judgments including forward price estimates, production costs,
and recovery rates based on available geological, geophysical, engineering and economic data. Changes
in these judgments may have a material impact on the estimated reserves. These estimates may change,
resulting in either negative or positive impacts to net earnings as further information becomes available and
as the economic environment changes.
b)
Commodity prices – Forward price estimates of crude oil and natural gas prices are incorporated into the
determination of expected future net cash flows. Commodity prices have fluctuated significantly in recent
years due to global and regional factors including supply and demand fundamentals, inventory level,
exchange rates, weather, economic, and geopolitical factors.
c)
Discount rates – Discount rates used to calculate the present value of expected future cash flows are based
on estimates of the recoverability of asset values in the current industry market conditions. Changes in the
general economic environment could result in significant changes to these estimates.
22
2014 Impairment
At December 31, 2014, Bellatrix performed an assessment of possible indicators of impairment on all of the
Company’s CGUs. Primarily as a result of declining crude oil and natural gas forward commodity prices, Bellatrix
completed impairment tests for each of its CGUs. The impairment amount was estimated using fair value less costs
to sell calculations based on expected future cash flows generated from proved and probable reserves, which
incorporated before-tax discount rates ranging from 10-15%. This impairment test resulted in an excess of the
carrying value over their recoverable amount in the Company’s 5 non-core CGUs. The total non-cash impairment
loss recognized in depletion, depreciation and impairment expense for the year ended December 31, 2014 was
$10.8 million. No impairment was recognized in relation to the Company’s core West Central Alberta CGU.
A 1% increase to the discount rates applied in 2014 year-end impairment calculations would result in an increase in
impairment expense of $0.4 million. Identical decreases would result from a 1% decrease to the discount rates
applied.
2013 Impairment
As at December 31, 2013, Bellatrix determined there were no impairment indicators requiring an impairment test to
be performed.
9.
LONG-TERM DEBT
In the Company’s semi-annual borrowing base review for November 30, 2014, Bellatrix increased its borrowing base
and credit facilities from $625 million to $725 million.
As of December 31, 2014, the Company’s credit facilities are available on an extendible revolving term basis and
consist of a $75 million operating facility provided by a Canadian bank and a $650 million syndicated facility
provided by nine financial institutions.
Amounts borrowed under the credit facilities will bear interest at a floating rate based on the applicable Canadian
prime rate, U.S. base rate, CDOR rate or LIBOR margin rate, plus between 0.8% to 3.75%, depending on the type
of borrowing and the Company’s senior debt to EBITDA ratio. A standby fee is charged of between 0.405% and
0.84375% on the undrawn portion of the credit facilities, depending on the Company’s senior debt to EBITDA ratio.
The credit facilities are secured by a $1 billion 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.
The revolving period for the revolving term credit facility will end on May 30, 2017, unless extended for a further
period of up to three years. Should the facility not be extended, the outstanding balance is due upon maturity. The
borrowing base will be subject to re-determination on or before May 31 and November 30 in each year prior to
maturity, with the next semi-annual redetermination occurring on or before May 31, 2015.
23
Bellatrix’s credit facilities are subject to a number of covenants, all of which were met as at December 31, 2014.
Bellatrix calculates its financial covenants quarterly. The calculation for each financial covenant is based on specific
definitions which are not in accordance with IFRS and cannot be readily replicated by referring to Bellatrix’s
Consolidated Financial Statements. As at December 31, 2014, the major financial covenants are:
Position at December 31, 2014
(1)
(2)
Total Debt must not exceed 3.5 times EBITDA for the last four fiscal quarters
(3)
Senior Debt must not exceed 3.0 times EBITDA for the last four fiscal quarters
EBITDA must not be less than 3.5 times interest expense for the last four fiscal quarters
2.08x
2.08x
14.97x
(1)
“Total Debt” is defined as the sum of the bank loan, the principal amount of long-term debt and certain other liabilities defined
in the agreement governing the credit facilities.
(2)
“EBITDA” refers to earnings before interest, taxes, depreciation and amortization. EBITDA is calculated based on terms and
definitions set out in the agreement governing the credit facilities which adjusts net income for financing costs, certain specific
unrealized and non-cash transactions, and acquisition and disposition activity and is calculated based on a trailing twelve month
basis.
(3)
“Senior Debt” is defined as Total Debt, excluding any unsecured or subordinated debt. Bellatrix currently does not have any
subordinated or unsecured debt.
In the event of a material acquisition, the Total Debt to EBITDA and Senior Debt to EBITDA covenants are relaxed
for two fiscal quarters after the close of the acquisition and must not exceed 4.0 and 3.5 times EBITDA, respectively.
Due to material acquisitions in the quarter ended December 31, 2014, the Total Debt to EBITDA and Senior Debt to
EBITDA covenants are temporarily increased until June 30, 2015 to not exceed 4.0 and 3.5 times, respectively.
Effective March 11, 2015, the Company’s banking syndicate agreed to amendments to certain of the financial
covenants in response to the recent decline in commodity prices. The Total Debt to EBITDA and Senior Debt to
EBITDA financial covenants have been revised such that they each must not exceed:
•
4.75 times for the fiscal quarters ending September 30, 2015, December 31, 2015, March 31, 2016 and
June 30, 2016; and
•
4.0 times for the fiscal quarters ending September 30, 2016, December 31, 2016 and March 31, 2017.
During the periods in which these revised financial covenants are in place, the additional automatic relaxation of the
debt to EBITDA financial covenants following a material acquisition will not apply. Commencing with the second
quarter of 2017, the maximum Senior Debt to EBITDA covenant will return to 3.0 times (3.5 times for the two fiscal
quarters immediately following a material acquisition) and the maximum Total Debt to EBITDA covenant will return
to 3.5 times (4.0 times for the two fiscal quarters immediately following a material acquisition).
The minimum EBITDA to interest expense ratio of 3.5 times remains unchanged.
As a corollary to these revised financial covenants, the applicable margin rate will range from 0.8% to 4.75%,
depending on the type of borrowing and the Company’s Senior Debt to EBITDA ratio and the standby fee will range
from 0.405% to 1.06875% on the undrawn portion of the credit facilities, depending on the Company’s Senior Debt
to EBITDA ratio.
In the event that the Company is not able to comply with these covenants, as amended, the banking syndicate may
not be willing to agree to a further amendment to the financial covenants and as a result the Company's access to
capital could be restricted or repayment could be required.
As at December 31, 2014, the Company had outstanding letters of credit totaling $0.7 million that reduce the amount
otherwise available to be drawn on the syndicated facility.
As at December 31, 2014, the Company had approximately $174.5 million or 24% of unused and available bank
credit under its credit facilities.
24
10. CONVERTIBLE DEBENTURES
On September 4, 2013, the Company issued a notice of redemption to holders of its then outstanding $55.0 million
convertible debentures, with the redemption date set as October 21, 2013. During September and October 2013,
the $55.0 million principal amount of convertible debentures was converted or redeemed for an aggregate of
9,794,848 common shares of the Company.
11. 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, 2014 totaled $15.3 million (2013: $15.3 million) with accumulated
depreciation of $2.3 million (2013: $1.5 million).
The following is a schedule of future minimum lease payments under the finance lease obligations:
Year ending December 31,
($000s)
2015
$
2016
3,244
3,059
2017
2,719
2018
2,138
2019
1,317
Thereafter
10,016
Total lease payments
22,493
Amount representing implicit interest at 15.28%
(10,856)
11,637
Current portion of finance lease obligation at December 31, 2014
(1,574)
Finance lease obligation at December 31, 2014
$
10,063
12. 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. At December 31, 2014, the Company estimated the
total undiscounted amount of cash flows required to settle its decommissioning liabilities to be approximately $147.9
million (2013: $122.7 million) which will be incurred between 2018 and 2065. A risk-free rate between 1.04% and
2.33% (2013: 1.13% and 3.24%) and an inflation rate of 2.0% (2013: 2.0%) were used to calculate the fair value of
the decommissioning liabilities as at December 31, 2014.
($000s)
Balance, beginning of year
2014
2013
$ 67,075
$ 43,909
Incurred on development activities
4,395
3,423
Acquired through business combinations
3,113
12,071
12,374
7,436
Revisions on estimates
Reversed on dispositions
(91)
Accretion expense
Balance, end of year
25
(619)
1,739
855
$ 88,605
$ 67,075
The $12.4 million increase as a result of changes in estimates was primarily due to reduced market interest rates
which resulted in decreases to discount rates applied to the valuation of liabilities between December 31, 2014 and
December 31, 2013, as well as revisions to timing estimates of future decommissioning cash flows made to better
reflect anticipated abandonment timelines.
13. SHAREHOLDER’S 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; no dividends
were declared by the Board of Directors during the years ended December 31, 2014 or 2013.
2014
Number
170,990,605
18,170,000
Common shares, opening balance
Issued for cash on equity issue
Share issue costs on equity issue and shelf
prospectus, net of tax effect of $2.0 million
(2013: $2.3 million)
Issued for Angle acquisition
Share issue costs on the Angle acquisition, net
of tax effect of $0.2 million
2013
Amount
($000s)
$ 824,065
172,615
(5,887)
-
Amount
($000s)
$
371,576
175,000
30,230,998
(7,020)
225,221
-
-
(576)
-
-
-
2,927,457
6,931
9,794,848
1,220,985
55,568
3,088
191,950,576
2,317
$ 1,000,041
170,990,605
-
Cancellation of shares
Issued on settlement of convertible
debentures
Shares issued for cash on exercise of options
Contributed surplus transferred on
exercised options
Balance, end of year
Number
107,868,774
21,875,000
(137,486)
$
1,208
824,065
On June 5, 2014, Bellatrix closed a bought deal financing of 18,170,000 common shares at a price of $9.50 per
common share for aggregate gross proceeds of $172.6 million (net proceeds of $165.5 million after transaction
costs).
14. SHARE-BASED COMPENSATION PLANS
The following table provides a summary of the Company’s share-based compensation plans for the year ended
December 31, 2014:
($000s)
Share
Options
Expense (recovery) for the year
ended December 31, 2014
Deferred
Restricted
Share Units
(2)
Awards
Performance
Awards
Total
$ 4,333
$ (1,287)
$
353
$
274
$
3,673
$
$
$
607
$ 1,051
$
4,416
(1)
Liability balance, December 31, 2014
-
2,758
(1)
The expense for share options is net of adjustments for forfeitures of $0.6 million, and capitalization of $2.6 million. The
expense for restricted awards is net of adjustments for forfeitures of $0.3 million and capitalization of $0.5 million. The expense
for performance awards is net of adjustments for forfeitures of $0.2 million and capitalization of $0.3 million.
(2)
During 2014, the Company settled $1.3 million of restricted awards which resulted in a decrease to the outstanding liability
balance related to restricted awards as at December 31, 2014.
26
The following table provides a summary of the Company’s share-based compensation plans for the year ended
December 31, 2013:
($000s)
Expense for the year ended December
31, 2013
Share
Deferred
Restricted
Performance
Options
Share Units
$
Awards
Awards
1,699
$
2,317
$
658
$
286
$ 4,960
Total
-
$
4,045
$
983
$
445
$ 5,473
(1)
Liability balance, December 31, 2013
$
(1)
The expense for share options is net of adjustments for forfeitures of $0.2 million, and capitalization of $1.2 million. The
expense for restricted awards is net of capitalization of $0.3 million. The expense for performance awards is net of capitalization
of $0.2 million.
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 nontransferable 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, 2014, Bellatrix granted 4,077,000 (2013: 3,281,500) share options. 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,
2014 and 2013, and the weighted average assumptions used in their determination are as noted below:
2014
2013
Share price
$ 8.06
$ 7.68
Exercise price
Inputs:
$ 8.06
$ 7.68
Risk free interest rate (%)
1.2
1.3
Option life (years)
2.8
2.8
Option volatility (%)
44
46
$ 2.42
$ 2.39
Results:
Weighted average fair value of each share option granted
Bellatrix calculates volatility based on historical share price. Bellatrix incorporates an estimated forfeiture rate
between 3% and 10% (2013: 3% to 10%) for stock options that will not vest, and adjusts for actual forfeitures as
they occur.
The weighted average trading price of the Company’s common shares on the Toronto Stock Exchange (“TSX”)
for the year ended December 31, 2014 was $7.95 (2013: $6.97).
27
The following tables summarize information regarding Bellatrix’s Share Option Plan:
Share Options Continuity
Weighted Average
Exercise Price
Number
Balance, December 31, 2012
$ 3.46
9,420,451
Granted
$ 7.68
3,281,500
Exercised
$ 2.53
(1,220,985)
Forfeited
$ 5.19
(298,003)
Balance, December 31, 2013
$ 4.75
11,182,963
Granted
$ 8.06
4,077,000
Exercised
$ 2.37
(2,927,457)
Forfeited
$ 7.25
(1,419,169)
Balance, December 31, 2014
$ 6.30
10,913,337
As of December 31, 2014, a total of 19,195,058 common shares were reserved for issuance on exercise of
share options, leaving an additional 8,281,721 available for future share option grants.
Share Options Outstanding, December 31, 2014
Outstanding
Exercisable
Weighted
Average
Exercise Price
$ 3.12 - $ 3.81
$ 3.82 - $ 4.03
$ 4.04 - $ 5.22
$ 5.23 - $ 7.24
$ 7.25 - $ 8.42
$ 8.43 - $ 9.24
$ 9.25 - $10.04
$ 1.07 - $10.04
At
December 31, 2014
1,528,669
1,289,667
1,244.501
1,860,000
2,352,000
2,400,500
238,000
10,913,337
Exercise Price
$ 3.36
$ 3.89
$ 4.21
$ 5.68
$ 7.83
$ 9.22
$ 9.50
$ 6.30
Weighted
Average
Remaining
Contractual Life
(years)
2.3
0.6
4.0
1.9
4.0
4.4
4.5
3.1
At
December 31, 2014
1,029,672
1,222,999
322,333
1,588,654
733,628
4,897,286
Exercise
Price
$ 3.38
$ 3.89
$ 4.63
$ 5.47
$ 7.85
$ 4.93
Share Options Outstanding, December 31, 2013
Outstanding
Exercise Price
$ 0.65 - $ 3.81
$ 3.82 - $ 4.03
$ 4.04 - $ 5.22
$ 5.23 - $ 7.24
$ 7.25 - $ 8.00
$ 0.65 - $ 8.00
b.
At
December 31, 2013
3,910,393
1,718,001
453,567
2,406,502
2,694,500
11,182,963
Exercisable
Weighted
Average
Exercise Price
$ 2.47
$ 3.89
$ 4.57
$ 5.67
$ 7.83
$ 4.75
Weighted
Average
Remaining
Contractual Life
1.8
1.5
2.8
3.0
5.0
2.8
At
December 31, 2013
2,687,717
1,584,667
240,896
1,216,151
5,729,431
Exercise Price
$ 2.07
$ 3.88
$ 4.64
$ 5.34
$ 3.37
Deferred Share Unit Plan
Under Bellatrix’s DSU Plan, 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 DSU 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
st
redemption of the DSUs. The DSUs vest immediately and must be redeemed by December 1 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
28
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 30, 2014, the Company granted 120,612 (2013: 124,382) DSUs, and had
653,518 DSUs outstanding as at December 31, 2014 (2013: 532,906). A total of $2.8 million (December 31,
2013: $4.0 million) was included in accounts payable and accrued liabilities as at December 31, 2014 in relation
to the DSUs.
c.
Incentive Plan
Bellatrix has approved an Incentive Plan where the Company may grant Restricted Awards (“RAs”) and
Performance Awards (“PAs”) to officers, employees, and other service providers. Unless approved by the TSX
(or such other stock exchange on which the common shares may be listed) and the shareholders, the Incentive
Plan does not provide for the issuance of common shares to holders of PAs or RAs, but rather RAs and PAs
are settled in cash in lieu of such common shares.
RAs granted to employees vest in equal annual amounts over the course of three years. Each RA entitles its
holder to receive a cash payment equal to the weighted average trading price of the Company’s shares trading
on the TSX for the five trading days preceding its vesting date. Unvested RAs are forfeited at the time the
holder’s employment with the Company ends, except on death in which case they vest immediately. Bellatrix
incorporates an estimated forfeiture rate between 3% and 10% for RAs that will not vest, and adjusts for actual
forfeitures as they occur. Outstanding RAs are revalued at each financial reporting date to their fair market
value at that time, determined by the weighted average trading price of the Company’s shares on the TSX for
the five trading days preceding period end. The revaluation is captured as part of share-based compensation
expense included in the Company’s Statements of Comprehensive Income. The fair value of the outstanding
RAs is recognized as a liability included as part of accounts payable on the Company’s Balance Sheet.
During the year ended December 31, 2014, the Company granted 572,850 (2013: 508,300) RAs, settled
169,932 (2013: nil) RAs, and had 767,051 RAs outstanding as at December 31, 2014 (2013: 508,300). A total
of 146,367 RAs were forfeited during 2014 (2013: nil). A total of $0.6 million (December 31, 2013: $1.0 million)
was included in accounts payable and accrued liabilities as at December 31, 2014 in relation to the RAs.
PAs vest on the third anniversary date of their issuance. Each PA entitles its holder to receive a cash payment
equal to the weighted average trading price of the Company’s shares trading on the TSX for the five trading
days preceding its vesting date, multiplied by a payout multiplier determined by the Company’s Board of
Directors based on determined corporate performance measures. Unvested PAs are forfeited at the time the
holder’s employment with the Company ends. Bellatrix incorporates an estimated forfeiture rate of 5% for PAs
that will not vest, and adjusts for actual forfeitures as they occur. Outstanding PAs are revalued at each
financial reporting date to their fair market value at that time, determined by the weighted average trading price
of the Company’s shares on the TSX for the five trading days preceding period end.
The revaluation is
captured as part of share-based compensation expense included in the Company’s Statements of
Comprehensive Income. The fair value of the outstanding PAs is recognized as a liability included in accounts
payable on the Company’s Balance Sheet.
During the year ended December 31, 2014, the Company granted 411,150 (2013: 470,700) PAs, and had
751,450 PAs outstanding as at December 31, 2014 (2013: 470,700). A total of 130,400 PAs were forfeited
during 2014 (2013: nil).
$1.1 million (2013: $0.4 million) was included in accounts payable and accrued
liabilities as at December 31, 2014 in relation to the PAs.
29
15. SUPPLEMENTAL CASH FLOW INFORMATION
Change in Non-cash Working Capital
2014
($000s)
Changes in non-cash working capital items:
Restricted cash
Accounts receivable
Deposits and prepaid expenses
Accounts payable and accrued liabilities
Advances from joint venture partners
Deferred lease inducements
$
$
Changes related to:
Operating activities
Financing activities
Investing activities
$
$
12,644
(29,812)
3,075
17,686
(22,992)
(19,399)
25,818
149
(45,366)
(19,399)
2013
$
$
$
$
(38,148)
(14,333)
(2,339)
49,451
92,832
285
87,748
(8,600)
(960)
97,308
87,748
16. 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, 2014, Bellatrix had
approximately $1.64 billion in tax pools available for deduction against future income. Included in this tax basis are
estimated non-capital loss carry forwards of approximately $162.3 million that expire in years through 2030.
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% (2013: 25.0%) to loss before taxes. This difference results from the
following items:
2014
($000s)
Expected income tax expense
$
Share based compensation expense
54,966
2013
$
1,182
Angle acquisition
446
-
Other
(3,923)
365
Deferred tax expense
$
30
56,513
22,789
171
$
19,483
st
The components of the net deferred tax asset at December 31 are as follows:
2014
($000s)
2013
Deferred tax liabilities:
Property, plant and equipment and exploration and evaluation assets
$ (153,087)
Commodity contract asset
$ (81,453)
(86)
-
Deferred tax assets:
Finance lease obligation
2,909
3,283
Commodity contract liability
-
4,319
Decommissioning liabilities
22,151
16,769
Share issue costs
3,529
3,910
Non-capital losses
40,574
23,621
Alberta non-capital losses greater than Federal non-capital losses
1,209
1,209
Other
1,130
1,394
Deferred tax liability
$
$
(81,585)
(27,034)
A continuity of the net deferred income tax asset (liability) for 2014 and 2013 is provided below:
Recognized
($000s)
Balance,
Recognized in
Recognized
in business
Balance,
Jan. 1, 2014
profit or loss
in equity
combinations
Dec. 31, 2014
Property, plant and equipment and
exploration and evaluation assets
Decommissioning liabilities
$ (81,453)
$ (71,634)
16,769
$
5,382
-
$
-
-
-
$ (153,087)
22,151
Commodity contract liability
4,233
(4,233)
-
-
-
Share issue costs
3,910
(2,343)
1,962
-
3,529
Non-capital losses
23,621
Finance lease obligation
16,953
3,283
(374)
-
-
40,574
-
-
2,909
-
-
1,209
Alberta non-capital losses greater
than Federal non-capital losses
Other
1,209
-
1,394
(264)
$ (27,034)
$
31
(56,513)
$
1,962
$
-
1,130
$ (81,585)
Recognized
($000s)
Balance,
Recognized in
Recognized
in business
Balance,
Jan. 1, 2013
profit or loss
in equity
combinations
Dec. 31, 2013
Property, plant and equipment and
exploration and evaluation assets
$ (17,737)
Decommissioning liabilities
$ (32,962)
10,977
Commodity contract liability
(43)
Share issue costs
834
Non-capital losses
2,500
$
-
$ (30,754)
$ (81,453)
2,838
-
2,954
16,769
3,961
-
315
4,233
(340)
2,532
884
3,910
6,196
-
14,925
23,621
244
555
-
-
Equity component of 4.75%
debentures
(799)
Finance lease obligation
3,639
(356)
-
-
3,283
1,209
(1,209)
-
-
-
-
1,209
-
-
1,209
458
936
-
-
1,394
Attributed Canadian Royalty
Income
Alberta non-capital losses greater
than Federal non-capital losses
Other
$
1,038
$
(19,483)
$
3,087
$
(11,676)
$ (27,034)
17. FINANCE INCOME AND EXPENSES
2014
($000s)
2013
Finance expense
Interest on long-term debt
$ 19,198
$
9,238
Interest on convertible debentures
-
1,954
Accretion on convertible debentures
-
1,296
1,739
855
Accretion on decommissioning liabilities
Non-cash finance expense
Finance expense
1,739
2,151
$ 20,937
$ 13,343
18. 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 for the years ended December 31, 2014 and 2013 are detailed in
the following table:
2014
($000s)
Production
General and administrative
(1)
Employee compensation
(1)
Amount shown is net of capitalization
32
2013
5,728
2,107
20,619
11,606
$ 26,347
$ 13,713
19. RELATED PARTY TRANSACTIONS
Key Management Compensation
Key management includes officers and directors (executive and non-executive) of the Company. The
compensation paid or payable to key management for employee services is shown below:
2014
($000s)
Salaries and other short-term employee benefits
$
Long-term incentive compensation
Share-based compensation
(1)
$
(3)
2013
5,632
(2)
$ 6,190
153
172
3,159
2,816
8,944
$ 9,178
(1)
Share-based compensation includes share options, RAs, PAs, and DSUs.
(2)
In 2013, the Company’s key management was comprised of 10 officers (including one executive director), and 8 non-
executive directors.
(3)
In 2014, the Company reorganized its senior management structure such that its key management was comprised of 6
officers (including one executive director), and 9 non-executive directors.
20. PER SHARE AMOUNTS
The calculation of basic earnings per share for the year ended December 31, 2014 was based on a net profit of
$163.1 million (2013: $71.7 million).
Basic common shares outstanding
2014
2013
191,950,576
170,990,605
10,913,337
11,182,963
Fully dilutive effect of:
Share options outstanding
Fully diluted common shares outstanding
Weighted average shares outstanding
Dilutive effect of share options
182,173,568
112,927,251
(1)
Diluted weighted average shares outstanding
(1)
202,863,913
183,216,536
1,731,286
2,841,185
184,947,822
115,768,436
For the year ended December 31, 2014, a total of 9,182,051 (2013: 8,341,778) share options were excluded from the
calculation as they were anti-dilutive.
21. 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, 2014 is as follows:
($000s)
Year
Gross Amount
Recoveries
Net amount
(850)
2016
6,238
6,195
(904)
5,388
5,291
2017
6,185
(904)
5,281
2018
2019
More than 5 years
5,884
(828)
-
5,056
2015
4,983
20,413
4,983
20,413
As at December 31, 2014, Bellatrix committed to drill 10 gross (4.4 net) wells pursuant to farm-in agreements.
Bellatrix expects to satisfy these drilling commitments at an estimated net cost of approximately $16.7 million.
33
In addition, Bellatrix entered into two joint operating agreements during the 2011 year and an additional joint
operation 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 Operating Agreement
Feb. 1, 2011
Aug. 4, 2011
Dec. 14, 2012
Commitment Term
2011 to 2015
2011 to 2016
2014 to 2018
3
5 to 10
2
15
40
10
$ 56.3
$ 150.0
$ 37.5
3
1
1
$ 11.3
$ 3.8
$ 3.8
Minimum wells per year (gross and net)
Minimum total wells (gross and net)
Estimated total cost ($millions)
Remaining wells to drill at December 31, 2014
Remaining estimated total cost ($millions)
Bellatrix also has certain drilling commitments relating to the Grafton Joint Venture, the Daewoo and Devonian
Partnership, and the Troika Joint Venture. In meeting the drilling commitments under these agreements, Bellatrix
will satisfy some of the drilling commitments under the joint operating agreements described above.
During September 2014, the CNOR Joint Venture was formed with CNOR a non-operated oil and gas company
managed by Grafton Asset Management Inc.. Through the joint venture, CNOR has committed $250 million in
capital towards future accelerated development of a portion of Bellatrix's undeveloped land holdings. Bellatrix is not
currently subject to any formal well or cost commitments in relation to the CNOR Joint Venture.
Daewoo and
(2)
Devonian
2013 to 2015
2013 to 2016
2013 to 2015
85
70
63
16.9
30.4
31.5
$ 305.0
$ 200.0
$ 240.0
$ 55.0
$ 100.0
$ 120.0
Remaining wells to drill at December 31, 2014 (gross)
38
23
7
Remaining wells to drill at December 31, 2014 (net)
7.7
11.7
3.5
$ 156.2
$ 94.9
$ 28.7
$ 31.3
$ 47.4
$ 14.4
Agreement
Grafton
Commitment Term
Minimum total wells (gross)
Minimum total wells (net)
(1)
(1)
Estimated total cost ($millions) (gross)
Estimated total cost ($millions) (net)
(1)
(1)
Remaining estimated total cost ($millions) (gross)
Remaining estimated total cost ($millions) (net)
(1)
(1)
Troika
(3)
(1)
Gross and net estimated total cost values and gross and net minimum estimated total wells for the Troika and Grafton Joint
Ventures represent Bellatrix’s total capital and well commitments pursuant to the Troika and Grafton joint venture agreements.
Gross and net minimum total wells for the Daewoo and Devonian Partnership represent Bellatrix’s total well commitments
pursuant to the Daewoo and Devonian Partnership agreement. Gross and net estimated total cost values for the Daewoo and
Devonian Partnership represent Bellatrix’s estimated cost associated with its well commitments under the Daewoo and
Devonian Partnership agreement. Remaining estimated total cost (gross) for the Daewoo and Devonian Partnership is based
on initial Daewoo Devonian Partnership gross capital divided by initial total gross capital including third parties.
(2)
During April 2014, Grafton elected to exercise an option to increase committed capital investment to the Grafton Joint Venture
established during 2013 by an additional $50 million, for a total commitment of $250 million, on the same terms and conditions
as the previously announced Grafton Joint Venture. Specific well commitments associated with the increase have been
incorporated into the commitments table.
(3)
The commitment term of the Troika Joint Venture has been extended to 2015 for the 7 gross (3.5 net) wells remaining to be
drilled.
34
22. FINANCIAL RISK MANAGEMENT
a.
Overview
The Company has exposure to the following risks from its use of financial instruments:
-
Credit risk
-
Liquidity risk
-
Market risk
This note presents information about the Company’s exposure to each of the above risks, the Company’s objectives,
policies and processes for measuring and managing risk, and the Company’s management of capital. Further
quantitative disclosures are included throughout these financial statements.
The Board of Directors has overall responsibility for the establishment and oversight of the Company’s risk
management framework. The Board has implemented and monitors compliance with risk management policies.
The Company’s risk management policies are established to identify and analyze the risks faced by the Company,
to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the
Company’s activities.
b.
Credit Risk
As at December 31, 2014, accounts receivable was comprised of the following:
Not past due
Aging ($000s)
Joint venture and other trade accounts receivable
Amounts due from government agencies
Revenue and other accruals
(less than 90
Past due (90
days)
days or more)
Total
49,640
9,106
58,746
877
807
1,684
46,129
3,895
50,024
-
Less: Allowance for doubtful accounts
Total accounts receivable
96,646
(336)
13,472
(336)
110,118
Amounts due from government agencies include GST and royalty adjustments. Accounts payable due to same
partners includes amounts which may be available for offset against certain receivables.
In order to determine the allowance for doubtful accounts, the Company conducts a qualitative analysis of each
account comprising the individual balances within its accounts receivable, including the counterparty’s identity,
customary pay practices, and the terms of the contract under which the obligation arose. Based on the review of the
individual balances within the accounts receivable balance at December 31, 2014 and specifically the balances
greater than 90 days, a provision of $0.3 million was made.
The carrying amount of accounts receivable and derivative assets represents the maximum credit exposure.
c.
Liquidity Risk
Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. The
Company’s approach to managing liquidity is to make reasonable efforts to sustain sufficient liquidity to meet its
liabilities when they become due, under both normal and stressed conditions, without incurring unacceptable losses
or risking harm to the Company’s reputation.
The Company prepares annual capital expenditure budgets which are regularly monitored and updated as
necessary. Further, the Company utilizes authorizations for expenditures on both operated and non-operated
projects to further manage capital expenditures. To facilitate the capital expenditure program, the Company has a
revolving reserve-based credit facility, as outlined in note 9, which is reviewed semi-annually by the lender. The
Company attempts to match its payment cycle with the collection of petroleum and natural gas revenues on the 25
35
th
of each month. The Company also mitigates liquidity risk by maintaining an insurance program to minimize exposure
to insurable losses.
The following are the contractual maturities of liabilities as at December 31, 2014:
More than
Liabilities ($000s)
Accounts payable and accrued liabilities
(1)
Advances from joint venture partners
Long-term debt – principal
(2)
Decommissioning liabilities
(3)
Finance lease obligation
Deferred lease inducements
Total
Total
< 1 Year
1-3 Years
3-5 Years
$
$ 154,094
$ 154,094
$
76,388
76,388
-
-
-
549,792
-
549,792
-
-
88,605
-
776
3,653
84,176
11,637
1,574
3,172
1,645
5,246
3,067
340
680
680
1,367
$ 883,583
$ 232,396
$ 554,420
$ 5,978
$ 90,789
-
-
5 years
$
-
(1)
Includes $0.8 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 three year facility, fully revolving until maturity, and extendable annually at the Company’s option
(subject to lender approval), provided that the term after any extension would not be more than three years. Interest due on
the bank credit facility is calculated based upon floating rates.
(3)
Amounts represent the inflated, discounted future abandonment and reclamation expenditures anticipated to be incurred over
the life of the Company’s properties (between 2018 and 2065).
d.
Market Risk
Market risk is the risk that changes in market prices, such as foreign exchange rates, commodity prices, and interest
rates will affect the Company’s net profit or the value of financial instruments. The objective of market risk
management is to manage and control market risk exposures within acceptable limits, while maximizing returns.
e.
Foreign Currency Exchange Rate Risk
Foreign currency exchange rate risk is the risk that the fair value of future cash flows will fluctuate as a result of
changes in foreign exchange rates. Although substantially all of the Company’s petroleum and natural gas sales are
denominated in Canadian dollars, the underlying market prices in Canada for petroleum and natural gas are
impacted by changes in the exchange rate between the Canadian and United States dollar. As at December 31,
2014, if the Canadian/US dollar exchange rate had decreased by US$0.01 with all other variables held constant,
after tax net profit for the year ended December 31, 2014 would have been approximately $1.2 million higher. An
equal and opposite impact would have occurred to net profit had the Canadian/US dollar exchange rate increased
by US$0.01.
The Company had no forward exchange rate contracts in place as at or during the year ended December 31, 2014.
f.
Commodity Price Risk
Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of changes in
commodity prices. Commodity prices for petroleum and natural gas are impacted by not only the relationship
between the Canadian and United States dollar, as outlined above, but also world economic events that dictate the
levels of supply and demand.
The Company utilizes both financial derivatives and physical delivery sales contracts to manage commodity price
risks. All such transactions are conducted in accordance with the commodity price risk management policy that has
been approved by the Board of Directors.
The Company’s formal commodity price risk management policy permits management to use specified price risk
management strategies including fixed price contracts, costless collars and the purchase of floor price options, other
derivative financial instruments, and physical delivery sales contracts to reduce the impact of price volatility and
36
ensure minimum prices for a maximum of eighteen months beyond the current 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 cash flows from operating activities, as well as, to ensure Bellatrix realizes positive
economic returns from its capital developments and acquisition activities.
As at December 31, 2014, the Company had no commodity price risk management in place.
Subsequent to December 31, 2014, the Company has entered into commodity price risk management arrangements
as follows:
Type
Period
Volume
Price Floor
Price Ceiling
Index
Oil fixed
February 1, 2015 to Dec. 31, 2015
2,000 bbl/d
$
70.27 CDN
$
70.27 CDN
WTI
Oil fixed
February 1, 2015 to Dec. 31, 2015
1,000 bbl/d
$
70.48 CDN
$
70.48 CDN
WTI
Natural gas fixed
April 1, 2015 to October 31, 2015
20,000 GJ/d
$
2.50 CDN
$
2.50 CDN
AECO
Natural gas fixed
April 1, 2015 to October 31, 2015
20,000 GJ/d
$
2.50 CDN
$
2.50 CDN
AECO
Natural gas fixed
April 1, 2015 to October 31, 2015
2,500 GJ/d
$
2.53 CDN
$
2.53 CDN
AECO
Natural gas fixed
April 1, 2015 to October 31, 2015
15,000 GJ/d
$
2.50 CDN
$
2.50 CDN
AECO
Natural gas fixed
April 1, 2015 to October 31, 2015
5,000 GJ/d
$
2.80 CDN
$
2.80 CDN
AECO
Natural gas fixed
April 1, 2015 to October 31, 2015
20,000 GJ/d
$
2.53 CDN
$
2.53 CDN
AECO
Natural gas fixed
April 1, 2015 to October 31, 2015
10,000 GJ/d
$
2.54 CDN
$
2.54 CDN
AECO
Natural gas fixed
April 1, 2015 to October 31, 2015
10,000 GJ/d
$
2.59 CDN
$
2.59 CDN
AECO
Natural gas fixed
April 1, 2015 to October 31, 2015
10,000 GJ/d
$
2.59 CDN
$
2.59 CDN
AECO
Natural gas fixed
April 1, 2015 to October 31, 2015
10,000 GJ/d
$
2.58 CDN
$
2.58 CDN
AECO
Natural gas fixed
March 1, 2015 to December 31, 2015
20,000 GJ/d
$
2.56 CDN
$
2.56 CDN
AECO
Natural gas fixed
March 1, 2015 to December 31, 2015
20,000 GJ/d
$
2.58 CDN
$
2.58 CDN
AECO
Natural gas fixed
March 1, 2015 to December 31, 2015
17,500 GJ/d
$
2.56 CDN
$
2.56 CDN
AECO
Natural gas fixed
March 1, 2015 to March 31, 2015
25,000 GJ/d
$
2.83 CDN
$
2.83 CDN
AECO
Natural gas fixed
March 1, 2015 to March 31, 2015
25,000 GJ/d
$
2.81 CDN
$
2.81 CDN
AECO
Natural gas fixed
March 1, 2015 to March 31, 2015
25,000 GJ/d
$
2.82 CDN
$
2.82 CDN
AECO
Natural gas fixed
March 1, 2015 to March 31, 2015
25,000 GJ/d
$
2.83 CDN
$
2.83 CDN
AECO
g.
Interest Rate Risk
Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in the market interest rates.
The Company is exposed to interest rate fluctuations on its bank debt which bears a floating rate of interest. As at
December 31, 2014, if interest rates had been 1% lower with all other variables held constant, after tax net profit for
the year ended December 31, 2014 would have been approximately $4.1 million higher, due to lower interest
expense. An equal and opposite impact would have occurred to net earnings had interest rates been 1% higher.
The Company had no interest rate swap or financial contracts in place as at or during the year ended December 31,
2014.
h.
Capital Management
The Company's policy is to maintain a strong capital base so as to maintain investor, creditor and market confidence
and to sustain the future development of the business. The Company manages its capital structure and makes
adjustments to it in the light of changes in economic conditions and the risk characteristics of the underlying
petroleum and natural gas assets. The Company considers its capital structure to include shareholders’ equity, bank
debt, and working capital. In order to maintain or adjust the capital structure, the Company may from time to time
issue common shares, issue convertible debentures, adjust its capital spending, and/or dispose of certain assets to
manage current and projected debt levels.
37
The Company monitors capital based on the ratio of total net debt to annualized funds flow from operations (the
“ratio”). This ratio is calculated as total net debt, defined as outstanding bank debt, plus the liability component of
any outstanding convertible debentures, plus or minus working capital (excluding commodity contract assets and
liabilities, the current portion of finance lease obligations and deferred lease inducements, and deferred tax assets
or liabilities), divided by funds flow from operations (cash flow from operating activities before changes in non-cash
working capital and deductions for decommissioning costs) for the most recent calendar quarter, annualized
(multiplied by four). The total net debt to annualized funds flow from operations ratio may increase at certain times
as a result of acquisitions, fluctuations in commodity prices, timing of capital expenditures and other factors. In
order to facilitate the management of this ratio, the Company prepares annual capital expenditure budgets which are
reviewed and updated as necessary depending on varying factors including current and forecast prices, successful
capital deployment and general industry conditions. The annual and updated budgets are approved by the Board of
Directors. Bellatrix does not pay dividends.
As at December 31, 2014 the Company’s ratio of total net debt to annualized funds flow from operations (based on
fourth quarter funds flow from operations) was 2.6 times.
The total net debt to annualized funds flow from
operations ratio as at December 31, 2014 increased from that at December 31, 2013 of 2.5 times primarily due to an
increase in total net debt resulting from the timing and expansion of the Company’s 2014 capital expenditure
program, and business combinations completed during the third and fourth quarters of 2014.
The Company
continues to take a balanced approach to the priority use of funds flows.
The Company’s capital structure and calculation of total net debt and total net debt to funds flow ratios as defined by
the Company is as follows:
Debt to Funds Flow from Operations Ratio
Year ended December 31,
2014
2013
($000s, except where noted)
Shareholders’ equity
Long-term debt
(2)
Adjusted working capital deficiency
(2)
Total net debt at year end
1,248,317
903,874
549,792
87,934
637,726
287,092
108,390
395,482
247,028
637,726
2.6x
157,396
395,482
2.5x
270,753
637,726
2.4x
143,459
395,482
2.8x
(1) (3)
Debt to funds flow from operations ratio (annualized)
(1)
Funds flow from operations (annualized)
(2)
Total net debt at year end
(3)
Total net debt to periods funds flow from operations ratio (annualized)
(1)
Debt to funds flow from operations ratio
(1)
Funds flow from operations for the year
(2)
Total net debt at year end
(2)
(1)
Total net debt to funds flow from operations ratio for the year
(1)
Funds flow from operations is an additional GAAP term that does not have any standardized meaning under GAAP.
Funds flow from operations is calculated as cash flow from operating activities, excluding decommissioning costs incurred,
changes in non-cash working capital incurred, and transaction costs
(2)
Total net debt is considered to be an additional GAAP measure. Therefore reference to the additional GAAP measure of
total net debt may not be comparable with the calculation of similar measures for other entities. The Company’s 2014
calculation of total net debt excludes deferred lease inducements, long-term commodity contract liabilities, decommissioning
liabilities, the long-term finance lease obligation, deferred lease inducements, and the deferred tax liability. Total net debt
includes the adjusted working capital deficiency (excess). The adjusted working capital deficiency (excess) is an additional
GAAP measure calculated as net working capital deficiency (excess) excluding current finance lease obligation and deferred
lease inducements.
(3)
For the years ended December 31, 2014 and 2013, total net debt to periods funds flow from operations ratio (annualized) is
calculated based upon fourth quarter funds flow from operations annualized.
The Company’s credit facility is based on petroleum and natural gas reserves (see note 9). The credit facility
outlines limitations on percentages of forecasted production, from external reserve engineer data, which may be
hedged through financial commodity price risk management contracts.
38
i.
Fair Value of Financial Instruments
The Company’s financial instruments as at December 31, 2014 include restricted cash, accounts receivable,
deposits, commodity contract asset, accounts payable and accrued liabilities, advances from joint venture partners,
deferred lease inducements, finance lease obligations, and long-term debt. The fair value of accounts receivable,
deposits, accounts payable and accrued liabilities approximate their carrying amounts due to their short-terms to
maturity.
The Company enters into commodity contracts under master netting arrangements. Under these arrangements, the
amounts owed by each counterparty for all contracts outstanding in the same currency or commodity are
aggregated into a single net amount receivable or payable. If a default occurs, the net amount subject to a master
netting arrangement is receivable or payable for settlement purposes. The carrying amounts of commodity contracts
held under master netting arrangements are recorded on a net basis. The gross amounts netted are negligible.
The fair value of commodity contracts is determined by discounting the difference between the contracted price and
published forward price curves as at the balance sheet date, using the remaining contracted petroleum and natural
gas volumes. The fair value of commodity contracts as at December 31, 2014 was nil (December 31, 2013: $16.9
million net liability). The commodity contracts are classified as level 2 within the fair value hierarchy.
Long-term bank debt bears interest at a floating market rate and the credit and market premiums therein are
indicative of current rates; accordingly the fair market value approximates the carrying value.
($000s)
2014
Commodity contract asset
$
Commodity contract liability
Net commodity contract liability
$
-
2013
$
345
-
(17,278)
-
$ (16,933)
Long-term bank debt bears interest at a floating market rate and the credit and market premiums therein are
indicative of current rates; accordingly the fair market value approximates the carrying value.
39