2 0 1 8 A N N U A L R E P O R T
FINANCIAL AND OPERATIONAL HIGHLIGHTS
OPERATING
Average daily production
Light oil (bbls/d)
Natural gas (Mcf/d)
NGLs (bbls/d)
Total (boe/d)
Average sales price (CDN$)(1)
Light oil (per bbl)
Natural gas (per Mcf)
NGLs (per bbl)
Total (per boe)
NETBACK AND COST ($/boe)
Petroleum and natural gas revenue(1)
Royalty expense
Operating expense
Transportation and other expense
Operating netback ($/boe)
General & administrative expense, net
Interest expense
Realized gain (loss) on financial instruments
Other income
Adjusted funds flow netback ($/boe)
Other compensation expense, net
Depletion and depreciation expense
Accretion expense
Amortization of deferred financing fees
Gain (loss) on sale of assets
Unrealized gain (loss) on financial instruments
Dividends on Series C preferred shares
Income tax recovery (expense)
Net income (loss) ($/boe)
Dividends on Series A preferred shares
Net income (loss) to common shareholders ($/boe)
FINANCIAL
Petroleum and natural gas revenue ($000s)(1)
Cash flow from operating activities ($000s)
Adjusted funds flow ($000s)
Per common share – basic ($)
Per common share – diluted ($)
Net income (loss) ($000s)
Net income (loss) to common shareholders ($000s)
Per common share – basic ($)
Per common share – diluted ($)
Common shares outstanding (000s)
End of period – basic
End of period – diluted
Weighted average common shares for period – basic
Weighted average common shares for period – diluted
Dividends on common shares ($000s)
Dividends on Series A preferred shares ($000s)
Dividends on Series C preferred shares ($000s)
Total capital expenditures ($000s)(2)
Long-term debt ($000s)
Adjusted working capital deficit ($000s)
Total debt ($000s)
Three months ended
December 31,
2017
2018
Twelve months ended
December 31,
2017
2018
4,788
363,596
11,021
76,408
5,283
385,280
10,607
80,103
4,873
372,170
10,195
77,096
6,004
320,927
8,471
67,963
41.39
3.03
34.73
22.01
22.01
(0.96)
(3.51)
(4.07)
13.47
(1.08)
(1.06)
0.24
0.03
11.60
(0.78)
(7.29)
(0.12)
(0.05)
(0.26)
11.02
(0.12)
(3.77)
10.23
(0.14)
10.09
154,720
92,200
81,517
0.31
0.30
71,947
70,900
0.27
0.27
265,911
284,699
265,910
267,288
6,648
1,047
875
52,886
605,267
21,187
626,454
68.58
2.64
40.08
22.54
22.55
(1.26)
(3.86)
(3.52)
13.91
(1.28)
(0.97)
1.46
0.04
13.16
(0.13)
(7.86)
(0.08)
(0.05)
1.86
(1.86)
(0.12)
(1.42)
3.50
(0.14)
3.36
166,149
88,995
97,008
0.36
0.36
25,820
24,773
0.09
0.09
265,797
282,895
265,792
267,619
6,644
1,047
875
18,669
587,126
11,067
598,193
68.66
2.45
44.66
22.08
22.08
(1.36)
(3.52)
(3.68)
13.52
(0.87)
(0.99)
(0.56)
0.02
11.12
(0.27)
(7.42)
(0.11)
(0.05)
(0.36)
2.28
(0.12)
(1.44)
3.63
(0.15)
3.48
621,421
324,434
312,922
1.18
1.17
102,212
98,025
0.37
0.37
265,911
284,699
265,852
267,323
26,586
4,187
3,500
298,018
605,267
21,187
626,454
61.42
2.72
33.39
22.44
22.45
(1.16)
(4.45)
(2.87)
13.97
(1.07)
(1.14)
1.03
0.02
12.81
(0.16)
(7.48)
(0.12)
(0.06)
(7.50)
0.22
(0.14)
0.54
(1.89)
(0.17)
(2.06)
556,942
287,660
317,680
1.20
1.19
(46,980)
(51,027)
(0.19)
(0.19)
265,797
282,895
265,182
267,873
26,522
4,047
3,500
276,125
587,126
11,067
598,193
(1) Excludes the effects of hedges using financial instruments but includes the effects of fixed price physical delivery contracts.
(2) See “Advisories – Capital Expenditures” in this Annual Report.
TABLE OF CONTENTS
02
04
06
08
10
12
15
16
28
38
41
101
105
130
132
132
134
141
142
Overview
Message to Shareholders
Executive Team
Management Team
History
2018 Accomplishments & 2019 Key Objectives
Peace River Arch
Montney/Doig Resource Play
2018 Year-End Reserves
Responsibility
Management’s Discussion and Analysis
Financial Statements
Notes to the Financial Statements
Glossary
Non-GAAP Measures
Presentation of Oil and Gas Reserves
Advisories
Team Birchcliff
Corporate Information
This Annual Report contains forward-looking statements and information within the meaning of applicable securities laws. Such forward-looking statements and information are based upon
certain expectations and assumptions and actual results may differ materially from those expressed or implied by such forward-looking statements and information. For further information
regarding the forward-looking statements and information contained herein, see “Advisories – Forward-Looking Statements” in this Annual Report. In addition, this Annual Report contains
references to “adjusted funds flow”, “adjusted funds flow per common share”, “free funds flow”, “operating netback”, “adjusted funds flow netback”, “adjusted working capital deficit”
and “total debt”, which do not have standardized meanings prescribed by GAAP and therefore may not be comparable to similar measures presented by other companies where similar
terminology is used. For further information, see “Non-GAAP Measures” in this Annual Report and in the management’s discussion and analysis for the year ended December 31, 2018
(the “MD&A”). Boe amounts in this Annual Report have been calculated by using the conversion ratio of 6 Mcf of natural gas to 1 bbl of oil.
OVERVIEW
Birchcliff Energy Ltd. is an intermediate
oil and gas company based in Calgary,
Alberta, with operations concentrated
within one core area, the Peace River
Arch of Alberta.
Our strategy is to continue to develop and expand our large Montney/Doig Resource
Play in the Peace River Arch, while maintaining low capital costs and operating costs.
Our Montney/Doig Resource Play provides us with an extensive inventory of repeatable,
low-cost drilling opportunities targeting natural gas, oil and NGLs. Birchcliff has the
ability to grow when commodity prices warrant doing so while also having the ability to
maintain production in low commodity price environments.
At December 31, 2018, 385 (380.6 net) Montney/Doig horizontal wells have been
successfully drilled and cased on Birchcliff’s lands. The majority of Birchcliff’s natural
gas is processed through our 100% owned and operated natural gas plant located in
the Pouce Coupe area of Alberta (the “Pouce Coupe Gas Plant”). The Pouce Coupe Gas
Plant has processing capacity of 340 MMcf/d and is the cornerstone of our strategy to
develop our Montney/Doig Resource Play, to control and expand our production in the
play and to further reduce our operating costs per boe.
We continue to operate essentially all of our high working interest production, which
is surrounded by large contiguous blocks of high working interest lands where we own
control and/or have long-term access to the infrastructure. Our operatorship, land
position and infrastructure ownership gives us a competitive advantage in our areas
of operation and supports our low F&D costs and low operating cost structure, which
helps us to maximize our funds flow.
Our common shares are listed on the TSX under the symbol BIR and are included in the
S&P/TSX Composite Index. Our Series A and Series C Preferred Shares are listed for
trading on the TSX under the symbols BIR.PR.A and BIR.PR.C, respectively.
2
2018 Annual Report BY THE NUMBERS
As at December 31, 2018
89%
99%
99%
385
380.6
NET
Average working interest
in undeveloped land
Operated production
New drilling initiated and controlled
Horizontal wells drilled and cased
on the Montney/Doig Resource Play
3
2018 Annual Report MESSAGE TO SHAREHOLDERS
“ In light of current
economic conditions,
we are dedicated
to continued strict
capital discipline.“
Dear Fellow Shareholder,
In 2018, Birchcliff achieved record average annual
production of 77,096 boe/d, generated significant
adjusted funds flow, earnings, grew our reserves, and
materially reduced our operating costs. In addition,
Birchcliff paid a dividend of $0.10 per common share.
By any metric, Birchcliff had another excellent year.
However, as a result of continued weak commodity
prices, lack of pipeline access to traditional and new
sales markets, and the continued rise in business costs,
share prices of Canadian energy producers remained low
as investors left the energy space.
We grew our production to record levels in 2018 and
achieved annual average production of 77,096 boe/d,
a 13% increase from 2017. Our proved developed
producing reserves grew to approximately 204 MMboe
at December 31, 2018, a 3% increase from December 31,
2017. In the third quarter of 2018, we brought our
80 MMcf/d Phase VI expansion of our Pouce Coupe
Gas Plant on-stream which increased the processing
capacity of the plant to 340 MMcf/d from 260 MMcf/d.
Our operating costs for 2018 were 21% lower than in
2017. We continued to pay a sustainable quarterly
dividend to our common shareholders in 2018, which
we subsequently increased by 5% in February, 2019.
Due to the recent issues at AECO and the extremely
volatile prices we saw throughout the year, we actively
pursued various market diversification and hedging
opportunities in order to reduce our exposure to AECO
pricing. To diversify our natural gas sales points, we have
agreements in place for the firm service transportation
of an aggregate of 175,000 GJ/d of natural gas on
TCPL’s Canadian Mainline for a 10-year term, whereby
natural gas is transported to the Dawn trading hub
located in Southern Ontario. The first tranche of this
service (120,000 GJ/d) became available to Birchcliff
on November 1, 2017, and the second tranche became
available on November 1, 2018 (30,000 GJ/d).
4
2018 Annual Report flexibility with the potential to accelerate or decelerate
capital expenditures throughout the year, depending
on commodity prices and economic conditions. We
expect that our 2019 F&D capital expenditures will be
significantly less than our adjusted funds flow during
2019, which will help us to protect our balance sheet.
I would like to thank our Board of Directors for their
support and guidance throughout 2018. During 2018,
we had one new addition to our Board, Stacey McDonald,
who was appointed in December 2018. Stacey brings
a wealth of knowledge and experience to the Board,
especially in the area of capital markets.
I would also like to thank all of our staff for their excellent
work and for helping us to deliver these strong results
for 2018. Our staff are truly dedicated to help Birchcliff
succeed and I believe that they are our best asset.
Lastly, I would like to thank all of our shareholders for
their continued support. We continue to strive to deliver
long-term value for all of you.
With respect,
A. Jeffery Tonken
President & Chief Executive Officer
March 13, 2019
The final tranche will become available November 1, 2019
(25,000 GJ/d) bringing the total to 175,000 GJ/d. We
expect that during 2019, approximately 65% of our
natural gas will be effectively sold at prices that are not
based on AECO.
In summary, in 2018 we strengthened Birchcliff by
growing our production and reserves, maintained a
healthy balance sheet and continued to reduce our
operating costs. We are more focused, better financed
and have added more production at lower costs across
our very large contiguous land base on our Montney/Doig
Resource Play.
OUTLOOK
Based on our 2019 budget, Birchcliff expects to
generate approximately $126 MM of free funds flow
over and above the capital required to achieve production
guidance. Birchcliff’s focus will continue to be on
protecting our balance sheet, improving our already-low
cost structure and paying a sustainable quarterly
dividend to our shareholders, while we maintain a
prudent pace of development and continue to position
Birchcliff for future growth.
In light of current economic conditions, we are dedicated
to continued strict capital discipline. The 2019 capital
program contemplates the drilling of a total of 17 net wells
during 2019 and targets an annual average production
rate of 76,000 to 78,000 boe/d. This program reflects
our long-term plan to continue the exploration and
development of our low-cost natural gas, crude oil and
liquids-rich assets on the Montney/Doig Resource
Play, increase our netbacks and maintain balance sheet
strength. In particular, we will focus on the drilling
of crude oil wells in Gordondale and condensate-rich
natural gas wells in Pouce Coupe. Our capital program
has been designed with financial and operational
5
2018 Annual Report T H E S T R E N G T H O F O U R P A R T N E R S H I P
EXECUTIVE TEAM
Drawing on extensive backgrounds in the energy sector, our Executive Team brings a rich
portfolio of skills and experience to Birchcliff’s business operations.
MYLES BOSMAN
Vice-President, Exploration &
Chief Operating Officer
JEFF TONKEN
President &
Chief Executive Officer
6
2018 Annual Report Under the oversight of our Board of Directors, our Executive Team collectively drives our
day-to-day pursuit of operational excellence, while identifying and pursuing responsible growth
opportunities. Deeply invested in our success and unified by a genuine sense of camaraderie,
our Executive Team works together to provide effective leadership and strategic direction.
BRUNO GEREMIA
Vice-President &
Chief Financial Officer
CHRIS CARLSEN
Vice-President, Engineering
DAVE HUMPHREYS
Vice-President, Operations
7
2018 Annual Report O U R P E O P L E A R E O U R B E S T A S S E T
MANAGEMENT TEAM
Birchcliff’s management team is comprised of talented, high-performing individuals who are
driven to help Birchcliff succeed.
JEFF ROGERS
Facilities Manager
RANDY ROUSSON
Drilling & Completions Manager
RYAN SLOAN
Health, Safety &
Environment Manager
ROBYN BOURGEOIS
General Counsel & Corporate Secretary
BRUCE PALMER
Manager of Geology
GATES AURIGEMMA
Manager, General Accounting
VICTOR SANDHAWALIA
Manager of Finance
ANDREW FULFORD
Surface Land Manager
GEORGE FUKUSHIMA
Manager of Engineering
8
2018 Annual Report With guidance from our Executive Team, our management team is instrumental in executing
our business strategy and managing our day-to-day operations.
BRIAN RITCHIE
Asset Manager – Gordondale
THEO VAN DER WERKEN
Asset Manager – Pouce Coupe
MICHELLE RODGERSON
Manager, Human Resources
& Corporate Services
HUE TRAN
Business Development Manager
JESSE DOENZ
Controller & Investor Relations Manager
PAUL MESSER
Manager of Information Technology
TYLER MURRAY
Mineral Land Manager
DUANE THOMPSON
Production Manager
9
2018 Annual Report B U I L D I N G O N O U R P A S T
HISTORY
Birchcliff was incorporated as a private corporation on July 6, 2004. Since our inception, we
have invested approximately $4.1 billion of capital in Alberta, primarily in the Montney/Doig
Resource Play. These investments have generated $4.0 billion in revenue, paid $342 million
in royalties to Albertans and delivered $2.1 billion in adjusted funds flow.
The following describes the major events in our history:
SEPTEMBER 22, 2007
Rig released first Montney/
Doig horizontal natural gas
well drilled by Birchcliff
utilizing multi-stage fracture
stimulation technology in
the Pouce Coupe area
OCTOBER 2012
Phase III of the Pouce Coupe
Gas Plant commenced
operations with a combined
processing capacity of
150 MMcf/d
JANUARY 19, 2005
Common shares
commenced trading on
the TSX Venture Exchange
FEBRUARY 6, 2005
Rig released first Montney/
Doig vertical exploration gas
well drilled by Birchcliff in
the Pouce Coupe area
2005
MAY 31, 2005
Completed acquisition of
properties in the Peace River
Arch for $242.8 million, including
a significant undeveloped land
position on the Montney/Doig
Resource Play
JULY 21, 2005
Common shares commenced
trading on the TSX
MARCH 2010
Phase I of the Pouce Coupe Gas
Plant commenced operations
with a processing capacity of
30 MMcf/d
NOVEMBER 2010
Phase II of the Pouce Coupe Gas
Plant commenced operations
with a combined processing
capacity of 60 MMcf/d
10
2018 Annual Report At December 31, 2018, the net present value of the future net revenue attributable to our
proved plus probable reserves (at a 10% discount rate, before income taxes) is $6.1 billion
as estimated by our independent qualified reserves evaluators.
JULY 13, 2016
Closed equity financings
for total gross proceeds
of $690.8 million
JULY 28, 2016
Completed acquisition
of assets at Gordondale
for approximately
$613.5 million
APRIL 3, 2018
Announced new long-term
processing arrangement at
Altagas’ deep-cut processing
facility in Gordondale
AUGUST 2018
Phase VI of the Pouce Coupe
Gas Plant commenced
operations with a combined
processing capacity of
340 MMcf/d
2018
SEPTEMBER 2014
Phase IV of the Pouce Coupe
Gas Plant commenced
operations with a combined
processing capacity of
180 MMcf/d
MARCH 31, 2017
Paid first quarterly dividend
to common shareholders
SEPTEMBER 2017
Phase V of the Pouce Coupe
Gas Plant commenced
operations with a combined
processing capacity of
260 MMcf/d
NOVEMBER 14, 2018
Announced entering into
a definitive purchase and
sale agreement to acquire
18 gross (15.1 net) contiguous
sections of Montney land
between Pouce Coupe and
Gordondale for $39 million
(subsequently closed on
January 3, 2019)
DECEMBER 31, 2018
385 (380.6 net)
Montney/Doig horizontal
wells successfully drilled
and cased to date
11
2018 Annual Report 2018 ACCOMPLISHMENTS
Achieved record annual average
production of 77,096 boe/d
(13% growth year-over-year)
Delivered reserves growth
year-over-year
Continued to pay quarterly
dividend to common shareholders
Drilled 36 wells, consisting of
19 Montney/Doig horizontal natural gas
wells at Pouce Coupe and 17 Montney
horizontal oil wells at Gordondale,
all at 100% working interest
Continued to reduce exposure to AECO
natural gas market with a total of
150,000 GJ/d of egress to the Dawn
market beginning November 1, 2018
2019 KEY OBJECTIVES
Preserve and protect the balance sheet
spending within adjusted funds flow
Further exploration and delineation
of the Montney/Doig Resource Play
in Pouce Coupe and Gordondale
Initiate the engineering and planning of
a 20,000 bbls/d inlet liquids-handling
facility at the Pouce Coupe Gas Plant
(anticipated completion in 2020) to
increase condensate production capability
to 10,000 bbls/d at Pouce Coupe
Continued commitment to science
and technology to drive operational
excellence and further our learnings on
field development planning
Drill, case and complete a total of
17 wells consisting of 9 Montney
condensate-rich horizontal natural gas
wells at Pouce Coupe and 8 Montney
horizontal oil wells at Gordondale,
all at 100% working interest
Optionality on commodity type allows us
to focus on Gordondale oil & Pouce Coupe
condensate wells while limiting dry gas
drilling in the current commodity
environment to maximize our returns
Continue to focus on full cycle
profitability while paying a
sustainable quarterly dividend
to common shareholders
Bring on a total of 26 wells including
9 wells drilled in late 2018 with the
2019 capital acceleration
12
2018 Annual Report “ WE HAVE OUR BEST
ASSET IN PLACE,
WHICH IS OUR PEOPLE.”
- A. JEFFERY TONKEN
President & Chief Executive Officer
13
2018 Annual Report ONE CORE AREA
PEACE
RIVER
ARCH
14
2018 Annual Report PEACE RIVER ARCH
Our operations are concentrated within our one core area, the Peace River Arch, which is
centered northwest of Grande Prairie, Alberta, adjacent to the Alberta/British Columbia border.
The Peace River Arch is considered by management to be one of the most desirable natural
gas and light oil drilling areas in North America.
Peace River Arch
The Peace River Arch is one of the most prolific natural gas and light oil producing areas of the Western Canadian
Sedimentary Basin and is generally characterized by multiple horizons with a myriad of structural, stratigraphic
and hydrodynamic traps. The Peace River Arch is highlighted by the Deep Basin hydrocarbon trapping phenomena.
The Deep Basin is a hydrodynamic or permeability trap where the water in the updip position cannot travel through
the fine grained reservoirs with characteristics that include overpressured reservoirs, continuous hydrocarbon
columns, low water production and long-life reserves with low terminal declines. The Peace River Arch provides
all-season access that allows the Corporation to drill, equip and tie-in wells on an almost continuous basis. In addition,
Birchcliff has excellent control of and/or long-term access to infrastructure in the Peace River Arch, which helps us
to control our costs and expand our production when market conditions recover.
15
2018 Annual Report L O W R I S K D E V E L O P M E N T
MONTNEY/DOIG RESOURCE PLAY
We are focused on the
Montney/Doig Resource Play
within the Peace River Arch.
ESTABLISHED MONTNEY/DOIG RESOURCE PLAY
Birchcliff characterizes its Montney/Doig Resource Play
as a regionally pervasive, continuous, low-permeability
hydrocarbon accumulation or system that typically
requires intensive stimulation to produce. The production
characteristics of this play generally include steep initial
declines that rapidly trend to much lower decline rates,
yielding long-life production and reserves. The play
exhibits a statistical distribution of estimated ultimate
recoveries and therefore provides a repeatable
distribution of drilling opportunities. Birchcliff’s
Montney/Doig Resource Play is ideally suited for the
application of horizontal drilling and multi-stage fracture
stimulation technology.
As more wells are drilled into a resource play, there is a
substantial decrease in both the geological and technical
risks. Over the past 14 years, Birchcliff has worked to
de-risk its Montney/Doig Resource Play by drilling both
vertical and horizontal exploration wells in order to
develop an in-depth understanding of the oil and gas
pools, rock properties and petrophysical characteristics
and reservoir parameters. Birchcliff designs, tests and
DRILLED AND CASED
385
( 380.6 net )
MONTNEY/
DOIG
HORIZONTAL
WELLS
At December 31, 2018
16
evaluates its drilling, completion and production
technologies and practices to achieve continual improvements
in productivity and expected ultimate recoveries in order
to drive down capital and operating costs. Birchcliff’s
pool delineation strategy de-risks future development
and helps to reduce future costs as new well pads and
infrastructure are designed and built to support multiple
horizontal well locations and increased production.
Stratigraphic Column and Production Zones
0 m
500 m
1000 m
1500 m
2000 m
2500 m
3000 m
Surface
Doe Creek
Dunvegan
Paddy/Cadotte
Notikewin
Falher
Bluesky
Gething
Cadomin
Nikanassin
Nordegg
Baldonnel
Boundary Lake
Subcrop
Halfway
Doig
Montney
Kiskatinaw
Exshaw
Wabamun
Duvernay
Leduc
Beaverhill Lake/
Granite Wash
PreCambrian
Graben Complex
2018 Annual Report BIRCHCLIFF OPERATIONS IN THE PEACE RIVER ARCH
The Montney/Doig Resource Play is managed by two technical teams at Birchcliff: the Pouce Coupe Team and the
Gordondale Team. These teams each have a full complement of highly skilled technical professionals, including
engineers, geoscientists and landmen.
Birchcliff Montney/Doig Resource Play in the Peace River Arch
BC
AB
BC
AB
Pouce Coupe
Team
Gordondale
Team
Pouce Coupe
Team
Gordondale
Team
L E G E ND
Montney/Doig Deep Basin Edge
Pouce Coupe Gas Plant
Gordandale Gas Plant
L E G E ND
Montney/Doig Deep Basin Edge
Pouce Coupe Gas Plant
Gordandale Gas Plant
MONTNEY/DOIG
RESOURCE PLAY
TREND
MONTNEY/DOIG
RESOURCE PLAY
TREND
SOURCE: IHS MARKIT
DISCLAIMER: The IHS Markit reports, data and information referenced herein (the “IHS Markit Materials”) are the copyrighted property of IHS Markit Ltd. and its subsidiaries (“IHS Markit”) and represent data,
research, opinions or viewpoints published by IHS Markit, and are not representations of fact. The IHS Markit Materials speak as of the original publication date thereof and not as of the date of this document.
The information and opinions expressed in the IHS Markit Materials are subject to change without notice and IHS Markit has no duty or responsibility to update the IHS Markit Materials. Moreover, while the
IHS Markit Materials reproduced herein are from sources considered reliable, the accuracy and completeness thereof are not warranted, nor are the opinions and analyses which are based upon it. IHS Markit
is a trademark of IHS Markit. Other trademarks appearing in the IHS Markit Materials are the property of IHS Markit or their respective owners.
17
2018 Annual Report Our Montney/Doig Resource Play is centred approximately 95 km northwest of Grande Prairie,
Alberta, Canada and, in the opinion of Birchcliff, is one of the most sought after resource plays
in North America. Within the Montney/Doig Resource Play, Birchcliff is focused on two key
operating areas: Pouce Coupe and Gordondale.
There are a number of attributes that the Montney/Doig Resource Play has that contribute to it being a world class
resource play, including resource density, large areal extent, exceptional “fracability”, high fracture stability and high
permeability, as discussed in further detail on the next page.
Select Unconventional Plays in North America
Birchcliff Montney/Doig
Source: Source: Canadian Discovery, RBC Rundle
SOURCE: RBC RUNDLE
18
2018 Annual Report GEOLOGY
The Montney/Doig Resource Play in Birchcliff’s area
of operations is approximately 300 metres (1,000 feet)
thick. The play has a large areal extent covering in excess
of 50,000 square miles. The Montney/Doig is composed
of a high percentage of hard minerals and a very low
percentage of clay minerals resulting in exceptional
“fracability”. This, combined with the current stress
regime, results in the rock shattering more like glass in
a complex fracture style versus a simple bi-wing style.
The rock parameters also yield exceptional fracture
stability; the fractures stay open due to low proppant
embedment. This is a key contributing factor to the
low terminal declines and large estimated ultimate
recoveries of the play. Unlike most shale plays that are
predominantly shale, the Montney/Doig is classified
by management as a hybrid resource play because it
is comprised of hydrocarbon-saturated rock with both
tight silt and sand reservoir rock interlayered with shale
source rock. This results in relatively high permeability
and productivity rates.
Hydrodynamics is another important attribute for resource
plays. A large portion of the Montney/Doig Resource
Play is over-pressured which reduces the potential for
significant water production. The Pouce Coupe and
Gordondale areas are predominantly over-pressured
which also results in higher hydrocarbons in-place.
The Montney and a majority of the Doig were deposited
in a lower to middle shore face environment that is
regionally extensive and results in a widespread style
deposit that provides for more repeatable results.
The Montney/Doig Resource Play exists in two geological
formations (the Montney and the Doig) and Birchcliff has
divided the geologic column in its areas of operations
into six drilling intervals from the youngest (top) to the
oldest (bottom): (i) the Basal Doig/Upper Montney; (ii) the
Montney D4; (iii) the Montney D3; (iv) the Montney D2;
(v) the Montney D1; and (vi) the Montney C. We have
drilled wells in each of the Basal Doig/ Upper Montney,
the Montney D4, the Montney D2, the Montney D1 and
the Montney C intervals. To date, we have not drilled any
wells in the Montney D3 interval.
300m
Birchcliff Montney/Doig Resource Play
Full Development Plan: Hexastack
DRILLING INTERVAL
Basal Doig/Upper Montney
Mature Developed/Commercial
72 Producing Wells
Montney D4
Mature Developed/Commercial
12 Producing Wells
Montney D3
0 Producing Wells
Montney D2
Mature Developed/Commercial
22 Producing Wells
Montney D1
Mature Developed/Commercial
264 Producing Wells
Montney C
Mature Developed/Commercial
2 Producing Wells
Mature Developed/Commercial
Future Potential
BASAL DOIG
MONTNEY D5
MONTNEY D4
M O N T N E Y D 3
M O N T N E Y D 2
M O N T N E Y D 1
M O N T N E Y C
60m
3 0 0 m
1600m
1600m
As of December 31, 2018
19
2018 Annual Report OUR OPERATIONS
At December 31, 2018, Birchcliff has successfully drilled
and cased an aggregate of 385.0 (380.6 net) horizontal
wells on the Montney/Doig Resource Play. Of these
wells, an aggregate of 372 (367.6 net) wells have been
completed and brought on production (including
87 (81.8 net) wells that were acquired in connection with
the Gordondale acquisition), consisting of 72 (71.3 net) wells
in the Basal Doig/Upper Montney interval, 12 (12.0 net) wells
in the Montney D4 interval, 22 (22.0 net) wells in the
Montney D2 interval, 264 (260.3 net) wells in the
Montney D1 interval and 2 (2.0 net) wells in the Montney C
interval. To date, the Corporation has not drilled any wells
in the Montney D3 interval.
2018 DRILLING AND COMPLETIONS
Birchcliff drilled a total of 36 (36.0 net) wells during
2018. Of the 36 (36.0 net) wells, 17 (17.0 net) were
Montney horizontal oil wells drilled in the Gordondale
area and 19 (19.0 net) were Montney/Doig horizontal
natural gas wells drilled in the Pouce Coupe area. A total
of 28 (28.0 net) wells were brought on production during
2018. Our 2018 capital program included the capital
associated with the completion, equipping and tie-in
of one well drilled in 2017, which was brought on
production in the first quarter of 2018.
All wells drilled in 2018 were drilled on multi-well
pads, which allows us to reduce our per well costs and
our environmental footprint. In addition, we actively
employ the evolving technology utilized by the industry
regarding horizontal well drilling and the related
multi-stage fracture stimulation technology.
2018 ACQUISITIONS AND DISPOSITIONS
During 2018, Birchcliff completed various non-core asset
sales for total proceeds of approximately $5.0 million
and completed various minor acquisitions for total
consideration of approximately $1.5 million.
On November 14, 2018, Birchcliff announced that it had
entered into a definitive purchase and sale agreement
to acquire 18 gross (15.1 net) contiguous sections of
Montney land located between the Corporation’s
existing Pouce Coupe and Gordondale properties,
as well as various other non-Montney lands and other
assets, for total cash consideration of $39 million
20
2018 Annual Report Birchcliff Montney/Doig Multi-Layer Opportunity
Elmworth
Sinclair
Glacier
Pouce Coupe
South
Pouce Coupe
North
Gordondale
Basal Doig
Montney D5
Montney D4
Montney D3
Montney D2
Montney D1
TSE
Montney C
Hydrocarbon Pore Volume
Bulk Volume Water
(the “Acquisition”). Closing of the Acquisition occurred on January 3, 2019 and further consolidated Birchcliff’s land
position in the area. Subsequent to year-end 2018, Birchcliff commenced the drilling of a 6-well pad on these lands which
is targeting condensate-rich natural gas wells.
SIGNIFICANT FUTURE DRILLING OPPORTUNITIES
As at December 31, 2018, Birchcliff held 367.4 sections of land that have potential for the Montney/Doig Resource Play.
Of these lands, 362.4 (340.3 net) sections have potential for the Basal Doig/Upper Montney interval, 343.9 (336.2 net)
sections have potential for the Montney D1 interval, 345.4 (337.7 net) sections have potential for the Montney D2
interval, 343.9 (336.2 net) sections have potential for the Montney D4 interval and 343.9 (336.2 net) sections have
potential for the Montney C interval. As at December 31, 2018, Birchcliff’s total land holdings on these five intervals
were 1,739.5 (1,686.6 net) sections. Assuming full development of four horizontal wells per section per drilling interval,
Birchcliff has 6,746.4 net existing horizontal wells and potential net future horizontal drilling locations in respect of the
Basal Doig/Upper Montney and the Montney D1, D2, D4 and C intervals as at December 31, 2018. With 385.0 (380.6 net)
horizontal locations drilled at the end of 2018, there remains 6,365.8 potential net future horizontal drilling locations as
at December 31, 2018, up from 4,710.0 at year-end 2017. This increase is largely due to the exploration and delineation
success of the Montney C interval as such interval is now considered commercial by Birchcliff.
Birchcliff’s consolidated reserves report effective December 31, 2018 attributed proved reserves to 888.8 net existing wells
and potential net future horizontal drilling locations (of which 521.6 net wells are potential future drilling locations) and proved
plus probable reserves to 1,121.8 net existing wells and potential net future horizontal drilling locations (of which 754.3 net wells
are potential future drilling locations). The remaining 5,624.6 potential net future horizontal drilling locations have not yet
had any proved or probable reserves attributed to them by Birchcliff’s independent qualified reserves evaluators.
21
2018 Annual Report POUCE COUPE TEAM
Birchcliff’s Pouce Coupe area is located west and northwest of Grande Prairie, Alberta
and consists of Birchcliff’s properties in Pouce Coupe and Elmworth. At December 31, 2018,
Birchcliff held an aggregate of 350.9 (331.6 net) sections of land in the Pouce Coupe area.
Annual average production in 2018 for the Pouce Coupe area was 48,943 boe/d (48,734 boe/d
in Pouce Coupe and 209 boe/d in Elmworth).
Birchliff was active in the Pouce Coupe area during 2018, drilling a total of 19 (19.0 net) wells and completing Phase VI
of the Pouce Coupe Gas Plant.
Pouce Coupe Team Highlight Map
R13W6
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T80
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L E G E N D
Pouce Coupe Non-Confidential Land
Birchcliff Non-Confidential Land
Birchcliff Vertical Producers
Birchcliff Horizontal Producers
2019 Capital Program
2018 Capital Program
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SOURCE: IHS MARKIT
22
2018 Annual Report DRILLING AND DEVELOPMENT
During 2018, Birchcliff was focused on the drilling of
liquids-rich natural gas wells and the pursuit of condensate
and other NGLs in several different Montney/Doig
intervals, including the Montney D1, D2 and C.
Birchcliff drilled 19 (19.0 net) horizontal wells and
brought 15 (15.0 net) wells on production in Pouce Coupe
in 2018.
SCIENCE AND TECHNOLOGY
MULTI-WELL PAD PROGRAM
As part of Birchcliff’s commitment to continuous
performance improvement, it designed and executed on
its science and technology pad in 2018, which involved
the drilling of one vertical well and four horizontal wells
in three different intervals (one Montney C, one Montney
D2 and two Montney D1 wells). Using the pad, Birchcliff
has been able to acquire high-quality subsurface and
operational data and thus gain important insights into
reservoir behaviour, including fracture initiation and
propagation, inter-well fracture communication, well
productivity by cluster, the role of natural fractures on
production and optimal well spacing by and between
zones. Birchcliff has also been able to increase its
knowledge regarding field development, including well
landing depths, well spacing both laterally and vertically
and completion, cluster and stage spacing.
In addition, a permanent fibre optic cable installed in one
of the horizontal wells allows Birchcliff to observe how
wells interact in the subsurface over time. Ultimately,
the knowledge gained from the science and technology
pad has helped Birchcliff to improve and refine its best
practices at the well, pad and field levels in order to
optimize field development.
Birchcliff is focused on continuous improvements in all
aspects of its business. In 2019, Birchcliff will continue
to pilot innovative technologies in its completions
operations in order to achieve better well results, including
zipper fracturing, plug and perf technology as well as
fluid additives to enhance its condensate production
and recoveries. Birchcliff’s operations team is focused
on maximizing fracture pumping time through surface
manifolds, which allows for a quick change over from
well to well on multi-well pads and on utilizing new smart
coil tubing units for wellbore milling operations post
fracture treatment. Regarding drilling in 2019, Birchcliff
has modified its drill bit, drilling fluid and downhole motor
selection to reduce drill times and has trialled the use of
rotary steerable technology for smoother well trajectories.
Birchcliff continues to utilize compressed natural gas
in 2019 to displace diesel from its operations for both
drilling and completions, which has helped to reduce costs
and lessen Birchcliff’s environmental footprint. Several
of these initiatives are a result of the important insights
that Birchcliff has been able to gain from the science and
technology pad it completed in 2018.
23
2018 Annual Report POUCE COUPE GAS PLANT
Our 100% owned and operated Pouce Coupe Gas
Plant located in the Pouce Coupe area of Alberta is
strategically situated in the heart of our Montney/Doig
Resource Play, enabling us to process natural gas at
a lower cost than that borne by others who rely on
third-party processing. The Pouce Coupe Gas Plant is the
cornerstone of our strategy to develop our Montney/Doig
Resource Play, to control and expand our production
in the play and to further reduce our operating costs
on a per boe basis.
In 2010, we began executing on our “build & fill” strategy
with the construction of the Pouce Coupe Gas Plant.
During 2010, we constructed Phases I and II of our
Pouce Coupe Gas Plant with 60 MMcf/d of natural
gas processing capacity. Processing capacity at the
Pouce Coupe Gas Plant was subsequently increased
to 150 MMcf/d (Phase III) in 2012, to 180 MMcf/d
(Phase IV) in 2014, to 260 MMcf/d (Phase V) in 2017
and to 340 MMcf/d (Phase VI) in 2018.
In Q4 2018, Birchcliff completed the re-configuration of
Phases V and VI to provide for shallow-cut capability. This
shallow-cut capability allows Birchcliff to extract propane
plus (C3+) from the natural gas stream, further enhancing
Birchcliff’s ability to maximize its liquids production.
During 2019, due to increased condensate volumes from
Pouce Coupe, Birchcliff has committed to the construction
of a 20,000 bbls/d (10,000 bbls/d condensate and
10,000 bbls/d water) inlet liquids-handling facility at its
Pouce Coupe Gas Plant. This facility is anticipated to be
online in Q3 2020 and will give Birchcliff the ability to grow
its condensate production from 3,000 to 10,000 bbls/d in
Pouce Coupe. Birchcliff plans on spending approximately
$9.5 million on the associated engineering and long-lead
equipment for this facility in 2019.
THE POUCE
COUPE GAS
PLANT IS
100%
OWNED AND OPERATED
enabling us to process natural gas at a lower cost than
that borne by others who rely on third-party processing
24
2018 Annual Report 2019 OUTLOOK
Birchcliff plans to invest approximately $100 million in Pouce Coupe during 2019. Key focus areas for Pouce Coupe
in 2019 will be the drilling of Montney/Doig condensate-rich horizontal natural gas wells and the further exploitation
and delineation of condensate-rich trends in the Montney D1, D2 and C intervals.
DRILLING AND DEVELOPMENT
Birchcliff plans to drill 9 (9.0 net) condensate-rich horizontal natural gas wells, consisting of 6 (6.0 net) Montney D1
wells, 2 (2.0 net) Montney D2 wells and 1 (1.0 net) Montney C well, all of which will be drilled on multi-well pads. This
includes a 6 well pad on the lands that Birchcliff recently acquired pursuant to the Acquisition. Birchcliff believes that the
acquired lands are located on a significant condensate-rich trend and are highly prospective in the Montney D1, D2,
C and Basal Doig/Upper Montney intervals. The lands are strategically located near Birchcliff’s science and technology
pad in Pouce Coupe where Birchcliff drilled four successful horizontal wells in 2018 (two in the Montney D1, one in
the Montney D2 and one in the Montney C intervals).
FACILITIES AND INFRASTRUCTURE
Birchcliff plans to invest in facilities and other strategic infrastructure during 2019, including approximately $9.5 million
directed towards associated engineering and long-lead equipment for the 20,000 bbls/d inlet liquids-handling facility
at the Pouce Coupe Gas Plant. This facility is anticipated to be online in the third quarter of 2020 and will give the
Corporation the ability to grow its condensate production in Pouce Coupe to 10,000 bbls/d.
25
2018 Annual Report GORDONDALE TEAM
Birchcliff’s Gordondale area is located northwest of Grande Prairie, Alberta and consists solely
of Birchcliff’s properties in Gordondale. At December 31, 2018, Birchcliff held an aggregate
of 139.0 (88.4 net) sections of land in the Gordondale area. Annual average production in
2018 for the Gordondale area was 28,028 boe/d.
During 2018, Birchcliff was focused on the drilling of Montney horizontal oil wells and the delineation of the Montney
D1 and D2 intervals in the Gordondale area. Birchcliff drilled 17 (17.0 net) horizontal wells and brought 13 (13.0 net)
wells on production in Gordondale in 2018.
Since Birchcliff acquired its assets in Gordondale in 2016, it has drilled 40 (40.0 net) wells in the area, consisting
of 22 (22.0 net) Montney D2 horizontal oil wells, 13 (13.0 net) Montney D1 horizontal oil wells, 4 (4.0 net) Montney D1
liquids-rich horizontal natural gas wells and 1 (1.0 net) water disposal well. When Birchcliff first acquired its assets in
Gordondale, the average production for such assets was approximately 22,000 boe/d at the date of the acquisition. The
horizontal wells that Birchcliff has subsequently drilled and brought on production have replaced the natural production
declines and significantly increased the production on its Gordondale assets. The Montney D2 horizontal wells that
Birchcliff has drilled, completed and brought on production to-date have significantly delineated, de-risked and proven
the commerciality of the Montney D2 play.
2019 OUTLOOK
Birchcliff plans to invest approximately $84 million in Gordondale during 2019. Key focus areas for Gordondale in 2019
will be the drilling of Montney horizontal oil wells and the further exploitation and delineation of oil in the Montney D1
and D2 intervals, specifically in the southeastern part of the Gordondale field.
DRILLING AND DEVELOPMENT
In 2019, Birchcliff plans to drill 8 (8.0 net) horizontal oil wells, consisting of 5 (5.0 net) Montney D2 wells and 3 (3.0 net)
Montney D1 wells, all of which will be drilled on multi-well pads.
26
2018 Annual Report Gordondale Team Highlight Map
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SOURCE: IHS MARKIT
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G
K
K
F
E
E
E
LL
G
G
LL
A
CC
F
F
F
CC
F
F
CC
F
F
CC
F
F
F
F
F
C
F
L
GG
F
F
C
G
L E G E N D
Gordondale Non-Confidential Land
Birchcliff Non-Confidential Land
Birchcliff Vertical Producers
Birchcliff Horizontal Producers
2019 Capital Program
2018 Capital Program
27
2018 Annual Report C O N T I N U E D R E S E R V E S G R O W T H
2018 YEAR-END RESERVES
Birchcliff retained two independent qualified reserves evaluators, Deloitte LLP (“Deloitte”) and McDaniel & Associates
Consultants Ltd. (“McDaniel”), to evaluate and prepare reports on 100% of Birchcliff’s light crude oil and medium crude oil
(combined), conventional natural gas, shale gas and NGLs reserves. Deloitte evaluated all of Birchcliff’s properties other than
the Corporation’s assets in Gordondale, representing approximately 78% of the assigned total proved plus probable reserves,
and McDaniel evaluated the reserves attributable to the Corporation’s assets in Gordondale, representing approximately
22% of the assigned total proved plus probable reserves.
The reserves data set forth below at December 31, 2018 is based upon the evaluation by Deloitte with an effective date
of December 31, 2018 as contained in the report of Deloitte dated February 13, 2019 (the “2018 Deloitte Reserves Report”)
and the evaluation by McDaniel with an effective date of December 31, 2018 as contained in the report of McDaniel dated
February 13, 2019 (the “2018 McDaniel Reserves Report”), which are contained in the consolidated report of Deloitte dated
February 13, 2019 with an effective date of December 31, 2018 (the “2018 Consolidated Reserves Report”). Deloitte prepared
the 2018 Consolidated Reserves Report by consolidating the properties evaluated by Deloitte in the 2018 Deloitte Reserves
Report with the properties evaluated by McDaniel in the 2018 McDaniel Reserves Report, in each case using Deloitte’s forecast
price and cost assumptions effective December 31, 2018 (the “2018 Deloitte Price Forecast”).
Deloitte also prepared an evaluation with an effective date of December 31, 2017 as contained in the report of Deloitte dated
February 9, 2018 (the “2017 Deloitte Reserves Report”) and McDaniel prepared an evaluation with an effective date of
December 31, 2017 as contained in the report of McDaniel dated February 14, 2018 (the “2017 McDaniel Reserves Report”),
which are contained in the consolidated report of Deloitte with an effective date of December 31, 2017 (the “2017 Consolidated
Reserves Report”). Deloitte prepared the 2017 Consolidated Reserves Report by consolidating the properties evaluated by
Deloitte in the 2017 Deloitte Reserves Report with the properties evaluated by McDaniel in the 2017 McDaniel Reserves Report,
in each case using Deloitte’s forecast price and cost assumptions effective December 31, 2017 (the “2017 Deloitte Price Forecast”).
All of the above-noted reserves reports were prepared in accordance with the standards contained in the Canadian Oil and
Gas Evaluation Handbook (the “COGE Handbook”) and National Instrument 51-101 – Standards of Disclosure for Oil and Gas
Activities (“NI 51-101”) in effect at the relevant time.
For additional information regarding the presentation of Birchcliff’s reserves disclosure contained herein, please see
“Presentation of Oil and Gas Reserves” and “Advisories” in this Annual Report. The reserves data provided in this Annual Report
presents only a portion of the disclosure required under NI 51-101. The disclosure required under NI 51-101 is contained in
Birchcliff’s Annual Information Form for the year ended December 31, 2018. In certain of the tables below, numbers may
not add due to rounding.
28
2018 Annual Report RESERVES SUMMARY
The following table summarizes the estimates of Birchcliff’s gross reserves at December 31, 2018 and December 31, 2017,
estimated using the forecast price and cost assumptions in effect as at the effective dates of the applicable reserves
evaluations:
Summary of Gross Reserves
(Forecast Prices and Costs)
Reserves Category
Proved Developed Producing
Total Proved
Probable
Total Proved Plus Probable
Corporate
Corporate Reserves
Dec 31, 2018
(Mboe)
Dec 31, 2017
(Mboe)
Change from
Dec 31, 2017
203,631.0
689,674.1
312,396.0
1,002,070.1
197,955.1
664,480.5
308,034.8
972,515.3
3%
4%
1%
3%
1,200
1,000
800
600
400
200
0
1,200
1,000
800
600
400
200
0
)
e
o
b
M
M
(
s
e
v
r
e
s
e
R
)
e
o
b
M
M
(
s
e
v
r
e
s
e
R
PDP
TP
2P
29
PDP
TP
2P
2010
2011
2012
2013
2014
2015
2016
2017
2018
Montney
2010
2011
2012
2013
2014
2015
2016
2017
2018
2018 Annual Report
The following table sets forth Birchcliff’s light crude oil and medium crude oil, conventional natural gas, shale gas and NGLs
reserves at December 31, 2018, estimated using the 2018 Deloitte Price Forecast:
Summary of Reserves at December 31, 2018
(Forecast Prices and Costs)
Reserves
Category
Proved
Developed
Producing
Developed
Non-Producing
Undeveloped
Total Proved
Probable
Total Proved
Plus Probable
Light Crude Oil and
Medium Crude Oil
Conventional
Natural Gas
Shale Gas
NGLs
Total Boe
Gross
(Mbbls)
Net
(Mbbls)
Gross
(MMcf)
Net
(MMcf)
Gross
(MMcf)
Net
(MMcf)
Gross
(Mbbls)
Net
(Mbbls)
Gross
(Mboe)
Net
(Mboe)
9,292.8
7,406.5
5,620.7
5,176.5
989,197.3
918,413.6 28,535.1
22,404.8
203,631.0
183,743.1
0.0
0.5
666.1
645.3
31,301.6
29,130.5
317.5
239.6
5,645.4
5,202.7
11,221.1
9,451.5
3,192.9
2,930.1 2,568,438.0 2,339,902.8 40,571.5
32,695.9
480,397.7 432,619.5
20,513.9
16,858.5
9,479.7
8,752.0 3,588,937.0
3,287,446.9 69,424.1
55,340.3
689,674.1 621,565.3
14,318.3
11,287.8
8,546.2
7,973.1
1,519,533.0
1,347,374.6 43,397.8
33,596.7
312,396.0 270,775.8
34,832.2
28,146.3
18,025.9
16,725.1 5,108,470.0
4,634,821.5 112,821.9
88,937.0 1,002,070.1
892,341.1
NET PRESENT VALUES OF FUTURE NET REVENUE
The following table sets forth the net present values of future net revenue attributable to Birchcliff’s reserves at December 31, 2018,
estimated using the 2018 Deloitte Price Forecast, before deducting future income tax expenses and calculated at various
discount rates:
Summary of Net Present Values of Future Net Revenue at December 31, 2018(1)
(Forecast Prices and Costs)
Reserves Category
Proved
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved
Probable
Total Proved Plus Probable
(1) Unit values are based on net reserves.
Before Income Taxes Discounted At (%/year)
0
(MM$)
5
(MM$)
10
(MM$)
15
(MM$)
20
(MM$)
Unit Value
Discounted
at 10%/yr
($/boe)(1)
4,259.1
98.6
8,155.5
12,513.2
6,869.4
3,027.3
64.4
4,217.5
7,309.1
2,898.5
19,382.6
10,207.6
2,320.1
46.1
2,342.1
4,708.3
1,433.1
6,141.4
1,874.6
35.2
1,341.1
3,250.9
789.6
4,040.5
1,572.9
12.63
28.2
761.3
2,362.4
469.2
2,831.6
8.87
5.41
7.57
5.29
6.88
30
2018 Annual Report PRICING ASSUMPTIONS
The following table sets forth the 2018 Deloitte Price Forecast used in the 2018 Consolidated Reserves Report:
2018 Deloitte Price Forecast
Crude Oil
Natural Gas
NGLs
Alberta
AECO
Average
Price
(CDN$/Mcf)(1)
Ontario
Dawn
Reference
Point
(CDN$/Mcf)(1)
Edmonton
City Gate
(CDN$/bbl)
NYMEX
Henry Hub
(US$/Mcf)(1)
Edmonton
Ethane
(CDN$/bbl)
Edmonton
Propane
(CDN$/bbl)
Edmonton
Butane
(CDN$/bbl)
Edmonton
Pentanes +
Condensate
(CDN$/bbl)
Currency
Exchange
Rate
(CDN$/US$)
Price and
Cost
Inflation
Rates
(%)
WT I at
Cushing
Oklahoma
(US$/bbl)
58.00
Year
2019
2020
61.20
2021
64.50
2022
2023
2024
2025
2026
2027
2028
2029
69.00
75.75
77.30
78.85
80.40
82.00
83.65
85.35
2030
87.05
2031
2032
2033
2034
2035
2036
88.80
90.55
92.35
94.20
96.10
98.00
2037
100.00
65.80
72.45
78.35
81.95
89.30
91.10
92.90
94.75
96.65
98.60
100.55
102.60
104.65
106.70
108.85
111.05
113.25
115.50
117.85
1.75
2.20
2.50
2.80
3.20
3.55
3.85
3.95
4.10
4.20
4.25
4.35
4.45
4.55
4.60
4.70
4.80
4.90
5.00
5.10
3.90
4.15
4.40
4.50
4.75
5.15
5.45
5.65
5.80
5.90
6.05
6.15
6.30
6.40
6.55
6.65
6.80
6.95
7.05
7.20
3.00
3.15
3.45
3.60
3.85
4.15
4.40
4.55
4.70
4.80
4.90
4.95
5.05
5.15
5.30
5.40
5.50
5.60
5.70
5.85
2038
102.00
120.20
2038+
2.0%
2.0%
2.0%
2.0%
2.0%
(1) 1 Mcf = 1 MMBtu.
5.70
6.10
6.95
7.85
8.95
9.90
10.70
11.10
11.50
11.70
11.95
12.20
12.45
12.70
12.95
13.20
13.45
13.70
14.00
14.30
2.0%
32.90
36.25
39.15
40.95
44.65
45.55
46.45
47.40
48.35
49.30
50.30
51.30
52.30
53.35
54.45
55.50
56.65
57.75
58.90
60.10
2.0%
29.60
39.90
50.95
53.25
58.05
59.25
60.40
61.65
62.85
64.10
65.40
66.70
68.05
69.40
70.80
72.20
73.65
75.10
76.65
78.15
2.0%
75.65
79.70
86.20
90.10
98.25
100.20
102.20
104.25
106.35
108.45
110.60
112.85
115.10
117.40
119.75
122.15
124.60
127.05
129.60
132.20
2.0%
0.760
0.760
0.770
0.790
0.800
0.800
0.800
0.800
0.800
0.800
0.800
0.800
0.800
0.800
0.800
0.800
0.800
0.800
0.800
0.800
0.800
0.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
31
2018 Annual Report RECONCILIATION OF CHANGES IN RESERVES
The following table sets forth a reconciliation of Birchcliff’s gross reserves at December 31, 2018 as set forth in the 2018
Consolidated Reserves Report, estimated using the 2018 Deloitte Price Forecast, to Birchcliff’s gross reserves at December 31, 2017
as set forth in the 2017 Consolidated Reserves Report, estimated using the 2017 Deloitte Price Forecast:
Reconciliation of Gross Reserves from December 31, 2017 to December 31, 2018
(Forecast Prices and Costs)
Factors
GROSS TOTAL PROVED
Opening balance December 31, 2017
Discoveries(1)
Extensions & Improved Recovery(2)
Technical Revisions(3)
Acquisitions(4)
Dispositions(5)
Economic Factors(6)
Production(7)
Closing balance December 31, 2018
GROSS TOTAL PROBABLE
Opening balance December 31, 2017
Discoveries(1)
Extensions & Improved Recovery(2)
Technical Revisions(3)
Acquisitions(4)
Dispositions(5)
Economic Factors(6)
Production(7)
Closing balance December 31, 2018
GROSS TOTAL PROVED PLUS PROBABLE
Opening balance December 31, 2017
Discoveries(1)
Extensions & Improved Recovery(2)
Technical Revisions(3)
Acquisitions(4)
Dispositions(5)
Economic Factors(6)
Production(7)
Light
Crude
Oil and
Medium
Crude Oil
(Mbbls)
Conventional
Natural Gas
(MMcf)
Shale Gas
(MMcf)
NGLs
(Mbbls)
Oil
Equivalent
(Mboe)
16,615.8
21,752.4
3,470,382.2
65,842.3
664,480.5
0.0
2,304.6
0.0
0.0
0.0
0.0
0.0
167,870.6
2,950.3
33,233.3
3,436.2
(4,081.1)
82,830.1
4,322.0
20,883.0
0.0
15.9
2,722.3
(235.3)
(4,941.9)
171.2
(2,416.2)
0.0
124.3
37.7
(11.9)
4.8
494.1
(1,070.8)
(206.0)
(1,778.6)
(849.4)
(134,992.5)
(3,721.1)
(28,140.0)
20,513.9
9,479.7
3,588,937.0
69,424.1
689,674.1
14,394.0
14,103.2
1,449,379.3
49,727.2
308,034.8
0.0
1,280.5
0.0
0.0
0.0
28,582.0
0.0
885.6
0.0
6,929.8
(1,094.9)
(4,924.4)
16,047.0
(8,214.5)
(7,455.7)
0.0
0.0
24,954.9
(264.3)
(2,210.4)
3.0
0.0
1,577.8
0.0
0.0
569.9
0.0
969.3
(6.6)
36.8
0.0
5,128.4
(639.2)
397.8
0.0
14,318.3
8,546.2
1,519,533.0
43,397.8
312,396.0
31,009.7
35,855.6
4,919,761.5
115,569.4
972,515.3
0.0
3,585.1
0.0
0.0
0.0
0.0
0.0
196,452.5
3,835.9
2,341.3
(9,005.5)
98,877.1
(3,892.5)
0.0
15.9
27,677.2
1,007.0
(499.5)
(7,152.4)
174.2
(838.4)
0.0
694.2
(18.5)
41.6
40,163.1
13,427.5
5,622.5
(1,710.0)
191.8
(1,778.6)
(849.4)
(134,992.5)
(3,721.1)
(28,140.0)
Closing balance December 31, 2018
34,832.2
18,025.9
5,108,470.0
112,821.9 1,002,070.1
(1) Additions to volumes in reservoirs where no reserves were previously booked.
(2) Additions to volumes resulting from capital expenditures for: (i) step-out drilling in previously discovered reservoirs; (ii) infill drilling in previously discovered reservoirs that were not drilled as part
of an enhanced recovery scheme; and (iii) the installation of improved recovery schemes.
(3) Positive or negative volume revisions to an estimate resulting from new technical data or revised interpretations on previously assigned volumes, performance and operating costs.
(4) Positive additions to volume estimates because of purchasing interests in oil and gas properties.
(5) Reductions in volume estimates because of selling all or a portion of an interest in oil and gas properties.
(6) Changes to volumes resulting from different price forecasts, inflation rates and regulatory changes.
(7) Reductions in the volume estimates due to production.
32
2018 Annual Report Key highlights include the following:
• Extensions and Improved Recovery – Reserves added were due to the Corporation’s successful 2018 capital program for
the wells drilled and brought on production, including the additional offsetting future drilling locations that were assigned.
• Technical Revisions – The positive technical revisions in the total proved and the total proved plus probable reserves
categories were primarily the result of the following: (i) for shale gas, increased well performance in existing and future
drilling locations in Pouce Coupe; (ii) for light and medium crude oil, the reclassification of drilling locations from shale
gas to light and medium crude oil in Gordondale; and (iii) for NGLs, the successful C3+ extraction project at Phases V
and VI of the Pouce Coupe Gas Plant. These positive technical revisions were offset by the loss of NGLs reserves due
to the cancellation of the proposed Phase VII deep-cut expansion at the Pouce Coupe Gas Plant in connection with
Birchcliff entering into a new long-term processing arrangement at Alta Gas’ deep-cut sour gas process facility
in Gordondale, as well as the removal of the conventional natural gas reserves for the planned abandonment of
a non-core facility.
The negative technical revisions in the total probable reserves category were primarily the result of the loss of NGLs
reserves due to the cancellation of Phase VII, the removal of the conventional natural gas reserves for the planned
abandonment of the non-core facility and the adjustment in light and medium crude oil reserves for future infill drilling
locations in Gordondale.
• Acquisitions – Changes were the result of various minor acquisitions Birchcliff completed in the Gordondale and
Pouce Coupe areas in 2018.
• Dispositions – Changes were the result of various non-core dispositions Birchcliff completed in 2018.
• Economic Factors – The lower natural gas price forecast resulted in the reduction of conventional natural gas reserves
in the proved reserves category as one future drilling location was not economic to develop and was reclassified into the
probable reserves category. In addition, the economic limit caused the reduction of proved plus probable conventional
natural gas reserves. This was offset by the slightly higher price forecasts for oil and NGLs which resulted in increases
to the light and medium crude oil, shale gas and NGLs reserves in all reserves categories.
33
2018 Annual Report FUTURE DEVELOPMENT COSTS
FDC reflects the independent reserves evaluators’ best estimate of what it will cost to bring the proved and proved plus
probable reserves on production. Changes in forecast FDC occur annually as a result of development activities, acquisition and
disposition activities and capital cost estimates. The following table sets forth development costs deducted in the estimation
of Birchcliff’s future net revenue attributable to the reserves categories noted below:
Future Development Costs
(Forecast Prices and Costs)
2019
2020
2021
2022
2023
Thereafter
Total undiscounted
Proved
(MM$)
244.9
492.5
399.6
720.5
477.0
627.3
2,961.8
Proved Plus Probable
(MM$)
271.0
514.5
506.4
791.8
535.0
1,673.1
4,291.8
FDC for total proved reserves decreased to $2.96 billion at December 31, 2018 from $3.23 billion at December 31, 2017. FDC for
total proved plus probable reserves decreased to $4.29 billion at December 31, 2018 from $4.50 billion at December 31, 2017.
The decreases in FDC for both proved and proved plus probable reserves were largely due to: (i) the cancellation of Phase VII;
and (ii) the completion of Phase VI of the Pouce Coupe Gas Plant which occurred in Q3 2018. These decreases were partially
offset by the FDC associated with a net increase in Montney/Doig potential net future drilling locations added in each category
of reserves as a result of Birchcliff’s successful 2018 drilling program.
The FDC for both proved and proved plus probable reserves are primarily the capital costs required to drill, complete, equip
and tie-in the net undeveloped locations. The estimates of FDC on a proved and proved plus probable basis also include
approximately $331 million for the continued expansion of the Pouce Coupe Gas Plant from the existing 340 MMcf/d to
660 MMcf/d of total throughput. The FDC for the expansions of the Pouce Coupe Gas Plant also include the costs of the
related gathering pipelines and maintenance capital.
The following table sets forth the average cost to drill, complete, equip and tie-in a multi-stage fractured horizontal well as
estimated by Deloitte and McDaniel:
Average Well Cost, as Estimated by
Deloitte or McDaniel
Pouce Coupe(1)
Gordondale(2)
December 31, 2018
(MM$)
December 31, 2017
(MM$)
4.7
5.4
4.6
5.2
(1) Estimated by Deloitte. Up slightly compared to 2017 based on actual costs incurred in 2018 from higher completions costs as a result of increased fracture intensities per well.
(2) Estimated by McDaniel. Up slightly compared to 2017 based on actual costs incurred in 2018 from higher completions costs as a result of increased fracture intensities per well.
34
2018 Annual Report RESERVES REPLACEMENT
The following table sets forth Birchcliff’s 2018 reserves replacement ratios:
Reserves Category
Proved Developed Producing
Proved
Proved Plus Probable
2018 Reserves Replacement,
Excluding the Effects of
Acquisitions and Dispositions(1)
2018 Reserves Replacement,
Including the Effects of
Acquisitions and Dispositions(1)
122%
192%
191%
120%
190%
205%
(1) Please see “Advisories – Oil and Gas Metrics” for a description of the methodology used to calculate reserves replacement.
RESERVES LIFE INDEX
The following table sets forth Birchcliff’s 2018 reserves life index:
Reserves Category
Proved Developed Producing
Total Proved
Total Proved Plus Probable
2018 Reserves Life Index(1)
7.2 years
24.5 years
35.6 years
(1) Based on a forecast production rate of 77,000 boe/d for 2019, which represents the mid-point of Birchcliff’s annual average production guidance range for 2019. Please see “Advisories – Oil and Gas
Metrics” for a description of the methodology used to calculate reserves life index.
35
2018 Annual Report
RESERVES ON THE MONTNEY/DOIG RESOURCE PLAY
Corporate
The following table summarizes the estimates of reserves attributable to Birchcliff’s horizontal wells on the Montney/Doig
Resource Play as contained in the 2018 Consolidated Reserves Report and the number of horizontal wells to which reserves
were attributed:
1,200
Montney/Doig Resource Play Reserves Data(1)(2)
1,000
Reserves
800
Category
Shale Gas
(Bcf)
Light Crude Oil
and Medium Crude
Oil Combined
(Mbbls)
NGLs
(Mbbls)
Total
(Mboe)
Existing Horizontal Wells
and Potential Future
Horizontal Well Locations
(Gross)
(Net)
2018
2017
2018
2017
2018
2017
2018
2017
2018
2017
2018
2017
Proved
)
e
o
Developed
b
M
600
M
Producing
(
s
e
v
r
e
s
e
R
Total Proved
400
973.4
976.5
9,239.1
8,323.4
27,923.0
23,066.0
199,396.1
194,145.1
368
339
364.3
PDP
TP
333.8
2P
3,572.8
3,464.1
20,460.2
16,318.7
68,779.3
65,348.2
684,710.4
659,029.0
903
862 888.8
846.0
Total
Proved Plus
Probable
5,088.6
4,911.2
34,758.7
30,428.7
111,985.9
114,869.1
994,848.1
963,836.1
1,154
1,103
1,121.8 1,072.0
200
(1) Estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.
(2) At December 31, 2018, the estimated FDC for Birchcliff’s reserves on its Montney/Doig Resource Play is $0.0 million on a proved developed producing basis (as compared to $0.0 million at December 31, 2017),
$2,958.7 million on a proved basis (as compared to $3,223.3 million at December 31, 2017) and $4,282.9 million on a proved plus probable basis (as compared to $4,480.8 million at December 31, 2017).
0
2010
2011
2012
2013
2014
2015
2016
2017
2018
Montney/Doig Reserves
Montney
1,200
1,000
800
600
400
200
0
)
e
o
b
M
M
(
s
e
v
r
e
s
e
R
36
PDP
TP
2P
2010
2011
2012
2013
2014
2015
2016
2017
2018
2018 Annual Report
2018 FINDING AND DEVELOPMENT COSTS
During 2018, our F&D costs were $299.7 million and our FD&A costs were $296.0 million.
The following table sets forth our estimates of our F&D costs per boe and FD&A costs per boe for 2018, 2017 and 2016,
excluding and including FDC:
Excluding FDC ($/boe)(1)
F&D – Proved Developed Producing
F&D – Proved
F&D – Proved Plus Probable
FD&A – Proved Developed Producing
FD&A – Proved
FD&A – Proved Plus Probable
Including FDC ($/boe)(1)
F&D – Proved
F&D – Proved Plus Probable
FD&A – Proved
FD&A – Proved Plus Probable
2018
$8.75
$5.56
$5.57
$8.75
$5.55
$5.13
2018(2)
$0.64
$1.27
$0.45
$1.47
2017
$6.29
$2.53
$2.54
$4.79
$1.95
$2.35
2017(3)
$8.14
$7.27
$7.16
$5.37
2016
$6.42
$1.57
$1.25
$9.32
$3.53
$2.33
2016(4)
$4.89
$4.43
$6.73
$5.58
3-Year
Average
$6.99
$2.72
$2.52
$7.71
$3.25
$2.66
3-Year
Average
$5.83
$5.27
$6.06
$5.06
(1) Please see “Advisories – Oil and Gas Metrics” for a description of the methodology used to calculate F&D and FD&A costs.
(2) Reflects the 2018 decrease in FDC from 2017 of $272.2 million on a proved basis and $211.2 million on a proved plus probable basis.
(3) Includes the 2017 increase in FDC from 2016 of $732.9 million on a proved basis and $352.9 million on a proved plus probable basis.
(4) Includes the 2016 increase in FDC from 2015 of $690.0 million on a proved basis and $1,059.0 million on a proved plus probable basis.
2018 RECYCLE RATIOS
The following table sets forth our recycle ratios for operating and adjusted funds flow netbacks for 2018 and 2017, excluding
and including FDC:
Excluding FDC
F&D – Proved Developed Producing
FD&A – Proved Developed Producing
F&D – Proved
FD&A – Proved
F&D – Proved Plus Probable
FD&A – Proved Plus Probable
Including FDC(4)
F&D – Proved
FD&A – Proved
F&D – Proved Plus Probable
FD&A – Proved Plus Probable
Operating Netback
Recycle Ratio(1)(2)
Adjusted Funds Flow Netback
Recycle Ratio(1)(3)
2018
2017
2018
2017
1.5
1.5
2.4
2.4
2.4
2.6
21.2
30.3
10.7
9.2
2.2
2.9
5.5
7.2
5.5
6.0
1.7
2.0
1.9
2.6
1.3
1.3
2.0
2.0
2.0
2.2
17.4
24.9
8.8
7.6
2.0
2.7
5.1
6.6
5.0
5.5
1.6
1.8
1.8
2.4
(1) Please see “Advisories – Oil and Gas Metrics” for a description of the methodology used to calculate recycle ratios.
(2) Birchcliff’s operating netback was $13.52/boe in 2018, as compared to $13.97/boe in 2017.
(3) Birchcliff’s adjusted funds flow netback was $11.12/boe in 2018, as compared to $12.81/boe in 2017.
(4) FDC decreased from 2017 primarily due to the cancellation of the proposed Phase VII deep-cut expansion at the Pouce Coupe Gas Plant.
During 2018, the average benchmark price for WTI crude oil was US$64.77/bbl and the average benchmark price for natural
gas sold at AECO was CDN$1.42/GJ. The operating netback was $13.52/boe in 2018, as compared to $13.97/boe in 2017.
Adjusted funds flow netback was $11.12/boe in 2018, as compared to $12.81/boe in 2017.
37
2018 Annual Report L O O K I N G O U T F O R O U R T E A M A N D T H E C O M M U N I T Y
RESPONSIBILITY
HEALTH, SAFETY AND ENVIRONMENT
Birchcliff is committed to constantly evolving and improving its health, safety and environmental management
program and conducting its activities in a manner that safeguards its employees, contractors, representatives, the
environment and the public at large. We have an active program to monitor and comply with health, safety and
environmental laws, rules and regulations applicable to our operations.
Birchcliff’s corporate policies require operational activities to be conducted in a manner which meets or exceeds regulatory
requirements and industry standards to safeguard the environment and protect employees, contractors and the public at
large. Employees receive pertinent health, safety and environmental training for their role. Birchcliff conducts operational
audits and assessments to identify risks and takes steps to reduce or prevent incidents. In addition, we have developed
emergency response plans in conjunction with local authorities, emergency services and the communities in which
we operate in order to be prepared to effectively respond to an incident should one arise. We rigorously conduct
annual emergency response exercises and training for our staff that exceed regulatory requirements.
Birchcliff participates in Alberta’s Certificate of Recognition (COR) Safety Program and has received and maintained
a COR certification since 2011. A COR certification demonstrates that the employer’s health and safety management
system has been evaluated by a certified auditor and meets provincial standards, as established by Occupational
Health and Safety (Alberta). Maintaining a COR certification requires a commitment to continuous improvement in
the health, safety and environment management practices, including sound planning and implementation.
Birchcliff’s Health and Safety program is audited externally every three years by an independent auditor and internally
annually by a certified professional. Birchcliff works hard to maintain the safety and integrity of its facility and pipeline
infrastructure. Our Asset Integrity staff manages our Pressure Equipment Integrity Program in compliance with the
Alberta Boilers Safety Association (ABSA) requirements and our Pipeline Integrity Program in compliance with Alberta
Energy Regulator requirements. These programs are audited internally on an annual basis and externally on a periodic
basis to evaluate their effectiveness and are updated based on the findings from such audits. Birchcliff has received
high audit scores from ABSA on two recent audits of its program. Our Chief Inspector and our Asset Integrity Group
make use of databases and associated work tracking systems to ensure that all integrity tasks (inspections, pigging,
etc.) are scheduled and completed according to the requirements set forth in our programs.
As part of our fundamental values, we recognize the importance of, and our responsibility for, environmental
stewardship. Birchcliff endeavors to maintain excellence in environmental reporting and response and to take proactive
steps to eliminate or reduce our environmental impact. As an organization which strives for continuous improvement,
Birchcliff continues to look for, and develop, new technology, systems and processes that will help improve efficiency,
reduce our environmental footprint and create a safer work environment. For example, Birchcliff utilizes multi-well
pads in many of our drilling operations and we recycle as much water from our completion operations as we can.
We are also proud that we have received our allocation benchmark from the Alberta Climate Change Office as part
of the Carbon Competitiveness Incentive Regulation (CCIR). To the extent the Pouce Coupe Plant’s total regulated
emissions is less than its output-based allocation, it will earn emission performance credits (EPCs). We anticipate
that the Pouce Coupe Gas Plant will generate EPCs in respect of the 2018 financial year.
Environmental assessments are undertaken for new projects or when acquiring new properties or facilities in order
to identify, assess and minimize environmental risks and operational exposures. Birchcliff conducts audits of operations
to confirm compliance with internal standards and to stimulate improvement in practices where needed. Documentation
is maintained to support internal accountability and measure operational performance against recognized industry
indicators to assist in achieving the objectives of the described policies and programs.
38
2018 Annual Report COMMUNITY SUPPORT
Fostering a strong relationship with the community and its stakeholders is as integral to the success of Birchcliff’s
projects as obtaining the required regulatory approvals. We believe cooperative, sincere and responsive consultation
efforts with stakeholders in the areas in which we operate creates a solid foundation for our business. Birchcliff has
an experienced team working with local stakeholders to learn their values and priorities and to resolve any issues or
concerns that arise in the course of our field operations.
Birchcliff recognizes the role that communities play in our success and looks for opportunities to “give back”. We are a
staunch supporter of the community and the business and educational initiatives of the Indigenous Communities who
live in areas in which we operate. Every year, we participate in a number of community support endeavours in the areas
surrounding our field operations and in Calgary. In 2018, Birchcliff contributed to a number of local community initiatives
that elevate and enhance quality of life at the local level, including minor hockey and other amateur sports, local schools,
agricultural societies and fire departments. To date, Birchcliff has helped raise over $1,000,000 for both the STARS
Air Ambulance in the Grande Prairie area and the United Way of Calgary. Each year, Birchcliff also raises funds for
the YWCA. We make an annual contribution to Home Front Calgary, a community-justice response team dedicated to
helping families experiencing domestic violence. Through our support of Momentum, Calgarians living in poverty learn
how to achieve a sustainable livelihood. We donate to the OneSight program and support the Canadian Cancer Society
daffodil campaign. Birchcliff volunteers with Feed the Hungry, providing healthy meals in an atmosphere of dignity and
respect. During the holiday season, Birchcliff employees “adopt” a number of families in need and donate gifts, food and
decorations to help make the holidays special. We also fill backpacks with living essentials and gifts for the Mustard Seed
and prepare sandwiches for the homeless for the Calgary Drop-In Centre.
Through these activities and numerous others, Birchcliff creates and maintains long-term, positive partnerships and
relationships, while promoting employee engagement in the communities in which we operate.
INDIGENOUS RELATIONS
Birchcliff’s activity is focused in the Peace River Area of Alberta which is within the traditional area occupied by the
Treaty 8 First Nations members and by the Metis people. Birchcliff recognizes and respects these indigenous groups,
their rights and their culture. Much of our activity takes place upon the unoccupied crown lands which are administered
by the Province of Alberta. We are committed to open, honest and straight forward communication with the indigenous
groups who have been formally recognized as having rights within the areas in which we operate. Currently those groups
include Horse Lake First Nation, Duncan’s First Nation, Gift Lake Metis Settlement and East Prairie Metis Settlement.
We provide support to these communities and their ventures to enhance their human, economic and cultural development.
Our support is aligned with several key philosophies and based upon the principle that all individuals should be treated
fairly and with respect.
The success of our children and future generations is the key. For this reason we are strong supporters of all education
initiatives from early childhood programs, programs that support adolescents, post-secondary courses, upgrading and
equivalency programs and trade and technical training programs. We believe that everyone should be aware of, and
proud of, their culture and heritage. We support many cultural events including round dances, formal events such as
Treaty 8 Days and cultural camps which bring youth and elders together for traditional learning and sharing opportunities.
Communities are most successful when their members drive the programs. We look to community members to set goals
and take the initiative to plan, prepare budgets, submit the request for support and organize their events.
We have long standing agreements with the key communities in our operations areas. We are proud of the relationships
that we have with these communities and the reputation we have worked hard to build and maintain. We believe that our
actions must always speak louder than our words.
39
2018 Annual Report 2018
FINANCIALS
40
2018 Annual Report MANAGEMENT’S DISCUSSION AND ANALYSIS
GENERAL
This Management’s Discussion and Analysis (“MD&A”) for Birchcliff Energy Ltd. (“Birchcliff” or the “Corporation”) is dated
March 13, 2019. This MD&A with respect to the three and twelve months ended December 31, 2018 (the “Reporting Periods”)
as compared to the three and twelve months ended December 31, 2017 (the “Comparable Prior Periods”) has been prepared
by management and approved by the Corporation’s Audit Committee and Board of Directors. This MD&A should be read in
conjunction with the audited financial statements of the Corporation and the related notes for the year ended December 31, 2018.
Birchcliff’s audited financial statements and the related notes for the year ended December 31, 2018 have been prepared in
accordance with GAAP. All dollar amounts are expressed in Canadian currency, unless otherwise stated.
This MD&A uses “adjusted funds flow”, “adjusted funds flow per common share”, “operating netback”, “free funds flow”, “total
cash costs”, “adjusted working capital deficit” and “total debt”, which do not have standardized meanings prescribed by GAAP
and therefore may not be comparable to similar measures presented by other companies where similar terminology is used.
For further information, see “Non-GAAP Measures” in this MD&A.
This MD&A contains forward-looking statements and information (collectively, “forward-looking statements”) within the
meaning of applicable Canadian securities laws. Such forward-looking statements are based upon certain expectations and
assumptions and actual results may differ materially from those expressed or implied by such forward-looking statements.
For further information regarding the forward-looking statements contained herein, see “Advisories – Forward-Looking
Statements” in this MD&A.
All boe amounts have been calculated by using the conversion ratio of 6 Mcf of natural gas to 1 bbl of oil and all Mcfe amounts
have been calculated by using the conversion ratio of 1 bbl of oil to 6 Mcf of natural gas. For further information, see “Advisories –
Boe and Mcfe Conversions” in this MD&A.
ABOUT BIRCHCLIFF
Birchcliff is a Calgary, Alberta based intermediate oil and natural gas company with operations concentrated within its one core
area, the Peace River Arch of Alberta. Birchcliff’s common shares and cumulative redeemable preferred shares, Series A and
Series C, are listed for trading on the Toronto Stock Exchange (the “TSX”) under the symbols “BIR”, “BIR.PR.A” and “BIR.PR.C”,
respectively. Additional information relating to the Corporation, including its Annual Information Form for the financial year
ended December 31, 2018, is available on the SEDAR website at www.sedar.com and on the Corporation’s website at
www.birchcliffenergy.com.
2018 FINANCIAL AND OPERATIONAL HIGHLIGHTS
2018 Year-End Highlights
• Production averaged 77,096 boe/d (20% oil and NGLs), a 13% increase from the twelve month Comparable Prior Period.
• Cash flow from operating activities of $324.4 million, a 13% increase from the twelve month Comparable Prior Period.
• Adjusted funds flow of $312.9 million, or $1.18 per basic common share, a 1% decrease and a 2% decrease, respectively,
from the twelve month Comparable Prior Period.
• Net income to common shareholders of $98.0 million, or $0.37 per basic common share, as compared to the net loss to
common shareholders of $51.0 million and $0.19 per basic common share in the twelve month Comparable Prior Period.
• Operating expense of $3.52/boe, a 21% decrease from the twelve month Comparable Prior Period.
• Total cash costs of $10.42/boe, a 3% decrease from the twelve month Comparable Prior Period.
• Operating netback of $13.52/boe, a 3% decrease from the twelve month Comparable Prior Period.
• Total capital expenditures of $298.0 million. During 2018, Birchcliff drilled 36 (36.0 net) wells and brought 28 (28.0 net)
wells on production.
• As at December 31, 2018, Birchcliff’s long-term bank debt was $605.3 million and its total debt was $626.5 million,
a 3% increase and a 5% increase, respectively, from its long-term and total debt as at December 31, 2017.
41
2018 Annual Report Fourth Quarter 2018 Highlights
• Production averaged 76,408 boe/d (21% oil and NGLs), a 5% decrease from the three month Comparable Prior Period.
• Cash flow from operating activities of $92.2 million, a 4% increase from the three month Comparable Prior Period.
• Adjusted funds flow of $81.5 million, or $0.31 per basic common share, a 16% decrease and a 14% decrease, respectively,
from the three month Comparable Prior Period.
• Net income to common shareholders of $70.9 million, or $0.27 per basic common share, a 186% increase and a 200%
increase, respectively, from the three month Comparable Prior Period.
• Operating expense of $3.51/boe, a 9% decrease from the three month Comparable Prior Period.
• Total cash costs of $10.68/boe, a 2% decrease from the three month Comparable Prior Period.
• Operating netback of $13.47/boe, a 3% decrease from the three month Comparable Prior Period.
• Total capital expenditures of $52.9 million. During the quarter, Birchcliff drilled 9 (9.0 net) wells.
See “Cash Flow from Operating Activities and Adjusted Funds Flow”, “Net Income (Loss) to Common Shareholders”, “Discussion
of Operations”, “Capital Expenditures” and “Capital Resources and Liquidity” in this MD&A for further information regarding the
financial and operational results for the Reporting Periods.
2019 OUTLOOK
Birchcliff’s disciplined 2019 capital program of $204 million (the “2019 Capital Program”) is focused on its high-value oil assets
in Gordondale and its condensate-rich assets in Pouce Coupe. Approximately $122 million has been allocated for drilling and
development in Pouce Coupe and Gordondale, $33.9 million for facilities and infrastructure and $47.9 million for maintenance
and optimization and other capital projects on the Montney/Doig Resource Play. The 2019 Capital Program contemplates the
drilling of a total of 17 (17.0 net) wells and the bringing on production of a total of 26 (26.0 net) wells during 2019.
The 2019 Capital Program targets an annual average production rate of 76,000 to 78,000 boe/d which is expected to generate
approximately $330 million of adjusted funds flow, based on the assumptions set forth herein. Total F&D capital expenditures
are estimated to be $204 million, which are significantly less than Birchcliff’s estimated 2019 adjusted funds flow.
Based on the assumptions set forth in the table below, Birchcliff currently expects that it will be well positioned to generate
significant free funds flow in 2019 as supported by its natural gas diversification and financial risk management contracts and
mix of long-life and low decline assets which provide it with a stable base of production. Any free funds flow will be allocated
based on what Birchcliff believes will provide the most value to its shareholders, with alternatives that may include debt
reduction, production growth and purchasing common shares under its normal course issuer bid. Any free funds flow will also
be allocated by Birchcliff to pay dividends on its common and preferred shares (including an increased dividend on the common
shares) and to pay for the recent acquisition in Pouce Coupe for total cash consideration of $39 million, which closed on
January 3, 2019 (the “Acquisition”). See “Subsequent Event” in this MD&A.
During 2019, the Corporation expects that approximately 65% of its natural gas will be effectively sold at prices that are
not based on AECO. In addition, effectively 87% of Birchcliff’s total revenue in 2019 is expected to be based on non-AECO
benchmark prices after taking into account Birchcliff’s commodity risk management contracts and expected sales from oil
and NGLs and based on the commodity price assumptions set forth in the table on the following page. This natural gas market
diversification together with Birchcliff’s financial risk management contracts will help to further strengthen Birchcliff’s balance
sheet and protect its cash flow and project economics.
42
2018 Annual Report The following table sets forth Birchcliff’s guidance and commodity price assumptions for 2019, as well as its 2018 actual
results for comparative purposes:
2019 Guidance and
Assumptions(1)
2018 Actual
Results
Production
Annual average production (boe/d)
% Natural gas
% Light oil
% Condensate
% Other NGLs
Average Expenses ($/boe)
Royalty
Operating
Transportation and other
Adjusted Funds Flow (MM$)
F&D Capital Expenditures (MM$)
Free Funds Flow (MM$)(6)
Acquisition Purchase Price (MM$)
Total Capital Expenditures (MM$)
Natural Gas Market Exposure(8)
AECO exposure as a % of total natural gas production
Dawn exposure as a % of total natural gas production
NYMEX HH exposure as a % of total natural gas production
Alliance pipeline exposure as a % of total natural gas production
Commodity Prices
Average WTI price (US$/bbl)
Average WTI-MSW differential (CDN$/bbl)
Average AECO price (CDN$/GJ)
Average Dawn price (CDN$/GJ)
Average NYMEX HH price (US$/MMBtu)(9)
Exchange rate (CDN$ to US$1)
76,000 – 78,000
79%
7%
6%
8%
1.30 – 1.50
3.15 – 3.35
4.65 – 4.85(2)
330(4)
204(5)
126
39(7)
245(5)
35%
39%
25%
1%
56.00
10.00
1.65
3.40
3.00
1.32
77,096
80%
6%
6%
8%
1.36
3.52
3.68(3)
312.9
299.7
13.2
N/A
298.0
61%
31%
N/A
8%
64.77
14.85
1.42
3.84
3.07
1.2961
(1) See “Advisories – Forward-Looking Statements”. Birchcliff’s guidance for its commodity mix, average expenses, funds flow, capital expenditures and natural gas market exposure in 2019 is based on an
annual average production rate of 77,000 boe/d during 2019, which is the mid-point of Birchcliff’s annual average production guidance for 2019.
(2) Includes transportation tolls for 150,000 GJ/d of natural gas sold at the Dawn price from January 1, 2019 to October 31, 2019 and 175,000 GJ/d from November 1, 2019 to December 31, 2019. Also
includes any new unused firm transportation costs associated with Birchcliff’s commitments on the NGTL system, which is available for future production growth.
(3) Includes transportation tolls for 120,000 GJ/d of natural gas sold at the Dawn price from January 1, 2018 to October 31, 2018 and 150,000 GJ/d from November 1, 2018 to December 31, 2018.
(4) Birchcliff’s estimate of adjusted funds flow takes into account the settlement of financial and physical commodity risk management contracts outstanding as at March 13, 2019. See “Commodity Price
Risk Management”.
(5) Birchcliff’s estimate of F&D capital expenditures corresponds to Birchcliff’s 2019 capital budget of $204 million. This estimate excludes the purchase price for the Acquisition and any other net potential
acquisitions and dispositions. Birchcliff’s estimate of total capital expenditures includes the purchase price for the Acquisition; however, this estimate does not take into account any other potential
acquisitions or dispositions as these amounts are unbudgeted. The estimate of total capital expenditures also includes minor administrative assets. See “Advisories – Capital Expenditures”.
(6) Free funds flow is calculated as adjusted funds flow less F&D capital expenditures and is prior to administrative assets, acquisitions, dispositions, dividend payments and abandonment and reclamation
obligations. See “Non-GAAP Measures”. Free funds flow may be used by Birchcliff to reduce debt, pursue additional growth, pay dividends and/or to fund share buybacks under its normal course issuer
bid. Any prolonged or significant decrease in commodity prices may leave insufficient free funds flow for debt reduction or the other foregoing purposes.
(7) Represents the purchase price for the Acquisition of $39 million.
(8) Birchcliff’s guidance regarding its natural gas market exposure in 2019 assumes: (i) 150,000 GJ/d being sold at the Dawn index price from January 1, 2019 to October 31, 2019 and 175,000 GJ/d from
November 1, 2019 to December 31, 2019; (ii) 5 MMcf/d being sold at Alliance’s Trading Pool daily index price; and (iii) 100,000 MMBtu/d being hedged at a fixed basis differential between the AECO price
and the NYMEX HH price.
(9) $1.00 per MMBtu equals $1.00 per Mcf based on a standard heat value of 37.4 MJ/m3 or a heat uplift of 1.055 when converting from $/GJ.
Birchcliff’s 2018 financial and operational results were generally in line with, or better than, guidance. Birchcliff’s 2018 production
results were within guidance of 76,000 boe/d to 78,000 boe/d. Royalty expense on a per boe basis in 2018 was 15% lower
than the low end of Birchcliff’s guidance of $1.60/boe to $1.80/boe. The variance was primarily a result of decreased averaged
realized oil sales prices in the three month Reporting Period. Operating expense on a per boe basis was in line with Birchcliff’s
guidance of $3.40/boe to $3.60/boe. Birchcliff’s transportation and other expense on a per boe basis was 3% lower than the
low end of Birchcliff’s guidance of $3.80/boe to $4.10/boe due to unbudgeted mitigation of excess transportation capacity.
43
2018 Annual Report SELECTED ANNUAL INFORMATION
Average daily production (boe)
Petroleum and natural gas revenue ($000s)(1)
Average sales price (CDN$)(1)
Light oil (per bbl)
Natural gas (per Mcf)
NGLs (per bbl)
Total (per boe)
Cash flow from operating activities ($000s)
Adjusted funds flow ($000s)
Per common share – basic ($)
Per common share – diluted ($)
Net income (loss) ($000s)
Net income (loss) to common shareholders ($000s)
Per common share – basic ($)
Per common share – diluted ($)
Total capital expenditures ($000s)(2)
Operating expense ($ per boe)
Total assets ($000s)
Capital securities ($000s)
Revolving term credit facilities ($000s)
Adjusted working capital deficit ($000s)
Total debt ($000s)
Common shares outstanding (000s):
End of period – basic
End of period – diluted
Weighted average common shares for period – basic
Weighted average common shares for period – diluted
Common shares – dividend distribution ($000s)
Per common share ($)
Series A preferred shares outstanding – end of period (000s)
Series A – dividend distribution ($000s)
Per Series A preferred share ($)
Series C preferred shares outstanding – end of period (000s)
Series C – dividend distribution ($000s)
Per Series C preferred share ($)
2018
77,096
621,421
68.66
2.45
44.66
22.08
324,434
312,922
1.18
1.17
102,212
98,025
0.37
0.37
298,018
3.52
2017
67,963
556,942
61.42
2.72
33.39
22.44
287,660
317,680
1.20
1.19
(46,980)
(51,027)
(0.19)
(0.19)
276,125
4.45
2,762,920
2,627,108
49,535
605,267
21,187
626,454
265,911
284,699
265,852
267,323
26,586
0.10
2,000
4,187
2.0935
2,000
3,500
1.7500
49,225
587,126
11,067
598,193
265,797
282,895
265,182
265,182
26,522
0.10
2,000
4,047
2.0234
2,000
3,500
1.7500
2016
49,236
337,586
51.40
2.41
31.23
18.73
140,514
147,443
0.74
0.73
(24,335)
(28,335)
(0.14)
(0.14)
762,030
4.18
2,710,457
48,916
572,517
27,495
600,012
264,042
279,881
199,581
199,581
-
-
2,000
4,000
2.0000
2,000
3,500
1.7500
(1) Excludes the effects of financial derivatives but includes the effects of physical delivery contracts.
(2) Birchcliff previously referred to total capital expenditures as “net capital expenditure” or “capital expenditures, net”. See “Advisories – Capital Expenditures”.
Annual average production in 2018 was 77,096 boe/d, up 13% from 2017 and up 57% from 2016. The increase in annual
average production from 2016 was primarily due to incremental production additions from new horizontal oil and natural gas
wells brought on production in Pouce Coupe and Gordondale in connection with Birchcliff’s successful 2017 and 2018 capital
programs and production volumes acquired pursuant to an asset acquisition in Gordondale in July 2016 (the “Gordondale
Acquisition”), partially offset by the disposition of the Corporation’s assets in the Worsley area (the “Worsley Assets”) in
August 2017 (the “Worsley Disposition”).
44
2018 Annual Report Birchcliff generated lower adjusted funds flow in 2018 as compared to 2017 and higher adjusted funds flow as compared to 2016.
The decrease in adjusted funds flow from 2017 was primarily due to a lower corporate average realized sales price, partially
offset by an increase in annual average production volumes in 2018. Adjusted funds flow in 2018 was also negatively impacted
by lower oil production as a result of the Worsley Disposition and a realized loss on financial instruments in 2018, as compared
to a realized gain on financial instruments in 2017. The increase in adjusted funds flow from 2016 was largely due to a higher
average realized sales price and an increase in annual average production volumes as a result of the Gordondale Acquisition.
Birchcliff recorded net income to common shareholders of $98.0 million ($0.37 per basic common share) in 2018, as compared
to the net loss to common shareholders of $51.0 million ($0.19 per basic common share) in 2017 and $28.3 million ($0.14 per
basic common share) in 2016. The change from a net loss to a net income position from the prior two years was primarily due
to changes in adjusted funds flow (as explained above), a $64.2 million unrealized mark-to-market gain on financial instruments
recorded in 2018 and a $132.3 million after-tax loss in connection with the Worsley Disposition, partially offset by higher
depletion and income tax expenses.
Total capital expenditures in 2018 were significantly lower as compared to 2016, and comparable to total capital expenditures
in 2017. Total capital expenditures in 2016 included the $613.5 million Gordondale Acquisition. Excluding the Gordondale
Acquisition, capital expenditures in the last three years were largely directed towards the Montney/Doig Resource Play which
included: (i) the drilling and completion of new horizontal oil and natural gas wells brought on production in Pouce Coupe and
Gordondale; and (ii) the Phase V and Phase VI expansion of the 100% owned and operated Pouce Coupe natural gas processing
plant located in Pouce Coupe (“Pouce Coupe Gas Plant”) (including related wells and infrastructure), which increased the
licensed natural gas processing capacity from 180 MMcf/d to a licensed processing capacity of 340 MMcf/d.
Operating expense on a per boe basis in 2018 was lower as compared to the prior two years primarily due to an incremental
increase in natural gas production processed at the Pouce Coupe Gas Plant and the reduced processing fees at AltaGas’ deep-cut
sour gas processing facility located in Gordondale (the “Gordondale Gas Plant”), as well as the disposition of the higher-cost
Worsley Assets in August 2017. During 2018, Birchcliff entered into a new long-term natural gas processing arrangement
effective January 1, 2018 (the “Gordondale Processing Arrangement”) which significantly reduced its processing fees at the
Gordondale Gas Plant.
CASH FLOW FROM OPERATING ACTIVITIES AND ADJUSTED FUNDS FLOW
The following table sets forth the Corporation’s cash flow from operating activities and adjusted funds flow for the Reporting
Periods and the Comparable Prior Periods:
($000s)
Cash flow from operating activities
Adjusted funds flow
Per common share – basic ($)
Per common share – diluted ($)
Three months ended
December 31,
Twelve months ended
December 31,
2018
92,200
81,517
0.31
0.30
2017
88,995
97,008
0.36
0.36
2018
324,434
312,922
1.18
1.17
2017
287,660
317,680
1.20
1.19
Adjusted funds flow in the three and twelve month Reporting Periods decreased by 16% and 1%, respectively, from the
Comparable Prior Periods. For the three month Reporting period, the decrease was primarily due to lower corporate
production, lower average realized oil and NGLs sales prices, higher interest and transportation and other expenses and lower
realized gains on financial instruments, partially offset by a higher average realized natural gas sales price. For the twelve
month Reporting Period, the decrease was primarily due to a realized loss on financial instruments as compared to a realized
gain on financial instruments in the twelve month Comparable Prior Period, as well as an increase in transportation and
other expense as a result of the Corporation increasing its Dawn and AECO firm service. The decrease was partially offset by
significantly higher revenues received by the Corporation due to higher natural gas and NGLs production in the twelve month
Reporting Period, notwithstanding the decrease in oil production as a result of Worsley Disposition.
Cash flow from operating activities for the three and twelve month Reporting Periods increased by 4% and 13%, respectively,
from the Comparable Prior Periods. The reason for the changes in cash flow from operating activities from the Comparable
Prior Periods is consistent with the explanation for adjusted funds flows as noted above, and additionally by an increase in non-cash
operating working capital, partially offset by higher decommissioning expenditures in the Reporting Periods as compared to the
Comparable Prior Periods.
45
2018 Annual Report The following table sets forth a breakdown of the Corporation’s total cash costs on a per unit basis and the percentage change
period-over-period for the Reporting Periods and the Comparable Prior Periods:
($/boe)
Royalty expense
Operating expense
Transportation and other expense
G&A expense, net
Interest expense
Total cash costs
Three months ended
December 31,
Twelve months ended
December 31,
2018
0.96
3.51
4.07
1.08
1.06
2017
1.26
3.86
3.52
1.28
0.97
10.68
10.89
Change
24%
(9)%
16%
(16)%
9%
(2)%
2018
1.36
3.52
3.68
0.87
0.99
2017
1.16
4.45
2.87
1.07
1.14
10.42
10.69
Change
17%
(21)%
28%
(19)%
(13)%
(3)%
See “Discussion of Operations” in this MD&A for further details regarding the period-over-period movement in total cash cost inputs.
NET INCOME (LOSS) TO COMMON SHAREHOLDERS
The following table sets forth the Corporation’s net income (loss) and net income (loss) to common shareholders for the
Reporting Periods and the Comparable Prior Periods:
($000s)
Net income (loss)
Net income (loss) to common shareholders(1)
Per common share – basic ($)
Per common share – diluted ($)
Three months ended
December 31,
Twelve months ended
December 31,
2018
71,947
70,900
0.27
0.27
2017
25,820
24,773
0.09
0.09
2018
102,212
98,025
0.37
0.37
2017
(46,980)
(51,027)
(0.19)
(0.19)
(1) Net income (loss) to common shareholders is calculated by adjusting net income (loss) for the dividends paid on the Series A Preferred Shares during the period. Per common share amounts are
calculated by dividing net income (loss) to common shareholders by the weighted average number of basic or diluted common shares outstanding for the period.
During the three and twelve month Reporting Periods, Birchcliff reported net income to common shareholders of $70.9 million
and $98.0 million, respectively, compared to net income to common shareholders of $24.8 million in the three month
Comparable Prior Period and a net loss to common shareholder of $51.0 million in the twelve month Comparable Prior Period.
The increase in net income to common shareholders from the three month Comparable Prior Period was primarily due to
a $77.5 million ($56.6 million, net of tax) unrealized mark-to-market gain on financial instruments, partially offset by lower
adjusted funds flow and higher income tax expenses. The change from a net loss to a net income position from the twelve
month Comparable Prior Period was primarily due to a $64.2 million ($46.9 million, net of tax) unrealized mark-to-market
gain on financial instruments recorded in the twelve month Reporting Period and a $181.3 million ($132.3 million, net of tax)
loss from the sale of the Worsley Assets in the twelve month Comparable Prior Period, partially offset by higher depletion
and income tax expenses.
POUCE COUPE GAS PLANT NETBACKS
During the twelve month Reporting Period, Birchcliff processed approximately 67% of its total corporate natural gas
production and 57% of its total corporate production through the Pouce Coupe Gas Plant as compared to 60% and 49%,
respectively, during the twelve month Comparable Prior Period. These increases were primarily due to the incremental
production from horizontal natural gas wells brought on production in Pouce Coupe. The average plant and field operating
expense for production processed through the Pouce Coupe Gas Plant was $0.34/Mcfe ($2.02/boe) and the operating netback
at the Pouce Coupe Gas Plant was $2.04/Mcfe ($12.24/boe), resulting in an operating margin of 68% in the twelve month
Reporting Period.
46
2018 Annual Report During the Reporting Periods, Birchcliff specifically targeted condensate-rich natural gas wells in Pouce Coupe. This materially
increased the amount of condensate being produced at the Pouce Coupe Gas Plant to 2,431 bbls/d in the twelve month
Reporting Period from 1,292 bbls/d in the twelve month Comparable Prior Period, an 88% increase. This resulted in a 53%
increase in the liquids-to-gas ratio from the twelve month Comparable Prior Period from 6.8 bbls/MMcf to 10.4 bbls/MMcf.
The following table sets forth Birchcliff’s average daily production and operating netback for wells producing to the Pouce Coupe
Gas Plant for the twelve month Reporting Period and the twelve month Comparable Prior Period:
Average production:
Natural gas (Mcf/d)
NGLs (bbls/d)(1)
Total (boe/d)
Liquids(1)-to-gas ratio (bbls/MMcf)
Netback and cost:
Petroleum and natural gas revenue(2)
Royalty expense
Operating expense(3)
Transportation and other expense(4)
Operating netback
Operating margin(5)
Twelve months ended
December 31, 2018
Twelve months ended
December 31, 2017
250,011
2,609
44,278
10.4
$/boe
18.11
(0.29)
(2.02)
(3.56)
$12.24
68%
$/Mcfe
3.04
(0.07)
(0.34)
(0.44)
$2.19
72%
193,417
1,316
33,552
6.8
$/boe
18.24
(0.44)
(2.07)
(2.61)
$13.12
72%
$/Mcfe
3.02
(0.05)
(0.34)
(0.59)
$2.04
68%
(1) Primarily condensate.
(2) Excludes the effects of financial derivatives but includes the effects of physical delivery contracts. See “Commodity Price Risk Management”.
(3) Represents plant and field operating expense.
(4) The increase in transportation and other expense was primarily due to transportation tolls for natural gas sold at the Dawn price during the twelve month Reporting Period. Birchcliff began selling natural
gas at the Dawn price on November 1, 2017.
(5) Operating margin is calculated by dividing the operating netback for the period by the petroleum and natural gas revenue for the period.
DISCUSSION OF OPERATIONS
Petroleum and Natural Gas Revenues
The following table sets forth Birchcliff’s P&NG revenues by product category for the Corporation’s Pouce Coupe operating
assets in the Montney/Doig Resource Play (the “Pouce Coupe assets”), the Corporation’s Gordondale operating assets in the
Montney/Doig Resource Play (the “Gordondale assets”) and on a corporate basis for the Reporting Periods and the Comparable
Prior Periods:
($000s)
Light oil(1)
Natural gas(1)
NGLs(1)
Total P&NG sales
Royalty revenue
Total P&NG revenues
% of corporate revenues
Three months ended
December 31, 2018
Three months ended
December 31, 2017
Pouce Coupe
assets
Gordondale
assets
Total
corporate(2)
Pouce Coupe
assets
Gordondale
assets
Total
corporate(3)
20
75,020
17,282
92,322
4
92,326
60%
18,208
26,226
17,902
62,336
23
62,359
40%
18,233
101,249
35,210
154,692
28
154,720
27
68,800
13,741
82,568
5
82,573
50%
33,186
24,450
25,350
82,986
45
83,031
50%
33,332
93,647
39,114
166,093
56
166,149
47
2018 Annual Report
($000s)
Light oil(1)
Natural gas(1)
NGLs(1)
Total P&NG sales
Royalty revenue
Total P&NG revenues
% of corporate revenues
Twelve months ended
December 31, 2018
Twelve months ended
December 31, 2017
Pouce Coupe
assets
Gordondale
assets
Total
corporate(2)
Pouce Coupe
assets
Gordondale
assets
Total
corporate(3)
225
247,793
77,419
325,437
18
121,622
84,629
88,798
295,049
107
122,118
332,979
166,194
621,291
130
163
108,593
224,402
38,170
262,735
14
88,373
64,189
261,155
260
134,597
318,790
103,244
556,631
311
325,455
295,156
621,421
262,749
261,415
556,942
52%
47%
47%
47%
(1) Excludes the effects of financial derivatives but includes the effects of physical delivery contracts.
(2) Includes revenue from Birchcliff’s other minor oil and natural gas properties which were not individually significant during the Reporting Periods.
(3) Includes revenues from other minor oil and natural gas properties which were not individually significant during the Comparable Prior Periods, and for the twelve month Comparable Prior Period,
also includes revenues from the Corporation’s oil-weighted Worsley Assets which were sold in August 2017.
Corporate P&NG revenues decreased 7% from the three month Comparable Prior Period largely due to lower production from
the Pouce Coupe and Gordondale assets and a lower corporate average realized sales price.
Corporate P&NG revenues increased 12% from the twelve month Comparable Prior Period largely due to higher production
from the Pouce Coupe and Gordondale assets, partially offset by a lower corporate average realized sales price and the
Worsley Disposition.
Production
The following table sets forth Birchcliff’s production by product category for the Pouce Coupe assets, the Gordondale assets
and on a corporate basis for the Reporting Periods and the Comparable Prior Periods:
Light oil (bbls/d)
Natural gas (Mcf/d)
NGLs (bbls/d)
Total production (boe/d)
Liquids(3)-to-gas ratio (bbls/MMcf)
% of corporate production
Light oil (bbls/d)
Natural gas (Mcf/d)
NGLs (bbls/d)
Total production (boe/d)
Liquids(3)-to-gas ratio (bbls/MMcf)
% of corporate production
Three months ended
December 31, 2018
Three months ended
December 31, 2017
Pouce Coupe
assets
Gordondale
assets
Total
corporate(1)
Pouce Coupe
assets
Gordondale
assets
Total
corporate(2)
7
266,774
3,484
47,953
13.1
63%
4,777
96,818
7,533
28,446
127.1
37%
4,788
5
363,596
282,084
11,021
76,408
43.5
2,119
49,138
7.5
61%
5,257
101,385
8,484
30,639
135.5
38%
5,283
385,280
10,607
80,103
41.2
Twelve months ended
December 31, 2018
Twelve months ended
December 31, 2017
Pouce Coupe
assets
Gordondale
assets
Total
corporate(1)
Pouce Coupe
assets
Gordondale
assets
Total
corporate(2)
9
276,004
2,933
48,943
10.7
63%
4,852
95,508
7,258
28,028
126.8
36%
4,873
372,170
10,195
77,096
40.5
8
224,561
1,657
39,092
7.4
58%
4,747
90,599
6,761
26,608
127.0
39%
6,004
320,927
8,471
67,963
45.1
(1) Includes production from Birchcliff’s other minor oil and natural gas properties which were not individually significant during the Reporting Periods.
(2) Includes production from other minor oil and natural gas properties which were not individually significant during the Comparable Prior Periods and, for the twelve month Comparable Prior Period,
also includes production from the Corporation’s oil-weighted Worsley Assets which were sold in August 2017.
(3) Liquids is comprised of oil and NGLs (ethane, propane, butane and pentanes plus).
48
2018 Annual Report
Corporate production averaged 76,408 boe/d in the three month Reporting Period and 77,096 boe/d in the twelve month
Reporting Period, a 5% decrease and 13% increase from the Comparable Prior Periods.
The decrease in corporate production from the three month Comparable Prior Period was primarily attributable to production
curtailments due to temporary restrictions in pipeline and compressor station capacity on the Alberta NGTL system and natural
production declines, partially offset by incremental production from new horizontal natural gas wells brought on production in
Pouce Coupe and new horizontal oil wells brought on production in Gordondale.
The increase in corporate production from the twelve month Comparable Prior Period was primarily attributable to the success
of Birchcliff’s capital programs which resulted in incremental production from new horizontal natural gas wells brought on
production in Pouce Coupe and new horizontal oil wells brought on production in Gordondale. This increase was partially offset by
the Worsley Disposition in the twelve month Comparable Prior Period, production curtailments due to temporary restrictions
in pipeline and compressor station capacity on the Alberta NGTL system and natural production declines.
During the three month Reporting Period, Birchcliff produced a total of 15,809 bbls/d of oil and NGLs (collectively, “liquids”)
on a corporate basis, which represented 21% of the Corporation’s total production and an average liquids-to-gas ratio of
43.5 bbls/MMcf. Birchcliff’s liquids-to-gas ratio for the three month Reporting Period was 13.1 bbls/MMcf for the Pouce Coupe
assets (of which 83% were higher-value oil and pentanes plus (“condensate”)) and 127.1 bbls/MMcf for the Gordondale assets
(of which 50% were higher-value oil and condensate). Birchcliff’s corporate NGLs production mix consisted of approximately
23% ethane, 23% propane, 15% butane and 39% condensate in the three month Reporting Period as compared to 28% ethane,
24% propane, 14% butane and 34% condensate in the three month Comparable Prior Period.
During the twelve month Reporting Period, Birchcliff produced a total of 15,068 bbls/d of liquids on a corporate basis, which
represented 20% of the Corporation’s total production and an average liquids-to-gas ratio of 40.5 bbls/MMcf. During the
twelve month Reporting Period, Birchcliff’s liquids-to-gas ratio was 10.7 bbls/MMcf for the Pouce Coupe assets (of which
93% were higher-value oil and condensate) and 126.8 bbls/MMcf for the Gordondale assets (of which 51% were higher-value
oil and condensate). Birchcliff’s corporate NGLs production mix consisted of approximately 24% ethane, 22% propane,
14% butane and 40% condensate in the twelve month Reporting Period as compared to 25% ethane, 26% propane, 16% butane
and 33% condensate in the twelve month Comparable Prior Period.
The following table sets forth Birchcliff’s production weighting by product category for its Pouce Coupe and Gordondale assets
and on a corporate basis for the Reporting Periods and the Comparable Prior Periods:
Three months ended
December 31, 2018
Three months ended
December 31, 2017
Pouce Coupe
assets
Gordondale
assets
Total
corporate(1)
Pouce Coupe
assets
Gordondale
assets
Total
corporate(2)
-
93%
7%
17%
57%
26%
6%
79%
15%
-
96%
4%
Twelve months ended
December 31, 2018
17%
55%
28%
7%
80%
13%
Twelve months ended
December 31, 2017
Pouce Coupe
assets
Gordondale
assets
Total
corporate(1)
Pouce Coupe
assets
Gordondale
assets
Total
corporate(2)
-
94%
6%
17%
57%
26%
6%
80%
14%
-
96%
4%
18%
57%
25%
9%
79%
12%
% Light oil production
% Natural gas production
% NGLs production
% Light oil production
% Natural gas production
% NGLs production
(1) Includes production weighting from Birchcliff’s other minor oil and natural gas properties which were not individually significant during the Reporting Periods.
(2) Includes production weighting from other minor oil and natural gas properties which were not individually significant during the Comparable Prior Periods and, for the twelve month Comparable Prior
Period, also includes production weighting from the Corporation’s oil-weighted Worsley Assets which were sold in August 2017.
Corporate oil production as a percentage of total production decreased from the twelve Comparable Prior Period largely due to
the Worsley Disposition.
Corporate NGLs production as a percentage of total production increased from the Comparable Prior Periods primarily due to
the addition of condensate-rich natural gas wells drilled in Pouce Coupe.
49
2018 Annual Report
Commodity Prices
The following table sets forth the average benchmark index prices and exchange rate for the Reporting Periods and the
Comparable Prior Periods:
Light oil – WTI Cushing (US$/bbl)
Light oil – WTI Cushing (CDN$/bbl)
Light oil – MSW (Mixed Sweet) (CDN$/bbl)(1)
Natural gas – NYMEX HH (US$/MMBtu)(2)
Natural gas – AECO 5A (CDN$/GJ)
Natural gas – AECO 5A (US$/MMBtu)(2)
Natural gas – Dawn Day Ahead (CDN$/GJ)
Natural gas – Dawn Day Ahead (US$/MMBtu)(2)
Natural gas – ATP 5A Day Ahead (CDN$/GJ)
Natural gas – Chicago City Gate (US$/MMBtu)(2)
Exchange rate (CDN$ to US$1)
Three months ended
December 31,
Twelve months ended
December 31,
2018
58.81
77.56
42.42
3.76
1.48
1.18
4.75
3.79
2.57
3.69
2017
55.40
70.47
68.62
2.92
1.60
1.33
3.53
2.93
1.16
2.88
2018
64.77
83.89
69.04
3.07
1.42
1.16
3.84
3.12
2.07
3.02
2017
50.95
66.11
62.52
3.02
2.04
1.66
3.74
3.04
2.02
2.90
1.3215
1.2717
1.2961
1.2979
(1) Previously referred to as the “Edmonton Par price”.
(2) $1.00/MMBtu = $1.00/Mcf based on a standard heat value Mcf. See “Advisories – MMBtu Pricing Conversions”.
Birchcliff sold substantially all of its light crude oil based on the MSW price during the Reporting Periods and Comparable Prior
Periods. Birchcliff sold substantially all of its natural gas production for prices based on the AECO and Dawn benchmark prices
during the Reporting Periods and sold substantially all of its natural gas production at the AECO benchmark price during the
first 10 months of 2017. Effective November 1, 2017, Birchcliff began selling a portion of its natural gas at the Dawn benchmark
price (see “Natural Gas Sales, Production and Average Realized Sales Price” for further details). Birchcliff has also financially
diversified a portion of its AECO production to NYMEX-based pricing (see “Commodity Price Risk Management”). The average
realized sales prices the Corporation receives for its light crude oil and natural gas production depends on a number of factors,
including the average benchmark prices for crude oil and natural gas, the US to Canadian dollar exchange rate, transportation
and product quality differentials and the heat premium on its natural gas production.
The benchmark prices for crude oil are impacted by global and regional events that dictate the level of supply and demand for
crude oil. The principal benchmark trading exchanges that Birchcliff compares its oil price to are the WTI oil price and the MSW
price. The differential between the WTI oil price and the MSW price can widen due to a number of factors, including, but not
limited to, downtime in North American refineries, rising domestic production, high inventory levels in North America and a
lack of pipeline infrastructure connecting to key consuming oil markets. The improved WTI benchmark crude oil prices in the
Reporting Periods was partially offset by the widening differential between WTI and MSW prices, which averaged CDN$35.14/bbl
and CDN$14.85/bbl in the three and twelve month Reporting Periods, respectively, compared to CDN$1.85/bbl and CDN$3.59/bbl
in the Comparable Prior Periods.
50
2018 Annual Report Canadian natural gas prices are mainly influenced by North American supply and demand fundamentals which can be impacted
by a number of factors, including, but not limited to, weather-related conditions in key consuming natural gas markets,
changing demographics, economic growth, underground storage levels, net import and export markets, pipeline takeaway
capacity, maintenance on key natural gas infrastructure, cost of competing renewable and non-renewable energy alternatives,
drilling and completion rates and efficiencies in extracting natural gas from North American natural gas basins. AECO natural
gas spot prices during the three month Reporting Period continued to receive a significant discount to the Dawn and NYMEX HH
prices primarily due to the high natural gas supplies in Western Canada relative to the limited economic transportation and
egress solutions out of Western Canadian natural gas basins. During the three month Reporting Period, AECO natural gas spot
prices were additionally challenged due to temporary restrictions in pipeline egress and compressor station capacity on the
Alberta NGTL system.
The following table sets forth Birchcliff’s average realized oil, natural gas and NGLs sales prices for the Reporting Periods and
the Comparable Prior Periods:
($/boe)
Light oil ($/bbl)
Natural gas ($/Mcf)
NGLs ($/bbl)
Average realized sales price ($/boe)(1)
Three months ended
December 31,
Twelve months ended
December 31,
2018
41.39
3.03
34.73
22.01
2017
68.58
2.64
40.08
22.54
Change
(40)%
15%
(13)%
(2)%
2018
68.66
2.45
44.66
22.08
2017
61.42
2.72
33.39
22.44
Change
12%
(10)%
34%
(2)%
(1) Excludes the effects of financial derivatives but includes the effects of physical delivery contracts.
The changes in the average realized sales prices from the Comparable Prior Periods were primarily the result of the movement
in the average benchmark index price for each respective commodity.
The average realized sales price for the Pouce Coupe assets was $20.93/boe in the three month Reporting Period and $18.22/boe
in the twelve month Reporting Period, a 15% increase and a 1% decrease, respectively, from the Comparable Prior Periods. The
average realized sales price for the Gordondale assets was $23.82/boe in the three month Reporting Period and $28.84/boe
in the twelve month Reporting Period, a 19% decrease and a 7% increase, respectively, from the Comparable Prior Periods.
The Gordondale assets received a higher average realized sales price compared to the Pouce Coupe assets, largely as a result
of higher volume weighting of liquids produced in the Gordondale area which received a higher value on a per unit basis
than Birchcliff’s natural gas sales. The higher weighting of liquids in the total corporate production mix generally improves
Birchcliff’s overall average realized sales price.
For further production and average realized pricing details for Birchcliff’s Pouce Coupe assets and Gordondale assets,
see “Discussion of Operations – Operating Netbacks” in this MD&A.
51
2018 Annual Report Natural Gas Sales, Production and Average Realized Sales Price
The following table sets forth Birchcliff’s natural gas sales, production and average realized sales price by natural gas market
for the Reporting Periods and the Comparable Prior Periods:
Three months ended
December 31, 2018
Three months ended
December 31, 2017
Natural
gas sales
($000s)(1)
33,788
64,969
2,492
Natural gas
production
(Mcf/d)
223,261
127,211
13,124
(%)
33
64
3
(%)
61
35
4
101,249 100
363,596 100
Average
realized
natural
gas price
($/Mcf)(1)(2)
1.67
5.55
2.06
3.03
Natural
gas sales
($000s)(1)
57,778
26,531
9,338
Natural gas
production
(Mcf/d)
266,437
73,222
45,621
(%)
62
28
10
(%)
69
19
12
93,647
100
385,280 100
Average
realized
natural
gas price
($/Mcf)(1)(2)
2.34
3.94
2.22
2.64
Twelve months ended
December 31, 2018
Twelve months ended
December 31, 2017
Natural
gas sales
($000s)(1)
132,342
182,385
18,252
Natural gas
production
(Mcf/d)
229,225
114,110
28,835
(%)
40
55
5
(%)
61
31
8
332,979 100
372,170 100
Average
realized
natural
gas price
($/Mcf)(1)(2)
1.59
4.38
1.73
2.45
Natural
gas sales
($000s)(1)
280,274
26,531
11,985
Natural gas
production
(Mcf/d)
285,977
18,456
16,494
(%)
88
8
4
(%)
89
6
5
318,790 100
320,927
100
Average
realized
natural
gas price
($/Mcf)(1)(2)
2.67
3.94
1.99
2.72
AECO
Dawn(3)
Alliance(4)
Total
AECO
Dawn(3)
Alliance(4)
Total
(1) Excludes the effects of financial derivatives but includes the effects of physical delivery contracts.
(2) Reflects the average realized natural gas wellhead price after adjusting for fuel to transport natural gas from the field receipt point to the delivery sales trading hub.
(3) The Corporation has in place firm service transportation for an aggregate of 175,000 GJ/d of natural gas on TCPL’s Canadian Mainline for a 10-year term, whereby natural gas is transported to the
Dawn trading hub. The first 120,000 GJ/d tranche of service became available to Birchcliff on November 1, 2017 and the second tranche of 30,000 GJ/d became available on November 1, 2018, with an
additional 25,000 GJ/d becoming available on November 1, 2019. During the three month Reporting Period, Birchcliff entered into physical delivery sales contracts at Dawn for 50,000 MMBtu/d at an
average contract price of US$5.05/MMBtu for the period from December 1, 2018 to March 31, 2019.
(4) Birchcliff has in place various natural gas delivery arrangements with third party marketers to deliver and sell natural gas on the Alliance pipeline system. Alliance sales are recorded net of transportation tolls.
Commodity Price Risk Management
Birchcliff maintains an ongoing commodity price risk management program in part to reduce volatility in its financial results. As
a part of this program, Birchcliff utilizes various financial derivative and physical delivery sales contracts. Subject to compliance
with the Corporation’s credit facilities, the Board has authorized the Corporation to execute a risk management strategy
whereby Birchcliff is authorized to enter into agreements and financial or physical transactions with one or more counterparties
from time to time that are intended to protect the Corporation from volatility in future commodity prices, foreign exchange
rates and/or interest rates.
Financial Derivative Contracts
Birchcliff has not designated its financial derivative contracts as effective accounting hedges, even though the Corporation
considers all commodity price contracts to be effective economic hedges. As a result, all such financial derivative contracts are
recorded on the statement of financial position on a mark-to-market fair value basis at December 31, 2018, with the changes
in fair value being recognized as a non-cash unrealized gain or loss in profit or loss. These contracts are not entered into for
trading or speculative purposes.
52
2018 Annual Report
As at December 31, 2018, Birchcliff had the following financial derivative contracts in place in order to manage commodity
price risk:
Product
Type of contract
Notional quantity
Term(1)
Contract price
Natural gas
AECO 7A basis swap(2)
30,000 MMBtu/d
Jan. 1, 2019 – Dec. 31, 2023
NYMEX HH less US$1.298/MMBtu
Natural gas
AECO 7A basis swap(2)
10,000 MMBtu/d
Jan. 1, 2019 – Dec. 31, 2023
NYMEX HH less US$1.32/MMBtu
Natural gas
AECO 7A basis swap(2)
30,000 MMBtu/d
Jan. 1, 2019 – Dec. 31, 2023
NYMEX HH less US$1.33/MMBtu
Natural gas
AECO 7A basis swap(2)
15,000 MMBtu/d
Jan. 1, 2019 – Dec. 31, 2024
NYMEX HH less US$1.185/MMBtu
Natural gas
AECO 7A basis swap(2)
5,000 MMBtu/d
Jan. 1, 2019 – Dec. 31, 2024
NYMEX HH less US$1.20/MMBtu
Natural gas
AECO 7A basis swap(2)
5,000 MMBtu/d
Jan. 1, 2019 – Dec. 31, 2024
NYMEX HH less US$1.20/MMBtu
Natural gas
AECO 7A basis swap(3)
10,000 MMBtu/d
Jan. 1, 2019 – Mar. 31, 2019
NYMEX HH less US$3.10/MMBtu
Natural gas
AECO 7A basis swap(3)
10,000 MMBtu/d
Jan. 1, 2019 – Mar. 31, 2019
NYMEX HH less US$3.15/MMBtu
Natural gas
AECO 7A basis swap(3)
30,000 MMBtu/d
Jan. 1, 2019 – Mar. 31, 2019
NYMEX HH less US$3.16/MMBtu
(1) Transactions with common terms and the same counterparty have been aggregated and presented at the weighted average price.
(2) Birchcliff sold AECO basis swap.
(3) Birchcliff bought AECO basis swap.
The following table provides a summary of the realized and unrealized gains (losses) on financial derivative contracts for the
Reporting Periods and the Comparable Prior Periods:
Realized gain (loss) on derivatives
Unrealized gain (loss) on derivatives
Three months ended
December 31,
Twelve months ended
December 31,
($000s)
1,658
77,443
2018
($/boe)
0.24
11.02
($000s)
10,787
2017
($/boe)
($000s)
2018
($/boe)
($000s)
1.46
(15,771)
(0.56)
25,785
(13,712)
(1.86)
64,222
2.28
5,387
2017
($/boe)
1.03
0.22
Birchcliff realized a cash loss on financial commodity price risk management contracts of $15.8 million in the twelve month
Reporting Period as compared to a realized cash gain of $25.8 million in the Comparable Prior Period. The realized loss was due
to the settlement of WTI fixed price financial contracts with an average contract price that was below the average benchmark
commodity index price in that period. This loss was partially offset by a realized gain of $4.0 million recorded in the three
month Reporting Period due to the monetization of Birchcliff’s outstanding 2019 WTI fixed price financial contracts.
Birchcliff recorded a $64.2 million unrealized mark-to-market gain on financial commodity price risk management contracts in the
twelve month Reporting Period as compared to a $5.4 million unrealized gain in the Comparable Prior Period. The unrealized gain
was due to an increase in the fair value of Birchcliff’s financial contracts to an asset position of $60.2 million at December 31, 2018,
as compared to a liability position of $4.0 million at December 31, 2017. The increase in the fair value of Birchcliff’s financial
contracts was primarily attributable to the addition of the multi-year AECO/NYMEX basis swap contracts entered into during the
twelve month Reporting Period and the settlement of the WTI fixed price financial contracts during the Reporting Periods. Any
changes in the forward commodity price assumptions period-over-period will also be reflected in the unrealized gain or loss
for unsettled financial risk management contracts. The fair value of the asset or liability is the estimated value to settle the
outstanding contracts at a point in time. As such, unrealized financial gains or losses do not impact adjusted funds flow and the
actual gains or losses realized on eventual cash settlement can vary materially due to subsequent fluctuations in commodity
prices as compared to the valuation assumptions.
53
2018 Annual Report The following financial derivative contracts were entered into subsequent to December 31, 2018:
Product
Type of contract
Notional quantity
Term(1)
Contract price
Natural gas
AECO 7A basis swap(2)
10,000 MMBtu/d
Jan. 1, 2025 – Dec. 31, 2025
NYMEX HH less US$1.020/MMBtu
Natural gas
AECO 7A basis swap(2)
20,000 MMBtu/d
Jan. 1, 2024 – Dec. 31, 2025
NYMEX HH less US$1.119/MMBtu
Natural gas
AECO 7A basis swap(2)
25,000 MMBtu/d
Jan. 1, 2024 – Dec. 31, 2025
NYMEX HH less US$1.135/MMBtu
Natural gas
AECO 7A basis swap(2)
5,000 MMBtu/d
Jan. 1, 2021 – Dec. 31, 2025
NYMEX HH less US$1.178/MMBtu
Natural gas
AECO 7A basis swap(2)
10,000 MMBtu/d
Jan. 1, 2021 – Dec. 31, 2025
NYMEX HH less US$1.175/MMBtu
Natural gas
AECO 7A basis swap(2)
5,000 MMBtu/d
Jan. 1, 2021 – Dec. 31, 2025
NYMEX HH less US$1.190/MMBtu
(1) Transactions with common terms and the same counterparty have been aggregated and presented at the weighted average price.
(2) Birchcliff sold AECO basis swap.
Physical Delivery Sales Contracts
Birchcliff also enters into physical delivery sales contracts to manage commodity price risk. These contracts are considered
normal executory sales contracts and are not recorded at fair value through profit or loss. At December 31, 2018, the
Corporation had the following physical delivery sales contract in place:
Product
Type of contract
Notional quantity
Term(1)
Contract price
Natural gas
AECO 7A basis swap(2)
5,000 MMBtu/d
Jan. 1, 2019 – Dec. 31, 2023
NYMEX HH less US$1.205/MMBtu
Natural gas
Dawn fixed price(3)
5,000 MMBtu/d
Jan. 1, 2019 – Mar. 31, 2019
US$5.100/MMBtu
Natural gas
Dawn fixed price(3)
10,000 MMBtu/d
Jan. 1, 2019 – Mar. 31, 2019
US$5.000/MMBtu
Natural gas
Dawn fixed price(3)
10,000 MMBtu/d
Jan. 1, 2019 – Mar. 31, 2019
US$5.005/MMBtu
Natural gas
Dawn fixed price(3)
10,000 MMBtu/d
Jan. 1, 2019 – Mar. 31, 2019
US$5.020/MMBtu
Natural gas
Dawn fixed price(3)
15,000 MMBtu/d
Jan. 1, 2019 – Mar. 31, 2019
US$5.103/MMBtu
(1) Transactions with common terms and the same counterparty have been aggregated and presented at the weighted average price.
(2) Birchcliff sold AECO basis swap.
(3) Birchcliff entered into a 4-month fixed price physical natural gas Dawn sales arrangement commencing December 1, 2018.
There were no long-term physical delivery sales contracts entered into subsequent to December 31, 2018.
Royalties
The following table sets forth Birchcliff’s royalty expense for the Reporting Periods and the Comparable Prior Periods:
Royalty expense ($000s)(1)
Royalty expense ($/boe)
Effective royalty rate (%)(2)
Three months ended
December 31,
Twelve months ended
December 31,
2018
6,763
0.96
4%
2017
9,271
1.26
6%
2018
38,306
1.36
6%
2017
28,727
1.16
5%
(1) Royalties are paid primarily to the Government of Alberta.
(2) The effective royalty rate is calculated by dividing the aggregate royalties into petroleum and natural gas sales for the period.
During the three month Reporting Period, Birchcliff’s aggregate and per unit royalties decreased from the Comparable Prior
Period primarily due to a decrease in the average realized oil and NGLs sales prices and the effect these lower prices have on
the sliding scale royalty calculation, partially offset by an increase in the average realized natural gas sales price.
During the twelve month Reporting Period, Birchcliff’s aggregate and per unit royalties increased from the Comparable Prior
Period primarily due to an increase in the average realized oil and NGLs sales prices and the effect these higher prices have on
the sliding scale royalty calculation, partially offset by a decrease in the average realized natural gas sales price.
See “Discussion of Operations – Operating Netbacks” in this MD&A for details on royalties for the Corporation’s Pouce Coupe
and Gordondale assets.
54
2018 Annual Report Operating Expense
The following table sets forth a breakdown of Birchcliff’s operating expense for the Reporting Periods and the Comparable
Prior Periods:
Field operating expense
Recoveries
Field operating expense, net
Expensed workovers and other
Operating expense
Three months ended
December 31,
Twelve months ended
December 31,
2018
2017
2018
2017
($000s)
($/boe)
($000s)
($/boe)
($000s)
($/boe)
($000s)
($/boe)
25,705
3.66
28,901
3.92
102,099
3.63
112,287
4.53
(1,028)
(0.15)
(523)
(0.07)
(2,995)
(0.11)
(1,917)
(0.08)
24,677
3.51
28,378
-
-
82
24,677
3.51
28,460
3.85
0.01
3.86
99,104
3.52
110,370
4.45
-
-
116
-
99,104
3.52
110,486
4.45
On an aggregate and per unit basis, operating expense decreased in the Reporting Periods as compared to the Comparable
Prior Periods primarily due to: (i) an incremental increase in natural gas production processed at the Pouce Coupe Gas Plant;
(ii) a reduction in third-party natural gas processing fees at the Gordondale Gas Plant as a result of the Gordondale Processing
Arrangement; and (iii) the sale of the higher-cost Worsley Assets in August 2017.
See “Discussion of Operations – Operating Netbacks” in this MD&A for details on operating expense for the Pouce Coupe assets
and Gordondale assets.
Transportation and Other Expense
The following table sets forth Birchcliff’s transportation and other expense for the Reporting Periods and the Comparable
Prior Periods:
Transportation
Fractionation
Other
Three months ended
December 31,
Twelve months ended
December 31,
2018
2017
2018
2017
($000s)
($/boe)
($000s)
($/boe)
($000s)
($/boe)
($000s)
($/boe)
28,014
521
32
3.99
0.08
-
25,852
3.52
99,889
-
31
-
-
3,533
125
3.55
0.13
-
71,098
2.87
-
126
-
-
Transportation and other expense(1)
28,567
4.07
25,883
3.52
103,547
3.68
71,224
2.87
(1) Previously referred to as “transportation and marketing expense” in the Comparable Prior Periods.
The increase in the aggregate and per unit transportation and other expense from the Comparable Prior Periods was largely
due to firm service pipeline transportation tolls for natural gas transported to Dawn which commenced November 1, 2017 and
new unused firm transportation costs associated with Birchcliff’s commitments on the NGTL system, which is available for
future production growth. Additionally, fractionation fees associated with NGLs production processed at third-party facilities
were reclassified from NGLs revenue for the Reporting Periods as a result of Birchcliff’s transition to IFRS 15: Revenue from Contracts
with Customers (“IFRS 15”) effective January 1, 2018. See “Changes in Accounting Policies” in this MD&A for further details.
See “Discussion of Operations – Operating Netbacks” in this MD&A for details on transportation and other expense for the
Pouce Coupe assets and Gordondale assets.
Operating Netback
The following table sets forth Birchcliff’s net production and operating netback for the Corporation’s assets in Pouce Coupe
and Gordondale on the Montney/Doig Resource Play and on a corporate basis for the Reporting Periods and the Comparable
Prior Periods:
55
2018 Annual Report Pouce Coupe Montney/Doig Resource Play:
Average production:
Light oil (bbls/d)
Natural gas (Mcf/d)
NGLs (bbls/d)
Total (boe/d)
% of corporate production
Liquids(1)-to-gas ratio (bbls/MMcf)
Netback and cost ($/boe):
Petroleum and natural gas revenue(2)
Royalty expense
Operating expense
Transportation and other expense
Operating netback
Gordondale Montney/Doig Resource Play:
Average production:
Light oil (bbls/d)
Natural gas (Mcf/d)
NGLs (bbls/d)
Total (boe/d)
% of corporate production
Liquids(3)-to-gas ratio (bbls/MMcf)
Netback and cost ($/boe):
Petroleum and natural gas revenue(2)
Royalty expense
Operating expense
Transportation and other expense
Operating netback
Total Corporate:
Average production:
Light oil (bbls/d)
Natural gas (Mcf/d)
NGLs (bbls/d)
Total (boe/d)(4)
Liquids(3)-to-gas ratio (bbls/MMcf)
Netback and cost ($/boe):
Petroleum and natural gas revenue(2)
Royalty expense
Operating expense
Transportation and other expense
Operating netback
Three months ended
December 31,
2017
2018
Twelve months ended
December 31,
2017
2018
7
4
9
7
266,774
282,084
276,004
224,561
3,484
47,953
63%
13.1
20.93
(0.33)
(2.29)
(4.16)
14.15
4,777
96,818
7,533
28,446
37%
127.1
23.83
(2.04)
(5.55)
(3.91)
12.33
2,120
49,138
61%
7.5
18.27
(0.50)
(2.37)
(3.69)
11.71
5,257
101,385
8,484
30,639
38%
135.5
29.46
(2.50)
(6.15)
(3.27)
17.54
2,933
48,943
63%
10.7
18.22
(0.29)
(2.28)
(3.59)
12.06
4,852
95,508
7,258
28,028
36%
126.8
28.85
(3.23)
(5.63)
(3.84)
16.15
1,658
39,092
58%
7.4
18.41
(0.40)
(2.66)
(2.68)
12.67
4,747
90,599
6,761
26,608
39%
127.0
26.92
(2.07)
(6.32)
(2.93)
15.60
4,788
5,283
4,873
6,004
363,596
385,280
372,170
320,927
11,021
76,408
43.5
22.01
(0.96)
(3.51)
(4.07)
13.47
10,607
80,103
41.2
22.55
(1.26)
(3.86)
(3.52)
13.91
10,195
77,096
40.5
22.08
(1.36)
(3.52)
(3.68)
13.52
8,471
67,963
45.1
22.45
(1.16)
(4.45)
(2.87)
13.97
(1) Primarily condensate.
(2) Excludes the effects of financial derivatives but includes the effects of physical delivery contracts.
(3) Liquids is comprised of oil and NGLs (ethane, propane, butane and condensate).
(4) Includes production from Birchcliff’s other minor oil and natural gas properties which were not individually significant and, for the twelve month Comparable Prior Period, also includes production from
the Corporation’s oil-weighted Worsley Assets which were sold in August 2017.
56
2018 Annual Report Pouce Coupe Montney/Doig Resource Play
Birchcliff’s average production from its Pouce Coupe assets was 47,953 boe/d in the three month Reporting Period and 48,943 boe/d
in the twelve month Reporting Period, a 2% decrease and 25% increase, respectively, from the Comparable Prior Periods.
The decrease in the three month Reporting Period was primarily attributable to production curtailments due to temporary
restrictions in pipeline and compressor station capacity on the Alberta NGTL system and natural production declines, partially
offset by incremental production from new horizontal natural gas wells being brought on production. The increase in the twelve
month Reporting Period was primarily attributable to the success of Birchcliff’s capital programs which resulted in incremental
production from new horizontal natural gas wells being brought on production in connection with the start-up of Phase V and
Phase VI of the Pouce Coupe Gas Plant, partially offset by production curtailments due to temporary restrictions in pipeline and
compressor station capacity on the Alberta NGTL system and natural production declines in the Reporting Period.
Birchcliff’s liquids-to-gas ratio for the Pouce Coupe assets was 13.1 bbls/MMcf in the three month Reporting Period and
10.7 bbls/MMcf in the twelve month Reporting Period as compared to 7.5 bbls/MMcf and 7.4 bbls/MMcf, respectively, in
the Comparable Prior Periods. During the Reporting Periods, Birchcliff specifically targeted condensate-rich natural gas wells
in Pouce Coupe which resulted in the increase in liquids-to-gas ratio from the Comparable Prior Periods. During the three
month Reporting Period, approximately 83% of the liquids produced in the Pouce Coupe area were comprised of higher-value
condensate which received an average price of $58.03/bbl. During the twelve month Reporting Period, approximately 93%
of the liquids produced in the Pouce Coupe area were comprised of higher-value condensate which received an average price
of $75.16/bbl.
Operating expense for the Pouce Coupe assets was $2.29/boe in the three month Reporting Period and $2.28/boe in the
twelve month Reporting Period, a 3% and 14% decrease, respectively, from the Comparable Prior Periods. Operating expense
per boe decreased largely due to an incremental increase in natural gas production processed through the Pouce Coupe Gas
Plant during the Reporting Periods.
Transportation and other expense for the Pouce Coupe assets was $4.16/boe in the three month Reporting Period and
$3.59/boe in the twelve month Reporting Period, a 13% and 34% increase, respectively, from the Comparable Prior Periods.
Transportation and other expense per boe increased mainly due to firm service pipeline transportation tolls for natural
gas transported to Dawn which commenced November 1, 2017 and new unused firm transportation costs associated with
Birchcliff’s commitments on the NGTL system, which is available for future production growth.
Birchcliff’s operating netback for the Pouce Coupe assets was $14.15/boe in the three month Reporting Period and $12.06/boe
in the twelve month Reporting Period, a 21% increase and 5% decrease, respectively, from the Comparable Prior Periods. The
increase in the three month Reporting Period was largely due to a higher average realized sales price received for Birchcliff’s
Pouce Coupe production and lower per boe royalty and operating expenses, partially offset by higher per boe transportation
and other expense. The decrease in the twelve month Reporting Period was largely due to a lower average realized sales price
received for Birchcliff’s Pouce Coupe production and higher per boe transportation and other expense, partially offset by lower
per boe royalty and operating expenses during the Reporting Period.
Gordondale Montney/Doig Resource Play
Birchcliff’s average production from the Gordondale assets was 28,446 boe/d in the three month Reporting Period and 28,028 boe/d
in the twelve month Reporting Period, a 7% decrease and 5% increase, respectively, from the Comparable Prior Periods.
The decrease in the three month Reporting Period was primarily attributable to production curtailments due to temporary
restrictions in pipeline and compressor station capacity on the Alberta NGTL system and natural production declines, partially
offset by incremental production from new horizontal oil wells being brought on production. The increase in production in
the twelve month Reporting Period was primarily attributable to the success of Birchcliff’s capital programs which resulted in
incremental production from new horizontal oil wells being brought on production, partially offset by production curtailments
due to temporary restrictions in pipeline and compressor station capacity on the Alberta NGTL system and natural production
declines in the Reporting Period.
Birchcliff’s liquids-to-gas ratio for the Gordondale assets was 127.1 bbls/MMcf in the three month Reporting Period and
126.8 bbls/MMcf in the twelve month Reporting Period as compared to 135.5 bbls/MMcf and 127.0 bbls/MMcf, respectively,
in the Comparable Prior Periods. During the three month Reporting Period, approximately 50% of the liquids produced in
Gordondale were comprised of higher-value oil and condensate which received an average price of $43.58/bbl. Birchcliff’s
Gordondale NGLs production mix consisted of approximately 34% ethane, 31% propane, 18% butane and 17% condensate
in the three month Reporting Period. During the twelve month Reporting Period, approximately 51% of the liquids produced
in Gordondale were comprised of higher-value oil and condensate which received an average price of $71.57/bbl. Birchcliff’s
Gordondale NGLs production mix consisted of approximately 33% ethane, 30% propane, 18% butane and 19% condensate in
the twelve month Reporting Period.
57
2018 Annual Report Operating expense for the Gordondale assets was $5.55/boe in the three month Reporting Period and $5.63/boe in the twelve
month Reporting Period, a 10% and 11% decrease, respectively, from the Comparable Prior Periods. The decrease in operating
expense for the Reporting Periods was primarily attributable to the reduction in third-party natural gas processing fees at the
Gordondale Gas Plant as a result of the Gordondale Processing Arrangement.
Transportation and other expense for the Gordondale assets was $3.91/boe in the three month Reporting Period and
$3.84/boe in the twelve month Reporting Period, a 20% and 31% increase respectively, from the Comparable Prior Periods.
Transportation and other expense per boe increased mainly due to firm service pipeline transportation tolls for natural
gas transported to Dawn which commenced November 1, 2017 and new unused firm transportation costs associated with
Birchcliff’s commitments on the NGTL system, which is available for future production growth.
Birchcliff’s operating netback for the Gordondale assets was $12.33/boe in the three month Reporting Period and $16.15/boe
in the twelve month Reporting Period, a 30% decrease and 4% increase, respectively, from the Comparable Prior Periods.
The decrease in the three month Reporting Period was largely due a lower average realized sales price received for Birchcliff’s
Gordondale liquids production and higher per boe transportation and other expense, partially offset by lower per boe royalty
and operating expenses. The increase in the twelve month Reporting Period was largely due to a higher average realized sales
price received for Birchcliff’s Gordondale production and lower per boe operating expense, partially offset by higher per boe
royalty expense and transportation and other expense.
Administrative Expense
The following table sets forth the components of Birchcliff’s net administrative expense for the Reporting Periods and the
Comparable Prior Periods:
Cash:
Salaries and benefits(1)
Other(2)
Operating overhead recoveries
Capitalized overhead(3)
G&A expense, net
G&A expense, net per boe
Non-cash:
Other compensation(4)
Capitalized compensation(3)
Other compensation, net
Other compensation, net per boe
Administrative expense, net
Administrative expense, net per boe
Three months ended
December 31,
Twelve months ended
December 31,
2018
(%)
75
25
100
(1)
(48)
51
100
(43)
57
($000s)
11,131
3,683
14,814
(33)
(7,163)
7,618
$1.08
9,668
(4,175)
5,493
$0.78
13,111
$1.86
($000s)
13,451
2,832
16,283
(52)
(6,781)
9,450
$1.28
2,370
(1,376)
994
$0.13
10,444
$1.41
2017
(%)
83
17
100
(1)
(41)
58
100
(58)
42
2017
(%)
70
30
100
(1)
(40)
59
100
(59)
41
($000s)
28,618
13,329
41,947
(150)
2018
(%)
68
32
100
(1)
($000s)
31,437
13,498
44,935
(202)
(17,195)
(40)
(18,229)
24,602
$0.87
14,758
(7,061)
7,697
$0.27
32,299
$1.14
59
26,504
100
(48)
52
$1.07
9,945
(5,886)
4,059
$0.16
30,563
$1.23
(1) Includes salaries, benefits and bonuses paid to officers and employees of the Corporation and retainer fees, meeting fees and benefits paid to directors of the Corporation.
(2) Includes costs such as rent, legal, tax, insurance, minor computer hardware and software and other business expenses incurred by the Corporation.
(3) Includes a portion of gross general and administrative expenses and other compensation directly attributable to the exploration and development activities of the Corporation, which have been capitalized.
(4) Birchcliff recorded a post-employment benefit expense of $7.8 million in the Reporting Periods (2017 - $nil).
On an aggregate basis, administrative expense for the three and twelve month Reporting Periods increased 26% and 6%,
respectively, from the Comparable Prior Periods. The increases were primarily due to the establishment of a post-employment
benefit plan for eligible employees, which provides for post-employment benefits based upon the age at retirement and
their period of service with Birchcliff. During the Reporting Periods, Birchcliff recorded a post-employment benefit expense
of $7.8 million (2017 - $nil). The increases were partially offset by lower net stock-based compensation expense in the
Reporting Periods, which reflects stock options with a lower fair value being expensed in the Reporting Periods as compared
to the Comparable Prior Periods. Birchcliff uses the fair-value method for the determination of non-cash related share-based
payments expense.
58
2018 Annual Report The following table sets forth the Corporation’s outstanding stock options for the Reporting Periods and the Comparable
Prior Periods:
Outstanding, beginning of period
Granted(1)
Exercised
Forfeited
Expired
Outstanding, end of period
(1) Each stock option granted entitles the holder to purchase one common share at the exercise price.
(2) Exercise price is calculated on a weighted average basis.
Outstanding, beginning of period
Granted(1)
Exercised
Forfeited
Expired
Outstanding, end of period
(1) Each stock option granted entitles the holder to purchase one common share at the exercise price.
(2) Exercise price is calculated on a weighted average basis.
Three months ended
December 31, 2018
Three months ended
December 31, 2017
Number
16,000,070
140,500
(26,000)
(10,000)
(257,000)
15,847,570
Exercise
price($)(2)
5.78
4.59
(3.35)
(5.03)
(7.46)
Number
14,378,009
137,000
(8,000)
(148,734)
(200,168)
5.74
14,158,107
Exercise
price($)(2)
6.90
4.96
(3.35)
(6.73)
(7.75)
6.88
Twelve months ended
December 31, 2018
Twelve months ended
December 31, 2017
Number
14,158,107
4,734,900
(114,664)
(483,405)
(2,447,368)
15,847,570
Exercise
price($)(2)
6.88
3.23
(3.35)
(5.59)
(7.57)
Number
12,899,775
4,867,400
(1,754,796)
(1,606,437)
(247,835)
5.74
14,158,107
Exercise
price($)(2)
6.45
7.67
(5.33)
(7.49)
(7.55)
6.88
At December 31, 2018, there were also 2,939,732 performance warrants outstanding with an exercise price of $3.00 which
expire on January 31, 2020.
Depletion and Depreciation Expense
Depletion and depreciation (“D&D”) expense is a function of the estimated proved plus probable reserve additions, the finding
and development costs attributable to those reserves, the associated future development costs required to recover those
reserves and the actual production in the relevant period. The Corporation determines its D&D expense on a field area basis.
The following table sets forth Birchcliff’s D&D expense for the Reporting Periods and the Comparable Prior Periods:
Three months ended
December 31,
Twelve months ended
December 31,
2018
2017
2018
2017
($000s)
($/boe)
($000s)
($/boe)
($000s)
($/boe)
($000s)
($/boe)
Depletion and depreciation expense
51,274
7.29
57,920
7.86
208,868
7.42
185,666
7.48
D&D expense on an aggregate basis for the three month Reporting Period was lower as compared to the Comparable Prior
Period mainly due to a decrease in production. D&D expense on an aggregate basis for the twelve month Reporting Period was
higher as compared to the Comparable Prior Period mainly due to an increase in production.
Included in the depletion calculation at December 31, 2018 were 1,002,070 Mboe of proved plus probable reserves and
$4.3 billion of future development costs required to recover those reserves as estimated by the Corporation’s independent
qualified reserves evaluators.
59
2018 Annual Report Asset Impairment Assessment
The Corporation reviews its petroleum and natural gas assets for impairment in accordance with International Accounting
Standards (“IAS”) 36 under IFRS. Birchcliff’s assets are grouped into cash generating units (“CGU”) for the purpose of
determining impairment. A CGU represents 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. In determining the Corporation’s CGUs,
the Corporation takes into consideration all available information, including, but not limited to: geographical proximity;
geological similarities (i.e. reservoir characteristics and production profiles); degree of shared infrastructure; independent
versus interdependent cash flows; operating structure; the regulatory environment; management decision-making; and
overall business strategy.
The Corporation’s CGUs are reviewed at each reporting date for both internal and external indicators of potential impairment.
Potential CGU impairment indicators include, but are not limited to: changes to Birchcliff’s business plan; deterioration in
commodity prices; negative changes in the technological, economic, legal, capital or operating environment; adverse changes
to the physical condition of a CGU; current expectations that a material CGU (or a significant component thereof) is more
likely than not to be sold or otherwise disposed of before the end of its previously estimated useful life; non-compliance with
the agreements governing the Corporation’s bank credit facilities; deterioration in the financial and operational performance
of a CGU; net assets exceeding market capitalization; and significant downward revisions of estimated proved plus probable
reserves of a CGU. If impairment indicators exist, an impairment test is performed by comparing a CGU’s carrying value to
its recoverable amount.
In light of industry conditions, Birchcliff determined there were impairment indicators present at December 31, 2018 and
December 31, 2017. Birchcliff performed an impairment assessment on a CGU basis and determined that the carrying value
of its P&NG properties and equipment was recoverable. Birchcliff’s P&NG properties and equipment were not impaired at
December 31, 2018 and December 31, 2017.
Management has determined that the calculation of the recoverable amount is most sensitive to key assumptions regarding
discount rates, commodity prices and estimated quantities of proved plus probable reserves and the future production profile
of those reserves. Each of these underlying key assumptions is reviewed by management and corroborated independently
to assess for reasonableness. The P&NG future prices are based on period-end commodity price forecast assumptions
determined by the Corporation’s independent reserves evaluator.
Finance Expense
The following table sets forth the components of the Corporation’s finance expense for the Reporting Periods and the
Comparable Prior Periods:
Three months ended
December 31,
Twelve months ended
December 31,
2018
2017
2018
2017
($000s)
($/boe)
($000s)
($/boe)
($000s)
($/boe)
($000s)
($/boe)
Cash:
Interest expense on credit facilities(1)
7,437
1.06
7,131
0.97
27,969
0.99
28,374
1.14
Non-cash:
Accretion(2)
Amortization of deferred financing fees
Finance expense
811
374
8,622
0.12
0.05
1.23
595
400
8,126
0.08
0.05
1.10
3,208
1,534
32,711
0.11
0.05
1.15
3,055
1,510
32,939
0.12
0.06
1.32
(1) At December 31, 2018, the Corporation’s credit facilities consisted of extendible revolving credit facilities in the aggregate principal amount of $950 million with maturity dates of May 11, 2021
(the “Credit Facilities”). At December 31, 2018, the Credit Facilities were comprised of: (i) an extendible revolving syndicated term credit facility (the “Syndicated Credit Facility”) of $850 million;
and (ii) an extendible revolving working capital facility (the “Working Capital Facility”) of $100 million.
(2) Includes accretion on decommissioning obligations and post-employment benefits.
Birchcliff’s interest expense is primarily impacted by the average effective interest rate and the average outstanding drawn
balance under its Syndicated Credit Facility in the period. Birchcliff draws on its Syndicated Credit Facility using Canadian
dollar denominated bankers’ acceptances and US dollar denominated LIBOR loans. The average effective interest rate under
the Syndicated Credit Facility is determined based on: (i) the market interest rate of its drawn bankers’ acceptances and LIBOR
loans; and (ii) Birchcliff’s stamping fee.
60
2018 Annual Report Birchcliff’s stamping fees are calculated using a pricing margin grid and will change as a result of the ratio of outstanding
indebtedness to the trailing four quarter EBITDA as calculated in accordance with the Corporation’s agreement governing
the Credit Facilities. EBITDA is defined as earnings before interest and non-cash items, including (if any) income taxes, stock-
based compensation, gains and losses on sale of assets, unrealized gains and losses on financial instruments and depletion,
depreciation and amortization.
The following table sets forth the Corporation’s effective interest rates under its Credit Facilities for the Reporting Periods and
the Comparable Prior Periods:
Revolving working capital facility
Revolving syndicated credit facility
Three months ended
December 31,
Twelve months ended
December 31,
2018
5.2%
4.7%
2017
5.0%
4.9%
2018
5.2%
4.7%
2017
5.0%
4.8%
Birchcliff’s average outstanding total credit facilities balance was approximately $620 million and $605 million in the three and
twelve month Reporting Periods, respectively, as compared to $586 million and $588 million in the Comparable Prior Periods,
calculated as the simple average of the month-end amounts.
The Corporation reviews its market interest rate risk exposure and may enter into interest rate swaps when market conditions
are favourable in order to reduce volatility in its financial results. Subsequent to December 31, 2018, Birchcliff entered into a
financial one-month bankers’ acceptance CDOR (Canadian Dollar Offered Rate) fixed interest rate swap on $350 million at
2.215% for the period from March 1, 2019 to March 1, 2024. The interest rate swap effectively fixes only the market interest
rate component of Birchcliff’s Syndicated Credit Facility.
Gain (Loss) on Sale of Assets
The following table details Birchcliff’s gain (loss) on sale of assets in the Reporting Periods and Comparable Prior Periods:
Gain (loss) on sale of assets
Three months ended
December 31,
Twelve months ended
December 31,
($000s)
(1,831)
2018
($/boe)
(0.26)
($000s)
13,705
2017
($/boe)
($000s)
2018
($/boe)
($000s)
1.86
(10,192)
(0.36)
(186,143)
2017
($/boe)
(7.50)
During the twelve month Reporting Period, Birchcliff completed the dispositions of certain non-core miscellaneous P&NG
properties and related assets and interests. The total cash consideration was $5.3 million, before customary closing
adjustments. As a result of the dispositions, Birchcliff recorded a loss on sale of assets of approximately $10.2 million ($7.4 million,
net of tax) in the twelve month Reporting Period. These dispositions are considered non-core as they represented less than
1% of both Birchcliff’s production during the Reporting Periods and proved plus probable reserves at December 31, 2018 and
therefore were not significant to the Corporation’s financial results or operational performance.
In October 2017, Birchcliff completed the sale of the Progress Charlie Lake assets for cash consideration of $31.7 million, before
closing adjustments. As a result of the disposition, Birchcliff recorded a gain on the sale of assets of approximately $13.7 million
($10.0 million, net of tax) in the Comparable Prior Periods.
In August 2017, Birchcliff completed the Worsley Disposition for total consideration of $100 million, before closing
adjustments. As a result of the disposition, Birchcliff recorded a loss on the sale of assets of approximately $181.3 million
($132.3 million, net of tax) in the Comparable Prior Periods.
61
2018 Annual Report Income Taxes
The components of the Corporation’s income taxes for the Reporting Periods and the Comparable Prior Periods are set forth in
the table below:
($000s)
Deferred income tax expense (recovery)
Dividend income tax expense on preferred shares
Income tax expense (recovery)
Income tax expense (recovery) per boe
Three months ended
December 31,
Twelve months ended
December 31,
2018
25,585
769
26,354
$3.77
2017
9,631
767
10,398
$1.42
2018
36,858
3,075
39,933
$1.44
2017
(16,906)
3,020
(13,886)
($0.54)
Birchcliff had an income tax expense in the Reporting Periods resulting from net income before tax recorded in the respective
periods. Birchcliff had an income tax expense in the three month Comparable Prior Period resulting from net income before
tax recorded in that period and an income tax recovery in the twelve month Comparable Prior Period largely resulting from the
accounting loss on the Worsley Disposition.
The Corporation’s estimated income tax pools were $2.1 billion at December 31, 2018. Management expects that future taxable
income will be available to utilize the accumulated tax pools. The components of the Corporation’s estimated income tax pools
are set forth in the table below:
($000s)
Canadian oil and gas property expense
Canadian development expense
Canadian exploration expense
Undepreciated capital costs
Non-capital losses and investment tax credits
SR&ED(1) & Investment tax credits
Financing costs and other
Estimated income tax pools(2)
Tax pools as at
December 31, 2018
415,609
358,212
284,401
341,590
643,116
23,940
13,331
2,080,199
(1) Scientific research and experimental development (“SR&ED”) tax pools.
(2) Excludes Veracel tax pools of $39.3 million which were reassessed by the Canada Revenue Agency (the “CRA”).
Veracel Tax Pools
Birchcliff’s 2006 income tax filings were reassessed by the CRA in 2011 (the “Reassessment”). The Reassessment was based
on the CRA’s position that the tax pools available to Veracel Inc. (“Veracel”), prior to its amalgamation with Birchcliff, ceased
to be available to Veracel after Birchcliff and Veracel amalgamated on May 31, 2005. The Veracel tax pools in dispute totalled
$39.3 million. Birchcliff appealed the Reassessment to the Tax Court of Canada (the “Trial Court”) and the trial of that appeal
occurred in November 2013. On October 1, 2015, the Trial Court issued its decision (the “Trial Decision”) and dismissed Birchcliff’s
appeal on the basis of the general anti-avoidance rule contained in the Income Tax Act (Canada). The Trial Decision was
rendered by a judge based on the written record and not by the judge who conducted the trial. As a result of the Trial Decision,
Birchcliff recorded a non-cash deferred income tax expense in the amount of $10.2 million in the fourth quarter of 2015.
Birchcliff appealed the Trial Decision to the Federal Court of Appeal (the “FCA”), which appeal was heard in January 2017. In
April 2017, the FCA issued its decision and allowed the appeal and set aside the Trial Decision, based on the lack of jurisdiction
by the judge who rendered the Trial Decision. In setting aside the Trial Decision, the FCA referred the matter back to the judge
of the Trial Court who initially conducted the trial in 2013 to render a judgment. The judge of the Trial Court rendered a decision
in November 2017 and dismissed the Corporation’s appeal. The Corporation appealed that decision to the FCA, which appeal
was heard on December 10, 2018 with judgment reserved.
62
2018 Annual Report
CAPITAL EXPENDITURES
The following table sets forth a summary of the Corporation’s capital expenditures for the Reporting Periods and the
Comparable Prior Periods:
($000s)
Land
Seismic
Workovers
Drilling and completions
Well equipment and facilities
Finding and development capital
Acquisitions
Dispositions
Finding, development and acquisition capital
Administrative assets
Total capital expenditures(1)
Three months ended
December 31,
Twelve months ended
December 31,
2018
390
332
1,804
37,888
11,907
52,321
-
(9)
52,312
574
52,886
2017
286
515
3,328
35,457
9,734
49,320
58
(31,159)
18,219
450
18,669
2018
2,226
1,310
6,281
200,782
89,055
299,654
1,524
2017
1,700
1,435
10,279
269,142
132,429
414,985
999
(5,184)
(141,690)
295,994
274,294
2,024
1,831
298,018
276,125
(1) Birchcliff previously referred to total capital expenditures as “net capital expenditure” or “capital expenditures, net”. See “Advisories – Capital Expenditures”.
During the three month Reporting Period, Birchcliff had total capital expenditures of $52.9 million which included approximately
$18.5 million (35%) on the drilling and completion of Montney/Doig horizontal wells in Pouce Coupe, $19.3 million (37%) on
the drilling and completion of Montney horizontal wells in Gordondale and $2.2 million (4%) on the Phase VI expansion of the
Pouce Coupe Gas Plant which was brought on-stream in August 2018.
During the twelve month Reporting Period, Birchcliff had total capital expenditures of $298.0 million which included approximately
$108.6 million (36%) on the drilling and completion of Montney/Doig horizontal wells in Pouce Coupe, $92.1 million (31%)
on the drilling and completion of Montney horizontal wells in Gordondale and $22.1 million (7%) on the Phase VI expansion
of the Pouce Coupe Gas Plant.
The remaining capital during the Reporting Periods was primarily attributed to land, seismic and infrastructure expansion projects
in the Montney/Doig Resource Play and on other oil and gas exploration and development projects in the Peace River Arch.
During the twelve month Reporting Period, Birchcliff brought on production a total of 28 (28.0 net) wells, consisting of
13 (13.0 net) Montney horizontal oil wells in Gordondale and 15 (15.0 net) Montney/Doig horizontal natural gas wells in
Pouce Coupe. During the three month Reporting Period, Birchcliff drilled an additional 9 (9.0 net) horizontal wells which
were originally targeted for 2019 in order to help to ensure the efficient execution of the 2019 Capital Program. During 2019,
the Corporation has targeted its F&D capital expenditures to be less than its estimate of adjusted funds flow.
CAPITAL RESOURCES AND LIQUIDITY
Liquidity and Capital Resources
The Corporation generally relies on its adjusted funds flow and available credit under its existing credit facilities to fund its
capital requirements, including its dividend payments. In addition, the Corporation may from time to time seek additional
capital in the form of debt and/or equity or dispose of non-core properties to fund its ongoing capital expenditure programs
and protect its statements of financial position.
63
2018 Annual Report The following table sets forth a summary of the Corporation’s capital resources for the Reporting Periods and the Comparable
Prior Periods:
($000s)
Adjusted funds flow
Changes in non-cash working capital from operations
Decommissioning expenditures
Exercise of stock options
Financing fees paid on credit facilities
Dividends paid on common shares
Dividends paid on preferred shares
Net change in revolving term credit facilities
Deposit on acquisition
Changes in non-cash working capital from investing
Capital resources
Three months ended
December 31,
Twelve months ended
December 31,
2018
81,517
10,838
(155)
87
-
(6,648)
(1,922)
(30,149)
(3,900)
3,218
52,886
2017
97,008
(7,920)
(93)
27
-
(6,644)
(1,922)
1,479
-
(63,225)
2018
312,922
12,591
(1,079)
384
(950)
2017
317,680
(29,226)
(794)
9,350
(2,375)
(26,586)
(26,522)
(7,687)
17,868
(3,900)
(5,540)
(7,547)
15,783
-
9,780
18,710
298,023
286,129
Birchcliff’s adjusted funds flow depends on a number of factors, including, but not limited to, commodity prices, production and
sales volumes, royalties, operating and transportation expenses and foreign exchange rates. The Corporation closely monitors
commodity prices and its capital spending and has taken proactive measures to ensure liquidity and financial flexibility in the
current environment.
Birchcliff’s market diversification initiatives have helped to reduce its exposure to volatility in commodity prices, including
AECO prices. The benchmark spot prices at Dawn outperformed AECO spot prices during the Reporting Periods. Birchcliff has
agreements for the firm service transportation of an aggregate of 175,000 GJ/d of natural gas on TCPL’s Canadian Mainline
for a 10-year term, whereby natural gas is transported to the Dawn trading hub in Southern Ontario. The first tranche of this
service (120,000 GJ/d) became available on November 1, 2017 and the second tranche (30,000 GJ/d) became available on
November 1, 2018. The last tranche of service (25,000 GJ/d) will become available on November 1, 2019. See “Discussion of
Operations – Petroleum and Natural Gas Revenues” in this MD&A. Birchcliff also has various financial and physical derivative
contracts outstanding to help protect its adjusted funds flow and capital expenditure programs. See “Discussion of Operations
– Commodity Price Risk Management” in this MD&A.
In addition to its adjusted funds flow, the Corporation’s other main source of liquidity is its Credit Facilities in the aggregate
principal amount of $950 million, of which $324.0 million remains available at December 31, 2018. The Corporation may each
year, at its option, request an extension to the maturity date of the Syndicated Credit Facility and the Working Capital Facility,
or either of them, for an additional period of up to three years from May 11 of the year in which the extension request is made.
In the second quarter of 2018, Birchcliff’s syndicate of lenders completed its semi-annual review of Birchcliff’s borrowing base
limit under its Credit Facilities. In connection with such review, Birchcliff and its syndicate of lenders agreed to: (i) an extension
of the maturity dates of each of the Syndicated Credit Facility and the Working Capital Facility from May 11, 2020 to May 11, 2021;
(ii) the borrowing base remaining unchanged at $950 million; and (iii) increasing the Working Capital Facility to $100 million
(from $50 million) with a corresponding reduction in the Syndicated Credit Facility to $850 million (from $900 million).
See also “Discussion of Operations – Finance Expense” and “Capital Resources and Liquidity – Bank Debt” in this MD&A for
further details.
Management believes that its adjusted funds flow will be sufficient to fund the Corporation’s ongoing 2019 Capital Program.
Should commodity prices deteriorate materially below Birchcliff’s assumptions, Birchcliff may adjust its ongoing capital
program, draw down on its Credit Facilities, seek additional equity financing and/or consider the potential sale of additional
non-core assets to fund planned growth. The 2019 Capital Program is designed with financial and operational flexibility with
the potential to accelerate or decelerate capital expenditures throughout the year, depending on commodity prices and industry
conditions. See “Advisories – Forward-Looking Statements”.
Working Capital
The Corporation’s adjusted working capital deficit increased to $21.2 million at December 31, 2018 from an $11.1 million
deficit at December 31, 2017. The deficit at December 31, 2018 was largely comprised of costs incurred from the drilling and
completion of new wells in Pouce Coupe and Gordondale.
64
2018 Annual Report At December 31, 2018, the major component of Birchcliff’s current assets was revenue to be received from its marketers
in respect of December 2018 production (54%), which was subsequently received in January 2019. In contrast, current
liabilities largely consisted of trade payables (60%) and accrued capital and operating expense (27%). Birchcliff monitors
the financial strength of its marketers. At this time, Birchcliff expects that such counterparties will be able to meet their
financial obligations.
Adjusted working capital includes items expected for normal operations, including trade receivables and payables, accruals,
deposits and prepaid expenses, and excludes the fair value of financial instruments. The Corporation’s adjusted working
capital varies from quarter to quarter primarily due to the timing of such items, as well as due to the size and timing of the
Corporation’s capital expenditures, volatility in commodity prices and changes in revenue, among other things. Birchcliff
manages any adjusted working capital deficit using adjusted funds flow and advances under its Credit Facilities. Any adjusted
working capital deficit position will not reduce the amount available under the Credit Facilities.
Bank Debt
Management of debt levels continues to be a priority for Birchcliff given its long-term growth plans and the current volatility
in the commodity price environment.
Total debt, including the adjusted working capital deficit, was $626.5 million at December 31, 2018 as compared to $598.2 million
at December 31, 2017. Total debt increased from December 31, 2017 primarily due to capital expenditures incurred on the
drilling and completion of new horizontal wells in Pouce Coupe and Gordondale, the Phase VI expansion of the Pouce Coupe
Gas Plant and the payment of common share and preferred share dividends, partially offset by an increase to adjusted funds
flow in the twelve month Reporting Period.
The following table sets forth the Corporation’s unused Credit Facilities as at December 31, 2018 and December 31, 2017:
As at, ($000s)
Maximum borrowing base limit(1):
Revolving term credit facilities
Principal amount utilized:
Drawn revolving term credit facilities
Outstanding letters of credit(2)
Unused credit
% unused credit
December 31,
2018
December 31,
2017
950,000
950,000
(608,821)
(594,823)
(17,205)
(12,184)
(626,026)
(607,007)
323,974
34%
342,993
36%
(1) The Credit Facilities are subject to a semi-annual review of the borrowing base limit, which is directly impacted by the value of Birchcliff’s P&NG reserves.
(2) Letters of credit are issued to various service providers. The letters of credit reduce the amount available under the Working Capital Facility.
Contractual Obligations & Commitments
The Corporation enters into various contractual obligations and commitments in the normal course of operations. The
following table lists Birchcliff’s estimated material contractual obligations and commitments at December 31, 2018:
($000s)
Accounts payable and accrued liabilities
Drawn revolving term credit facilities
Operating leases(1)
Firm transportation and fractionation(2)
Natural gas processing(3)
Estimated contractual obligations(4)
2019
76,567
-
4,408
107,678
17,155
2020
2021-2023
Thereafter
-
-
4,408
116,574
17,702
-
608,821
13,707
364,742
51,465
-
-
19,667
348,079
154,536
522,282
205,808
138,684
1,038,735
(1) On December 2, 2015, the Corporation entered into an operating lease commitment relating to a new office premises beginning February 1, 2018 and expiring on January 31, 2028. The commitment
amount under the new 10 year office lease is estimated to be $42.2 million, which includes costs allocated to base rent, parking and building operating expenses. The office lease commitment amounts
disclosed in the above table have not been reduced for any rents receivable by the Corporation.
(2) Includes firm transportation service arrangements with various terms on TCPL’s Alberta NGTL System and on TCPL’s Canadian Mainline to the AECO and Dawn trading hubs and fractionation
commitments associated with NGLs production processed at third-party facilities.
(3) Includes natural gas processing commitments at third-party facilities.
(4) Contractual obligations and commitments that are not material to Birchcliff are excluded from the above table. The Corporation’s decommissioning obligations are excluded from the table as these
obligations arose from a regulatory requirement rather than from a contractual arrangement. Birchcliff estimates the total undiscounted cash flow to settle its decommissioning obligations on its wells
and facilities at December 31, 2018 to be approximately $272 million and are estimated to be incurred as follows: 2019 - $2.7 million, 2020 - $0.6 million and $268.7 million thereafter. The estimate for
determining the undiscounted decommissioning obligations requires significant assumptions on both the abandonment cost and timing of the decommissioning and therefore the actual obligation may
differ materially.
Birchcliff’s Series C Preferred Shares, which are redeemable by their holders after December 31, 2020, have not been included in this table as they are not contractual obligations of the Corporation at the
end of the reporting period. Upon receipt of a notice of redemption, the Corporation has an obligation to redeem the Series C Preferred Shares, at its option, for cash or common shares.
65
2018 Annual Report
OFF-BALANCE SHEET TRANSACTIONS
The Corporation has certain lease arrangements, all of which are reflected in the contractual obligations and commitments
table above, 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 expense or general and administrative expense depending on the nature
of the lease. Other than the foregoing, Birchcliff was not involved in any off-balance sheet transactions during the Reporting
Periods and the Comparable Prior Periods.
OUTSTANDING SHARE INFORMATION
At March 13, 2019, Birchcliff had common shares, Series A Preferred Shares and Series C Preferred Shares that were outstanding.
Birchcliff’s common shares are listed on the TSX under the symbol “BIR” and are included in the S&P/TSX Composite Index.
Birchcliff’s Series A Preferred Shares and Series C Preferred Shares are individually listed on the TSX under the symbols
“BIR.PR.A” and “BIR.PR.C”, respectively.
The following table sets forth the common shares issued by the Corporation:
Balance at December 31, 2017
Exercise of options
Balance at December 31, 2018
Exercise of options
Balance at March 12, 2019
Common shares
265,796,698
114,664
265,911,362
10,000
265,921,362
At March 12, 2019, the Corporation had the following securities outstanding: 265,921,362 common shares; 2,000,000 Series A
Preferred Shares; 2,000,000 Series C Preferred Shares; 18,728,436 stock options to purchase an equivalent number of common
shares; and 2,939,732 performance warrants to purchase an equivalent number of common shares.
Dividends
The following table sets forth the dividend distributions by the Corporation for each class of shares for the Reporting Periods
and the Comparable Prior Periods:
($000s)
Common shares:
Dividend distribution ($000s)
Per common share ($)
Preferred shares - Series A:
Series A dividend distribution ($000s)
Per Series A preferred share ($)
Preferred shares - Series C:
Series C dividend distribution ($000s)
Per Series C preferred share ($)
Three months ended
December 31,
Twelve months ended
December 31,
2018
2017
2018
2017
6,648
0.0250
1,047
0.5234
875
0.4375
6,644
0.0250
1,047
0.5234
875
0.4375
26,586
0.1000
4,187
2.0935
3,500
1.7500
26,522
0.1000
4,047
2.0234
3,500
1.7500
All dividends have been designated as “eligible dividends” for the purposes of the Income Tax Act (Canada).
Normal Course Issuer Bid
On November 20, 2018, Birchcliff announced that the TSX had accepted the Corporation’s notice of intention to make a normal
course issuer bid (the “NCIB”). Pursuant to the NCIB, Birchcliff may purchase up to 18,767,520 of its outstanding common shares.
The total number of common shares that Birchcliff is permitted to purchase is subject to a daily purchase limit of 320,520
common shares; provided, however, that the Corporation may make one block purchase per calendar week which exceeds the
daily purchase restriction. The NCIB commenced on November 23, 2018 and will terminate on November 22, 2019, or such
earlier time as the NCIB is completed or is terminated at the option of Birchcliff. Purchases under the NCIB will be effected
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2018 Annual Report through the facilities of the TSX and/or Canadian alternative trading systems at the prevailing market price at the time of such
transaction. All common shares purchased under the NCIB will be cancelled. As at the date of this MD&A, Birchcliff has not
purchased any common shares pursuant to the NCIB.
A security holder of the Corporation may obtain, for no charge, a copy of the notice in respect of the NCIB filed with the TSX
by contacting the Corporation at 403-261-6401.
SUMMARY OF QUARTERLY RESULTS
The following table sets forth a summary of the Corporation’s quarterly results for the eight most recently completed quarters:
Quarter ending,
Dec. 31,
2018
Sep. 30,
2018
Jun. 30,
2018
Mar. 31,
2018
Dec. 31,
2017
Sep. 30,
2017
Jun. 30,
2017
Mar. 31,
2017
Average production (boe/d)
76,408
79,331
76,296
76,323
80,103
65,276
64,636
61,662
Realized natural gas sales price ($/Mcf)(1)
Realized oil sales price ($/bbl)(1)
Realized NGLs sales price ($/bbl)(1)
Average realized sales price ($/boe)
Total revenues ($000s)(1)
Operating expense ($/boe)
3.03
41.39
34.73
22.01
2.06
80.16
49.17
21.45
2.01
79.55
47.81
21.68
2.72
71.92
48.09
23.22
2.64
68.58
40.08
22.54
2.11
55.62
27.67
18.55
3.13
60.38
31.10
24.90
3.06
62.59
32.09
23.90
154,720
156,609
150,561
159,531
166,149
111,488
146,597
132,708
3.51
3.45
3.36
3.78
3.86
4.27
4.67
5.22
Total capital expenditures ($000s)
52,886
45,524
66,464
133,144
18,669
12,136
120,782
124,538
Cash flow from operating activities ($000s)
92,200
68,556
71,825
91,853
88,995
70,584
57,467
70,614
Adjusted funds flow ($000s)
81,517
75,378
72,369
83,658
97,008
64,430
88,612
67,630
Per common share – basic ($)
Per common share – diluted ($)
0.31
0.30
0.28
0.28
0.27
0.27
0.31
0.31
0.36
0.36
0.24
0.24
0.33
0.33
0.26
0.25
Net income (loss) ($000s)
71,947
7,703
7,437
15,125
25,820 (120,743)
18,015
29,928
Net income (loss) to common shareholders
($000s)(2)
Per common share – basic ($)
Per common share – diluted ($)
Total assets ($ million)
70,900
6,657
6,390
14,078
24,773
(121,743)
17,015
28,928
0.27
0.27
0.03
0.02
2,763
2,707
0.02
0.02
2,715
0.05
0.05
0.09
0.09
2,697
2,627
(0.46)
(0.46)
2,615
0.06
0.06
2,871
0.11
0.11
2,797
Long-term bank debt ($000s)
605,267
635,120
617,291
573,935
587,126
585,323
628,401
578,954
Total debt ($000s)
626,454
641,484
661,409
657,732
598,193
666,808
700,484
664,352
Dividends on common shares ($000s)
Dividends on pref. shares – Series A ($000s)
Dividends on pref. shares – Series C ($000s)
Pref. shares outstanding – Series A (000s)
Pref. shares outstanding – Series C (000s)
Common shares outstanding (000s)
6,648
1,047
875
2,000
2,000
6,647
1,046
875
2,000
2,000
6,646
1,047
875
2,000
2,000
6,645
1,047
875
2,000
2,000
6,644
1,047
875
2,000
2,000
6,635
1,000
875
2,000
2,000
6,635
1,000
875
2,000
2,000
6,604
1,000
875
2,000
2,000
Basic
Diluted
265,911
265,885
265,845
265,805
265,797
265,789
265,417
264,442
284,699
285,825
285,253
285,692
282,895
283,106
284,461
284,160
Wtd. avg. common shares outstanding (000s)
Basic
Diluted
265,910
265,877
265,820
265,797
265,792
265,490
265,326
264,099
267,288
268,605
267,773
266,179
267,619
267,988
268,203
268,077
(1) Excludes the effects of financial derivatives but includes the effects of physical delivery contracts.
(2) Reduced for the Series A Preferred Share dividends paid in the period.
67
2018 Annual Report Average daily production volumes from the third quarter of 2017 to the fourth quarter of 2017 increased largely due to
production volumes from new horizontal natural gas wells being brought on production in Pouce Coupe in connection with
the start-up of Phase V of the Pouce Coupe Gas Plant and new horizontal oil wells being brought on production in Gordondale,
partially offset by the Worsley Disposition in August 2017 and natural production declines. Average daily production
volumes for the four quarters of 2018 decreased compared to the fourth quarter of 2017 primarily attributable to production
curtailments due to temporary restrictions in pipeline and compressor station capacity on the Alberta NGTL system and
natural production declines, partially offset by new horizontal wells brought on production in Pouce Coupe and Gordondale
during the Reporting Periods.
Quarterly variances in revenues, adjusted funds flow and net income (loss) are primarily due to fluctuations in commodity
prices and production volumes. Oil and gas revenues and adjusted funds flow in the last eight quarters were largely impacted
by incremental production additions in Pouce Coupe and Gordondale and the average realized sales price received for
Birchcliff’s production. Birchcliff recorded a net loss in the third quarter of 2017 primarily as a result of the after-tax book loss
of $132.3 million in connection with the Worsley Disposition. Birchcliff’s net income in the fourth quarter of 2018 included a
$77.5 million unrealized mark-to-market gain on financial instruments. Net income or loss in the last eight quarters was also
impacted by certain non-cash adjustments, including depletion expense, unrealized gains and losses on financial instruments
and gains and losses on the sale of non-core assets recognized in those periods.
The Corporation’s capital expenditures program fluctuates based on the outlook in commodity prices and market conditions,
as well as the timing of acquisitions and dispositions. Quarterly variances in long-term debt and total debt are primarily due to
fluctuations in adjusted funds flow and the amount and timing of capital expenditures (including acquisitions and dispositions).
SUBSEQUENT EVENT
On November 14, 2018, Birchcliff announced that it had entered into a definitive purchase and sale agreement for the
Acquisition. Pursuant to the Acquisition, the Corporation acquired 18 gross (15.1 net) contiguous sections of Montney land
located between the Corporation’s existing Pouce Coupe and Gordondale properties, as well as various other non-Montney
lands and other assets, for total cash consideration of $39 million. Closing of the Acquisition occurred on January 3, 2019
and further consolidated Birchcliff’s land position in the area.
POTENTIAL TRANSACTIONS
Within its focus area, the Corporation is continually reviewing potential asset acquisitions and dispositions and corporate
mergers and acquisitions for the purpose of determining whether any such potential transaction is of interest to the
Corporation, as well as the terms on which such a potential transaction would be available. As a result, the Corporation may
from time to time be involved in discussions or negotiations with other parties or their agents in respect of potential asset
acquisitions and dispositions and corporate merger and acquisition opportunities.
INTERNAL CONTROL OVER FINANCIAL REPORTING
Disclosure Controls and Procedures
The Corporation’s Chief Executive Officer and Chief Financial Officer (the “Certifying Officers”) have designed, or caused to be
designed under their supervision, disclosure controls and procedures (“DC&P”), as defined in National Instrument 52-109 –
Certification of Disclosure in Issuer’s Annual and Interim Filings (“NI 52-109”), to provide reasonable assurance that: (i) material
information relating to the Corporation is made known to the Certifying Officers by others, particularly during the period
in which the annual filings are being prepared; and (ii) information required to be disclosed by the Corporation in its annual
filings, interim filings or other reports filed or submitted by the Corporation under securities legislation is recorded, processed,
summarized and reported within the time periods specified in securities legislation. The Certifying Officers have evaluated, or
caused to be evaluated under their supervision, the effectiveness of the Corporation’s DC&P at December 31, 2018 and have
concluded that the Corporation’s DC&P were effective at December 31, 2018.
While the Certifying Officers believe that the Corporation’s DC&P provide a reasonable level of assurance and are effective,
they do not expect that the DC&P will prevent all errors and fraud. A control system, no matter how well conceived, maintained
and operated, can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met.
Internal Control over Financial Reporting
The Certifying Officers have designed, or caused to be designed under their supervision, internal control over financial
reporting (“ICFR”), as defined in NI 52-109, to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance with the generally accepted accounting
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2018 Annual Report principles applicable to the Corporation. The control framework the Certifying Officers used to design the Corporation’s ICFR
is “Internal Control – Integrated Framework (May 2013)” published by The Committee of Sponsoring Organizations of the
Treadway Commission (COSO). The Certifying Officers have evaluated, or caused to be evaluated under their supervision, the
effectiveness of the Corporation’s ICFR at December 31, 2018 and have concluded that the Corporation’s ICFR was effective at
December 31, 2018. There were no changes in the Corporation’s ICFR that occurred during the period beginning on October 1, 2018
and ended on December 31, 2018 that have materially affected, or are reasonably likely to materially affect, the Corporation’s ICFR.
While the Certifying Officers believe that the Corporation’s ICFR provides a reasonable level of assurance and is effective, they
do not expect that the ICFR will prevent all errors and fraud. A control system, no matter how well conceived, maintained and
operated, can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met.
CRITICAL ACCOUNTING ESTIMATES
The preparation of the financial statements requires management to make judgments, estimates and assumptions that affect
the application of IFRS accounting policies, reported amounts of assets and liabilities and income and expenses. Accordingly,
actual results may differ from these estimates. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions
to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected.
Critical Judgments in Applying Accounting Policies:
The following are the critical judgments that management has made in the process of applying the Corporation’s accounting
policies and that have the most significant effect on the amounts recognized in these financial statements:
Identification of Cash-Generating Units
Birchcliff’s assets are required to be aggregated into CGUs for the purpose of calculating impairment based on their ability
to generate largely independent cash inflows. CGUs have been determined based on similar geological structure, shared
infrastructure, geographical proximity, operating structure, commodity type and similar exposures to market risks. By their
nature, these assumptions are subject to management’s judgment and may impact the carrying value of the Corporation’s
assets in future periods.
Identification of Impairment Indicators
IFRS requires Birchcliff to assess, at each reporting date, whether there are any indicators that its petroleum and natural gas
assets may be impaired. Birchcliff is required to consider information from both external sources (such as negative downturn
in commodity prices, significant adverse changes in the technological, market, economic or legal environment in which the
entity operates) and internal sources (such as downward revisions in reserves, significant adverse effects on the financial and
operational performance of a CGU, evidence of obsolescence or physical damage to the asset). By their nature, these
assumptions are subject to management’s judgment.
Tax Uncertainties
IFRS requires Birchcliff, at each reporting date, to make certain judgments on uncertain tax positions by relevant tax authorities.
Judgments include determining whether the Corporation will “more likely than not” be successful in defending its tax positions
by considering information from relevant tax interpretations and tax laws in Canada. As such, this recognition threshold is
subject to management’s judgment and may impact the carrying value of the Corporation’s deferred tax assets and liabilities
at the end of the reporting period.
Key Sources of Estimation Uncertainty:
The following are the key assumptions concerning the sources of estimation uncertainty at the end of the reporting period that
have a significant risk of causing adjustments to the carrying amounts of assets and liabilities within the next financial year:
Reserves
Reported recoverable quantities of proved and probable reserves requires estimation regarding production profile, commodity
prices, exchange rates, remediation costs, timing and amount of future development costs, and production, transportation and
marketing costs for future cash flows. It also requires interpretation of geological and geophysical models in order to make
an assessment of the size, shape, depth and quality of reservoirs, and their anticipated recoveries. The economical, geological
and technical factors used to estimate reserves may change from period to period. Changes in reported reserves can impact
the carrying values of the Corporation’s petroleum and natural gas properties and equipment, the calculation of depletion
and depreciation, the provision for decommissioning obligations, and the recognition of deferred tax assets due to changes in
expected future cash flows. The recoverable quantities of reserves and estimated cash flows from Birchcliff’s petroleum and
natural gas interests are independently evaluated by reserve engineers at least annually.
69
2018 Annual Report The Corporation’s petroleum and natural gas reserves represent the estimated quantities of petroleum, natural gas and NGLs
which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be economically
recoverable in future years from known reservoirs and which are considered commercially producible. Such reserves may be
considered commercially producible if management has the intention of developing and producing them and such intention is
based upon (i) a reasonable assessment of the future economics of such production; (ii) a reasonable expectation that there
is a market for all or substantially all the expected petroleum and natural gas production; and (iii) evidence that the necessary
production, transmission and transportation facilities are available or can be made available. Reserves may only be considered
proved and probable if producibility is supported by either production or conclusive formation tests. Birchcliff’s oil and gas
reserves are determined in accordance with the standards contained in National Instrument 51-101 – Standards of Disclosure
for Oil and Gas Activities (“NI 51-101”) and the Canadian Oil and Gas Evaluation Handbook (“COGE”).
Share-based payments
All equity-settled, share-based awards issued by the Corporation are fair valued using the Black-Scholes option-pricing model.
In assessing the fair value of equity-based compensation, estimates have to be made regarding the expected volatility in share
price, option life, dividend yield, risk-free rate and estimated forfeitures at the initial grant date.
Decommissioning obligations
The Corporation estimates future remediation costs of production facilities, wells and pipelines at different stages of
development and construction of assets or facilities. In most instances, removal of assets occurs many years into the
future. This requires an estimate regarding abandonment date, future environmental and regulatory legislation, the extent
of reclamation activities, the engineering methodology for estimating cost, future removal technologies in determining the
removal cost and liability-specific discount rates to determine the present value of these cash flows.
Post-employment benefit obligation
The Corporation estimates the post-employment benefit obligation at the end of each reporting period. In most instances,
the obligation occurs many years into the future. The Corporation uses estimates related to the initial measurement of the
obligation for eligible employees including expected age of employee retirement, employee turnover, probability of early
retirement, discount rate and inflation rate on salary and benefits. From time to time, these estimates may change causing
the obligation recorded by the Corporation to change.
Impairment of non-financial assets
For the purposes of determining the extent of any impairment or its reversal, estimates must be made regarding future cash
flows taking into account key assumptions including future petroleum and natural gas prices, expected forecasted production
volumes and anticipated recoverable quantities of proved and probable reserves. These assumptions are subject to change
as new information becomes available. Changes in economic conditions can also affect the rate used to discount future cash
flow estimates. Changes in the aforementioned assumptions could affect the carrying amount of the Corporation’s assets,
and impairment charges and reversal will affect profit or loss.
Income taxes
Birchcliff files corporate income tax, goods and service tax and other tax returns with various provincial and federal taxation
authorities in Canada. There can be differing interpretations of applicable tax laws and regulations. The resolution of these tax
positions through negotiations or litigation with tax authorities can take several years to complete. The Corporation does not
anticipate that there will be any material impact upon the results of its operations, financial position or liquidity.
Tax provisions are based on enacted or substantively enacted laws. Changes in those laws could affect amounts recognized
in profit or loss both in the period of change, which would include any impact on cumulative provisions, and in future periods.
Deferred tax assets (if any) are recognized only to the extent it is considered probable that those assets will be recoverable.
This involves an assessment of when those deferred tax assets are likely to reverse and a judgment as to whether or not there
will be sufficient taxable profits available to offset the tax assets when they do reverse. This requires assumptions regarding
future profitability and is therefore inherently uncertain. Estimates of future taxable income are based on forecasted cash
flows from operations. To the extent that any interpretation of tax law is challenged by the tax authorities or future cash flows
and taxable income differ significantly from estimates, the ability of Birchcliff to realize the deferred tax assets recorded at the
statement of financial position date could be impacted.
70
2018 Annual Report CHANGES IN ACCOUNTING POLICIES
Accounting Pronouncements Adopted
On January 1, 2018, Birchcliff adopted IFRS 15 using the cumulative effect method. Under this method, the comparative
periods have not been restated and the cumulative effect on net earnings and the change in opening retained earnings as a
result of the application of IFRS 15 to revenue contracts in progress at January 1, 2018 is nil. The Corporation reviewed its
revenue streams and major contracts with customers using the IFRS 15 five step model and there were no changes to net
earnings or timing of petroleum and natural gas sales recognized. It should be noted, however, that certain profit and loss line
item reclassifications were made.
On January 1, 2018, Birchcliff adopted IFRS 9: Financial Instruments (“IFRS 9”) to replace IAS 39: Financial Instruments:
Recognition and Measurement (“IAS 39”). IFRS 9 contains three principal classification categories for financial assets: measured
at amortized cost, fair value through other comprehensive income and fair value through profit or loss. The previous IAS 39
categories of held to maturity, loans and receivables and available for sale are eliminated. IFRS 9 bases the classification of
financial assets on the contractual cash flow characteristics and the Corporation’s business model for managing the financial
asset. Additionally, embedded derivatives are not separated if the host contract is a financial asset within the scope of IFRS 9.
Instead, the entire hybrid contract is assessed for classification and measurement. IFRS 9 largely retains the existing
requirements in IAS 39 for the classification of financial liabilities. The adoption of IFRS 9 has resulted in changes to the
Corporation’s investment in securities which, upon adoption of IFRS 9, are measured at fair value through profit or loss. Under
the previous IAS 39 standard, Birchcliff’s investment in securities were categorized as available for sale which required the
securities to be fair valued with any gains or losses recognized in other comprehensive income. There were no changes to the
treatment of distributions declared on the investment in securities which are recorded to profit or loss. The adoption of IFRS 9
had no impact on the amounts recorded in the financial statements as at January 1, 2018 or on the comparative periods.
Future Accounting Pronouncements
In January 2016, the IASB issued IFRS 16: Leases (“IFRS 16”) which sets out the principles for the recognition, measurement,
presentation and disclosure of leases for both parties to a contract, i.e. the customer (“lessee”) and the supplier (“lessor”) and
replaces the previous lease standards, IAS 17: Leases and IFRIC 4: Determining whether an Arrangement contains a Lease. IFRS 16
requires the recognition of a right-of-use asset and lease liability on the statement of financial position for most leases, where
Birchcliff is acting as a lessee. For lessees applying IFRS 16, the dual classification model of leases as either operating leases
or finance leases no longer exists, effectively treating all leases as finance leases. IFRS 16 is effective for annual reporting
periods beginning on or after January 1, 2019. The standard is required to be adopted either retrospectively or using a modified
retrospective approach. The Corporation will adopt IFRS 16 using the modified retrospective approach, which does not require
restatement of prior period financial information and applies the standard prospectively.
IFRS 16 is expected to increase Birchcliff’s total assets and liabilities at January 1, 2019. Future net income will be impacted
as the finance charges and depreciation charges associated with lease contracts are not expected to correspond in any one
period to the amount of related cash flows. Cash flows associated with lease repayments will be allocated between operating
and financing activities based on their interest repayment and principal repayment portions. The actual impact of applying
IFRS 16 on the financial statements in the period of initial application will depend on multiple factors and conditions, including
but not limited to, the Corporation’s borrowing rate at January 1, 2019, the composition of the Corporation’s lease portfolio at
that date, the Corporation’s latest assessment of whether it will exercise any lease renewal options, and the extent to which
the Corporation chooses to use practical expedients and recognition exemptions. On initial adoption, Birchcliff will have the
following optional practical expedients available under IFRS 16:
• Certain short-term leases and leases of low value assets that have been identified for recognition at January 1, 2019 can
be excluded from recognition on the statements of financial position. Payments for these leases will be disclosed in the
notes to the financial statements.
• Certain classes of lease arrangements that transfer a separate good or service under the same contract that have been
identified for recognition at January 1, 2019 can be recognized as a single lease component rather than separating
between their lease and non-lease components.
•
For leases having similar characteristics, a portfolio approach can be used by applying a single discount rate.
The Corporation continues to review all existing contracts in detail. The full extent of the impact has not yet been determined.
At minimum, Birchcliff expects to record a right-of-use asset and corresponding lease liability on the statement of financial
position for the Corporation’s head office lease. The Corporation will disclose the financial impact of IFRS 16 in its unaudited
financial statements for the first quarter 2019 and continue to develop and implement changes to its internal controls,
information systems and business and accounting processes throughout 2019.
71
2018 Annual Report RISK FACTORS AND RISK MANAGEMENT
Investors should carefully consider the risk factors set out below and consider all other information contained herein and in
the Corporation’s other public filings before making an investment decision. The risks set out below are not an exhaustive list
and should not be taken as a complete summary or description of all the risks associated with the Corporation’s business and
the oil and natural gas business generally. If any of the risks set out below materialize, the Corporation’s business, financial
condition, results of operations, prospects, cash flows and reputation may be adversely affected, which may, in turn, reduce or
restrict the Corporation’s ability to pay dividends and may materially affect the market price of the Corporation’s securities.
Financial Risks and Risks Relating to Economic Conditions
Prices, Markets and Marketing
Numerous factors beyond the Corporation’s control do, and will continue to, affect the marketability and price of oil and natural
gas acquired, produced or discovered by the Corporation. The Corporation’s revenues, operating results and financial condition
depend substantially on prevailing prices for oil and natural gas and the Corporation’s ability to successfully market its oil and
natural gas production from its properties.
The Corporation’s ability to market its oil and natural gas may depend upon its ability to acquire capacity on pipelines that
deliver natural gas, crude oil and NGLs to commercial markets or contract for the delivery of crude oil by rail (see “Risk Factors
and Risk Management – Financial Risks and Risks Relating to Economic Conditions – Weakness in the Oil and Gas Industry” and
“Risk Factors and Risk Management – Business and Operational Risks – Gathering and Processing Facilities, Pipeline Systems and
Rail”). Deliverability uncertainties include the distance the Corporation’s reserves are from pipelines, railway lines, processing
and storage facilities and operational problems affecting pipelines, railway lines and facilities.
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 that are beyond the Corporation’s control.
These factors include, but are not limited to, the following:
•
•
•
•
•
•
•
•
global energy supply and demand;
the actions taken by OPEC and other oil and gas exporting nations;
political conditions, instability and hostilities;
domestic and foreign supplies of crude oil, NGLs and natural gas;
the level of consumer demand, including demand for different qualities and types of crude oil and NGLs;
the production and storage levels of North American natural gas and crude oil and the supply and price of imported oil;
the ability to export oil, LNG and NGLs from North America;
the availability, proximity and capacity of gathering, transportation, processing and/or refining facilities in regional or
localized areas that may affect the realized prices for oil and natural gas;
• weather conditions;
•
•
•
•
government regulations, including existing and proposed changes to such regulations;
the effect of world-wide environmental regulations and energy conservation and GHG reduction measures;
the price and availability of alternative energy supplies; and
global and domestic economic conditions, including currency fluctuations.
Oil and natural gas prices are expected to remain volatile for the near future because of market uncertainties over the supply
and demand of these commodities due to the current state of the world economy, increased growth of shale oil production in
the United States and other concerns of over-supply, OPEC actions, sanctions imposed on certain oil producing nations by other
countries, political uncertainties 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.
A material decline in oil and natural gas prices could result in a reduction of the Corporation’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. The Corporation might also elect not to produce from certain wells at lower prices. In addition, any prolonged
period of low crude oil or natural gas prices could result in a decision by the Corporation to suspend or slow exploration and
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2018 Annual Report development activities or the construction or expansion of new or existing facilities or reduce its production levels. Any
substantial and prolonged decline in the price of oil and natural gas would have an adverse effect on the carrying value of the
Corporation’s assets, borrowing capacity, revenues, profitability and cash flows from operations and may have a material
adverse effect on the Corporation’s business, financial condition, results of operations, prospects, its ability to pay dividends
and ultimately on the market prices of the Corporation’s securities.
Lower commodity prices may also affect the volume and value of the Corporation’s reserves, rendering certain reserves
uneconomic for development. The Corporation’s reserves at December 31, 2018 are estimated using forecast prices and
costs. If oil and natural gas prices stay at current levels or decrease, the Corporation’s reserves may be substantially reduced
as economic limits of developed reserves are reached earlier and undeveloped reserves become uneconomic at such prices.
Even if some reserves remain economic at lower price levels, sustained low prices may compel the Corporation to re-evaluate
its development plans and reduce or eliminate various projects with marginal economics. Any decrease in the value of the
Corporation’s reserves may reduce the borrowing base under the Credit Facilities, which, depending on the level of the
Corporation’s indebtedness, could result in the Corporation having to repay a portion of its indebtedness. See “Risk Factors
and Risk Management – Financial Risks and Risks Relating to Economic Conditions – Credit Facilities”.
In addition, lower commodity prices restrict the Corporation’s cash flow resulting in less funds from operations being available
to fund the Corporation’s capital expenditure programs. The Corporation’s capital expenditure plans are impacted by the
Corporation’s cash flow. Consequently, the Corporation may not be able to replace its production with additional reserves and
both the Corporation’s production and reserves could be reduced on a year-over-year basis.
In addition to possibly resulting in a decrease in the value of the Corporation’s economically recoverable reserves, lower
commodity prices may also result in a decrease in the value of the Corporation’s infrastructure and facilities, all of which could
also have the effect of requiring a write down of the carrying value of its oil and natural gas assets on its balance sheet and the
recognition of an impairment charge on its income statement.
Weakness in the Oil and Natural Gas Industry
Recent market events and conditions, including global excess oil and natural gas supply, actions taken by OPEC, slowing
growth in China and emerging economies, market volatility and disruptions in Asia, weakening global relationships, isolationist
trade policies, increased shale production in the United States, sovereign debt levels and political upheavals in various countries
have caused significant weakness and volatility in commodity prices. These events and conditions have caused a significant
decrease in the valuation of oil and natural gas companies and a decrease in the confidence in the oil and natural gas industry.
These difficulties have been exacerbated in Canada by political and other actions resulting in uncertainty surrounding
regulatory, tax, royalty changes and environmental regulation. In addition, the inability to get the necessary approvals to build
pipelines, LNG plants and other facilities to provide better access to markets for the oil and natural gas industry in Western
Canada has led to additional downward price pressure on oil and natural gas produced in Western Canada and uncertainty and
reduced confidence in the oil and natural gas industry in Western Canada.
Substantial Capital and Additional Funding Requirements
The Corporation anticipates that it will make substantial capital expenditures for the acquisition, exploration, development
and production of oil and natural gas reserves and resources in the future. As future capital expenditures are expected to be
financed out of cash generated from operations, borrowings and possible future equity sales, the Corporation’s ability to do
so is dependent on, among other factors:
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•
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the overall state of the capital markets;
the Corporation’s credit rating (if applicable);
commodity prices;
interest rates;
royalty rates;
tax burden due to current and future tax laws; and
investor appetite for investments in the energy industry and the Corporation’s securities in particular.
The Corporation’s cash flow from its properties may not be sufficient to fund its ongoing activities at all times and from time
to time the Corporation may require additional financing. The inability of the Corporation to access sufficient capital for its
operations and activities could have a material adverse effect on the Corporation’s financial condition, results of operations
and prospects.
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2018 Annual Report Due to the conditions in the oil and natural gas industry and/or global economic and political volatility, the Corporation may
from time to time have restricted access to capital and increased borrowing costs. The conditions in or affecting the oil and
natural gas industry have negatively impacted the ability of oil and natural gas companies to access additional financing.
Failure to obtain financing on a timely basis could cause the Corporation to forfeit its interest in certain properties, miss certain
acquisition opportunities and reduce or terminate its operations.
There can be no assurance that debt or equity financing or cash generated by operations will be available or sufficient to meet
the Corporation’s requirements or, if debt or equity financing is available, that it will be on terms acceptable to the Corporation.
To the extent that external sources of capital become limited, unavailable or available on onerous terms, the Corporation’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 Corporation’s petroleum properties may require additional financing and there are no assurances that such financing will
be available or, if available, will be available upon acceptable terms. The Corporation may be required to seek additional equity
financing on terms that are highly dilutive to existing shareholders. Moreover, future activities may require the Corporation to
alter its capitalization significantly.
Credit Facilities
The amount authorized under the Credit Facilities is dependent on the borrowing base determined by the Corporation’s lenders.
The Credit Facilities are subject to a semi‐annual review of the borrowing base limit by Birchcliff’s syndicate of lenders, which
limit is directly impacted by the value of Birchcliff’s oil and natural gas reserves. The Corporation’s lenders use the Corporation’s
reserves, commodity prices and other factors to determine the Corporation’s borrowing base. Commodity prices continue to be
depressed and have fallen dramatically since 2014. Continued depressed commodity prices or further declines in commodity
prices could result in a reduction in the Corporation’s borrowing base, thereby reducing the funds available to the Corporation
under the Credit Facilities. As the borrowing base is determined based on the lender’s interpretation of the Corporation’s
reserves and future commodity prices, there can be no assurance as to the amount of the borrowing base determined at each
review. In addition, a majority of lenders have the right once per year to redetermine the borrowing base in between scheduled
redeterminations and the borrowing base may also be reduced in connection with asset dispositions. If, at the time of a
borrowing base redetermination, the outstanding borrowings under the Credit Facilities were to exceed the borrowing base as
a result of any such redetermination, the Corporation would be required to make principal repayments or otherwise eliminate
the borrowing base shortfall. If the Corporation is forced to repay a portion of its indebtedness under the Credit Facilities,
it may not have sufficient funds to make such repayments. If it does not have sufficient funds and is otherwise unable to
negotiate renewals of its borrowings or arrange new financing, it may have to sell significant assets. Any such sale could have
a material adverse effect on the Corporation’s business and financial results.
The maturity date of the Credit Facilities is currently May 11, 2021. The Corporation may each year, at its option, request an
extension to the maturity date of the Syndicated Credit Facility and the Working Capital Facility, or either of them, for an
additional period of up to three years from May 11 of the year in which the extension request is made. In the event that either
of the Credit Facilities is not extended before the maturity date, all outstanding indebtedness under such Credit Facility will be
repayable at the maturity date. There is also a risk that the Credit Facilities will not be renewed for the same principal amount
or on the same terms. Any of these events could adversely affect the Corporation’s ability to fund its ongoing operations and
to pay dividends.
The Corporation is required to comply with covenants under the Credit Facilities. In the event that the Corporation does not
comply with these covenants, the Corporation’s access to capital could be restricted or repayment could be required. Events
beyond the Corporation’s control may contribute to the failure of the Corporation to comply with such covenants. A failure to
comply with covenants could result in an event of default under the Credit Facilities, which could result in the Corporation being
required to repay amounts owing thereunder and may prevent the payment of dividends to shareholders. The acceleration
of the Corporation’s indebtedness under one agreement may permit acceleration of indebtedness under other agreements
that contain cross-default or cross-acceleration provisions. In addition, the Credit Facilities impose certain restrictions on
the Corporation, including, but not limited to, restrictions on the payment of dividends, incurring of additional indebtedness,
dispositions of properties and the entering into of amalgamations, mergers, plans of arrangements, reorganizations or
consolidations with any person. The Credit Facilities do not currently contain any financial maintenance covenants; however,
there is no assurance that the Corporation’s lenders will not impose any such covenants on the Corporation in the future.
Any such covenants may either affect the availability or price of additional funding.
The impact of the Supreme Court of Canada’s decision in Redwater Energy Corporation (Re) (“Redwater”) on lending practices
in the oil and natural gas sector and actions taken by secured creditors and receivers/trustees of insolvent borrowers has not
yet been determined but could affect lending practices.
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2018 Annual Report If the Corporation’s lenders require repayment of all or portion of the amounts outstanding under the Credit Facilities for any
reason, including for a default of a covenant, there is no certainty that the Corporation would be in a position to make such
repayment. Even if the Corporation is able to obtain new financing in order to make any required repayment under the Credit
Facilities, it may not be on commercially reasonable terms or terms that are acceptable to the Corporation. If the Corporation is
unable to repay amounts owing under the 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.
Dividends
The declaration and payment of dividends (and the amount thereof) is subject to the discretion of the Board and may vary
depending on a variety of factors and conditions existing from time to time, including fluctuations in commodity prices, the
financial condition of Birchcliff, production levels, results of operations, capital expenditure requirements, working capital
requirements, debt service requirements, operating costs, royalty burdens, foreign exchange rates, interest rates, contractual
restrictions, Birchcliff’s hedging activities or programs, available investment opportunities, Birchcliff’s business plan, strategies
and objectives, the satisfaction of the solvency and liquidity tests imposed by the Business Corporations Act (Alberta) (the “ABCA”)
for the declaration and payment of dividends and other factors that the Board may deem relevant. Depending on these and
various other factors, many of which are beyond the control of Birchcliff, the dividend policy of the Corporation may vary from
time to time and, as a result, future cash dividends could be reduced or suspended entirely.
Pursuant to the ABCA, the Corporation may not declare or pay a dividend if there are reasonable grounds for believing that:
(i) the Corporation is, or would after the payment be, unable to pay its liabilities as they become due; or (ii) the realizable value
of its assets would thereby be less than the aggregate of its liabilities and stated capital of its outstanding shares. Additionally,
pursuant to the agreement governing the Credit Facilities, the Corporation is not permitted to make any distribution (which
includes dividends) at any time when an event of default exists or would reasonably be expected to exist upon making such
distribution, unless such event of default arose subsequent to the ordinary course declaration of the applicable distribution.
Dividends may be reduced or suspended during periods of lower cash flows from operations. The timing and amount of
Birchcliff’s capital expenditures, and the ability of the Corporation to repay or refinance existing debt as it becomes due, directly
affects the amount of cash dividends that may be declared by the Board. Future acquisitions, expansions of Birchcliff’s assets,
and other capital expenditures and the repayment or refinancing of existing debt as it becomes due may be financed from
sources such as cash flows from operations, the issuance of additional shares or other securities of Birchcliff, and borrowings.
Dividends may be reduced, or even eliminated, at times when significant capital or other expenditures are made. There can be
no assurance that sufficient capital will be available on terms acceptable to Birchcliff, or at all, to make additional investments,
fund future expansions or make other required capital expenditures. To the extent that external sources of capital, including the
issuance of additional shares or other securities or the availability of additional credit facilities, become limited or unavailable
on favourable terms or at all due to credit market conditions or otherwise, the ability of the Corporation to make the necessary
capital investments to maintain or expand its operations, to repay outstanding debt and to invest in assets, as the case may
be, may be impaired. To the extent Birchcliff is required to use cash flows from operations to finance capital expenditures
or acquisitions or to repay existing debt as it becomes due, the cash available for dividends may be reduced and the level of
dividends declared may be reduced.
The market value of the Corporation’s securities may deteriorate if dividends are reduced or suspended. Furthermore, the
future treatment of dividends for tax purposes will be subject to the nature and composition of dividends paid by Birchcliff and
potential legislative and regulatory changes.
Hedging
The Corporation 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. Similarly, the Corporation may enter into agreements to fix the differential or
discount pricing gap which exists and may fluctuate between different grades of oil, NGLs and natural gas and the various
market prices received for such products. However, to the extent that the Corporation 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, if the Corporation enters into
hedging arrangements it may be exposed to the risk of financial loss in certain circumstances, including instances in which:
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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; and/or
•
a sudden unexpected material event impacts crude oil and natural gas prices.
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2018 Annual Report Similarly, the Corporation may enter into agreements to fix the exchange rate of Canadian dollars 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 the other
currencies. However, if the Canadian dollar declines in value compared to such fixed currencies, the Corporation will not benefit
from the fluctuating exchange rate.
Further, the Corporation may enter into hedging arrangements to fix interest rates applicable to the Corporation’s debt.
However, if interest rates decrease as compared to the interest rate fixed by the Corporation, the Corporation will not benefit
from the lower interest rate.
Issuance of Debt
From time to time, the Corporation may finance its activities (including asset acquisitions) in whole or in part with debt, which
may increase the Corporation’s debt levels above industry standards for peers of similar size. Depending on future exploration
and development plans, the Corporation may require additional debt financing that may not be available or, if available, may not
be available on favourable terms. Neither the Corporation’s articles nor its by-laws limit the amount of indebtedness that the
Corporation may incur. The level of the Corporation’s indebtedness from time to time could impair the Corporation’s ability to
obtain additional financing on a timely basis to take advantage of business opportunities that may arise.
Credit Risk
The Corporation may be exposed to third-party credit risk through its contractual arrangements with joint venture partners,
marketers of its petroleum and natural gas production and other parties. In addition, the Corporation may be exposed to
third-party credit risk from operators of properties in which the Corporation has a working or royalty interest. In the event such
entities fail to meet their contractual obligations to the Corporation, such failures may have a material adverse effect on the
Corporation’s business, financial condition, results of operations and prospects. In addition, poor credit conditions in the industry
generally and of joint venture partners may affect a joint venture partner’s willingness to participate in the Corporation’s
ongoing capital program, potentially delaying the program and the results of such program until the Corporation finds a
suitable alternative partner. To the extent that any of such third parties go bankrupt, become insolvent or make a proposal
or institute any proceedings relating to bankruptcy or insolvency, it could result in the Corporation being unable to collect all
or a portion of any money owing from such parties. Any of these factors could materially adversely affect the Corporation’s
financial and operational results.
Conversely, the Corporation’s counterparties may deem the Corporation to be at risk of defaulting on its contractual obligations.
These counterparties may require that the Corporation provide additional credit assurance by prepaying anticipated expenses
or posting letters of credit, which would decrease the Corporation’s available liquidity.
Variations in Foreign Exchange Rates and Interest Rates
World oil and natural gas prices are quoted in United States dollars. The Canadian/United States dollar exchange rate, which
fluctuates over time, consequently affects the price received by Canadian producers of oil and natural gas. Material increases
in the value of the Canadian dollar relative to the United States dollar may negatively affect the Corporation’s production
revenues. Accordingly, Canadian/United States exchange rates could impact the future value of the Corporation’s reserves as
determined by independent evaluators. Although a low value of the Canadian dollar relative to the United States dollar may
positively affect the price the Corporation receives for its oil and natural gas production, it could also result in an increase in
the price for certain goods used for the Corporation’s operations, which may have a negative impact on the Corporation’s
financial results.
To the extent that the Corporation engages in risk management activities related to foreign exchange rates, there is credit risk
associated with the counterparties with whom the Corporation may contract. See “Risk Factors and Risk Management –
Financial Risks and Risks Relating to Economic Conditions – Hedging”.
An increase in interest rates could result in a significant increase in the amount the Corporation pays to service debt, resulting
in a reduced amount available to fund its exploration and development activities and the cash available for dividends and could
negatively impact the market prices of the Corporation’s securities.
Business and Operational Risks
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 Corporation depends on its ability to find, acquire, develop
and commercially produce oil and natural gas reserves. Without the continual addition of new reserves, any existing reserves
the Corporation may have at a particular point in time and the production therefrom, will decline over time as such existing
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2018 Annual Report reserves are produced. A future increase in the Corporation’s reserves will depend on both the ability of the Corporation 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 Corporation will be able to continue to find satisfactory properties to acquire or participate in.
Moreover, management of the Corporation may determine that current markets, terms of acquisition, participation or pricing
conditions make potential acquisitions or participation uneconomic. There is also no assurance that the Corporation will
discover or acquire further commercial quantities of oil and natural gas. The success of the Corporation’s business is highly
dependent on its ability to acquire or discover new reserves in a cost efficient manner as substantially all of the Corporation’s
cash flow is derived from the sale of the petroleum and natural gas reserves that it accumulates and develops. In order to
remain financially viable, the Corporation must be able to replace reserves over time at a lesser cost on a per unit basis than
its cash flow on a per unit basis.
Future oil and natural gas exploration may involve unprofitable efforts from dry wells or 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 ensure 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, the shutting-in of wells resulting from extreme weather conditions, insufficient
storage or transportation capacity or geological and mechanical conditions. While diligent well supervision, effective maintenance
operations and the development and utilization of enhanced recovery technologies 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 or the environment and cause personal injury or threaten wildlife. Particularly, the
Corporation may explore for and produce sour natural gas in certain areas. An unintentional leak of sour natural gas could result
in 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 Corporation.
Oil and natural gas production operations are also subject to geologic and seismic risks, 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 Corporation’s business, financial condition,
results of operations and prospects.
As is standard industry practice, the Corporation is not fully insured against all risks, nor are all risks insurable. Although the
Corporation maintains liability and business interruption insurance in amounts that it considers consistent with industry
practice, liabilities associated with certain risks could exceed policy limits or not be covered. In either event, the Corporation
could incur significant costs. See “Risk Factors and Risk Management – Other Risks – Insurance”.
Gathering and Processing Facilities, Pipeline Systems and Rail
The Corporation delivers its products through gathering and processing facilities, pipeline systems and, in certain circumstances,
by rail. The amount of oil and natural gas that the Corporation can produce and sell is subject to the accessibility, availability,
proximity and capacity of these gathering and processing facilities, pipeline systems and railway lines. Notwithstanding recent
actions taken by the Government of Alberta, the ongoing lack of availability of capacity in any of the gathering and processing
facilities, pipeline systems and railway lines could result in the Corporation’s inability to realize the full economic potential of its
production or in a reduction of the price offered for the Corporation’s production. The lack of firm pipeline capacity continues
to affect the oil and natural gas industry and limits the ability to transport produced oil and natural gas to market. In addition,
the pro-rationing of capacity on inter-provincial pipeline systems continues to affect the ability to export oil and natural gas.
Unexpected shut-downs or curtailment of capacity of pipelines for maintenance or integrity work or because of actions
taken by regulators could also affect the Corporation’s production, operations and financial results. As a result, 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. Any significant change in market factors or other conditions affecting
these infrastructure systems and facilities, as well as any delays or uncertainties in constructing new infrastructure systems
and facilities, could harm the Corporation’s business and, in turn, the Corporation’s financial condition, results of operations
and cash flows. Announcements and actions taken by the Federal Government of Canada and the provincial governments of
British Columbia, Alberta and Quebec relating to the approval of infrastructure projects may continue to intensify, leading to
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2018 Annual Report increased challenges to interprovincial and international infrastructure projects moving forward. In addition, while the Federal
Government has introduced Bill C-69 to overhaul the existing environmental assessment process and replace the National
Energy Board with a new regulatory agency, the impact of the new proposed regulatory scheme on proponents and the timing
of receipt of approvals of major projects remains unclear.
Following major accidents in Lac-Megantic, Quebec and North Dakota, the Transportation Safety Board of Canada and the U.S.
National Transportation Board recommended additional regulations for railway tank cars carrying crude oil. In June 2015, as
a result of these recommendations, the Government of Canada passed the Safe and Accountable Rail Act which increased
insurance obligations on the shipment of crude oil by rail and imposed a per tonne levy of $1.65 on crude oil shipped by rail
to compensate victims and for environmental cleanup in the event of a railway accident. In addition to this legislation, new
regulations have implemented the TC-117 standard for all rail tank cars carrying flammable liquids which formalized the
commitment to retrofit, and phase out DOT-111 tank cars carrying crude oil. The increased regulation of rail transportation
may reduce the ability of railway transportation to alleviate pipeline constraints and adds additional costs to the transportation
of crude oil by rail. On July 13, 2016, the Minister of Transport (Canada) issued Protective Direction No. 38, which directed that
the shipping of crude oil on DOT-111 tank cars end by November 1, 2016. Tank cars entering Canada from the United States
will be monitored to ensure they are compliant with Protective Direction No. 38.
The Corporation’s production passes through Birchcliff owned or third-party infrastructure prior to it being ready for sale.
There is a risk that should this infrastructure fail and cause a significant portion of the Corporation’s production to be shut-in
and unable to be sold, this could have a material adverse effect on the Corporation’s available cash flow. With respect to
facilities owned by third parties and over which the Corporation has no control, 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 material adverse effect on the Corporation’s ability to process its production and deliver
the same to market. Midstream and pipeline companies may take actions to maximize their return on investment which may
in turn adversely affect producers and shippers, especially when combined with a regulatory framework that may not always
align with the interests of particular shippers.
Further, the Corporation has certain long-term take-or-pay commitments to deliver products through third-party owned
infrastructure which creates a financial liability and there can be no assurance that future volume commitments will be met
which may adversely affect the Corporation’s financial condition and cash flows from operations.
Project Risks
The Corporation manages a variety of small and large projects in the conduct of its business. Project delays and interruptions may
delay expected revenues from operations. Significant project cost overruns could make a project uneconomic. The Corporation’s
ability to execute projects and successfully market its oil and natural gas depends upon numerous factors beyond the
Corporation’s control, including:
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the availability and proximity of processing and pipeline capacity;
the availability of storage capacity;
the availability of, and the ability to acquire, water supplies needed for drilling and hydraulic fracturing and the
Corporation’s ability to dispose of water used or removed from strata at a reasonable cost and in accordance with
applicable environmental regulations;
the effects of inclement weather;
the availability of drilling and related equipment;
unexpected cost increases;
accidental events;
currency fluctuations;
regulatory changes;
the availability and productivity of skilled labour; and
the regulation of the oil and natural gas industry by various levels of government and governmental agencies.
Because of these factors, the Corporation could be unable to execute projects on time, on budget, or at all, and may be
unable to effectively market the oil and natural gas that it produces.
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2018 Annual Report Uncertainty of Reserves Estimates
There are numerous uncertainties inherent in estimating oil, natural gas and NGLs reserves and the future net revenue
attributed to such reserves. In general, estimates of economically recoverable oil, natural gas and NGLs reserves and the future
net revenue therefrom are based upon a number of variable factors and assumptions, such as historical production from the
properties, production rates, ultimate reserves recovery, the timing and amount of capital expenditures, marketability of oil,
natural gas and NGLs, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs,
all of which may vary materially from actual results. For these reasons, estimates of the economically recoverable oil, natural
gas and NGLs reserves attributable to any particular group of properties, the classification of such reserves based on risk
of recovery and estimates of future net revenue associated with reserves prepared by different engineers, or by the same
engineer at different times, may vary. The Corporation’s actual production, revenues, taxes and development and operating
expenditures with respect to its reserves will vary from estimates thereof and such variations could be material.
The estimation of proved reserves that may be developed and produced in the future is often based upon volumetric calculations
and upon analogy to similar types of reserves rather than actual production history. Recovery factors and drainage areas are
often estimated by experience and analogy to similar producing pools. Estimates based on these methods are generally less
reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production
history and production practices will result in variations in the estimated reserves and such variations could be material.
In accordance with applicable securities laws in Canada, the Corporation’s independent qualified reserves evaluators have used
forecast prices and costs in estimating the reserves and future net revenue. Actual future net revenue will be affected by other
factors such as actual production levels, supply and demand for oil and natural gas, curtailments or increases in consumption
by oil and natural gas purchasers, changes in governmental regulations or taxation and the impact of inflation on costs.
Actual production and cash flows derived from the Corporation’s reserves will vary from the estimates contained in the
Corporation’s independent reserves evaluations and such variations could be material. The independent reserves evaluations
are based in part on the assumed success of activities the Corporation intends to take in future years. The reserves and estimated
future net revenue to be derived therefrom and contained in the Corporation’s independent reserves evaluations will be reduced
to the extent that such activities do not achieve the level of success assumed in the evaluations.
Availability and Cost of Equipment and Services
Oil and natural gas exploration, development and operating activities are dependent on the availability and cost of specialized
equipment and other materials (typically leased from third parties) and skilled personnel trained to use such equipment in
the areas where such activities will be conducted. The availability of such equipment, materials and personnel is limited.
An increase in demand or cost, or a decrease in the availability of, such equipment, materials or personnel may impede
the Corporation’s exploration, development and operating activities, which, in turn, could materially adversely affect the
Corporation’s business and financial condition.
Potential Future Drilling Locations
The Corporation’s identified potential future drilling locations represent a significant part of the Corporation’s future growth.
The Corporation’s ability to drill and develop these locations and the drilling locations on which it actually drills wells depends
on a number of uncertainties and factors, including, but not limited to, the availability of capital, equipment and personnel, oil
and natural gas prices, costs, inclement weather, seasonal restrictions, drilling results, additional geological, geophysical and
reservoir information that is obtained, production rate recovery, gathering system and transportation constraints, the net price
received for commodities produced, regulatory approvals and regulatory changes. As a result of these uncertainties, there can
be no assurance that the potential future drilling locations that Birchcliff has identified will ever be drilled and, if drilled, that
such locations will result in additional oil, NGLs or natural gas production and, in the case of unbooked locations, additional
reserves. As such, the Corporation’s actual drilling activities may differ materially from those presently identified, which could
adversely affect the Corporation’s business.
Seasonality and Extreme Weather Conditions
The level of activity in the Canadian oil and natural gas industry is influenced by seasonal weather patterns. Wet weather and
spring thaw may make the ground unstable. Consequently, municipalities and provincial transportation departments may
enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels. Road bans
and other restrictions generally result in a reduction of drilling and exploratory activities and may also result in the shut-in
of some of the Corporation’s production if not otherwise tied-in. In addition, certain oil and natural gas producing properties
are located in areas that are inaccessible other than during the winter months because the ground surrounding the sites in
these areas consists of swampy terrain. Further, extreme cold weather, heavy snowfall and heavy rainfall may restrict the
Corporation’s ability to access its properties and cause operational difficulties including damage to machinery or contribute
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2018 Annual Report to personnel injury because of dangerous working conditions. Seasonal factors and unexpected weather patterns may lead to
declines in exploration and production activity and also to volatility in commodity prices as the demand for natural gas typically
fluctuates during cold winter months and hot summer months.
Competition
The oil and natural gas industry is highly competitive in all of its phases. The Corporation competes with numerous other
entities in the exploration, development, production and marketing of oil and natural gas, including land, acquisitions of
reserves, access to drilling and service rigs and other equipment, access to transportation and skilled technical and operating
personnel. The Corporation’s competitors include oil and natural gas companies that have substantially greater financial
resources, staff and facilities than those of the Corporation. Some of these companies not only explore for, develop and
produce oil and natural gas, but also carry on refining operations and market oil and natural gas on an international basis.
As a result of these complementary activities, some of these competitors may have greater and more diverse competitive
resources to draw on than the Corporation. The Corporation’s ability to increase its reserves in the future will depend not only
on its ability to explore and develop its present properties, but also on its ability to select and acquire other suitable producing
properties or prospects for exploratory drilling.
Hydraulic Fracturing
Hydraulic fracturing involves the injection of water, sand and small amounts of additives under pressure into rock formations
to stimulate the production of oil and natural gas. Specifically, hydraulic fracturing enables the production of commercial
quantities of oil and natural gas from reservoirs that were previously unproductive. While hydraulic fracturing has been
in use for many years, there has been increased focus on the environmental aspects of hydraulic fracturing practices in
recent years. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition
(including litigation) to oil and natural gas production activities using hydraulic fracturing techniques. Any new laws,
regulations or permitting requirements regarding hydraulic fracturing could lead to operational delays, increased operating
costs, third-party or governmental claims and could increase the Corporation’s costs of compliance and doing business, as
well as delay the development of oil and natural gas resources from certain formations which are not commercial without
the use of hydraulic fracturing. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas
that the Corporation is ultimately able to produce from its reserves and, therefore, could adversely affect the Corporation’s
business, financial condition, results of operations and prospects.
All Assets in One Area
All of the Corporation’s producing properties are geographically concentrated in the Peace River Arch area of Alberta. As
a result of this concentration, the Corporation may be disproportionately exposed to the impact of delays or interruptions
of production from that area caused by transportation capacity constraints, curtailment of production, natural disasters,
availability of equipment, facilities or services, adverse weather conditions or other events which impact that area. Due to the
concentrated nature of the Corporation’s portfolio of properties, a number of the Corporation’s properties could experience any
of the same conditions at the same time, resulting in a relatively greater impact on the Corporation’s results of operations than
they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could
have a material adverse effect on the Corporation’s financial condition and results of operations.
Operational Dependence
Other companies operate some of the assets in which the Corporation has an interest. The Corporation has limited ability to
exercise influence over the operation of those assets or their associated costs, which could adversely affect the Corporation’s
business, financial condition, results of operations and prospects. The Corporation’s return on assets operated by others
depends upon a number of factors that may be outside of the Corporation’s control, including, but not limited to, the timing
and amount of capital expenditures, the operator’s expertise and financial resources, the approval of other participants, the
selection of technology and risk management practices.
In addition, due to the current low and volatile commodity price environment, many companies, including companies that
may operate some of the assets in which the Corporation has an interest, may be in financial difficulty, which could impact
their ability to fund and pursue capital expenditures, carry out their operations in a safe and effective manner and satisfy
regulatory requirements with respect to abandonment and reclamation obligations. If companies that operate some of the assets
in which the Corporation has an interest fail to satisfy regulatory requirements with respect to abandonment and reclamation
obligations, the Corporation may be required to satisfy such obligations and to seek recourse from such companies. To the
extent that any of such companies go bankrupt, become insolvent or make a proposal or institute any proceedings relating to
bankruptcy or insolvency, it could result in such assets being shut-in, the Corporation potentially becoming subject to additional
liabilities relating to such assets and the Corporation having difficulty collecting revenue due to it from such operators or
recovering amounts owing to the Corporation from such operators for their share of abandonment and reclamation obligations.
Any of these factors could have a material adverse effect on the Corporation’s financial and operational results.
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2018 Annual Report Expiration of Licences and Leases
The Corporation’s properties are held in the form of licences and leases and working interests in licences and leases held by
others. If the Corporation or the holder of the licence or lease fails to meet the specific requirements of a licence or lease,
the licence or lease may terminate or expire. There can be no assurance that any of the obligations required to maintain each
licence or lease will be met. The termination or expiration of the Corporation’s licences or leases or the working interests
relating to a licence or lease may have a material adverse effect on the business, financial condition, results of operations and
prospects of the Corporation.
Cost of New Technologies
The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new
products and services utilizing new technologies. Other oil and natural gas companies may have greater financial, technical
and personnel resources that allow them to implement and benefit from new technologies before the Corporation. There can
be no assurance that the Corporation will be able to respond to such competitive pressures and implement such technologies
on a timely basis or at an acceptable cost. If the Corporation implements such technologies, there is no assurance that the
Corporation will do so successfully. One or more of the technologies currently utilized by the Corporation or implemented in the
future may become obsolete. In such case, the Corporation’s business, financial condition, results of operations and prospects
could be affected adversely and materially. If the Corporation is unable to utilize the most advanced commercially available
technology or is unsuccessful in implementing certain technologies, its business, financial condition, results of operations and
prospects could also be adversely affected in a material way.
Alternatives to and Changing Demand for Petroleum Products
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas
and technological advances in fuel economy and renewable energy generation devices could reduce the demand for oil, natural
gas and liquid hydrocarbons. Recently, certain jurisdictions have implemented policies or incentives to decrease the use of fossil
fuels and encourage the use of renewable fuel alternatives, which may lessen the demand for petroleum products and put
downward pressure on commodity prices. In addition, advancements in energy efficient products have a similar effect on the
demand for oil and natural gas products. The Corporation cannot predict the impact of the changing demand for oil and natural
gas products and any major changes may have a material adverse effect on the Corporation’s business, financial condition,
results of operations and cash flows by decreasing the Corporation’s profitability, increasing its costs, limiting its access to
capital or decreasing the value of its assets.
Expansion into New Activities
The operations and expertise of the Corporation’s management are currently focused primarily on oil and natural gas
production, exploration and development in the Peace River Arch area of Alberta. In the future, the Corporation may acquire
or move into new industry-related activities or new geographical areas or may acquire different energy-related assets, and as
a result, the Corporation may face unexpected risks or alternatively, the Corporation’s exposure to one or more existing risk
factors may be significantly increased, which may in turn result in the Corporation’s future operational and financial condition
being adversely affected.
Regulatory, Political and Environmental Risks
Regulatory
Various levels of governments impose extensive controls and regulations on oil and natural gas operations (including
exploration, development, production, pricing, marketing, transportation and infrastructure). Governments may regulate or
intervene with respect to exploration and production activities, prices, taxes, royalties, the exportation of oil and natural gas and
infrastructure projects. Amendments to these controls and regulations may occur from time to time in response to economic
or political conditions. The implementation of new regulations or the modification to existing regulations affecting the oil and
natural gas industry could reduce the demand for crude oil and natural gas and increase the Corporation’s costs or make certain
projects uneconomic, which may have a material adverse effect on the Corporation’s business, financial condition, results of
operations and prospects.
Although the current Federal Government has introduced Bill C-69 to overhaul the existing environmental assessment process
and replace the National Energy Board with a new regulatory agency, the impact of the new proposed regulatory scheme on
proponents and the timing of receipt of approvals of major projects remains unclear.
Even when projects are approved at a federal level, such projects often face further delays due to interference by provincial
and municipal governments, as well as court challenges related to issues such as indigenous title, the government’s duty to
consult and accommodate indigenous peoples and the sufficiency of the relevant environmental review processes. In addition,
export pipelines from Canada to the United States face additional uncertainty as such pipelines require approvals of several
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2018 Annual Report levels of government in the United States. The ongoing third-party challenges to regulatory decisions or orders has reduced the
efficiency of the regulatory regime, as the implementation of the decisions and orders has been delayed resulting in uncertainty
and interruption to business of the oil and natural gas industry.
Recently, the Federal Government and certain provincial governments have taken steps to initiate protocols and regulations to
limit the release of methane from oil and natural gas operations. Such draft regulations and protocols may require additional
expenditures or otherwise negatively impact the Corporation’s operations and may affect the Corporation’s revenues and
financial condition.
Further, in response to widening pricing differentials, the Government of Alberta implemented production curtailment.
The Corporation is not currently subject to a curtailment order; however, no assurance can be given that the Government of
Alberta will not in the future enact rules which would require the Corporation to curtail its production.
In order to conduct oil and natural gas operations, the Corporation requires regulatory permits, licences, registrations,
approvals and authorizations from various governmental authorities. There can be no assurance that the Corporation will
be able to obtain all of the permits, licences, registrations, approvals and authorizations that may be required to conduct
operations that it may wish to undertake. In addition, the Corporation may have to comply with the requirements of certain
federal legislation such as the Competition Act (Canada) and the Investment Canada Act (Canada), which may adversely
affect its business and financial condition and the market value of its securities or assets, particularly when undertaking,
or attempting to undertake, an acquisition or disposition.
Political Uncertainty
In the last several years, the United States and certain European countries have experienced significant political events that
have cast uncertainty on global financial and economic markets.
Since the 2016 U.S. presidential election, the current United States administration has begun taking steps to implement
certain of its promises made during the campaign. The administration has withdrawn the United States from the Trans-Pacific
Partnership and Congress has passed sweeping tax reform, which, among other things, significantly reduces U.S. corporate
tax rates. This may affect competitiveness of other jurisdictions, including Canada. In addition, the North American Free Trade
Agreement (“NAFTA”) was renegotiated and on November 30, 2018, Canada, the U.S. and Mexico signed the United States-
Mexico-Canada Agreement which will replace NAFTA once ratified by the three signatory countries. The administration has
also taken action with respect to reducing regulation which may also affect the relative competitiveness of other jurisdictions.
It is unclear exactly what other actions the United States administration will implement, and if implemented, how these
actions may impact Canada and in particular the oil and natural gas industry. Any actions taken by the current United States
administration may have a negative impact on the Canadian economy and on the businesses, financial condition, results of
operations, prospects and the valuation of Canadian oil and natural gas companies, including the Corporation.
In addition to the political disruption in the United States, the citizens of the United Kingdom voted to withdraw from the
European Union and the Government of the United Kingdom has taken steps to implement such withdrawal. The terms of
the United Kingdom’s exit from the European Union and whether it will occur at all remain to be determined. Some European
countries have also experienced the rise of anti-establishment political parties and public protests held against open-door
immigration policies, trade and globalization. To the extent that certain political actions taken in North America, Europe and
elsewhere in the world result in a marked decrease in free trade, access to personnel and freedom of movement, it could have
an adverse effect on the Corporation’s ability to market its products internationally, increase costs for goods and services
required for the Corporation’s operations, reduce access to skilled labour and negatively impact the Corporation’s business,
operations, financial condition and the market value of its securities.
A change in federal, provincial or municipal governments in Canada may have an impact on the directions taken by such
governments on matters that may impact the oil and natural gas industry, including the balance between economic development
and environmental policy such as the potential impact of the recent change of government in British Columbia and announcements
and actions by the Government of British Columbia that may impact the completion of the Trans-Mountain Pipeline project,
LNG facilities and other infrastructure projects.
Geopolitical Risks
Political changes in North America and political instability in the Middle East and elsewhere may cause disruptions in
the supply of oil that affects the marketability and price of crude oil and natural gas. Conflicts, or conversely peaceful
developments, arising outside of Canada, including changes in political regimes or parties in power, may have a significant
impact on the price of oil and natural gas. Any particular event could result in a material decline in prices and result in a
reduction of the Corporation’s revenue.
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2018 Annual Report 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 oil and natural 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 Corporation to incur costs to remedy such discharge. Although
the Corporation believes that it is in material compliance with current applicable environmental legislation, no assurance can
be given that environmental compliance requirements 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 Corporation’s
business, financial condition, results of operations and prospects.
In addition, political and economic events may significantly affect the scope and timing of climate change measures that are
put in place. The implementation of new environmental regulations or the modification of existing environmental regulations
affecting the oil and natural gas industry generally could reduce demand for oil and natural gas and increase costs. See “Risk
Factors and Risk Management – Regulatory, Political and Environmental Risks – Climate Change”.
Climate Change
The Corporation’s exploration and production facilities and other operations and activities emit GHGs which requires the
Corporation to comply with applicable GHG emissions legislation. Climate change policy is evolving at regional, national and
international levels and political and economic events may significantly affect the scope and timing of climate change measures
that are ultimately put in place. As a signatory to the United Nations Framework Convention on Climate Change and the Paris
Agreement, the Government of Canada pledged to cut its GHG emissions by 30% from 2005 levels by 2030. One of the
pertinent policies announced to date by the Government of Canada to reduce GHG emissions is the planned implementation of
a nation-wide price on carbon emissions. The federal carbon levy goes into effect April 1, 2019 and will affect those provinces
that have not implemented their own carbon taxes, cap-and-trade systems or other plans for carbon pricing, namely Ontario,
Manitoba, Saskatchewan and New Brunswick. The federal carbon levy will be at an initial rate of $20 per tonne. Provincially,
the Government of Alberta has already implemented a carbon levy on almost all sources of GHG emissions, now at a rate of
$30 per tonne. The implementation of the federal carbon levy is currently subject to constitutional challenges by the Provinces
of Saskatchewan and Ontario, which are supported by the Province of New Brunswick.
Concerns about climate change have resulted in a number of environmental activists and members of the public opposing the
continued exploitation and development of fossil fuels. Historically, political and legal opposition to the fossil fuel industry
focused on public opinion and the regulatory process. More recently, however, there has been a movement to more directly hold
governments and oil and natural gas companies responsible for climate change through climate litigation. In November 2018,
ENvironment JEUnesse, a Quebec advocacy group, applied to the Quebec Superior Court to certify a class action against
the Government of Canada for climate related matters. In January 2019, the City of Victoria became the first municipality in
Canada to endorse exploring the initiation of a class action lawsuit against oil and natural gas producers for climate-related
harms. See “Risk Factors and Risk Management – Non-Governmental Organizations and Eco-Terrorism Risks” and “Risk Factors –
Public Opinion and Reputational Risk“.
In addition, there has been public discussion that climate change may be associated with extreme weather conditions and
increased volatility in seasonal temperatures. Extreme weather could interfere with the Corporation’s production and increase
the Corporation’s costs. At this time, the Corporation is unable to determine the extent to which climate change may lead to
increased storm or weather hazards affecting its operations.
The direct or indirect costs of compliance with GHG-related legislation may have a material adverse effect on the Corporation’s
business, financial condition, results of operations and prospects. Adverse impacts to the Corporation’s business as a result of
GHG legislation may include, but are not limited to, increased compliance costs, permitting delays, increased operating costs
and capital expenditures and reduced demand for the oil, natural gas and NGLs that the Corporation produces. In addition, the
Pouce Coupe Gas Plant is subject to the Carbon Competitiveness Incentive Regulation (Alberta) and some of the Corporation’s
other significant facilities may ultimately become subject to future regional, provincial and/or federal climate change regulations
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2018 Annual Report to manage GHG emissions. Given the evolving nature of the debate related to climate change and the control of GHG and
resulting requirements, it is expected that current and future climate change regulations will have the effect of increasing
the Corporation’s operating expenses and in the long-term reducing the demand for oil and natural gas production resulting
in a decrease in the Corporation’s profitability and a reduction in the value of its assets or asset write-offs.
Carbon Pricing Risk
The majority of countries across the globe have agreed to reduce their carbon emissions in accordance with the Paris Agreement.
In Canada, the Federal Government and certain provincial governments have implemented legislation aimed at incentivizing
the use of alternative fuels and in turn reducing carbon emissions. The taxes placed on carbon emissions may have the effect
of decreasing the demand for oil and natural gas products and at the same time, increasing the Corporation’s operating
expenses, each of which may have a material adverse effect on the Corporation’s profitability and financial condition. Further,
the imposition of carbon taxes puts the Corporation at a disadvantage with its counterparts who operate in jurisdictions where
there are less costly carbon regulations.
Liability Management Programs
Alberta has developed a licensee Liability Management Rating Program (the “AB LMR Program”) which is designed to prevent
taxpayers from incurring costs associated with the suspension, abandonment, remediation and reclamation of wells, facilities
and pipelines in the event that a licensee or permit holder is unable to satisfy its regulatory obligations. This program involves
an assessment of the ratio of a licensee’s deemed assets to deemed liabilities. If a licensee’s deemed liabilities exceed its
deemed assets, a security deposit is generally required. Changes to the required ratio of the Corporation’s deemed assets
to deemed liabilities or other changes to the requirements of the AB LMR Program may result in the requirement for security
to be posted in the future and may result in significant increases to the Corporation’s compliance obligations. In addition, the
AB LMR Program may prevent or interfere with the Corporation’s ability to acquire or dispose of assets as both the vendor and
the purchaser of oil and natural gas assets must be in compliance with the AB LMR Program (both before and after the transfer
of the assets) for the applicable regulatory agency to allow for the transfer of such assets.
The impact and consequences of the Supreme Court of Canada’s decision in the Redwater case on the AER’s rules and policies,
lending practices in the crude oil and natural gas sector and on the nature and determination of secured lenders to take
enforcement proceedings will no doubt evolve as the consequences of the decision are evaluated and considered by regulators,
lenders and receivers/trustees.
Royalty Regimes
There can be no assurance that the Government of Alberta will not adopt a new royalty regime or modify the existing royalty
regime, which may have an impact on the economics of the Corporation’s projects. An increase in royalties would reduce
the Corporation’s earnings and could make future capital investments, or the Corporation’s operations, less economic or
uneconomic. On January 29, 2016, the Government of Alberta adopted a new royalty regime which took effect on January 1, 2017.
Disposal of Fluids Used in Operations
The safe disposal of the hydraulic fracturing fluids (including the additives) and water recovered from oil and natural gas wells
is subject to ongoing regulatory review by the federal and provincial governments, including its effect on fresh water supplies
and the ability of such water to be recycled, amongst other things. While it is difficult to predict the impact of any regulations
that may be enacted in response to such review, the implementation of stricter regulations may increase the Corporation’s
costs of compliance which may impact the economics of certain projects and, in turn, impact activity levels and new capital
spending on the Corporation’s oil and natural gas properties.
Other Risks
Market Prices of the Corporation’s Securities
The market price of the Corporation’s securities may be volatile, which may affect the ability of holders to sell such securities
at an advantageous price. The trading price of securities of oil and natural gas issuers is subject to substantial volatility often
based on factors related and unrelated to the financial performance or prospects of the issuers involved. Factors unrelated
to the Corporation’s performance could include macroeconomic developments nationally, within North America or globally,
domestic and global commodity prices or current perceptions of the oil and natural gas market. In recent years, the volatility
of commodities has increased due to, in part, the implementation of computerized trading and the decrease of discretionary
commodity trading. In addition, in certain jurisdictions, institutions, including government-sponsored entities, have determined
to decrease their ownership in oil and natural gas entities which may impact the liquidity of certain securities and may put
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2018 Annual Report downward pressure on the trading price of those securities. Similarly, the market prices of the Corporation’s securities could
be subject to significant fluctuations in response to variations in the Corporation’s operating results, financial condition,
liquidity and other internal factors. In addition, market price fluctuations in the Corporation’s securities may also be due to the
Corporation’s results failing to meet the expectations of securities analysts or investors in any quarter, downward revision in
securities analysts’ estimates and material public announcements by the Corporation, along with a variety of additional factors,
including, without limitation, those set forth under "Advisories – Forward-Looking Statements”. Accordingly, the prices at which
the Corporation’s securities will trade cannot be accurately predicted.
Reliance on Key Personnel
The Corporation’s success depends, in large measure, on certain key personnel. The loss of the services of such key personnel
could have a material adverse effect on the Corporation’s business, financial condition, results of operations and prospects.
The Corporation does not have any key personnel insurance in effect. The contributions of the existing management team to
the immediate and near-term operations of the Corporation are likely to be of central importance. In addition, the competition
for qualified personnel in the oil and natural gas industry is intense and there can be no assurance that the Corporation will
be able to continue to attract and retain all of the personnel necessary for the development and operation of its business.
Investors must rely upon the ability, expertise, judgment, discretion, integrity and good faith of the Corporation’s management.
Skilled Workforce
An inability to recruit and retain a skilled workforce may negatively impact the Corporation. The operations and management
of the Corporation require the recruitment and retention of a skilled workforce, including engineers, technical personnel
and other professionals. The loss of key members of such workforce, or a substantial portion of the workforce as a whole,
could result in the failure to implement the Corporation’s business plans. The Corporation competes with other companies
in the oil and natural gas industry as well as other industries for this skilled workforce. A decline in market conditions has led
to increasing numbers of skilled personnel to seek employment in other industries. In addition, certain of the Corporation’s
current employees are senior and have significant institutional knowledge that must be transferred to other employees prior to
their departure from the workforce. If the Corporation is unable to retain current employees, successfully complete effective
knowledge transfers and/or recruit new employees with comparable knowledge and experience, the Corporation could be
negatively impacted. In addition, the Corporation could experience increased costs to retain and recruit these professionals.
Public Opinion and Reputational Risk
The Corporation’s business, financial condition, operations or prospects may be negatively impacted as a result of any negative
public opinion towards the Corporation or as a result of any negative sentiment towards, or in respect of, the Corporation’s
reputation with stakeholders, special interest groups, political leadership, the media or other entities. Public opinion may be
influenced by certain media and special interest groups’ negative portrayal of the industry in which the Corporation operates,
as well as their opposition to certain oil and natural gas projects. Potential impacts of negative public opinion or reputational
issues may include delays or interruptions in operations, legal or regulatory actions or challenges, blockades, increased
regulatory oversight, reduced support for, delays in, challenges to, or the revocation of regulatory approvals, permits and/or
licences and increased costs and/or cost overruns.
Any environmental damage, loss of life, injury or damage to property caused by the Corporation’s operations could damage
its reputation. Negative sentiment towards the Corporation could result in a lack of willingness of municipal authorities to
grant the necessary licenses or permits for the Corporation to operate its business. In addition, negative sentiment towards
the Corporation could result in the residents of the areas where the Corporation is doing business opposing further operations
in the area by the Corporation. If the Corporation develops a reputation of having an unsafe work site, this may impact its
ability to attract and retain the necessary skilled employees and consultants to operate its business. Further, the Corporation’s
reputation could be affected by actions and activities of other corporations operating in the oil and natural gas industry, particularly
other producers, over which the Corporation has no control. Further, opposition from special interest groups opposed to oil and
natural gas development and the possibility of climate related litigation against governments and fossil fuel companies may
impact the Corporation’s reputation. See “Risk Factors and Risk Management – Regulatory, Political and Environmental Risks –
Climate Change”.
Reputational risk cannot be managed in isolation from other forms of risk. Credit, market, operational, insurance, regulatory and
legal risks, among others, must all be managed effectively to safeguard the Corporation’s reputation. Damage to the Corporation’s
reputation could result in negative investor sentiment towards the Corporation, which may result in limiting the Corporation’s
access to capital, increasing the cost of capital and decreasing the price and liquidity of the Corporation’s securities.
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2018 Annual Report Changing Investor Sentiment
A number of factors, including the concerns of the effects of the use of fossil fuels on climate change, concerns of the impact of
oil and natural gas operations on the environment, concerns of environmental damage relating to spills of petroleum products
during transportation and concerns of indigenous rights, have affected certain investors’ sentiments towards investing in the
oil and natural gas industry. As a result of these concerns, some institutional, retail and public investors have announced that
they no longer are willing to fund or invest in oil and natural gas properties or companies or are reducing the amount thereof
over time. In addition, certain institutional investors are requesting that issuers develop and implement more robust social,
environmental and governance policies and practices. Developing and implementing such policies and practices can involve
significant costs and require a significant time commitment from the Corporation’s Board, management and employees.
Failing to implement the policies and practices as requested by institutional investors may result in such investors reducing
their investment in the Corporation or not investing in the Corporation at all. Any reduction in the investor base interested or
willing to invest in the oil and natural gas industry and more specifically, in the Corporation, may result in limiting Birchcliff’s
access to capital, increasing the cost of capital and decreasing the price and liquidity of the Corporation’s securities, even if the
Corporation’s operating results, underlying asset value or prospects have not changed. Additionally, these factors, as well as
other related factors, may cause a decrease in the value of the Corporation’s assets which may result in an impairment charge.
Non-Governmental Organizations and Eco-Terrorism Risks
The crude oil and natural gas industry may, at times, be subject to public opposition. Such public opposition could expose
the Corporation to the risk of higher costs, delays or even project cancellations due to increased pressure on governments
and regulators by special interest groups including Aboriginal groups, landowners, environmental interest groups (including
those opposed to oil and gas production operations) and other non-governmental organizations. Potential impacts of such
pressure and opposition include blockades, legal or regulatory actions or challenges, increased regulatory oversight, reduced
support of the federal, provincial or municipal governments, and delays in, challenges to, or the revocation of regulatory
approvals, permits and/or licences. There is no guarantee that the Corporation will be able to satisfy the concerns of the special
interest groups and non-governmental organizations and attempting to address such concerns may require significant and
unanticipated capital and operating expenditures which may negatively impact the Corporation’s business, financial condition,
results of operations and prospects.
In addition, the Corporation’s oil and natural gas properties, wells and facilities or the third-party facilities and pipelines utilized
by the Corporation could be the subject of a terrorist attack. If any of such properties, wells or facilities are the subject of
terrorist attack, it may have a material adverse effect on the Corporation’s business, financial condition, results of operations
and prospects.
Management of Growth and Integration
The Corporation may be subject to both integration and growth-related risks, including capacity constraints and pressure on
its internal systems and controls. The ability of the Corporation to effectively manage growth and the integration of additional
assets will require it to continue to implement and improve its operational and financial systems and to expand, train and
manage its employee base. The inability of the Corporation to effectively deal with this integration and growth could have a
material adverse impact on its business, financial condition, results of operations and prospects.
Risks Associated with Acquisitions and Dispositions
The Corporation considers acquisitions and dispositions of assets in the ordinary course of business. Typically, once an
acquisition opportunity is identified, a review of available information relating to the assets is conducted. There is a risk that
even a detailed review of records and assets may not necessarily reveal every existing or potential problem, nor will it permit
the Corporation to become sufficiently familiar with the assets to fully assess their deficiencies and potential. There is no
guarantee that defects in the chain of title will not arise to defeat the Corporation’s title to certain assets or that environmental
defects, liabilities or deficiencies do not exist or are greater than anticipated. Inspections may not always be performed on
every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an
inspection is undertaken. Even when problems are identified, the Corporation may assume certain environmental and other
risk liabilities in connection with acquired assets.
In addition, acquisitions of oil and natural gas properties or companies are based in large part on engineering, environmental
and economic assessments. These assessments include a series of assumptions regarding such factors as recoverability and
marketability of oil and natural gas, environmental restrictions and prohibitions regarding releases and emissions of various
substances, future prices of oil and natural gas, future operating costs, future capital expenditures and royalties and other government
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2018 Annual Report levies which will be imposed over the producing life of the reserves. Many of these factors are subject to change and are
beyond the control of the Corporation. All such assessments involve a measure of geologic, engineering, environmental and
regulatory uncertainty that could result in lower production and reserves or higher operating or capital expenditures than anticipated.
Achieving the benefits of acquisitions depends on successfully consolidating functions and integrating operations and
procedures in a timely and efficient manner and the Corporation’s ability to realize the anticipated growth opportunities and
synergies from combining the acquired businesses and operations with those of the Corporation. The integration of acquired
businesses and assets may require substantial management effort, time and resources, diverting management’s focus away
from other strategic opportunities and operational matters.
Management continually assesses the value and contribution of the various assets within its portfolio. In this regard, certain
assets may be periodically disposed of so the Corporation can focus its efforts and resources more efficiently. Depending on the
state of the market for such assets, there is a risk that certain assets of the Corporation could realize less on disposition than what
the market may expect for such disposition or realize less than their carrying value on the Corporation’s financial statements.
Information Technology Systems and Cyber-Security
The Corporation has become increasingly dependent upon the availability, capacity, reliability and security of its information
technology infrastructure and its ability to expand and continually update this infrastructure to conduct daily operations.
The Corporation depends on various information technology systems to estimate reserves, process and record financial data,
manage its financial resources and land base, analyze seismic information, administer its contracts with its operators and
lessees and communicate with employees and third-party partners.
In the event the Corporation is unable to regularly deploy software and hardware, effectively upgrade systems and network
infrastructure and take other steps to maintain or improve the efficiency and efficacy of its information technology systems,
the operation of such systems could be interrupted or result in the loss, corruption or release of data. Further, the Corporation
is subject to a variety of information technology and system risks as a part of its normal course operations, including
potential breakdown, invasion, virus, cyber-attack, cyber-fraud, security breach, and destruction or interruption of the
Corporation’s information technology systems by third parties or insiders. Unauthorized access to these systems by employees
or third parties could lead to corruption or exposure of confidential, fiduciary or proprietary information, interruption to
communications or operations or disruption to its business activities or its competitive position. In addition, cyber-phishing
attempts, in which a malicious party attempts to obtain sensitive information such as usernames, passwords, and credit card
details (and money) by disguising as a trustworthy entity in an electronic communication, have become more widespread and
sophisticated in recent years. If the Corporation becomes a victim to a cyber-phishing attack it could result in a loss or theft
of the Corporation’s financial resources or critical data and information or could result in a loss of control of the Corporation’s
technological infrastructure or financial resources. The Corporation’s employees are often the targets of such cyber-phishing
attacks, as they are and will continue to be targeted by parties using fraudulent “spoof” emails to misappropriate information
or to introduce viruses or other malware through “trojan horse” programs to the Corporation’s computers. These emails appear
to be legitimate emails, but direct recipients to fake websites operated by the sender of the email or request recipients to send
a password or other confidential information through email or to download malware.
In addition to the oversight provided by the Corporation’s Information Technology Committee, there is further reporting on
the Corporation’s information technology and cyber-security risks to the Board. Further, the Corporation maintains policies
and procedures that address and implement employee protocols with respect to electronic communications and electronic
devices and the Corporation periodically conducts cyber-security risk assessments. The Corporation also employs encryption
protection for some of its confidential information. Despite the Corporation’s efforts to mitigate such phishing attacks
through education and training, phishing activities remain a serious problem that may damage its information technology
infrastructure. The Corporation applies technical and process controls in line with industry-accepted standards to protect
its information assets and systems, including a written incident response plan for responding to a cyber-security incident.
However, these controls may not adequately prevent cyber-security breaches. Disruption of critical information technology
services, or breaches of information security, could have a negative effect on the Corporation’s performance and earnings,
as well as on its reputation, and any damages sustained may not be adequately covered by the Corporation’s current insurance
coverage, or at all. The significance of any such event is difficult to quantify, but may in certain circumstances be material and
could have a material adverse effect on the Corporation’s business, financial condition, results of operations and prospects.
To date, the Corporation has not been subject to a cyber-security attack or other breach that has had a material impact on its
business or operations or resulted in material losses to the Corporation; however, there is no assurance that the measures the
Corporation takes to protect its business systems and operational control systems will be effective in protecting against a
breach in the future and that the Corporation will not incur such losses in the future.
87
2018 Annual Report Insurance
Although the Corporation maintains insurance in accordance with industry standards to address certain risks, such insurance
has limitations on liability and may not be sufficient to cover the full extent of liabilities. In addition, certain risks are not, in all
circumstances, insurable or, in certain circumstances, the Corporation may elect not to obtain insurance to deal with specific
risks due to the high premiums associated with such insurance or other reasons. The payment of any uninsured liabilities would
reduce the funds available to the Corporation. The occurrence of a significant event that the Corporation is not fully insured
against, or the insolvency of the insurer of such event, could have a material adverse effect on the Corporation’s business,
financial condition, results of operations and prospects.
Litigation
In the normal course of the Corporation’s operations, it may become involved in, be named as a party to or be the subject of,
various legal proceedings, including regulatory proceedings, tax proceedings and legal actions. Such proceedings may develop
in relation to personal injury (including claims resulting from exposure to hazardous substances), property damage, property
taxes, land and access rights, royalty rights, the environment (including claims relating to contamination) and lease and
contractual disputes. The outcome of outstanding, pending or future proceedings cannot be predicted with certainty and may
be determined adversely to the Corporation and, as a result, could have a material adverse effect on the Corporation’s assets,
liabilities, business, financial condition and results of operations. Even if the Corporation prevails in any such legal proceedings,
the proceedings could be costly and time-consuming and may divert the attention of management and key personnel from the
Corporation’s business operations, which may adversely affect the Corporation.
Due to the rapid development of oil and natural gas technology, the Corporation may become involved in, be named as a party to
or be the subject of, various legal proceedings in which it is alleged that the Corporation has infringed the intellectual property
rights of others or conversely, the Corporation may commence lawsuits against others who the Corporation believes are
infringing upon its intellectual property rights. The Corporation’s involvement in intellectual property litigation could result
in significant expense, adversely affecting the development of its assets or intellectual property or diverting the efforts of
its technical and management personnel, whether or not such litigation is resolved in the Corporation’s favour. In the event
of an adverse outcome as a defendant in any such litigation, the Corporation may, among other things, be required to: (i) pay
substantial damages; (ii) cease the use of infringing intellectual property; (iii) expend significant resources to develop or acquire
non-infringing intellectual property; (iv) discontinue processes incorporating infringing technology; or (v) obtain licences to the
infringing intellectual property. However, the Corporation may not be successful in such development or acquisition or such licences
may not be available on reasonable terms. Any such development, acquisition or licence could require the expenditure of
substantial time and other resources and could have a material adverse effect on the Corporation’s business and financial results.
Aboriginal Claims
Aboriginal peoples have claimed aboriginal title and rights in portions of Western Canada. The Corporation is not aware that
any claims have been made in respect of its properties or assets; however, the legal basis of an aboriginal land claim and
aboriginal rights is a matter of considerable legal complexity and the impact of the assertion of such a claim, or the possible
effect of a settlement of such claim, upon the Corporation cannot be predicted with any degree of certainty at this time.
In addition, no assurance can be given that any recognition of aboriginal rights or claims whether by way of a negotiated
settlement or by judicial pronouncement (or through the grant of an injunction prohibiting exploration or development
activities pending resolution of any such claim) would not delay or even prevent the Corporation’s exploration and development
activities. If a claim arose and was successful, such claim may have a material adverse effect on the Corporation’s business,
financial condition, results of operations and prospects. In addition, the process of addressing such claims, regardless of
the outcome, is expensive and time consuming and could result in delays which could have a material adverse effect on the
Corporation’s business, financial condition, results of operations and prospects.
Internal Controls
Effective internal controls are necessary for the Corporation to provide reliable financial reports and to help prevent fraud.
Although the Corporation undertakes a number of procedures in order to help ensure the reliability of its financial reports,
including those imposed on it under Canadian securities laws, the Corporation cannot be certain that such measures will ensure
that the Corporation will maintain adequate control over financial processes and reporting. Failure to implement required new
or improved controls, or difficulties encountered in their implementation, could harm the Corporation’s results of operations
or cause it to fail to meet its reporting obligations. If the Corporation or its independent auditors discover a material weakness,
the disclosure of that fact, even if quickly remedied, could reduce the market’s confidence in the Corporation’s financial
statements and harm the trading prices of the Corporation’s securities.
88
2018 Annual Report Title to Assets
The Corporation’s actual title to and interest in its properties, and its right to produce and sell the oil and natural gas therefrom,
may vary from the Corporation’s records. In addition, there may be valid legal challenges or legislative changes that affect the
Corporation’s title to and right to produce from its oil and natural gas properties, which could impair the Corporation’s activities
on them and result in a reduction of the revenue received by the Corporation.
If a defect exists in the chain of title or in the Corporation’s right to produce, or a legal challenge or legislative change arises,
it is possible that the Corporation may lose all or a portion of the properties to which the title defect relates and/or its right
to produce from such properties. This may have a material adverse effect on the Corporation’s business, financial condition,
results of operations and prospects.
Breaches of Confidentiality
While discussing potential business relationships or other transactions with third parties, the Corporation may disclose
confidential information relating to the business, operations or affairs of the Corporation. Although confidentiality agreements
are generally signed by third parties prior to the disclosure of any confidential information, a breach could put the Corporation
at competitive risk and may cause significant damage to its business. The harm to the Corporation’s business from a breach
of confidentiality cannot presently be quantified, but may be material and may not be compensable in damages. There is no
assurance that, in the event of a breach of confidentiality, the Corporation will be able to obtain equitable remedies, such as
injunctive relief, from a court of competent jurisdiction in a timely manner, if at all, in order to prevent or mitigate any damage
to its business that such a breach of confidentiality may cause.
Income Taxes
The Corporation files all required income tax returns and believes that it is in full compliance with the provisions of the Income
Tax Act (Canada) and all other applicable provincial tax legislation. However, such returns are subject to reassessment by the
applicable taxation authority. In the event of a successful reassessment of the Corporation, such reassessment may have an
impact on current and future taxes payable.
Income tax laws relating to the oil and natural gas industry, such as the treatment of resource taxation or dividends, may in
the future be changed or interpreted in a manner that adversely affects the Corporation. Furthermore, tax authorities having
jurisdiction over the Corporation may disagree with how the Corporation calculates its income for tax purposes or could change
administrative practices to the Corporation’s detriment.
Negative Impact of Additional Sales or Issuances of Securities
The Corporation may issue an unlimited number of Common Shares without any vote or action by the shareholders, subject
to the rules of any stock exchange on which the Corporation’s securities may be listed. The Corporation may make future
acquisitions or enter into financings or other transactions involving the issuance of securities of the Corporation which may
be dilutive. If the Corporation issues additional securities, the percentage ownership of existing shareholders will be reduced
and diluted and the price of the Corporation’s securities could decrease.
Additional Taxation Applicable to Non-Residents
Tax legislation in Canada may impose withholding or other taxes on the cash dividends, stock dividends or other property
transferred by the Corporation to non-resident shareholders. These taxes may be reduced pursuant to tax treaties between
Canada and the non-resident shareholder’s jurisdiction of residence. Evidence of eligibility for a reduced withholding rate must
be filed by the non-resident shareholder in prescribed form with their broker (or in the case of registered shareholders, with
the transfer agent). In addition, the country in which the non-resident shareholder is resident may impose additional taxes on
such dividends. Any of these taxes may change from time to time.
Foreign Exchange Risk for Non-Resident Shareholders
The Corporation’s cash dividends are declared in Canadian dollars and may be converted in certain instances to foreign
denominated currencies at the spot exchange rate at the time of payment. As a consequence, non-resident shareholders and
shareholders who calculate their return in currencies other than the Canadian dollar are subject to foreign exchange risk.
To the extent that the Canadian dollar strengthens with respect to their currency, the amount of any dividend will be reduced
when converted to their home currency.
89
2018 Annual Report Conflicts of Interest
Certain directors or officers of the Corporation may also be directors or officers of other oil and natural gas companies and as
such may, in certain circumstances, have a conflict of interest. Conflicts of interest, if any, will be subject to and governed by
procedures prescribed by the ABCA which require a director or officer of a Corporation who is a party to, or is a director or an
officer of, or has a material interest in any person who is a party to, a material contract or proposed material contract with the
Corporation to disclose his or her interest and, in the case of directors, to refrain from voting on any matter in respect of such
contract unless otherwise permitted under the ABCA.
Forward-Looking Information May Prove Inaccurate
Shareholders and prospective investors are cautioned not to place undue reliance on the Corporation’s forward-looking
statements. By their nature, forward-looking statements involve numerous assumptions and known and unknown risks and
uncertainties, of both a general and specific nature, that could cause actual results to differ materially from those suggested
by the forward-looking statements or contribute to the possibility that predictions, forecasts or projections will prove to
be materially inaccurate. Additional information on the risks, assumptions and uncertainties relating to forward-looking
statements is found under the heading “Advisories – Forward-Looking Statements”.
90
2018 Annual Report ABBREVIATIONS
The abbreviations set forth below have the following meanings:
AECO
bbl
bbls
bbls/d
boe
boe/d
F&D
G&A
GAAP
GHG
GJ
GJ/d
HH
IFRS
LNG
m3
Mboe
Mcf
Mcf/d
Mcfe
MJ
MM$
MMBtu
MMBtu/d
MMcf
MMcf/d
MSW
NGLs
NGTL
NYMEX
P&NG
TCPL
WTI
000s
$000s
benchmark price for natural gas determined at the AECO ‘C’ hub in southeast Alberta
barrel
barrels
barrels per day
barrel of oil equivalent
barrel of oil equivalent per day
finding and development
general and administrative
generally accepted accounting principles for Canadian public companies which are currently IFRS
greenhouse gas
gigajoule
gigajoules per day
Henry Hub
International Financial Reporting Standards as issued by the International Accounting
Standards Board
liquefied natural gas
cubic metres
thousand barrels of oil equivalent
thousand cubic feet
thousand cubic feet per day
thousand cubic feet of gas equivalent
megajoule
millions of dollars
million British thermal units
million British thermal units per day
million cubic feet
million cubic feet per day
price for mixed sweet crude oil at Edmonton, Alberta
natural gas liquids
NOVA Gas Transmission Ltd.
New York Mercantile Exchange
petroleum and natural gas
TransCanada PipeLines Limited
West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma,
for crude oil of standard grade
thousands
thousands of dollars
91
2018 Annual Report NON-GAAP MEASURES
This MD&A uses “adjusted funds flow”, “adjusted funds flow per common share”, “free funds flow”, “operating netback”, “total
cash costs”, “adjusted working capital deficit” and “total debt”. These measures do not have standardized meanings prescribed
by GAAP and therefore may not be comparable to similar measures presented by other companies where similar terminology
is used. Management believes that these non-GAAP measures assist management and investors in assessing Birchcliff’s
profitability, efficiency, liquidity and overall performance. Each of these measures is discussed in further detail below.
“Adjusted funds flow” denotes cash flow from operating activities before the effects of decommissioning expenditures and
changes in non-cash working capital and “adjusted funds flow per common share” denotes adjusted funds flow divided by
the basic or diluted weighted average number of common shares outstanding for the period. Birchcliff eliminates changes in
non-cash working capital and settlements of decommissioning expenditures from cash flow from operating activities as the
amounts can be discretionary and may vary from period-to-period depending on its capital programs and the maturity of its
operating areas. The settlement of decommissioning expenditures are managed with Birchcliff’s capital budgeting process
which considers available adjusted funds flow. Management believes that adjusted funds flow and adjusted funds flow per
common share assist management and investors in assessing Birchcliff’s profitability, as well as its ability to generate the
cash necessary to fund future growth through capital investments, decommission its assets, pay dividends and repay debt.
Investors are cautioned that adjusted funds flow should not be construed as an alternative to or more meaningful than cash
flow from operating activities or net income or loss as determined in accordance with GAAP as an indicator of Birchcliff’s
performance. Birchcliff previously referred to adjusted funds flow as “funds flow from operations”.
The following table provides a reconciliation of cash flow from operating activities, as determined in accordance with GAAP,
to adjusted funds flow for the Reporting Periods and Comparable Prior Periods:
($000s)
Cash flow from operating activities
Adjustments:
Change in non-cash working capital
Funds flow
Adjustments:
Decommissioning expenditures
Adjusted funds flow
2018
92,200
(10,838)
81,362
155
81,517
Three months ended
December 31,
Twelve months ended
December 31,
2018
2017
324,434
287,660
(12,591)
311,843
29,226
316,886
2017
88,995
7,920
96,915
93
1,079
794
97,008
312,922
317,680
“Free funds flow” denotes adjusted funds flow less F&D capital expenditures. Management believes that free funds flow
assists management and investors in assessing Birchcliff’s ability to generate the cash necessary to repay debt, pay dividends,
fund a portion of its future growth investments and/or fund share buybacks.
92
2018 Annual Report “Operating netback” denotes petroleum and natural gas revenue less royalties, less operating expense and less transportation
and other expense. All netbacks are calculated on a per unit basis, unless otherwise indicated. Management believes that
operating netback assists management and investors in assessing Birchcliff’s profitability and its operating results on a per unit
basis to better analyze its performance against prior periods on a comparable basis. The following table provides a breakdown
of Birchcliff’s operating netback for the Reporting Periods and Comparable Prior Periods:
Three months ended
December 31,
2018
2017
($000s)
($/boe)
($000s)
($/boe)
($000s)
Twelve months ended
December 31,
2018
($/boe)
2017
($000s)
($/boe)
Petroleum and natural gas revenue
154,720
22.01
166,149
22.55
621,421
22.08
556,942
Royalty expense
Operating expense
(6,763)
(0.96)
(9,271)
(1.26)
(38,306)
(1.36)
(28,727)
(24,677)
(3.51)
(28,460)
(3.86)
(99,104)
(3.52)
(110,486)
(4.45)
22.45
(1.16)
Transportation and other expense
(28,567)
(4.07)
(25,883)
(3.52)
(103,547)
(3.68)
(71,224)
(2.87)
Operating netback(1)
94,713
13.47
102,535
13.91
380,464
13.52
346,505
13.97
(1) All per boe amounts are calculated by dividing each aggregate financial amount by the production (boe) in the respective period.
“Total cash costs” are comprised of royalty, operating, transportation and other, general and administrative and interest
expenses. Total cash costs are calculated on a per unit basis. Management believes that total cash costs assists management
and investors in assessing Birchcliff’s efficiency and overall cash cost structure.
“Adjusted working capital deficit” is calculated as current assets minus current liabilities excluding the effects of any financial
instruments. Management believes that adjusted working capital deficit assists management and investors in assessing
Birchcliff’s liquidity. The following table reconciles working capital deficit (current assets minus current liabilities), as
determined in accordance with GAAP, to adjusted working capital deficit:
As at, ($000s)
Working capital deficit (surplus)
Financial instrument – asset
Financial instrument – liability
Adjusted working capital deficit
December 31,
2018
December 31,
2017
(15,611)
36,798
-
21,187
15,113
-
(4,046)
11,067
“Total debt” is calculated as the revolving term credit facilities plus adjusted working capital deficit. Management believes that
total debt assists management and investors in assessing Birchcliff’s liquidity. The following table provides a reconciliation of
the revolving term credit facilities, as determined in accordance with GAAP, to total debt:
As at, ($000s)
Revolving term credit facilities
Adjusted working capital deficit
Total debt
December 31,
2018
December 31,
2017
605,267
21,187
626,454
587,126
11,067
598,193
93
2018 Annual Report ADVISORIES
Boe and Mcfe Conversions
Boe amounts have been calculated by using the conversion ratio of 6 Mcf of natural gas to 1 bbl of oil and Mcfe amounts have
been calculated by using the conversion ratio of 1 bbl of oil to 6 Mcf of natural gas. Boe and Mcfe amounts may be misleading,
particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 bbl and an Mcfe conversion ratio of 1 bbl: 6 Mcf 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.
MMBtu Pricing Conversions
$1.00 per MMBtu equals $1.00 per Mcf based on a standard heat value Mcf.
Oil and Gas Metrics
This MD&A contains metrics commonly used in the oil and natural gas industry, including operating netback. These oil
and gas metrics do not have any standardized meanings or standard methods of calculation and therefore may not be
comparable to similar measures presented by other companies where similar terminology is used. As such, they should
not be used to make comparisons. Management uses these oil and gas metrics for its own performance measurements
and to provide shareholders with measures to compare Birchcliff’s performance over time; however, such measures are
not reliable indicators of Birchcliff’s future performance, which performance may not compare to Birchcliff’s performance
in previous periods, and therefore should not be unduly relied upon. For further information regarding netbacks, see
“Non-GAAP Measures”.
Capital Expenditures
Unless otherwise stated, any references in this MD&A to: (i) “F&D capital” denotes capital for land, seismic, workovers, drilling
and completions and well equipment and facilities; and (ii) “total capital expenditures” denotes F&D capital plus acquisitions,
less any dispositions, plus administrative assets. Birchcliff previously referred to total capital expenditures as “net capital
expenditures” or “capital expenditures, net”.
Reserves
Birchcliff retained two independent qualified reserves evaluators, Deloitte LLP and McDaniel & Associates Consultants Ltd.,
to evaluate and prepare reports on 100% of Birchcliff’s light crude oil and medium crude oil (combined), conventional natural
gas, shale gas and NGLs reserves effective December 31, 2018. Such evaluations were prepared in accordance with the
standards contained in the COGE Handbook and NI 51-101. Further information regarding the Corporation’s reserves can be
found in the Corporation’s Annual Information Form for the financial year ended December 31, 2018.
Certain terms used herein are defined in NI 51-101 or the COGE Handbook and, unless the context otherwise requires, shall
have the same meanings in this MD&A as in NI 51-101 or the COGE Handbook, as the case may be.
Forward-Looking Statements
Certain statements contained in this MD&A constitute forward-looking statements within the meaning of applicable Canadian
securities laws. The forward-looking statements contained in this MD&A relate to future events or Birchcliff’s future plans,
operations or performance and are based on Birchcliff’s current expectations, estimates, projections, beliefs and assumptions.
Such forward-looking statements have been made by Birchcliff in light of the information available to it at the time the statements
were made and reflect its experience and perception of historical trends. All statements and information other than historical
fact may be forward-looking statements. Such forward-looking statements are often, but not always, identified by the use of
words such as “seek”, “plan”, “expect”, “project”, “intend”, “believe”, “anticipate”, “estimate”, “forecast”, “potential”, “proposed”,
“predict”, “budget”, “continue”, “targeting”, “may”, “will”, “could”, “might”, “should” and other similar words and expressions.
By their nature, forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause
actual results or events to differ materially from those anticipated in such forward-looking statements. Accordingly, readers are
cautioned not to place undue reliance on such forward-looking statements. Although Birchcliff believes that the expectations
reflected in the forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be
correct and Birchcliff makes no representation that actual results achieved will be the same in whole or in part as those set out
in the forward-looking statements.
94
2018 Annual Report In particular, this MD&A contains forward-looking statements relating to the following: Birchcliff’s plans and other aspects
of its anticipated future financial performance, operations, focus, objectives, strategies, opportunities, priorities and goals;
the information set forth under the heading “2019 Outlook” as it relates to Birchcliff’s 2019 guidance (including: Birchcliff’s
estimates of annual average production, commodity mix, average expenses, adjusted and free funds flow, capital expenditures
and natural gas market exposure in 2019; Birchcliff’s expectation that during 2019 65% of its natural gas production will be
sold at prices that are not based on AECO; Birchcliff’s expectation that 87% of its total revenue in 2019 is expected to be based
on non-AECO benchmark prices; Birchcliff’s expectation that it will be well positioned to generate significant free funds flow in
2019; that any free funds flow will be allocated based on what Birchcliff believes will provide the most value to its shareholders,
with alternatives that may include debt reduction, production growth and purchasing common shares under its normal course
issuer bid; that any free funds flow will also be allocated by Birchcliff to pay dividends and to pay for the Acquisition; and
Birchcliff’s expectation that its natural gas market diversification and financial risk management contracts will help to further
strengthen its statements of financial position and protect its cash flow and project economics); Birchcliff’s guidance regarding
its 2019 Capital Program and its proposed exploration and development activities and the timing thereof (including: that the
program targets an annual average production rate of 76,000 to 78,000 boe/d which is expected to generate approximately
$330 million of adjusted funds flow; that total F&D capital expenditures are estimated to be $204 million, which are
significantly less than Birchcliff’s estimated 2019 adjusted funds flow; the number and types of wells to be drilled,
completed and brought on production and the timing thereof; estimates of capital expenditures and capital allocation; the
focus of, the objectives of and the anticipated results from the program; that Birchcliff has the ability to expand its drilling
program and increase its natural gas production given the available capacity at the Pouce Coupe Gas Plant; the financial and
operational flexibility of the 2019 Capital Program and that Birchcliff has the ability to expand its drilling program should
commodity prices and/or economic conditions improve during 2019);Birchcliff’s marketing and transportation arrangements
(including that an additional tranche of service will become available later in 2019 and the aggregate level of firm service
on the Canadian Mainline that will become available on November 1, 2019); Birchcliff’s market diversification and hedging
activities, risk management strategy and use of risk management techniques (including statements that Birchcliff maintains
an ongoing commodity price risk management program; and that Birchcliff’s current strategy is to hedge up to 50% of its
estimated forecast annual average production using a combination of financial derivatives and physical sales contracts); the
Corporation’s estimated income tax pools and management’s expectation that future taxable income will be available to utilize
the accumulated tax pools; the Corporation’s liquidity (including: the Corporation’s financial flexibility; the sources of funding
for the Corporation’s activities and capital requirements; that the Corporation generally relies on its adjusted funds flow and
available credit under its existing credit facilities to fund its capital requirements; statements that the Corporation may from
time to time seek additional capital in the form of debt and/or equity or dispose of non-core properties to fund its ongoing
capital expenditure programs and protect its statements of financial position; management’s belief that its adjusted funds flow
will be sufficient to fund the 2019 Capital Program; statements that Birchcliff may adjust its ongoing capital program, draw
down on its Credit Facilities, seek additional equity financing and/or consider the potential sale of additional non-core assets
to fund planned growth should commodity prices deteriorate materially; and the Corporation’s expectation that counterparties
will be able to meet their financial obligations); statements that management of debt levels continues to be a priority for
Birchcliff; estimates of Birchcliff’s material contractual obligations and commitments and decommissioning obligations;
statements relating to the Corporation’s normal course issuer bid (including potential purchases under the bid and the
cancellation of common shares under the bid); and statements regarding future accounting pronouncements (including the
timing for adoption by the Corporation and the impact on the Corporation’s financial statements). Statements relating to
reserves are forward-looking as they involve the implied assessment, based on certain estimates and assumptions, that the
reserves exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.
With respect to the forward-looking statements contained in this MD&A, assumptions have been made regarding, among
other things: prevailing and future commodity prices and differentials, currency exchange rates, interest rates, inflation rates,
royalty rates and tax rates; the state of the economy, financial markets and the exploration, development and production
business; the political environment in which Birchcliff operates; the regulatory framework regarding royalties, taxes and
environmental laws; the Corporation’s ability to comply with existing and future environmental, climate change and other
laws; future cash flow, debt and dividend levels; future operating, transportation, marketing, G&A and other expenses;
Birchcliff’s ability to access capital and obtain financing on acceptable terms; the timing and amount of capital expenditures
and the sources of funding for capital expenditures and other activities; the sufficiency of budgeted capital expenditures
to carry out planned operations; the successful and timely implementation of capital projects; results of future operations;
Birchcliff’s ability to continue to develop its assets and obtain the anticipated benefits therefrom; the performance of
existing and future wells, well production rates and well decline rates; success rates for future drilling; reserves and resource
volumes and Birchcliff’s ability to replace and expand reserves through acquisition, development or exploration; the impact
95
2018 Annual Report of competition on Birchcliff; the availability of, demand for and cost of labour, services and materials; the ability to obtain any
necessary regulatory or other approvals in a timely manner; the satisfaction by third parties of their obligations to Birchcliff;
the ability of Birchcliff to secure adequate processing and transportation for its products; Birchcliff’s ability to market oil and
gas; the availability of hedges on terms acceptable to Birchcliff; and natural gas market exposure. In addition to the foregoing
assumptions, Birchcliff has made the following assumptions with respect to certain forward-looking statements contained in
this MD&A:
• Birchcliff’s 2019 guidance assumes the following commodity prices during 2019: an average WTI price of US$56.00/bbl;
an average WTI-MSW differential of $10.00/bbl; an average AECO price of $1.65/GJ; an average Dawn price of $3.40/GJ;
an average NYMEX HH price of US$3.00/MMBtu; and an exchange rate (CDN$ to US$1) of 1.32.
• With respect to estimates of 2019 capital expenditures, statements that total F&D capital expenditures are expected to
be significantly less than adjusted funds flow and Birchcliff’s spending plans for 2019, such estimates, statements and
plans are based on the following:
o Estimates of capital expenditures and any allocation thereof assume that the 2019 Capital Program will be carried out
as currently contemplated.
o Statements that Birchcliff’s total F&D capital expenditures are expected to be significantly less than adjusted funds
flow assume that: the 2019 Capital Program will be carried out as currently contemplated; and the production targets,
commodity mix, natural gas market exposure and commodity price assumptions set forth herein are met.
o Birchcliff makes acquisitions and dispositions in the ordinary course of business. Any acquisitions and dispositions
completed could have an impact on Birchcliff’s capital expenditures, production, adjusted funds flow, free funds flow,
costs and total debt, which impact could be material.
o The amount and allocation of capital expenditures for exploration and development activities by area and the number
and types of wells to be drilled is dependent upon results achieved and is subject to review and modification by
management on an ongoing basis throughout the year. Actual spending may vary due to a variety of factors, including
commodity prices, economic conditions, results of operations and costs of labour, services and materials. Birchcliff will
monitor economic conditions and commodity prices and, where deemed prudent, will adjust its capital programs to
respond to changes in commodity prices and other material changes in the assumptions underlying such programs.
• With respect to Birchcliff’s production guidance for 2019, such guidance assumes that: the 2019 Capital Program will
be carried out as currently contemplated; no unexpected outages occur in the infrastructure that Birchcliff relies on
to produce its wells and that any transportation service curtailments or unplanned outages that occur will be short in
duration or otherwise insignificant; the construction of new infrastructure meets timing and operational expectations;
existing wells continue to meet production expectations; and future wells scheduled to come on production meet timing,
production and capital expenditure expectations. Birchcliff’s production guidance may be affected by acquisition and
disposition activity and acquisitions and dispositions could occur that may impact expected production.
• With respect to Birchcliff’s estimates of adjusted and free funds flow for 2019 and statements that Birchcliff expects to
generate significant free funds flow during 2019, such estimates and statements assume that: the 2019 Capital Program
will be carried out as currently contemplated and the level of capital spending for 2019 set forth herein will be achieved;
and the production targets, commodity mix, natural gas market exposure and commodity price assumptions set forth
herein are met. In addition, Birchcliff’s estimate of adjusted funds flow takes into account the settlement of financial and
commodity risk management contracts outstanding as at March 13, 2019.
• With respect to statements of future wells to be drilled and brought on production, the key assumptions are: the
continuing validity of the geological and other technical interpretations performed by Birchcliff’s technical staff, which
indicate that commercially economic volumes can be recovered from Birchcliff’s lands as a result of drilling future wells;
and that commodity prices and general economic conditions will warrant proceeding with the drilling of such wells.
• With respect to estimates of reserves, the key assumption is the validity of the data used by Deloitte and McDaniel in their
independent reserves evaluations.
Birchcliff’s actual results, performance or achievements could differ materially from those anticipated in the forward-looking
statements as a result of both known and unknown risks and uncertainties including, but not limited to: general economic,
market and business conditions which will, among other things, impact the demand for and market prices of Birchcliff’s
products and Birchcliff’s access to capital; volatility of crude oil and natural gas prices; fluctuations in currency and interest
rates; stock market volatility; loss of market demand; an inability to access sufficient capital from internal and external sources;
fluctuations in the costs of borrowing; operational risks and liabilities inherent in oil and natural gas operations; the occurrence
96
2018 Annual Report of unexpected events such as fires, equipment failures and other similar events affecting Birchcliff or other parties whose
operations or assets directly or indirectly affect Birchcliff; uncertainty that development activities in connection with its assets will
be economical; uncertainties associated with estimating oil and natural gas reserves and resources; the accuracy of oil and natural
gas reserves estimates and estimated production levels; geological, technical, drilling, construction and processing problems;
uncertainty of geological and technical data; horizontal drilling and completions techniques and the failure of drilling results to
meet expectations for reserves or production; uncertainties related to Birchcliff’s future potential drilling locations; potential
delays or changes in plans with respect to exploration or development projects or capital expenditures, including delays in the
completion of gas plants and other facilities; the accuracy of cost estimates and variances in Birchcliff’s actual costs and economic
returns from those anticipated; incorrect assessments of the value of acquisitions (including the Acquisition) and exploration and
development programs; changes in tax laws, Crown royalty rates, environmental laws, carbon tax regimes, incentive programs
and other regulations that affect the oil and natural gas industry and other actions by government authorities; an inability of the
Corporation to comply with existing and future environmental, climate change and other laws; the cost of compliance with current
and future environmental laws; political uncertainty and uncertainty associated with government policy changes; uncertainties
and risks associated with pipeline restrictions and outages to third-party infrastructure that could cause disruptions to production;
the lack of available pipeline capacity and an inability to secure adequate processing and transportation for Birchcliff’s products;
the inability to satisfy obligations under Birchcliff’s firm marketing and transportation arrangements or other agreements;
shortages in equipment and skilled personnel; the absence or loss of key employees; competition for, among other things, capital,
acquisitions of reserves, undeveloped lands, equipment and skilled personnel; management of Birchcliff’s growth; environmental
risks, claims and liabilities; uncertainties associated with the outcome of litigation or other proceedings involving Birchcliff;
unforeseen title defects; uncertainties associated with credit facilities and counterparty credit risk; non-performance or default
by counterparties; risks associated with Birchcliff’s risk management program and the risk that hedges on terms acceptable
to Birchcliff may not be available; risks associated with the declaration and payment of dividends, including the discretion of
Birchcliff’s board of directors to declare dividends and change the Corporation’s dividend policy; the failure to obtain any required
approvals in a timely manner or at all; the failure to realize the anticipated benefits of acquisitions (including the Acquisition)
and dispositions and the risk of unforeseen difficulties in integrating acquired assets into Birchcliff’s operations; negative public
perception of the oil and natural gas industry, including transportation, hydraulic fracturing and fossil fuels; the Corporation’s
reliance on hydraulic fracturing; the availability of insurance and the risk that certain losses may not be insured; and breaches or
failure of information systems and security (including risks associated with cyber-attacks).
Readers are cautioned that the foregoing lists of factors are not exhaustive. Additional information on these and other risk factors
that could affect results of operations, financial performance or financial results are included in Birchcliff’s most recent Annual
Information Form and in other reports filed with Canadian securities regulatory authorities.
This MD&A contains information that may constitute future-orientated financial information or financial outlook information
(collectively, “FOFI”) about Birchcliff’s prospective results of operations including, without limitation, adjusted funds flow and free
funds flow, all of which is subject to the same assumptions, risk factors, limitations and qualifications as set forth above. Readers
are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of
preparation, may prove to be imprecise or inaccurate and, as such, undue reliance should not be placed on FOFI. Birchcliff’s actual
results, performance and achievements could differ materially from those expressed in, or implied by, the FOFI. Birchcliff has
included the FOFI in order to provide readers with a more complete perspective on Birchcliff’s future operations and Birchcliff’s
current expectations relating to its future performance. Such information may not be appropriate for other purposes and readers
are cautioned that any FOFI contained herein should not be used for purposes other than those for which it has been disclosed
herein. FOFI contained herein was made as of the date of this MD&A. Unless required by applicable laws, Birchcliff does not
undertake any obligation to publicly update or revise any FOFI statements, whether as a result of new information, future events
or otherwise.
Management has included the above summary of assumptions and risks related to forward-looking statements provided in this
MD&A in order to provide readers with a more complete perspective on Birchcliff’s future operations. Readers are cautioned that
this information may not be appropriate for other purposes.
The forward-looking statements contained in this MD&A are expressly qualified by the foregoing cautionary statements. The
forward-looking statements contained herein are made as of the date of this MD&A. Unless required by applicable laws, Birchcliff
does not undertake any obligation to publicly update or revise any forward-looking statements, whether as a result of new
information, future events or otherwise.
97
2018 Annual Report MANAGEMENT’S REPORT
To the Shareholders of Birchcliff Energy Ltd.
The annual financial statements of Birchcliff Energy Ltd. for the year ended December 31, 2018 were prepared by management
within the acceptable limits of materiality and are in accordance with International Financial Reporting Standards.
Management is responsible for ensuring that the financial and operating information presented in the annual report is
consistent with that shown in the financial statements.
The financial statements have been prepared by management in accordance with the accounting policies as described in the
notes to the financial statements. Timely release of financial information sometimes necessitates the use of estimates when
transactions affecting the current accounting period cannot be finalized until future periods. When necessary, such estimates
are based on informed judgments made by management.
Management has designed and maintains an appropriate system of internal controls to provide reasonable assurance that
all assets are safeguarded and financial records properly maintained to facilitate the preparation of financial statements for
reporting purposes.
KPMG LLP, an independent firm of Chartered Professional Accountants appointed by shareholders, have conducted an
examination of the corporate and accounting records in order to express their opinion on the financial statements.
The Audit Committee, consisting of non-management directors, has met with representatives of KPMG LLP and management
in order to determine if management has fulfilled its responsibilities in the preparation of the financial statements. The Board
of Directors has approved the financial statements on the recommendation of the Audit Committee.
Respectfully,
(signed) “Bruno P. Geremia”
Bruno P. Geremia
Vice-President and Chief Financial Officer
(signed) “A. Jeffery Tonken”
A. Jeffery Tonken
President and Chief Executive Officer
Calgary, Canada
March 13, 2019
98
2018 Annual Report INDEPENDENT AUDITORS’ REPORT
To the Shareholders of Birchcliff Energy Ltd.
Opinion
We have audited the financial statements of Birchcliff Energy Ltd. (the “Company”), which comprise:
•
•
•
•
•
the statements of financial position as at December 31, 2018 and December 31, 2017
the statements of income (loss) and comprehensive income (loss) for the years then ended
the statements of changes in shareholders’ equity for the years then ended
the statements of cash flows for the years then ended
and notes to the financial statements, including a summary of significant accounting policies
(Hereinafter referred to as the “financial statements”).
In our opinion, the accompanying financial statements present fairly, in all material respects, the financial position of the
Company as at December 31, 2018 and December 31, 2017, and its financial performance and its cash flows for the years then
ended in accordance with International Financial Reporting Standards (“IFRS”).
Basis for Opinion
We conducted our audit in accordance with Canadian generally accepted auditing standards. Our responsibilities under those
standards are further described in the “Auditors’ Responsibilities for the Audit of the Financial Statements” section of our
auditors’ report.
We are independent of the Company in accordance with the ethical requirements that are relevant to our audit of the financial
statements in Canada and we have fulfilled our other ethical responsibilities in accordance with these requirements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.
Other Information
Management is responsible for the other information. Other information comprises:
•
•
the information included in Management’s Discussion and Analysis filed with the relevant Canadian Securities Commissions.
the information, other than the financial statements and the auditors’ report thereon, included in a document entitled
“2018 Annual Report”.
Our opinion on the financial statements does not cover the other information and we do not and will not express any form of
assurance conclusion thereon.
In connection with our audit of the financial statements, our responsibility is to read the other information identified above and,
in doing so, consider whether the other information is materially inconsistent with the financial statements or our knowledge
obtained in the audit and remain alert for indications that the other information appears to be materially misstated.
We obtained the information included in Management’s Discussion and Analysis filed with the relevant Canadian Securities
Commissions and the information, other than the financial statements and the auditors’ report thereon, included in a document
entitled “2018 Annual Report” as at the date of this auditors’ report. If, based on the work we have performed on this other
information, we conclude that there is a material misstatement of this other information, we are required to report that fact in
the auditors’ report.
We have nothing to report in this regard.
The information, other than the financial statements and the auditors’ report thereon, included in a document to be entitled
“Annual Report” is expected to be made available to us after the date of this auditors’ report. If, based on the work we will
perform on this other information, we conclude that there is a material misstatement of this other information, we are required
to report that fact to those charged with governance.
Responsibilities of Management and Those Charged with Governance for the Financial Statements
Management is responsible for the preparation and fair presentation of the financial statements in accordance with IFRS, and
for such internal control as management determines is necessary to enable the preparation of financial statements that are
free from material misstatement, whether due to fraud or error.
99
2018 Annual Report In preparing the financial statements, management is responsible for assessing the Company’s ability to continue as a going
concern, disclosing as applicable, matters related to going concern and using the going concern basis of accounting unless
management either intends to liquidate the Company or to cease operations, or has no realistic alternative but to do so.
Those charged with governance are responsible for overseeing the Company’s financial reporting process.
Auditors’ Responsibilities for the Audit of the Financial Statements
Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material
misstatement, whether due to fraud or error, and to issue an auditors’ report that includes our opinion.
Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with Canadian
generally accepted auditing standards will always detect a material misstatement when it exists.
Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could
reasonably be expected to influence the economic decisions of users taken on the basis of the financial statements.
As part of an audit in accordance with Canadian generally accepted auditing standards, we exercise professional judgment
and maintain professional skepticism throughout the audit.
We also:
•
Identify and assess the risks of material misstatement of the financial statements, whether due to fraud or error, design
and perform audit procedures responsive to those risks, and obtain audit evidence that is sufficient and appropriate to
provide a basis for our opinion.
The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud
may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control.
• Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in
the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control.
• Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related
disclosures made by management.
• Conclude on the appropriateness of management's use of the going concern basis of accounting and, based on the audit
evidence obtained, whether a material uncertainty exists related to events or conditions that may cast significant doubt
on the Company’s ability to continue as a going concern. If we conclude that a material uncertainty exists, we are required
to draw attention in our auditors’ report to the related disclosures in the financial statements or, if such disclosures are
inadequate, to modify our opinion. Our conclusions are based on the audit evidence obtained up to the date of our auditors’
report. However, future events or conditions may cause the Company to cease to continue as a going concern.
• Evaluate the overall presentation, structure and content of the financial statements, including the disclosures, and whether
the financial statements represent the underlying transactions and events in a manner that achieves fair presentation.
• Communicate with those charged with governance regarding, among other matters, the planned scope and timing of
the audit and significant audit findings, including any significant deficiencies in internal control that we identify during
our audit.
• Provide those charged with governance with a statement that we have complied with relevant ethical requirements
regarding independence, and communicate with them all relationships and other matters that may reasonably be thought
to bear on our independence, and where applicable, related safeguards.
The engagement partner on the audit resulting in this auditors’ report is Timothy Arthur Richards.
(signed) “KPMG LLP”
Chartered Professional Accountants
Calgary, Canada
March 13, 2019
100
2018 Annual Report BIRCHCLIFF ENERGY LTD.
STATEMENTS OF FINANCIAL POSITION
(Expressed in thousands of Canadian dollars)
As at December 31,
ASSETS
Current assets:
Cash
Accounts receivable (Note 18)
Prepaid expenses and deposits
Financial instruments (Note 18)
Non-current assets:
Deposit on acquisition (Note 22)
Petroleum and natural gas properties and equipment (Note 5)
Investment in securities (Note 6)
Financial instruments (Note 18)
Total assets
LIABILITIES
Current liabilities:
Accounts payable and accrued liabilities
Financial instruments (Note 18)
Non-current liabilities:
Revolving term credit facilities (Note 7)
Decommissioning obligations (Note 8)
Deferred income taxes (Note 9)
Capital securities (Note 10)
Other liabilities (Note 14)
Total liabilities
SHAREHOLDERS’ EQUITY
Share capital (Note 10)
Common shares
Preferred shares (perpetual)
Contributed surplus
Retained earnings
Total shareholders’ equity and liabilities
Subsequent event (Note 22)
Commitments (Note 19)
The accompanying notes are an integral part of these financial statements.
Approved by the Board
(signed) “Dennis A. Dawson”
Dennis A. Dawson
Lead Independent Director
(signed) “A. Jeffery Tonken”
A. Jeffery Tonken
Director
2018
2017
53
51,941
3,386
36,798
92,178
3,900
2,633,460
10,005
23,377
2,670,742
2,762,920
76,567
-
76,567
605,267
129,264
119,553
49,535
7,844
911,463
988,030
48
69,302
2,622
-
71,972
-
2,545,131
10,005
-
2,555,136
2,627,108
83,039
4,046
87,085
587,126
124,825
82,694
49,225
-
843,870
930,955
1,478,260
1,477,750
41,434
76,747
178,449
1,774,890
2,762,920
41,434
69,959
107,010
1,696,153
2,627,108
101
2018 Annual Report BIRCHCLIFF ENERGY LTD.
STATEMENTS OF NET INCOME (LOSS) AND
COMPREHENSIVE INCOME (LOSS)
(Expressed in thousands of Canadian dollars, except per share information)
Years Ended December 31,
REVENUE
Petroleum and natural gas sales (Note 11)
Royalties
Net revenue from oil and natural gas sales
Other income (Note 6)
Realized gain (loss) on financial instruments (Note 18)
Unrealized gain (loss) on financial instruments (Note 18)
EXPENSES
Operating (Note 12)
Transportation and other
Administrative, net (Note 13)
Depletion and depreciation (Note 5)
Finance (Note 15)
Dividends on capital securities (Note 10)
Loss on sale of assets (Note 5)
Net income (loss) before taxes
Income tax expense (recovery) (Note 9)
NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
Net income (loss) per common share (Note 10)
Basic
Diluted
The accompanying notes are an integral part of these financial statements.
2018
2017
621,421
(38,306)
583,115
800
(15,771)
64,222
632,366
99,104
103,547
32,299
208,868
32,711
3,500
10,192
490,221
142,145
39,933
102,212
$0.37
$0.37
556,942
(28,727)
528,215
268
25,785
5,387
559,655
110,486
71,224
30,563
185,666
32,939
3,500
186,143
620,521
(60,866)
(13,886)
(46,980)
($0.19)
($0.19)
102
2018 Annual Report BIRCHCLIFF ENERGY LTD.
STATEMENTS OF CHANGES
IN SHAREHOLDERS’ EQUITY
(Expressed in thousands of Canadian dollars)
Share Capital
Common
Shares
Preferred
Shares
Contributed
Surplus
Retained
Earnings
Total
As at December 31, 2016
1,464,567
41,434
63,847
184,559
1,754,407
Dividends on common shares (Note 10)
Dividends on perpetual preferred shares (Note 10)
Exercise of stock options
Stock-based compensation
Net loss and comprehensive loss
-
-
13,183
-
-
-
-
-
-
-
-
-
(26,522)
(4,047)
(3,833)
9,945
-
-
(26,522)
(4,047)
9,350
9,945
-
(46,980)
(46,980)
As at December 31, 2017
1,477,750
41,434
69,959
107,010
1,696,153
Dividends on common shares (Note 10)
Dividends on perpetual preferred shares (Note 10)
Exercise of stock options (Note 10)
Stock-based compensation (Note 13)
Net income and comprehensive income
-
-
510
-
-
-
-
-
-
-
-
-
(126)
6,914
-
(26,586)
(26,586)
(4,187)
-
-
(4,187)
384
6,914
102,212
102,212
As at December 31, 2018
1,478,260
41,434
76,747
178,449
1,774,890
The accompanying notes are an integral part of these financial statements.
103
2018 Annual Report
BIRCHCLIFF ENERGY LTD.
STATEMENTS OF CASH FLOWS
(Expressed in thousands of Canadian dollars)
Years ended December 31,
Cash provided by (used in):
OPERATING
Net income (loss) and comprehensive income (loss)
Adjustments for items not affecting operating cash:
Unrealized (gain) on financial instruments
Depletion and depreciation
Other compensation (Note 13)
Finance
Loss on sale of assets
Income tax expense (recovery)
Interest paid
Dividends on capital securities
Decommissioning expenditures
Changes in non-cash working capital (Note 20)
FINANCING
Exercise of stock options
Financing fees paid on credit facilities
Dividends on common shares
Dividends on perpetual preferred shares
Dividends on capital securities
Net change in revolving term credit facilities
INVESTING
Petroleum and natural gas properties
Acquisition of petroleum and natural gas properties and equipment
Sale of petroleum and natural gas properties and equipment (Note 5)
Deposit on acquisition
Changes in non-cash working capital (Note 20)
Net change in cash
Cash, beginning of year
CASH, END OF YEAR
The accompanying notes are an integral part of these financial statements.
104
2018
2017
102,212
(46,980)
(64,222)
208,868
7,697
32,711
10,192
39,933
(27,969)
3,500
(1,079)
12,591
324,434
384
(950)
(26,586)
(4,187)
(3,500)
17,868
(16,971)
(5,387)
185,666
4,059
32,939
186,143
(13,886)
(28,374)
3,500
(794)
(29,226)
287,660
9,350
(2,375)
(26,522)
(4,047)
(3,500)
15,783
(11,311)
(301,763)
(416,786)
(1,524)
5,269
(3,900)
(5,540)
(999)
131,657
-
9,780
(307,458)
(276,348)
5
48
53
1
47
48
2018 Annual Report BIRCHCLIFF ENERGY LTD.
NOTES TO THE FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2018 AND 2017
(Expressed In thousands Of Canadian Dollars, Unless Otherwise Stated)
1. NATURE OF OPERATIONS
Birchcliff Energy Ltd. (“Birchcliff” or the “Corporation”) is domiciled and incorporated in Alberta, Canada. Birchcliff is
engaged in the exploration for and the development, production and acquisition of petroleum and natural gas reserves
in Western Canada. The Corporation’s financial year end is December 31. The address of the Corporation’s registered
office is Suite 1000, 600 – 3rd Avenue S.W., Calgary, Alberta, Canada T2P 0G5. Birchcliff’s common shares, Series A
Preferred Shares and Series C Preferred Shares are listed for trading on the Toronto Stock Exchange under the symbols
“BIR”, “BIR.PR.A” and “BIR.PR.C”, respectively.
These financial statements were approved and authorized for issuance by the Board of Directors on March 13, 2019.
2. BASIS OF PREPARATION
These financial statements present Birchcliff’s financial results of operations and financial position under International
Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) as at and for
the years ended December 31, 2018 and December 31, 2017. The financial statements have been prepared in accordance
with IFRS accounting policies and methods of computation as set forth in Note 3.
Operating, transportation and marketing expenses in profit or loss are presented as a combination of function and nature
in conformity with industry practices. Depletion and depreciation, finance expenses, dividends on capital securities and gain
or loss on sale of assets are presented in a separate line by their nature, while net administrative expenses are presented on
a functional basis. Significant expenses such as salaries and benefits and other compensation are presented by their nature
in the notes to the financial statements.
Birchcliff’s financial statements are prepared on a historical cost basis, except for certain financial and non-financial assets
and liabilities which have been measured at fair value. The Corporation’s financial statements include the accounts of
Birchcliff only and are expressed in Canadian dollars, unless otherwise stated. Birchcliff does not have any subsidiaries.
3. SIGNIFICANT ACCOUNTING POLICIES
(a) Revenue Recognition
Revenue from the sale of crude oil, natural gas and natural gas liquids (“NGLs”) is measured based on the consideration
specified in contracts with marketers and other third parties. Birchcliff recognizes revenue when it transfers control of the
product to the contract counterparty. In making this evaluation, management considers if Birchcliff has the ability to direct
the use of, and obtain substantially all of the remaining benefits from the delivery of the product.
Birchcliff evaluates its arrangements with marketers and other third parties to determine if the Corporation acts as the
principal or as an agent. In making this evaluation, the Corporation considers if it obtains control of the product delivered or
services provided, which is indicated by the Corporation having the primary responsibility for the delivery of the product or
rendering of the service, having the ability to establish prices or having inventory risk. If the Corporation acts in the capacity
of an agent rather than as a principal in a transaction, then the revenue is recognized on a net-basis, only reflecting the fee,
if any, realized by the Corporation from the transaction.
(b) Cash and Cash Equivalents
Cash may consist of cash on hand, deposits and term investments held with a financial institution, with an original maturity
of three months or less. Restricted cash is not considered part of cash and cash equivalents.
105
2018 Annual Report (c) Jointly Owned Assets
Certain activities of the Corporation are conducted jointly with others where the participants have a direct ownership interest
in the related assets. Accordingly, the accounts of Birchcliff reflect only its working interest share of revenues, expenses and
capital expenditures related to these jointly owned assets. The relationship with jointly owned asset partners have been
referred to as joint venture in the remainder of the financial statements as this is common terminology in the Canadian
oil and natural gas industry.
(d) Exploration and Evaluation Assets
Costs incurred prior to obtaining the right to explore a mineral resource are recognized as an expense in the period incurred.
Intangible exploration and evaluation expenditures are initially capitalized and may include mineral license acquisitions,
geological and geophysical evaluations, technical studies, exploration drilling and testing and other directly attributable
administrative costs. Tangible assets acquired which are consumed in developing an intangible exploration asset are recorded
as part of the cost of the exploration asset. These costs are accumulated in cost centres by exploration area pending the
determination of technical feasibility and commercial viability.
The technical feasibility and commercial viability of extracting a mineral resource in an exploration area is considered to be
determinable when economic quantities of proved reserves are determined to exist. A review of each exploration project
by area is carried out at each reporting date to ascertain whether such reserves have been discovered. Upon determination
of commercial proved reserves, associated exploration costs are transferred from exploration and evaluation to developing
and producing petroleum and natural gas properties and equipment as reported on the statements of financial position.
Exploration and evaluation assets are reviewed for impairment prior to any such transfer. Assets classified as exploration
and evaluation are not subject to depletion and depreciation until they are reclassified to petroleum and natural gas properties
and equipment.
(e) Petroleum and Natural Gas Properties and Equipment
(i) Recognition and measurement
Petroleum and natural gas properties and equipment are measured at cost less accumulated depletion and depreciation
and accumulated impairment losses, if any.
Petroleum and natural gas properties and equipment consists of the purchase price and costs directly attributable
to bringing the asset to the location and condition necessary for its intended use. Petroleum and natural gas assets
include developing and producing interests such as mineral lease acquisitions, geological and geophysical costs, facility
and production equipment and associated turnarounds, other directly attributable administrative costs and the initial
estimate of the costs of dismantling and removing an asset and restoring the site on which it was located.
(ii) Subsequent costs
Costs incurred subsequent to the determination of technical feasibility and commercial viability are recognized as
developing and producing petroleum and natural gas interests when they increase the future economic benefits
embodied in the specific asset to which they relate. Such capitalized petroleum 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 an area basis. The cost of day-to-day servicing of an item of petroleum and
natural gas properties and equipment is expensed in profit or loss as incurred.
Petroleum and natural gas properties and equipment are de-recognized upon disposal or when no future economic
benefits are expected to arise from the continued use of the asset. Any gain or loss arising from the disposal of an asset,
determined as the difference between the net disposal proceeds and the carrying amount of the asset, is recognized in
profit or loss.
(iii) Asset exchanges
For exchanges or parts of exchanges that involve only exploration and evaluation assets, the exchange is accounted for
at carrying value. Exchanges of development and production assets are measured at fair value, unless the exchange
transaction lacks commercial substance or the fair value of the assets given up or the assets received cannot be
reliably estimated. The cost of the acquired asset is measured at the fair value of the asset given up, unless the fair
value of the asset received is more reliable. Where fair value is not used, the cost of the acquired asset is measured at
the carrying amount of the asset given up. Any gain or loss on the de-recognition of the asset given up is recognized in
profit and loss.
106
2018 Annual Report (iv) Depletion and depreciation
The net carrying value of developing and producing petroleum and natural gas assets, net of estimated residual value,
is depleted on an area basis using the unit of production method. This depletion calculation includes actual production
in the period and total estimated proved plus probable reserves attributable to the assets being depreciated, taking into
account total capitalized costs plus estimated future development costs necessary to bring those reserves into production.
Relative volumes of reserves and production (before royalties) are converted at the energy equivalent conversion ratio of
six thousand cubic feet of natural gas to one barrel of oil. These estimates are reviewed by the Corporation’s independent
reserves evaluator at least annually.
Capitalized plant turnaround costs are depreciated on a straight-line basis over the estimated time until the next turnaround
is completed. Corporate assets, which include office furniture and equipment, software, computer equipment and leasehold
improvements, are depreciated on a straight-line basis over the estimated useful lives of the assets, which are estimated
to be four years.
When significant parts of property and equipment, including petroleum and natural gas interests, have different useful
lives, they are accounted for as separate items (major components). Depreciation methods, useful lives and residual
values for petroleum and natural gas properties and equipment are reviewed at each reporting date.
(f) Provisions
Provisions are recognized when the Corporation has a present obligation (legal or constructive), as a result of a past event,
if it is probable that the Corporation will be required to settle the obligation and a reliable estimate can be made of the amount
of the obligation.
The amount recognized as a provision is the best estimate of the consideration required to settle the present obligation at
the end of the reporting period, taking into account the risks and uncertainties surrounding the obligation. When a provision
is measured using the cash flows estimated to settle the present obligation, its carrying amount is the present value of those
cash flows (where the effect of the time value of money is significant).
When some or all of the economic benefits required to settle a provision are expected to be recovered from a third party,
a receivable is recognized as an asset if it is virtually certain that reimbursement will be received and the amount of the
receivable can be measured reliably.
Provisions are not recognized for future operating losses.
(g) Decommissioning Obligations
The Corporation’s activities give rise to dismantling, restoration and site disturbance remediation activities. Costs related
to abandonment activities are estimated by management in consultation with the Corporation’s independent reserves
evaluators based on risk-adjusted current costs which take into consideration current technology in accordance with existing
legislation and industry practices.
Decommissioning obligations are measured at the present value of the best estimate of expenditures required to settle the
present obligations at the reporting date. When the best estimate of the liability is initially measured, the estimated cost,
discounted using a pre-tax risk-free discount rate, is capitalized by increasing the carrying amount of the related petroleum
and natural gas properties and equipment. The increase in the provision due to the passage of time, which is referred to as
accretion, is recognized as a finance expense. Actual costs incurred upon settlement of the liability are charged against the
obligation to the extent that the obligation was previously established. The carrying amount capitalized in petroleum and
natural gas properties and equipment is depleted in accordance with the Corporation’s depletion and depreciation policy.
The Corporation reviews the obligation at each reporting date and revisions to the estimated timing of cash flows, discount
rates and estimated costs result in an increase or decrease to the obligations and the related petroleum and natural gas
properties and equipment. Any difference between the actual costs incurred upon settlement of the obligation and the
recorded liability is recognized as a gain or loss in profit or loss.
(h) Share-Based Payments
Equity-settled share-based awards granted by the Corporation include stock options and performance warrants granted to
officers, directors and employees. The fair value determined at the grant date of an award is expensed on a graded basis over
the vesting period of each respective tranche of an award with a corresponding increase to contributed surplus. In calculating
the expense of share-based awards, the Corporation revises its estimate of the number of equity instruments expected to
vest by applying an estimated forfeiture rate for each vesting tranche and subsequently revising this estimate throughout the
vesting period, as necessary, with a final adjustment to reflect the actual number of awards that vest. Upon the exercise of
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2018 Annual Report share-based awards, consideration paid together with the amount previously recognized in contributed surplus is recorded
as an increase to share capital. In the event that vested share-based awards expire without being exercised, previously
recognized compensation costs associated with such awards are not reversed. The expense related to share-based awards
is included within administrative expenses in profit or loss.
The fair value of equity-settled share-based awards is measured using the Black-Scholes option-pricing model taking into
account the terms and conditions upon which the awards were granted. Measurement inputs as at the grant date include:
share price, exercise price, expected volatility (based on weighted average historical traded daily volatility), weighted average
expected life of the instruments (based on historical experience and general option holder behaviour), expected dividends and
the risk-free interest rate (based on government bonds) applicable to the term of the award.
A portion of share-based compensation expense directly attributable to the exploration and development of the Corporation’s
assets are capitalized.
(i) Finance Income and Expenses
Finance expenses include interest expense on borrowings, accretion of the discount on decommissioning and post-employment
benefit obligation, amortization of deferred charges and impairment losses (if any) recognized on financial assets. Interest and
dividend income is recognized as it is earned and is presented as “other income” in profit and loss.
(j) Borrowing Costs
Borrowing costs incurred for the acquisition, construction or production of qualifying assets are capitalized during the period
of time that is required to complete and prepare the asset for its intended use or sale. Assets are considered to be qualifying
assets when this period of time is substantial. The capitalization rate, used to determine the amount of borrowing costs to be
capitalized, is the weighted average interest rate applicable to the Corporation’s outstanding borrowings during the period.
All other borrowing costs are charged to profit or loss using the effective interest method.
(k) Financial Instruments
(i) Non-derivative financial instruments
Non-derivative financial instruments are comprised of cash, accounts receivable, deposits, investment in securities,
accounts payable and accrued liabilities, outstanding credit facilities and capital securities. Non-derivative financial
instruments are recognized initially at fair value plus any directly attributable transaction costs. Subsequent to initial
recognition, non-derivative financial instruments are measured based on their classification. The Corporation has made
the following classifications:
• Cash, accounts receivable and deposits are classified as loans and receivables and are measured at amortized
cost using the effective interest method. Typically, the fair value of these balances approximates their carrying
value due to their short term to maturity.
•
Investment in securities have been categorized as fair value through profit and loss which requires the securities
to be fair valued at the end of each reporting period with any gains or losses recognized in other comprehensive
income. In the event of disposal or impairment the cumulative fair value changes recognized in other comprehensive
income are reclassified to profit or loss. Distributions declared are recorded to profit or loss and presented as an
operating activity on the statement of cash flow.
• Accounts payable and accrued liabilities and outstanding credit facilities are classified as other financial liabilities
and are measured at amortized cost using the effective interest method. Due to the short-term nature of accounts
payable and accrued liabilities, their carrying values approximate their fair values. The Corporation’s outstanding
credit facilities bear interest at a floating rate and accordingly the fair market value approximates the carrying
value before the carrying value is reduced for any remaining unamortized costs. The interest costs and financing
fees associated with the Corporation’s credit facilities have been deferred and netted against the amounts drawn,
and are being amortized to profit or loss using the effective interest method over the applicable term.
• The proceeds from the issuance of Series C Preferred Shares, which are presented as “capital securities” on the
statement of financial position, are classified as “other financial liabilities” under IFRS. The incremental costs
directly attributable to the issuance of Series C Preferred Shares are initially recognized as a reduction to capital
securities and subsequently amortized to profit and loss, using the effective interest rate method, as a finance
expense. Dividend distributions on capital securities are recorded as an expense directly to profit and loss and
presented as a financing activity on the statements of cash flows.
108
2018 Annual Report (ii) Derivative financial instruments
Derivatives may be used by the Corporation to manage economic exposure to market risk relating to commodity prices,
interest rates and foreign exchange. Birchcliff’s policy is not to utilize derivative financial instruments for speculative
purposes. The Corporation does not designate its financial derivative contracts as hedges, and as such does not apply
hedge accounting. As a result, financial derivatives are classified at fair value through profit or loss and are recorded on
the statements of financial position at fair value.
The fair value of commodity price risk management contracts is determined by discounting the difference between the
contracted prices/rates and published forward price/rate curves as at the statement of financial position date. The fair
value of options and costless collars is based on option models that use published information with respect to volatility,
prices and interest rates.
The Corporation accounts for any forward physical delivery sales 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, these contracts are not considered to be derivative financial instruments
and have not been recorded at fair value on the statements of financial position. Settlements on physical sales contracts
are recognized in petroleum and natural gas sales in profit and loss.
(iii) Share capital
Common shares and perpetual preferred shares are classified as equity. Incremental costs directly attributable to the
issuance of shares are recognized as a reduction in share capital, net of any tax effects.
(l) Impairment
Impairment of financial assets
(i)
Impairment of financial assets is determined by measuring the assets' expected credit loss ("ECL"). Birchcliff’s financial
assets are not considered to have a significant financing component and a lifetime ECL is measured at the date of initial
recognition of the financial asset. ECL allowances have not been recognized for cash and cash equivalents due to the
virtual certainty associated with their collection. The ECL pertaining to accounts receivable, financial instruments and
investment in securities is assessed at initial recognition and this provision is re-assessed at each reporting date. ECLs
are a probability-weighted estimate of all possible default events related to the financial asset (over the lifetime or within
12 months after the reporting period, as applicable) and are measured as the difference between the present value of
the cash flows due to Birchcliff and the cash flows the Corporation expects to receive, including cash flows expected
from collateral and other credit enhancements that are a part of contractual terms. In making an assessment as to
whether financial assets are credit-impaired, the Corporation considers historically realized bad debts, evidence of a
debtor’s present financial condition and whether a debtor has breached certain contracts, the probability that a debtor
will enter bankruptcy or other financial reorganization, changes in economic conditions that correlate to increased
levels of default, the number of days a debtor is past due in making a contractual payment, and the term to maturity
of the specified receivable. The carrying amounts of financial assets are reduced by the amount of the ECL through an
allowance account and losses are recognized within general and administrative expense in profit and loss.
Based on contractual terms and conditions, the Corporation considers its financial assets to be in default when the
counterparty fails to make contractual payments as required. Once the Corporation has pursued collection activities and
it has been determined that the incremental cost of pursuing collection outweighs the benefits, Birchcliff derecognizes
the gross carrying amount of the financial asset and the associated allowance from the statement of financial position.
Impairment of non-financial assets
(ii)
The Corporation’s petroleum and natural gas properties and equipment are grouped into Cash Generating Units (“CGUs”)
for the purpose of assessing impairment. A CGU represents 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.
CGUs are reviewed at each reporting date for indicators of potential impairment. Such indicators may include, but are
not limited to, changes in the Corporation’s business plan, deterioration in commodity prices or a significant downward
revision of estimated recoverable reserves. If indicators of asset impairment exist, an impairment test is performed by
comparing a CGU’s carrying value to its recoverable amount. A CGU’s recoverable amount is the greater of its fair value
less cost to sell and its current value in use. The calculation of the recoverable amount is sensitive to the assumptions
regarding production volumes, discount rates and commodity prices. Any excess of carrying value over recoverable
amount is recognized as impairment loss in profit or loss.
109
2018 Annual Report In assessing the value in use, the estimated future cash flows from proved and probable reserves are discounted to
their present value using a pre-tax discount rate that reflects current market assessment of the time value of money.
Fair value is determined as the amount that would be obtained from the sale of the asset in an arm’s length transaction
between knowledgeable and willing parties. The petroleum and natural gas future prices used in the impairment test are
based on period-end commodity price forecasts estimated by the Corporation’s independent reserves evaluator and are
adjusted for petroleum and natural gas differentials and transportation and marketing costs specific to the Corporation.
Where circumstances change such that an impairment no longer exists or is less than the amount previously recognized,
the carrying amount of the CGU is increased to the revised estimate of its recoverable amount as long as the revised
estimate does not exceed the carrying amount that would have been determined, net of depletion and depreciation,
had no impairment loss been recognized for the CGU in prior periods. A reversal of an impairment loss is recognized
immediately through profit or loss.
Exploration and evaluation assets are assessed for impairment if: (i) sufficient data exists to determine technical
feasibility and commercial viability of an exploration area, or (ii) facts and circumstances suggest that the carrying
amount exceeds the recoverable amount. For purposes of impairment testing, exploration and evaluation assets are
allocated to CGUs.
(m) Income Taxes
Birchcliff is a corporation as defined under the Income Tax Act (Canada) and is subject to Canadian Federal and provincial
taxes. Birchcliff is subject to provincial taxes in Alberta as the Corporation operates in this jurisdiction. The Corporation’s
income tax expenses include current and/or deferred tax. Income tax expense is recognized through profit or loss except
to the extent that it relates to items recognized directly in equity, in which case the related income taxes are also recognized
in equity.
Current tax is the expected tax payable on taxable income and Part VI.I dividend tax payable on taxable preferred shares for
the period, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable
in respect of previous years.
Deferred tax is recognized on temporary differences between the carrying amounts of assets and liabilities in the financial
statements and the corresponding tax bases used in the computation of taxable income. Deferred tax liabilities are generally
recognized for all taxable temporary differences. Deferred tax assets are generally recognized for all deductible temporary
differences to the extent that it is probable that taxable income will be available against which those deductible temporary
differences can be utilized. The carrying amount of deferred tax assets is reviewed at the end of each reporting period and
reduced to the extent that it is no longer probable that sufficient taxable income will be available to allow all or part of the
asset to be recovered.
Deferred tax assets and liabilities are measured at the tax rates that are expected to apply in the period in which the liability is
expected to be settled or the asset realized, based on tax rates (and tax laws) that have been enacted or substantively enacted
by the end of the reporting period. The measurement of deferred tax liabilities and assets reflects the tax consequences that
would follow from the manner in which Birchcliff expects, at the end of the reporting period, to recover or settle the carrying
amount of its assets and liabilities.
(n) Flow-Through Shares
The Corporation may issue flow-through shares to finance a portion of its capital expenditure program. Pursuant to the
terms of the flow-through share agreements, the tax deductions associated with the expenditures are renounced to the
subscribers. The difference between the value ascribed to flow-through shares issued and the value that would have been
received for common shares at the date of announcements of the flow-through shares is initially recognized as a liability on
the statements of financial position. When the expenditures are incurred, the liability is drawn down, a deferred tax liability
is recorded equal to the estimated amount of deferred income tax payable by the Corporation as a result of the renunciation
and the difference is recognized as a deferred tax expense.
(o) Per Common Share
The Corporation calculates per common share amounts using net income available to Birchcliff’s shareholders, reduced
for perpetual preferred share dividends and divided by the weighted average number of common shares outstanding. Basic
per share information is computed using the weighted average number of basic common shares outstanding during the
period. Diluted per share information is calculated using the treasury stock method, which assumes that any proceeds from
the exercise of “in-the-money” stock options, performance warrants or warrants (the “Securities”), plus the unamortized
stock-based compensation expense amounts, would be used to purchase common shares at the average market price during
110
2018 Annual Report the period. No adjustment to diluted earnings per share is made if the result of these calculations is anti-dilutive. The average
market value of the Corporation’s shares for the purpose of calculating the dilutive effect is based on average quoted market
prices for the time that the Securities were outstanding during the period.
(p) Business Combinations
The purchase method of accounting is used to account for acquisitions of businesses and assets that meet the definition of
a business under IFRS. The cost of an acquisition is measured as the fair value of the assets given and liabilities incurred or
assumed at the date of exchange. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business
combination are measured initially at their fair values at the acquisition date. If the consideration given up is less than the
fair value of the net assets received, the difference is recognized immediately in the income statement. If the consideration
is greater than the fair value of the net assets received, the difference is recognized as goodwill on the statement of financial
position. Acquisition costs incurred are expensed.
(q) Post-Employment Benefit Obligation
Birchcliff’s post-employment benefits are defined benefit obligations under IFRS. The cost of the post-employment benefit
obligation is determined using the projected unit credit method. The obligation is determined by discounting the estimated
future cash outflows using interest rates of high-quality corporate bonds that have terms to maturity approximating the
terms of the related liability. Post-employment benefit obligation is presented on the statements of financial position as
other liabilities. Past service cost is the change in the present value of the obligation and can arise from the introduction,
amendment or curtailment of a plan. Current service cost is the increase in the present value of the obligation resulting from
the service provided by an employee in the current period. Current and past service costs are recognized as post-employment
benefit expenses of the Corporation when incurred and presented in profit and loss as an administrative expense. The
unwinding of the present value of the post-employment benefit obligation is recorded as accretion (interest) expense and
is presented in profit and loss as a finance expense.
Remeasurements of the post-employment benefit obligation will result in gains and losses and will be included in other
comprehensive income. Remeasurements result from increases or decreases in the present value of the obligation as a
result of changes in assumptions including unexpectedly high or low rates of employee turnover, early retirement, change
in expected future salaries and benefits and revision to the discount rate. Settlements will be recorded as a reduction to the
obligation in the period incurred. Any difference between the actual costs incurred upon settlement of the obligation and
the recorded liability is recognized as a gain or loss in profit or loss.
(r) Critical Accounting Judgments and Key Sources of Estimation Uncertainty
The timely preparation of the financial statements requires management to make judgments, estimates and assumptions
that affect the application of accounting policies and reported amounts of assets and liabilities and income and expenses.
Accordingly, actual results may differ from these estimates. Estimates and underlying assumptions are reviewed on an
ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any
future periods affected.
Critical judgments in applying accounting policies:
The following are the critical judgments that management has made in the process of applying the Corporation’s accounting
policies and that have the most significant effect on the amounts recognized in these financial statements:
Identification of cash-generating units
(i)
Birchcliff’s assets are required to be aggregated into CGUs for the purpose of calculating impairment based on their
ability to generate largely independent cash inflows. CGUs have been determined based on similar geological structure,
shared infrastructure, geographical proximity, operating structure, commodity type and similar exposures to market
risks. By their nature, these assumptions are subject to management’s judgment and may impact the carrying value of
the Corporation’s assets in future periods.
Identification of impairment indicators
(ii)
IFRS requires Birchcliff to assess, at each reporting date, whether there are any indicators that its petroleum and natural
gas assets may be impaired. Birchcliff is required to consider information from both external sources (such as negative
downturn in commodity prices, significant adverse changes in the technological, market, economic or legal environment
in which the entity operates) and internal sources (such as downward revisions in reserves, significant adverse effect on
the financial and operational performance of a CGU, evidence of obsolescence or physical damage to the asset). By their
nature, these assumptions are subject to management’s judgment.
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2018 Annual Report (iii) Tax uncertainties
IFRS requires Birchcliff, at each reporting date, to make certain judgments on uncertain tax positions by relevant
tax authorities. Judgments include determining whether the Corporation will “more likely than not” be successful in
defending its tax positions by considering information from relevant tax interpretations and tax laws in Canada. As such,
this recognition threshold is subject to management’s judgment and may impact the carrying value of the Corporation’s
deferred tax assets and liabilities at the end of the reporting period.
Key sources of estimation uncertainty:
The following are the key assumptions concerning the sources of estimation uncertainty at the end of the reporting period, that
have a significant risk of causing adjustments to the carrying amounts of assets and liabilities within the next financial year:
(i) Reserves
Reported recoverable quantities of proved and probable reserves requires estimation regarding production profile,
commodity prices, exchange rates, remediation costs, timing and amount of future development costs, and production,
transportation and marketing costs for future cash flows. It also requires interpretation of geological and geophysical
models in order to make an assessment of the size, shape, depth and quality of reservoirs, and their anticipated
recoveries. The economical, geological and technical factors used to estimate reserves may change from period to
period. Changes in reported reserves can impact the carrying values of the Corporation’s petroleum and natural gas
properties and equipment, the calculation of depletion and depreciation, the provision for decommissioning obligations,
and the recognition of deferred tax assets due to changes in expected future cash flows. The recoverable quantities of
reserves and estimated cash flows from Birchcliff’s petroleum and natural gas interests are independently evaluated
by reserve engineers at least annually.
The Corporation’s petroleum and natural gas reserves represent the estimated quantities of petroleum, natural gas
and NGLs which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be
economically recoverable in future years from known reservoirs and which are considered commercially producible.
Such reserves may be considered commercially producible if management has the intention of developing and
producing them and such intention is based upon (i) a reasonable assessment of the future economics of such
production; (ii) a reasonable expectation that there is a market for all or substantially all the expected petroleum and
natural gas production; and (iii) evidence that the necessary production, transmission and transportation facilities are
available or can be made available. Reserves may only be considered proved and probable if producibility is supported
by either production or conclusive formation tests. Birchcliff’s oil and gas reserves are determined in accordance with
the standards contained in National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities and the
Canadian Oil and Gas Evaluation Handbook.
(ii) Share-based payments
All equity-settled, share-based awards issued by the Corporation are fair valued using the Black-Scholes option-pricing
model. In assessing the fair value of equity-based compensation, estimates have to be made regarding the expected
volatility in share price, option life, dividend yield, risk-free rate and estimated forfeitures at the initial grant date.
(iii) Decommissioning obligations
The Corporation estimates future remediation costs of production facilities, wells and pipelines at different stages
of development and construction of assets or facilities. In most instances, removal of assets occurs many years into
the future. This requires an estimate regarding abandonment date, future environmental and regulatory legislation,
the extent of reclamation activities, the engineering methodology for estimating cost, future removal technologies in
determining the removal cost and liability-specific discount rates to determine the present value of these cash flows.
(iv) Post-employment benefit obligation
The Corporation estimates the post-employment benefit obligation at the end of each reporting period. In most instances,
the obligation occurs many years into the future. The Corporation uses estimates related to the initial measurement of
the obligation for eligible employees including expected age of employee retirement, employee turnover, probability
of early retirement, discount rate and inflation rate on salary and benefits. From time to time, these estimates may
change causing the obligation recorded by the Corporation to change.
Impairment of non-financial assets
(v)
For the purposes of determining the extent of any impairment or its reversal, estimates must be made regarding future
cash flows taking into account key assumptions including future petroleum and natural gas prices, expected forecasted
production volumes and anticipated recoverable quantities of proved and probable reserves. These assumptions are
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2018 Annual Report subject to change as new information becomes available. Changes in economic conditions can also affect the rate used
to discount future cash flow estimates. Changes in the aforementioned assumptions could affect the carrying amount of
the Corporation’s assets, and impairment charges and reversal will affect profit or loss.
Income taxes
(vi)
Birchcliff files corporate income tax, goods and service tax and other tax returns with various provincial and federal
taxation authorities in Canada. There can be differing interpretations of applicable tax laws and regulations. The resolution
of these tax positions through negotiations or litigation with tax authorities can take several years to complete. The
Corporation does not anticipate that there will be any material impact upon the results of its operations, financial
position or liquidity.
Tax provisions are based on enacted or substantively enacted laws. Changes in those laws could affect amounts
recognized in profit or loss both in the period of change, which would include any impact on cumulative provisions, and
in future periods.
Deferred tax assets (if any) are recognized only to the extent it is considered probable that those assets will be recoverable.
This involves an assessment of when those deferred tax assets are likely to reverse and a judgment as to whether
or not there will be sufficient taxable profits available to offset the tax assets when they do reverse. This requires
assumptions regarding future profitability and is therefore inherently uncertain. Estimates of future taxable income are
based on forecasted cash flows from operations. To the extent that any interpretation of tax law is challenged by the tax
authorities or future cash flows and taxable income differ significantly from estimates, the ability of Birchcliff to realize
the deferred tax assets recorded at the statement of financial position date could be impacted.
4. CHANGES IN ACCOUNTING POLICIES
Accounting Pronouncements Adopted
On January 1, 2018, Birchcliff adopted IFRS 15: Revenue from Contracts with Customers (“IFRS 15”) using the cumulative
effect method. Under this method, the comparative periods have not been restated and the cumulative effect on net earnings
and the change in opening retained earnings as a result of the application of IFRS 15 to revenue contracts in progress at
January 1, 2018 is nil. The Corporation reviewed its revenue streams and major contracts with customers using the IFRS 15
five step model and there were no changes to net earnings or timing of petroleum and natural gas sales recognized. It should
be noted, however, that certain profit and loss line item reclassifications were made.
On January 1, 2018, Birchcliff adopted IFRS 9: Financial Instruments (“IFRS 9”) to replace IAS 39: Financial Instruments:
Recognition and Measurement (“IAS 39”). IFRS 9 contains three principal classification categories for financial assets:
measured at amortized cost, fair value through other comprehensive income and fair value through profit or loss. The
previous IAS 39 categories of held to maturity, loans and receivables and available for sale are eliminated. IFRS 9 bases
the classification of financial assets on the contractual cash flow characteristics and the Corporation’s business model for
managing the financial asset. Additionally, embedded derivatives are not separated if the host contract is a financial asset
within the scope of IFRS 9. Instead, the entire hybrid contract is assessed for classification and measurement. IFRS 9 largely
retains the existing requirements in IAS 39 for the classification of financial liabilities. The adoption of IFRS 9 has resulted
in changes to the Corporation’s investment in securities which, upon adoption of IFRS 9, are measured at fair value through
profit or loss. Under the previous IAS 39 standard, Birchcliff’s investment in securities were categorized as available for sale
which required the securities to be fair valued with any gains or losses recognized in other comprehensive income. There were
no changes to the treatment of distributions declared on the investment in securities which are recorded to profit or loss.
The adoption of IFRS 9 had no impact on the amounts recorded in the financial statements as at January 1, 2018 or on the
comparative periods.
113
2018 Annual Report Future Accounting Pronouncements
In January 2016, the IASB issued IFRS 16: Leases (“IFRS 16”) which sets out the principles for the recognition, measurement,
presentation and disclosure of leases for both parties to a contract, i.e. the customer (“lessee”) and the supplier (“lessor”) and
replaces the previous lease standards, IAS 17: Leases and IFRIC 4: Determining whether an Arrangement contains a Lease.
IFRS 16 requires the recognition of a right-of-use asset and lease liability on the statement of financial position for most
leases, where Birchcliff is acting as a lessee. For lessees applying IFRS 16, the dual classification model of leases as either
operating leases or finance leases no longer exists, effectively treating all leases as finance leases. IFRS 16 is effective for
annual reporting periods beginning on or after January 1, 2019. The standard is required to be adopted either retrospectively
or using a modified retrospective approach. The Corporation will adopt IFRS 16 using the modified retrospective approach,
which does not require restatement of prior period financial information and applies the standard prospectively.
IFRS 16 is expected to increase Birchcliff’s total assets and liabilities at January 1, 2019. Future net income will be impacted
as the finance charges and depreciation charges associated with lease contracts are not expected to correspond in any one
period to the amount of related cash flows. Cash flows associated with lease repayments will be allocated between operating
and financing activities based on their interest repayment and principal repayment portions. The actual impact of applying
IFRS 16 on the financial statements in the period of initial application will depend on multiple factors and conditions, including
but not limited to, the Corporation’s borrowing rate at January 1, 2019, the composition of the Corporation’s lease portfolio at
that date, the Corporation’s latest assessment of whether it will exercise any lease renewal options, and the extent to which
the Corporation chooses to use practical expedients and recognition exemptions. On initial adoption, Birchcliff will have the
following optional practical expedients available under IFRS 16:
• Certain short-term leases and leases of low value assets that have been identified for recognition at January 1, 2019
can be excluded from recognition on the statements of financial position. Payments for these leases will be
disclosed in the notes to the financial statements.
• Certain classes of lease arrangements that transfer a separate good or service under the same contract that have
been identified for recognition at January 1, 2019 can be recognized as a single lease component rather than
separating between their lease and non-lease components.
•
For leases having similar characteristics, a portfolio approach can be used by applying a single discount rate.
The Corporation continues to review all existing contracts in detail. The full extent of the impact has not yet been determined.
At minimum, Birchcliff expects to record a right-of-use asset and corresponding lease liability on the statement of financial
position for the Corporation’s head office lease. The Corporation will disclose the financial impact of IFRS 16 in its unaudited
financial statements for the first quarter 2019 and continue to develop and implement changes to its internal controls,
information systems and business and accounting processes throughout 2019.
114
2018 Annual Report 5. PETROLEUM AND NATURAL GAS PROPERTIES AND EQUIPMENT
The continuity for petroleum and natural gas (“P&NG”) properties and equipment are as follows:
Exploration
& Evaluation
Assets(5)
Developed
& Producing
Assets
Corporate
Assets
($000s)
Cost:
As at December 31, 2016
Additions
Acquisitions
Dispositions(1)
As at December 31, 2017
Additions
Acquisitions
Dispositions(2)
As at December 31, 2018(3)
Accumulated depletion and depreciation:
As at December 31, 2016
Depletion and depreciation expense
Dispositions(1)
As at December 31, 2017
Depletion and depreciation expense
Dispositions(2)
As at December 31, 2018
Net book value:
As at December 31, 2017(4)
As at December 31, 2018(4)
Total
3,390,239
457,696
999
(542,027)
3,306,907
313,931
2,173
(55,636)
3,567,375
(744,402)
(185,666)
168,292
(761,776)
(208,868)
36,729
13,950
1,774
-
-
15,724
2,013
-
-
17,737
(9,181)
(1,835)
-
(11,016)
(1,976)
-
53
28
-
-
81
31
-
-
112
-
-
-
-
-
-
-
3,376,236
455,894
999
(542,027)
3,291,102
311,887
2,173
(55,636)
3,549,526
(735,221)
(183,831)
168,292
(750,760)
(206,892)
36,729
(920,923)
(12,992)
(933,915)
81
112
2,540,342
2,628,603
4,708
4,745
2,545,131
2,633,460
(1) Consists largely of two asset dispositions, the Worsley Charlie Lake Light Oil Pool Disposition (the “Worsley Disposition”) and the Progress Area Disposition (the “Progress Disposition”). The Worsley
Disposition had a net book value of $321.1 million for total consideration of $100 million, before closing adjustments and other costs, consisting of: (i) cash consideration of $90 million; and
(ii) securities of affiliates of the purchaser with a total value of $10 million (Note 6). The Worsley Disposition closed on August 31, 2017. The Progress Disposition had a net book value of $18.7 million
for cash consideration of $31.7 million, before closing adjustments and other costs. The Progress Disposition closed on October 2, 2017.
(2) Consists mainly of two asset dispositions with a combined net book value of $18.9 million for total consideration of $5.3 million.
(3) The Corporation’s P&NG properties and equipment were pledged as security for its credit facilities. Although the Corporation believes that it has title to its P&NG properties, it cannot control or
completely protect itself against the risk of title disputes and challenges. There were no borrowing costs capitalized to P&NG properties and equipment.
(4) Birchcliff performed an impairment assessment of its P&NG assets on a CGU basis and determined there were impairment indicators present at the end of each reporting period. The Corporation
performed an asset impairment test to ensure that the carrying value of its P&NG properties and equipment was recoverable. Birchcliff’s P&NG properties and equipment were not impaired at
December 31, 2018 and December 31, 2017.
(5) E&E assets consist of the Corporation’s exploration activities which are pending the determination of economic quantities of commercially producible proved reserves. Additions represent the
Corporation’s net share of costs incurred on E&E activities during the period. A review of each exploration project by area is carried out at each reporting date to ascertain whether economical
quantities of proved reserves have been discovered and whether such costs should be transferred to depletable petroleum and natural gas components. There were no exploration costs
reclassified from the E&E category to petroleum and natural gas properties and equipment category during 2018 and 2017.
6. INVESTMENT IN SECURITIES
The Corporation received on August 31, 2017 (the “Issuance Date”) securities consisting of 4,500,000 common A units
(the “Common A LP Units”) in a limited partnership (the “Limited Partnership”) affiliated with the purchaser and 10,000,000
preferred units (the “Preferred Trust Units”) in a trust (the “Trust”) affiliated with the purchaser (collectively, the “Securities”)
at a combined value of $10 million. The Securities acquired are not publicly listed and do not constitute significant
investments of the entities.
The Securities have limited voting rights and, in the case of the Common A LP Units, no redemption rights and limited
participation rights in the event of the liquidation, dissolution or wind-up of the Limited Partnership. Holders of the Securities
are entitled to, if and when declared, non-cumulative, quarterly dividend distributions for each three month period ending
March 31, June 30, September 30 and December 31. The Preferred Trust Units are redeemable on demand by Birchcliff.
For each Preferred Trust Unit redeemed by Birchcliff within the first five years of the Issuance Date, the redemption price
115
2018 Annual Report
will be equal to the lesser of (i) 90% of the fair market value of each redeemed Preferred Trust Unit at the date the redemption
and (ii) $0.90 per redeemed Preferred Trust Unit. For each Preferred Trust Unit redeemed on a date that is later than five
years from the Issuance Date, being after August 31, 2022 (the “Fifth Anniversary Date”), the redemption price will be
equal to the lesser of (i) the fair market value of each redeemed Preferred Trust Unit at the date the redemption and
(ii) $1.00 per redeemed Preferred Trust Unit.
Payment of the redemption price by the Trust is limited to a maximum cash amount of $10,000 per month (or a greater
amount, if the trustees of the Trust so decide) and any portion of the redemption price in excess of such cash amount (the
“Balance”) will be repaid through the Trust’s issuance of a redemption note or an in specie distribution of the Trust’s property.
If the Preferred Trust Units are redeemed by Birchcliff before the Fifth Anniversary Date, the Balance is paid by the Trust through
the issuance of redemption notes due and payable prior to the sixth anniversary of the Issuance Date, being August 31, 2023.
If the Preferred Trust Units are redeemed by Birchcliff after the Fifth Anniversary Date, the Balance is paid by the Trust through
the issuance of redemption notes due and payable within less than a year of the date the redemption notes are issued.
The Securities had a fair value of $10 million at December 31, 2018 and December 31, 2017. During 2018, Birchcliff recorded
$0.8 million (2017 - $0.3 million) in dividend distributions in respect of the Securities that are included in other income.
7. REVOLVING TERM CREDIT FACILITIES
The components of the Corporation’s revolving credit facilities include:
As at December 31, ($000s)
Syndicated credit facility
Working capital facility
Drawn revolving term credit facilities
Unamortized prepaid interest on bankers’ acceptances
Unamortized deferred financing fees
Revolving term credit facilities
2018
586,000
22,821
608,821
(1,021)
(2,533)
605,267
2017
578,000
16,823
594,823
(4,891)
(2,806)
587,126
At December 31, 2018, the Corporation’s credit facilities consisted of extendible revolving credit facilities in the aggregate
principal amount of $950 million with maturity dates of May 11, 2021 (the “Credit Facilities”). At December 31, 2018, the
Credit Facilities were comprised of: (i) an extendible revolving syndicated term credit facility (the “Syndicated Credit Facility”)
of $850 million; and (ii) an extendible revolving working capital facility (the “Working Capital Facility”) of $100 million.
Birchcliff has outstanding $17.2 million in letters of credit at December 31, 2018 (see Note 17). The letters of credit reduces the
amount available under the Working Capital Facility from $100 million to approximately $82.8 million.
The Credit Facilities allow for prime rate loans, LIBOR loans, U.S. base rate loans, bankers’ acceptances and, in the case of the
Working Capital Facility only, letters of credit. The interest rates applicable to the drawn loans are based on a pricing margin
grid and will change as a result of the ratio of outstanding indebtedness to EBITDA as calculated in accordance with the
agreement governing the Credit Facilities. EBITDA is defined as earnings before interest and non-cash items including (if any)
income taxes, other compensation, gains and losses on sale of assets, unrealized gains and losses on financial instruments
and depletion, depreciation and amortization.
The Credit Facilities are subject to a semi-annual review of the borrowing base limit by Birchcliff’s syndicate of lenders, which
limit is directly impacted by the value of Birchcliff’s oil and natural gas reserves. In addition, pursuant to the terms of the
credit agreement governing the Credit Facilities, the borrowing base of the Credit Facilities may be adjusted in certain other
circumstances. Upon any change in or redetermination of the borrowing base limit which results in a borrowing base shortfall,
Birchcliff must eliminate the borrowing base shortfall amount. Birchcliff may each year, at its option, request an extension to
the maturity date of the Syndicated Credit Facility and the Working Capital Facility, or either of them, for an additional period
of up to three years from May 11 of the year in which the extension request is made. In connection with the most recently
completed semi-annual review of the Corporation’s borrowing base limit under its credit facilities, the Corporation and the
lenders agreed to the borrowing base remaining unchanged at $950 million.
The Credit Facilities are secured by a fixed and floating charge debenture and pledge charging substantially all of the Corporation’s
assets. No fixed charges have been granted pursuant to such debenture. The Credit Facilities do not contain any financial
maintenance covenants.
116
2018 Annual Report 8. DECOMMISSIONING OBLIGATIONS
The Corporation’s decommissioning obligations result from its net ownership interests in petroleum and natural gas assets,
including well sites, gathering systems and processing facilities. The Corporation estimates the total undiscounted (inflated)
amount of cash flow required to settle its decommissioning obligations is approximately $272.1 million at December 31, 2018
(December 31, 2017 – $269.7 million) and is expected to be incurred up until 2069.
A reconciliation of the decommissioning obligations is set forth below:
As at December 31, ($000s)
Balance, beginning
Obligations incurred
Obligations acquired
Obligations divested
Changes in estimated future cash flows(2)
Accretion expense
Actual expenditures
Balance, ending(1)
2018
124,825
3,930
649
2017
133,470
8,468
626
(3,446)
(45,902)
1,177
3,208
(1,079)
129,264
25,902
3,055
(794)
124,825
(1) Birchcliff applied a risk-free rate of 2.36% and an inflation rate of 2.0% to calculate the discounted fair value of its decommissioning liabilities as at December 31, 2018 and December 31, 2017.
(2) Changes in estimated future cash flows largely due to the revision in abandonment and reclamation cost and date estimates for Birchcliff’s oil and natural gas wells and facilities.
9. INCOME TAXES
Included in income tax expense is a deferred income tax expense of $36.9 million in 2018 and deferred income tax recovery
of $16.9 million in 2017. Part VI.I dividend tax totalling $3.1 million in 2018 (2017 – $3.0 million) resulting from preferred
share dividends paid during the period. For the purposes of determining the current and deferred income tax, the Corporation
applied a combined Canadian federal and provincial income tax rate of 27% in 2018 (2017 – 27%).
The components of income tax expense (recovery) are set forth below:
Years ended December 31, ($000s)
Net income (loss) before taxes
Computed expected income tax expense (recovery)
Decrease (increase) in taxes resulting from:
Non-deductible stock-based compensation
Non-deductible dividends on capital securities
Non-deductible expenses
Non-capital losses and investment tax credits
Balance, ending
2018
2017
142,145
(60,866)
38,379
(16,434)
2,315
945
155
(1,861)
1,275
945
161
167
39,933
(13,886)
117
2018 Annual Report The components of net deferred income tax liabilities are set forth below:
As at December 31, ($000s)
Deferred income tax liabilities:
P&NG properties and equipment and E&E assets
Deferred financing fees
Capital securities
Risk management contracts
Deferred income tax assets:
Decommissioning obligations
Risk management contracts
Share issue costs
Non-capital losses and investment tax credits
Deferred income tax liabilities
A continuity of the net deferred income tax liabilities is set forth below:
($000s)
P&NG and E&E assets
Deferred financing fees
Capital securities
Decommissioning obligations
Risk management contracts
Share issue costs
Non-capital losses and investment tax credits
($000s)
P&NG and E&E assets
Deferred financing fees
Capital securities
Decommissioning obligations
Risk management contracts
Share issue costs
Non-capital losses and investment tax credits
2018
2017
322,526
286,604
684
125
16,247
758
209
-
(34,901)
(33,703)
-
(3,599)
(1,092)
(5,133)
(181,529)
(164,949)
119,553
82,694
Balance
Jan. 1, 2018
286,604
758
209
(33,703)
(1,092)
(5,133)
(164,949)
82,694
Recognized in
Profit or Loss
Balance
Dec. 31, 2018
35,922
(74)
(84)
(1,198)
17,339
1,534
(16,580)
36,859
322,526
684
125
(34,901)
16,247
(3,599)
(181,529)
119,553
Balance
Jan. 1, 2017
Recogniz d in
Profit or Loss
Balance
Dec. 31, 2017
309,741
(23,137)
286,604
441
293
(36,037)
(2,547)
(6,041)
(166,251)
99,599
317
(84)
2,334
1,455
908
1,302
(16,905)
758
209
(33,703)
(1,092)
(5,133)
(164,949)
82,694
As at December 31, 2018, the Corporation had approximately $2.1 billion (2017 – $2.1 billion) in tax pools available for deduction
against future taxable income. Included in this tax basis are estimated non-capital loss carry forwards of approximately
$641 million that expire between 2028 and 2038. Discretionary tax deductions, including Canadian Development Expenses,
Canadian Oil and Gas Property Expense and Capital Cost Allowance, were maximized in the respective tax years in order to
reduce Birchcliff’s accounting profits into a loss position for tax purposes.
118
2018 Annual Report
10. CAPITAL STOCK
Share Capital
(a) Authorized:
Unlimited number of voting common shares, with no par value.
Unlimited number of preferred shares, with no par value.
The preferred shares may be issued in one or more series and the directors are authorized to fix the number of shares in each
series and to determine the designation, rights, privileges, restrictions and conditions attached to the shares of each series.
(b) Number of common shares and perpetual preferred shares issued:
The following table sets forth the number of common shares and perpetual preferred shares issued:
As at December 31, (000’s)
Common Shares:
Outstanding at beginning of period
Exercise of stock options
Outstanding at end of period(1)
Series A Preferred Shares (perpetual)(2):
Outstanding at beginning of period
Outstanding at end of period
2018
2017
265,797
264,042
144
1,755
265,911
265,797
2,000
2,000
2,000
2,000
(1) On November 20, 2018, Birchcliff announced that the TSX had accepted the Corporation’s notice of intention to make a normal course issuer bid (the “NCIB”). Pursuant to the NCIB, Birchcliff may
purchase up to 18,767,520 of its outstanding common shares. The total number of common shares that Birchcliff is permitted to purchase is subject to a daily purchase limit of 320,520 common
shares; provided, however, that the Corporation may make one block purchase per calendar week which exceeds the daily purchase restriction. The NCIB commenced on November 23, 2018 and
will terminate on November 22, 2019, or such earlier time as the NCIB is completed or is terminated at the option of Birchcliff. Purchases under the NCIB will be effected through the facilities of
the TSX and/or Canadian alternative trading systems at the prevailing market price at the time of such transaction. All common shares purchased under the NCIB will be cancelled. During 2018
and 2017, Birchcliff has not purchased any common shares pursuant to the NCIB.
(2) In August 2012, Birchcliff completed a bought deal equity financing for gross proceeds of $50 million. The Corporation issued 2,000,000 preferred units at a price of $25.00 per preferred unit
for gross proceeds of $50 million. Each preferred unit was comprised of one cumulative redeemable five year rate reset Series A Preferred Share of Birchcliff, to yield initially 8% per annum.
The Series A Preferred Shares paid cumulative dividends of $2.00 per Series A Preferred Share per annum for the initial five year period ending September 30, 2017. On September 30, 2017,
the Series A Preferred Shares dividend was reset to $2.09 per Series A Preferred Share per annum, payable quarterly if, as and when declared by Birchcliff’s Board of Directors. Thereafter,
the dividend rate will be reset every five years at a rate equal to the then current five year Government of Canada bond yield plus 6.83%. The Series A Preferred Shares were redeemable at
$25.00 per preferred share at the option of the Corporation on September 30, 2017. The Corporation did not exercise the option to redeem any Series A Preferred Shares on September 30, 2017.
The next opportunity for the Corporation to redeem the Series A Preferred Shares at $25.00 per preferred share is September 30, 2022 and on September 30 in every fifth year thereafter.
Holders of the Series A Preferred Shares had the right, at their option, to convert their Series A Preferred Shares into cumulative redeemable floating rate Series B Preferred Shares, subject to
certain conditions, on September 30, 2017. None of Birchcliff’s outstanding Series A Preferred Shares were converted into Series B Preferred Shares on September 30, 2017 as only 165,960
Series A Preferred Shares were tendered for conversion, which was less than the 250,000 shares required to give effect to conversions into Series B Preferred Shares. The next opportunity for
holders of the Series A Preferred Shares to convert their Series A Preferred Shares into Series B Preferred Shares, subject to certain conditions, is September 30, 2022 and on September 30 in
every fifth year thereafter. The holders of the Series B Preferred Shares will be entitled to receive quarterly floating rate cumulative preferential cash dividends, if declared by Birchcliff’s Board of
Directors, at a rate equal to the sum of the then current 90 day Government of Canada Treasury Bill rate plus 6.83%. In the event of liquidation, dissolution or winding-up of Birchcliff, the holders
of the Series A Preferred Shares and Series B Preferred Shares will be entitled to receive $25.00 per share as well as all accrued unpaid dividends before any amounts will be paid or any assets
will be distributed to the holders of any other shares ranking junior to the Series A Preferred Shares and the Series B Preferred Shares. The holders of the Series A Preferred Shares and the
Series B Preferred Shares will not be entitled to share in any further distribution of the assets of the Corporation.
Capital Securities
On June 14, 2013, Birchcliff completed a $50 million preferred share issue. The Corporation issued 2,000,000 cumulative
redeemable Series C Preferred Shares, at a price of $25.00 per share. The Series C Preferred Shares bear a 7% dividend and
their holders are entitled to receive, as and when declared by the Board of Directors of Birchcliff, fixed cumulative preferential
cash dividends at an annual rate of $1.75 per share, payable quarterly.
The Series C Preferred Shares are not redeemable by the Corporation prior to June 30, 2018. On and after June 30, 2018, the
Corporation may, at its option, redeem for cash, all or any number of the outstanding Series C Preferred Shares at $25.75 per
share if redeemed before June 30, 2019, at $25.50 per share if redeemed on or after June 30, 2019 but before June 30, 2020
and at $25.00 per share if redeemed on or after June 30, 2020, in each case together with all accrued and unpaid dividends
to but excluding the date fixed for redemption.
The Series C Preferred Shares are not redeemable by the holders of the preferred shares prior to June 30, 2020. On and
after June 30, 2020, a holder of Series C Preferred Shares may, at its option, redeem for cash, all or any number of Series C
Preferred Shares held by such holder on the last day of March, June, September and December of each year at $25.00 per
share, together with all accrued and unpaid dividends to but excluding the date fixed for redemption. Upon receipt of the
Notice of Redemption, the Corporation may, at its option elect to convert such Series C Preferred Shares into common shares
of the Corporation.
119
2018 Annual Report
On or after June 30, 2018, the Corporation may, at its option, convert all or any number of the outstanding Series C Preferred
Shares into common shares. The Corporation has outstanding 2,000,000 Series C Preferred Shares at December 31, 2018
(December 31, 2017 – 2,000,000).
As at December 31, 2018, Birchcliff has not redeemed for cash any of its outstanding Series C Preferred Shares or converted
any number of the outstanding Series C Preferred Shares into common shares.
Dividends
The following table sets forth the dividend distributions by the Corporation for each class of shares:
Years ended December 31,
Common Shares:
Outstanding at beginning of period ($000's)
Per common share ($)
Preferred Shares - Series A:
Series A dividend distribution ($000's)
Per Series A preferred share ($)
Preferred Shares - Series C:
Series C dividend distribution ($000's)
Per Series C preferred share ($)
Per Common Share
The following table sets forth the computation of net income (loss) per common share:
Years ended December 31, ($000's, except for per share information)
Net income (loss)
Dividends on Series A preferred shares
Net income (loss) to common shareholders
Weighted average common shares:
Weighted average basic common shares outstanding
Effects of dilutive securites
Weighted average diluted common shares outstanding(1)
Net income (loss) per common share
Basic
Diluted
2018
2017
26,586
0.1000
4,187
2.0935
3,500
1.7500
26,522
0.1000
4,047
2.0234
3,500
1.7500
2018
2017
102,212
(46,980)
(4,187)
98,025
(4,047)
(51,027)
265,852
265,182
1,471
-
267,323
265,182
$0.37
$0.37
($0.19)
($0.19)
(1) The weighted average diluted common shares outstanding as of December 31, 2018 excludes 9,512,201 common shares issuable pursuant to outstanding stock options that were anti-dilutive.
As the Corporation reported a loss in 2017, the basic and diluted weighted average shares outstanding are the same for the periods and all stock options and warrants were anti-dilutive.
11. PETROLEUM AND NATURAL GAS SALES
The following table sets forth Birchcliff’s petroleum and natural gas sales:
Years ended December 31, ($000's)
Light oil sales
Natural gas sales
NGLs sales
Total P&NG sales(1)(2)
Royalty income
Total P&NG sales
2018
122,118
332,979
166,194
621,291
2017
134,597
318,790
103,245
556,632
130
310
621,421
556,942
(1) Excludes the effects of financial derivatives but includes the effects of any physical delivery sales contracts outstanding during the period.
(2) Included in accounts receivable at December 31, 2018 was $49.1 million in P&NG sales to be received from its marketers in respect of December 2018 production, which was subsequently received
in January 2019.
120
2018 Annual Report 12. OPERATING EXPENSES
The Corporation’s operating expenses include all costs with respect to day-to-day well and facility operations. The
components of operating expenses are set forth below:
Years ended December 31, ($000s)
Field operating costs
Recoveries
Field operating costs, net
Expensed workovers and other
Operating expenses
13. ADMINISTRATIVE EXPENSES
The components of administrative expenses are set forth below:
Years ended December 31, ($000s)
Cash:
Salaries and benefits(1)
Other(2)
General and administrative, gross
Operating overhead recoveries
Capitalized overhead(3)
General and administrative, net
Non-cash:
Other compensation(4)
Capitalized compensation(3)
Other compensation, net
Administrative expenses, net
2018
102,099
(2,995)
99,104
-
2017
112,287
(1,917)
110,370
116
99,104
110,486
2018
2017
28,618
13,329
41,947
(150)
31,437
13,498
44,935
(202)
(17,195)
(18,229)
24,602
26,504
14,758
(7,061)
7,697
32,299
9,945
(5,886)
4,059
30,563
(1) Includes salaries, benefits and bonuses paid to officers and employees of the Corporation and retainer fees, meeting fees and benefits paid to directors of the Corporation.
(2) Includes costs such as rent, legal, tax, insurance, minor computer hardware and software and other business expenses incurred by the Corporation.
(3) Includes a portion of gross general and administrative expenses and other compensation directly attributable to the exploration and development activities of the Corporation, which have
been capitalized.
(4) Includes stock-based compensation expense of $6.9 million and post-employment benefit expense of $7.8 million in 2018 (2017 - $9.9 million and $nil, respectively) (Notes 14 & 16).
Gross compensation for the Corporation’s executive officers and directors are comprised of the following:
Years ended December 31, ($000s)
Salaries and benefits(1)
Stock-based compensation(2)
Post-employement benefit expense(3)
Executive Officers and Directors compensation
2018
6,312
1,770
7,844
15,926
2017
8,623
2,256
-
10,879
(1) Includes salaries, benefits and bonuses paid to officers of the Corporation and directors’ fees and benefits paid to the directors of the Corporation.
(2) Represents the amortization of stock-based compensation expense in the year associated with options granted to the executive officers participating in the Option Plan (as defined herein).
(3) Represents past service costs associated with post-employment benefits granted in the year to the Corporation’s executive officers (Note 14).
14. OTHER LIABILITIES
The Corporation has established a post-employment benefit plan for eligible employees, which provides for post-employment
benefits based upon the age at retirement and their period of service with Birchcliff (the “Plan”). The Plan is not funded and
as such no plan assets exist. The post-employment benefit obligation arising from the Plan is determined by discounting
the estimated future cash outflows using interest rates of high-quality corporate bonds that have terms to maturity
approximating the terms of the related liability. The expenses associated with the Plan are comprised of current and past
service costs and the interest (accretion) on the unwinding of the present value of the post-employment benefit obligation.
121
2018 Annual Report The Corporation estimates the total undiscounted (inflated) amount of cash flow required to settle its post-employment
obligations is approximately $14.8 million at December 31, 2018 (December 31, 2017 – $nil). A reconciliation of the discounted
post-employment benefit obligation is set forth below:
As at, December 31 ($000s)
Balance, beginning
Post-employement benefit expense(1)
Balance, ending(2)
2018
-
7,844
7,844
2017
-
-
-
(1) Represents the past service costs associated with post-employment benefits.
(2) Birchcliff applied a discount rate of 2.8% and an inflation rate of 3.0% to calculate the present value of the post-employment benefit obligation at December 31 2018.
Birchcliff recorded a post-employment benefit obligation of $7.8 million at December 31, 2018 (December 31, 2017 – $nil).
A 1% increase in the discount rate would result in a $0.3 million decrease in the post-employment benefit obligation at
December 31, 2018 (December 31, 2017 - $nil)
15. FINANCE EXPENSES
The components of finance expenses are set forth below:
Years ended December 31, ($000s)
Cash:
Interest on credit facilities
Non-cash:
Accretion(1)
Amortization of deferred financing fees
Finance expenses
(1) Includes accretion on decommissioning obligations and post-employment benefits.
16. SHARE-BASED PAYMENTS
Stock Options
2018
2017
27,969
28,374
3,208
1,534
32,711
3,055
1,510
32,939
At December 31, 2018, the Corporation’s stock option plan (the “Option Plan”) permitted the grant of options in respect of a
maximum of 26,591,136 (December 31, 2017 – 26,579,670) common shares. At December 31, 2018, there remained available
for issuance options in respect of 10,743,566 (December 31, 2017 – 12,421,563) common shares. For stock options exercised
during 2018, the weighted average common share trading price on the Toronto Stock Exchange was $4.03 (2017 – $6.22)
per common share.
A summary of the outstanding stock options is set forth below:
Outstanding, December 31, 2016
Granted(2)
Exercised
Forfeited
Expired
Outstanding, December 31, 2017
Granted(2)
Exercised
Forfeited
Expired
Outstanding, December 31, 2018
(1) Calculated on a weighted average basis.
(2) Each stock option granted entitles the holder to purchase one common share at the exercise price.
Number
12,899,775
4,867,400
(1,754,796)
(1,606,437)
(247,835)
14,158,107
4,734,900
(114,664)
(483,405)
(2,447,368)
15,847,570
Price ($)(1)
6.45
7.67
(5.33)
(7.49)
(7.55)
6.88
3.23
(3.35)
(5.59)
(7.57)
5.74
122
2018 Annual Report The weighted average fair value per option granted during 2018 was $1.03 (2017 – $2.96). In determining the stock-based
compensation expense for options issued during 2018, the Corporation applied a weighted average estimated forfeiture rate
of 11% (2017 – 11%).
The weighted average assumptions used in calculating the Black-Scholes fair values are set forth below:
Years ended December 31,
Risk-free interest rate
Expected life (years)
Expected volatility
Dividend yield
2018
2.0%
4.0
49.7%
3.2%
2017
1.0%
4.0
49.3%
0.1%
A summary of the stock options outstanding and exercisable under the Option Plan at December 31, 2018 is set forth below:
Exercise Price ($)
Awards Outstanding
Awards Exercisable
Weighted
Average
Remaining
Contractual
Life (years)
3.5
1.9
1.0
2.6
Weighted
Average
Exercise
Price ($)
3.34
7.64
10.07
5.74
Weighted
Average
Remaining
Contractual
Life (years)
2.1
1.3
0.7
1.4
Weighted
Average
Exercise
Price ($)
3.49
7.57
10.25
6.75
Quantity
1,595,513
5,932,938
103,666
7,632,117
Low
3.00
6.01
9.01
High
6.00
9.00
12.00
Quantity
7,056,369
8,668,201
123,000
15,847,570
Performance Warrants
On January 14, 2005, Birchcliff issued 4,049,665 performance warrants as part of the Corporation’s initial restructuring
to become a public entity. There are 2,939,732 performance warrants outstanding and exercisable at December 31, 2018
(December 31, 2017 – 2,939,732). Each performance warrant is exercisable at a price of $3.00 to purchase one common
share of Birchcliff and expires on January 31, 2020.
17. CAPITAL MANAGEMENT
The Corporation’s general policy is to maintain a sufficient capital base in order to manage its business in the most effective
manner with the goal of increasing the value of its assets and thus its underlying share value. The Corporation’s objectives
when managing capital are to maintain financial flexibility in order to preserve its ability to meet financial obligations
(including potential obligations arising from additional acquisitions), to maintain a capital structure that allows Birchcliff to
finance its business strategy using primarily internally-generated cash flow and its available debt capacity and to optimize the
use of its capital to provide an appropriate investment return to its shareholders. There were no changes in the Corporation’s
approach to capital management during 2018 and 2017.
The following table sets forth the Corporation’s total available credit:
As at December 31, ($000s)
Maximum borrowing base limit(1):
Revolving term credit facilities
Principal amount utilized:
Drawn revolving term credit facilities
Outstanding letters of credit(2)
Unused credit
2018
2017
950,000
950,000
(608,821)
(594,823)
(17,205)
(12,184)
(626,026)
(607,007)
323,974
342,993
(1) The Credit Facilities are subject to a semi-annual review of the borrowing base limit, which is directly impacted by the value of Birchcliff’s petroleum and natural gas reserves.
(2) Letters of credit are issued to various service providers. The letters of credit reduced the amount available under the Working Capital Facility.
123
2018 Annual Report
The capital structure of the Corporation is as follows:
As at December 31, ($000s)
Shareholders’ equity(1)
Capital securities
2018
2017
% Change
1,774,890
1,696,153
49,535
49,225
Shareholders’ equity & capital securities
1,824,425
1,745,378
5%
Shareholders’ equity & capital securities as a % of total capital(2)
Working capital deficit(3)
Drawn revolving term credit facilities
Drawn debt
Drawn debt as a % of total capital
Total capital
(1) Shareholders’ equity is defined as share capital plus contributed surplus plus retained earnings, less any deficit.
(2) Of the 74%, approximately 95% relates to common capital stock and 5% relates to preferred capital stock.
(3) Working capital is defined as current assets less current liabilities (excluding fair value of financial instruments).
18. FINANCIAL RISK MANAGEMENT
74%
74%
21,187
11,067
605,267
594,823
626,454
605,890
26%
26%
2,450,879
2,351,268
3%
4%
Birchcliff is exposed to credit risk, liquidity risk and market risk as part of its normal course of business. The Board of Directors
has overall responsibility for the establishment and oversight of the Corporation’s financial risk management framework and
periodically reviews the results of all risk management activities and all outstanding positions.
Credit Risk
Credit risk is the risk of financial loss to the Corporation if a customer or counterparty to a financial asset fails to meet its
contractual obligation, and arises principally from Birchcliff’s receivables from its oil and natural gas marketers and
its financial instruments. Cash is comprised of bank balances. Historically, the Corporation has not carried short-term
investments. Should this change in the future, counterparties will be selected based on credit ratings, management
will monitor all investments to ensure a stable return and complex investment vehicles with higher risk will be avoided.
The Corporation’s exposure to cash credit risk at the statement of financial position date is low.
The carrying amount of accounts receivable reflects management’s assessment of the credit risk associated with these
customers. The following table illustrates the Corporation’s maximum exposure for accounts receivable:
As at December 31, ($000s)
Marketers(1)
Joint venture
Other
Accounts receivable
2018
49,070
2,342
529
2017
59,821
3,544
5,937
51,941
69,302
(1) At December 31, 2018, approximately 33% was due from one marketer (2017 – 23%, one marketer). During 2018, the Corporation received 23%, 11% and 10% of its revenue, respectively, from
three marketers (2017 – 20%, 16% and 10% of its revenue, respectively, from three marketers).
Typically, Birchcliff’s maximum credit exposure from its marketers is revenue from its commodity sales. Receivables
from marketers are normally collected on the 25th day of the month following production. Birchcliff mitigates the credit
risk associated with these receivables by establishing marketing relationships with credit worthy purchasers, obtaining
guarantees from their ultimate parent companies and obtaining letters of credit, if and as appropriate. The Corporation
historically has not experienced any material collection issues with its marketers.
Birchcliff’s accounts receivables are aged as follows:
As at December 31, ($000s)
Current (less than 30 days)
30 to 60 days
61 to 90 days
91 to 120 days
Over 120 days
Accounts receivable
124
2018
48,052
2,006
1,099
160
624
2017
66,901
1,637
666
26
72
51,941
69,302
2018 Annual Report At December 31, 2018, approximately $0.6 million or 1.2% (2017 – $0.07 million or 0.1%) of Birchcliff’s total accounts receivable
are aged over 120 days and considered past due. The majority of these accounts are due from various joint venture partners.
Birchcliff attempts to mitigate the credit risk from joint venture receivables by obtaining pre-approval of significant capital
expenditures. However, the receivables are from participants in the oil and natural gas sector, and collection of the outstanding
balances is dependent on industry factors such as commodity price fluctuations, escalating costs and the risk of unsuccessful
drilling. In addition, further risk exists with joint venture partners as disagreements occasionally arise that increases the
potential for non-collection. The Corporation does not typically obtain collateral from petroleum and natural gas marketers
or joint venture partners; however, the Corporation does have the ability to withhold production from joint venture partners
in the event of non-payment.
The carrying amount of Birchcliff’s accounts receivable, financial instruments and investment in securities represents its
maximum credit exposure. Birchcliff determined that the ultimate collection of these financial assets were not in doubt and
therefore no allowance or charge to profit or loss was recorded in 2018 and 2017.
Liquidity Risk
Liquidity risk is the risk that the Corporation will not be able to meet its obligations associated with financial liabilities that are
settled by cash as they become due. Birchcliff’s approach to managing liquidity is to ensure, as much as possible, that it will
have sufficient liquidity to meet its short-term and long-term financial obligations when due, under both normal and unusual
conditions without incurring unacceptable losses or risking harm to the Corporation’s reputation. Birchcliff actively manages
its liquidity using cash and debt management programs. Strategies include monitoring forecast and actual cash flows from
operating, financing, and investing activities and managing available credit and working capital under its Credit Facilities.
All of the Corporation’s contractual financial liabilities can be settled in cash. Typically, the Corporation ensures that it has
sufficient cash on demand to meet expected operational expenses, including the servicing of financial obligations. To achieve this
objective, the Corporation prepares annual capital expenditure budgets, which are approved by the Board of Directors and are
regularly reviewed and updated as considered necessary. Petroleum and natural gas production is monitored daily and is used
to provide monthly cash flow estimates. Further, the Corporation utilizes authorizations for expenditures on both operated and
non-operated projects to manage capital expenditure. The Corporation also attempts to match its payment cycle with collection
of petroleum and natural gas revenue on the 25th of each month. Should commodity prices deteriorate materially, Birchcliff may
adjust its capital spending accordingly to ensure that it is able to service its short-term financial obligations.
To facilitate the capital expenditure program, the Corporation has an aggregate $950 million reserve-based bank credit
facilities at the end of 2018 (2017 – $950 million) which are reviewed semi-annually by its lenders. The principal amount
drawn under the Corporation’s total credit facilities at December 31, 2018 was $626.0 million (2017 – $607.0 million) and
$324 million in unused credit was available at the end of 2018 (2017 – $343.0 million) to fund future obligations.
The following table lists the Corporation’s financial liabilities at December 31, 2018 in the period they are due:
($000s)
Accounts payable and accrued liabilities
Drawn revolving credit facilities
Financial liabilities
Market Risk
2019
76,567
-
76,567
2021
-
608,821
608,821
Market risk is the risk that changes in market conditions, such as commodity prices, exchange rates and interest rates, will affect
the Corporation’s net income or the value of its financial instruments, if any. The objective of market risk management is to
manage and control exposures within acceptable limits, while maximizing returns. These risks are consistent with prior years.
All risk management transactions are conducted within risk management tolerances that are reviewed by the Board of Directors.
Commodity Price Risk
Commodity price risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in commodity
prices. Significant changes in commodity prices can materially impact cash flows and the Corporation’s borrowing base limit.
Lower commodity prices can also reduce the Corporation’s ability to raise capital. Commodity prices for petroleum and natural
gas are not only influenced by Canadian (“CDN”) and United States (“US”) demand, but also by world events that dictate the
levels of supply and demand.
125
2018 Annual Report Financial Derivative Contracts
As of December 31, 2018, Birchcliff had certain financial derivative contracts outstanding in order to manage commodity price
risk. These instruments are not used for trading or speculative purposes. Birchcliff has not designated its financial derivative
contracts as effective accounting hedges, even though the Corporation considers all commodity contracts to be effective
economic hedges. As a result, all such financial derivative contracts are recorded on the statement of financial position at fair
value, with the changes in fair value being recognized as an unrealized gain or loss in profit or loss.
As at December 31, 2018, Birchcliff had the following financial derivative contracts in place in order to manage commodity
price risk:
Product
Type of Contract
Notional Quantity
Term(1)
Contract Price
Natural gas
AECO 7A basis swap(2)
30,000 MMBtu/d
Jan. 1, 2019 – Dec. 31, 2023 NYMEX HH less US$1.298/MMBtu
Natural gas
AECO 7A basis swap(2)
10,000 MMBtu/d
Jan. 1, 2019 – Dec. 31, 2023 NYMEX HH less US$1.32/MMBtu
Natural gas
AECO 7Abasis swap(2)
30,000 MMBtu/d
Jan. 1, 2019 – Dec. 31, 2023 NYMEX HH less US$1.33/MMBtu
Natural gas
AECO 7A basis swap(2)
15,000 MMBtu/d
Jan. 1, 2019 – Dec. 31, 2024 NYMEX HH less US$1.185/MMBtu
Natural gas
AECO 7A basis swap(2)
5,000 MMBtu/d
Jan. 1, 2019 – Dec. 31, 2024 NYMEX HH less US$1.20/MMBtu
Natural gas
AECO 7A basis swap(2)
5,000 MMBtu/d
Jan. 1, 2019 – Dec. 31, 2024 NYMEX HH less US$1.20/MMBtu
Natural gas
AECO 7A basis swap(3)
10,000 MMBtu/d
Jan. 1, 2019 – Mar. 31, 2019 NYMEX HH less US$3.10/MMBtu
Natural gas
AECO 7A basis swap(3)
10,000 MMBtu/d
Jan. 1, 2019 – Mar. 31, 2019 NYMEX HH less US$3.15/MMBtu
Natural gas
AECO 7A basis swap(3)
30,000 MMBtu/d
Jan. 1, 2019 – Mar. 31, 2019 NYMEX HH less US$3.16/MMBtu
Fair Value Asset
(1) Transactions with common terms and the same counterparty have been aggregated and presented at the weighted average price.
(2) Birchcliff sold AECO basis swap.
(3) Birchcliff bought AECO basis swap.
Fair Value
($000s)
16,474
5,079
13,273
11,288
3,826
3,604
1,246
1,276
4,109
60,175
The fair value asset of the Corporation’s financial derivative contracts at December 31, 2018 was $60.2 million (2017 – liability
of $4.0 million).
The following table provides a summary of the realized and unrealized gains (losses) on financial derivative contracts:
Years ended December 31, ($000s)
Realized gain (loss) on derivatives(1)
Unrealized gain on derivatives
2018
(15,771)
64,222
2017
25,785
5,387
(1) During the fourth quarter of 2018, Birchcliff monetized all of its outstanding USD WTI fixed price contracts and recorded a realized gain of $4.0 million.
At December 31, 2018, if the future AECO/NYMEX basis was US$0.10/MMBtu higher, with all other variables held constant,
after tax net income in 2018 would have increased by $15.5 million.
The following financial derivative contracts were entered into subsequent to December 31, 2018:
Product
Natural gas
Natural gas
Natural gas
Natural gas
Natural gas
Natural gas
Type of Contract
Notional Quantity
Term(1)
Contract Price
AECO 7A basis swap(2)
10,000 MMBtu/d
Jan. 1, 2025 – Dec. 31, 2025
NYMEX HH less US$1.020/MMBtu
AECO 7A basis swap(2)
20,000 MMBtu/d
Jan. 1, 2024 – Dec. 31, 2025
NYMEX HH less US$1.119/MMBtu
AECO 7A basis swap(2)
25,000 MMBtu/d
Jan. 1, 2024 – Dec. 31, 2025
NYMEX HH less US$1.135/MMBtu
AECO 7A basis swap(2)
5,000 MMBtu/d
Jan. 1, 2021 – Dec. 31, 2025
NYMEX HH less US$1.178/MMBtu
AECO 7A basis swap(2)
10,000 MMBtu/d
Jan. 1, 2021 – Dec. 31, 2025
NYMEX HH less US$1.175/MMBtu
AECO 7A basis swap(2)
5,000 MMBtu/d
Jan. 1, 2021 – Dec. 31, 2025
NYMEX HH less US$1.190/MMBtu
(1) Transactions with common terms and the same counterparty have been aggregated and presented at the weighted average price.
(2) Birchcliff sold AECO basis swap.
126
2018 Annual Report Physical Delivery Sales Contracts
Birchcliff also enters into physical delivery sales contracts to manage commodity price risk. These contracts are considered
normal executory sales contracts and are not recorded at fair value through profit or loss. At December 31, 2018, the Corporation
had the following physical delivery sales contract in place:
Product
Type of Contract
Notional Quantity
Term(1)
Contract Price
Natural gas
AECO 7A basis swap(2)
5,000 MMBtu/d
Jan. 1, 2019 – Dec. 31, 2023
NYMEX HH less US$1.205/MMBtu
Natural gas
Dawn fixed price(3)
5,000 MMBtu/d
Jan. 1, 2019 – Mar. 31, 2019
US$5.100/MMBtu
Natural gas
Dawn fixed price(3)
10,000 MMBtu/d
Jan. 1, 2019 – Mar. 31, 2019
US$5.000/MMBtu
Natural gas
Dawn fixed price(3)
10,000 MMBtu/d
Jan. 1, 2019 – Mar. 31, 2019
US$5.005/MMBtu
Natural gas
Dawn fixed price(3)
10,000 MMBtu/d
Jan. 1, 2019 – Mar. 31, 2019
US$5.020/MMBtu
Natural gas
Dawn fixed price(3)
15,000 MMBtu/d
Jan. 1, 2019 – Mar. 31, 2019
US$5.103/MMBtu
(1) Transactions with common terms and the same counterparty have been aggregated and presented at the weighted average price.
(2) Birchcliff sold AECO basis swap.
(3) Birchcliff entered into a 4-month fixed price physical natural gas Dawn sales arrangement commencing December 1, 2018.
There were no long-term physical delivery sales contracts entered into subsequent to December 31, 2018.
Foreign Currency Risk
Foreign currency risk is the risk that future cash flows will fluctuate as a result of changes in foreign currency exchange rates.
The exchange rate effect cannot be quantified but generally an increase in the value of the CDN dollar as compared to the
US dollar will reduce the CDN dollar prices received by Birchcliff for its petroleum and natural gas sales. The Corporation had
no forward exchange rate contracts in place as at or during the years ended December 31, 2018 and 2017.
Interest Rate Risk
Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The Corporation’s
credit facilities are exposed to interest rate cash flow risk on a floating interest rate due to fluctuations in market interest
rates. The remainder of Birchcliff’s financial assets and liabilities are not exposed directly to interest rate risk.
A 1% change in the CDN prime interest rate in 2018 would have changed after-tax net income by approximately $4.4 million
(2017 – $4.3 million), assuming that all other variables remain constant. A sensitivity of 1% is considered reasonable given the
current level of the bank prime rate and market expectations for future movements.
The Corporation reviews its market interest rate risk exposure and may enter into interest rate swaps when market conditions
are favourable in order to reduce volatility in its financial results. Subsequent to December 31, 2018, Birchcliff entered into
a financial one-month bankers’ acceptance CDOR (Canadian Dollar Offered Rate) fixed interest rate swap on $350 million
at 2.215% for the period from March 1, 2019 to March 1, 2024.
Fair Value of Financial Instruments
Birchcliff’s financial instruments include cash, accounts receivable, deposits, investment in securities, accounts payable and
accrued liabilities, financial derivative contracts, outstanding credit facilities and capital securities. All of Birchcliff’s financial
instruments are transacted in active markets. Financial instruments carried at fair value are assessed using the following
hierarchy based on the amount of observable inputs used to value the instrument:
Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets
are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly
or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for
commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace.
127
2018 Annual Report Level 3 – Valuations in this level are those with inputs for the asset or liability that are not based on observable market data.
Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the
placement within the fair value hierarchy level.
The carrying value and fair value of the Corporation’s financial assets and liabilities at December 31, 2018 are set forth below:
($000s)
Loans and receivables:
Cash
Accounts receivable
Deposits
Investment in securities(1)
Fair value of financial derivatives(2)
Other liabilities:
Accounts payable and accrued liabilities
Capital Securities
Drawn revolving term credit facilities
(1) Investment in securities are fair valued based on level 1.
(2) Financial derivative contracts are fair valued based on level 2.
19. COMMITMENTS
Carrying
Value
53
51,941
2,756
10,005
60,175
76,567
49,535
608,821
Fair
Value
53
51,941
2,756
10,005
60,175
76,567
48,400
608,821
The Corporation enters into contracts and commitments in the normal course of operations. The following table lists
Birchcliff’s commitments at December 31, 2018:
($000s)
Operating leases(1)
Firm transportation, processing and fractionation(2)
Natural gas processing(3)
Commitments
2019
4,408
107,678
17,155
129,241
2020
4,408
116,574
17,702
138,684
2021 - 2023
Thereafter
13,707
364,742
51,465
429,914
19,667
348,079
154,536
522,282
(1) On December 2, 2015, the Corporation entered into an operating lease commitment relating to a new office premises beginning February 1, 2018 and expiring on January 31, 2028. The
commitment amount under the new 10 year office lease is estimated to be $42.2 million, which includes costs allocated to base rent, parking and building operating expenses. The office lease
commitment amounts disclosed in the above table have not been reduced for any rents receivable by the Corporation.
(2) Includes firm transportation service arrangements with various terms on TCPL’s Alberta NGTL System and on TCPL’s Canadian Mainline to the AECO and Dawn trading hubs and fractionation
commitments associated with NGLs production processed at third-party facilities.
(3) Includes natural gas processing commitments at third-party facilities.
20. SUPPLEMENTARY CASH FLOW INFORMATION
Years ended December 31, ($000s)
Provided by (used in):
Accounts receivable
Prepaid expenses and deposits
Accounts payable and accrued liabilities
Dividend tax
Provided by (used in):
Operating
Investing
128
2018
2017
17,361
(764)
(6,472)
(3,074)
(6,730)
(621)
(9,076)
(3,019)
7,051
(19,446)
12,591
(29,226)
(5,540)
9,780
7,051
(19,446)
2018 Annual Report
21. CONTINGENT LIABILITY
Birchcliff’s 2006 income tax filings were reassessed by the Canada Revenue Agency (the “CRA”) in 2011 (the “Reassessment”).
The Reassessment was based on the CRA’s position that the tax pools available to Veracel Inc. (“Veracel”), prior to its
amalgamation with Birchcliff, ceased to be available to Veracel after Birchcliff and Veracel amalgamated on May 31, 2005.
The Veracel tax pools in dispute totalled $39.3 million. Birchcliff appealed the Reassessment to the Tax Court of Canada
(the “Trial Court”) and the trial of that appeal occurred in November 2013. On October 1, 2015, the Trial Court issued its
decision (the “Trial Decision”) and dismissed Birchcliff’s appeal on the basis of the general anti-avoidance rule contained in
the Income Tax Act (Canada). The Trial Decision was rendered by a judge based on the written record and not by the judge who
conducted the trial. As a result of the Trial Decision, Birchcliff recorded a non-cash deferred income tax expense in the amount
of $10.2 million in the fourth quarter of 2015.
Birchcliff appealed the Trial Decision to the Federal Court of Appeal (the “FCA”), which appeal was heard in January 2017.
In April 2017, the FCA issued its decision and allowed the appeal and set aside the Trial Decision, based on the lack of
jurisdiction by the judge who rendered the Trial Decision. In setting aside the Trial Decision, the FCA referred the matter back
to the judge of the Trial Court who initially conducted the trial in 2013 to render a judgment. The judge of the Trial Court
rendered a decision in November 2017 and dismissed the Corporation’s appeal. The Corporation appealed that decision
to the FCA, which appeal was heard on December 10, 2018 with judgment reserved.
22. SUBSEQUENT EVENT
On November 14, 2018, Birchcliff announced that it had entered into a definitive purchase and sale agreement to acquire
Montney lands located between the Corporation’s existing properties, as well as various other non-Montney lands and
other assets, for total cash consideration of $39 million (the “Acquisition”). The Corporation paid a deposit of $3.9 million
in connection with the Acquisition, the full amount of which was drawn under the Credit Facilities at December 31, 2018.
The remaining cash required to close the Acquisition was financed by the Corporation’s Credit Facilities on closing which
occurred on January 3, 2019.
129
2018 Annual Report GLOSSARY
DEFINITIONS
Capitalized terms not otherwise defined in this Annual Report shall have the following meanings:
“Birchcliff”, “its”, “our” “us” or “we” means Birchcliff Energy Ltd.
“CSA Staff Notice 51-324”
means CSA Staff Notice 51-324 – Revised Glossary to NI 51-101 Standards of Disclosure
for Oil and Gas Activities.
“GAAP”
means generally accepted accounting principles for publicly accountable enterprises
in Canada which is currently in accordance with International Financial Reporting
Standards as issued by the International Accounting Standards Board.
“Montney/Doig Resource Play”
means Birchcliff’s Montney and Doig formations resource play located northwest of
Grande Prairie, Alberta.
“TSX”
means the Toronto Stock Exchange.
“Western Canadian
Sedimentary Basin”
means the vast sedimentary basin underlying Western Canada that is the source of
most of Western Canada’s current oil and gas production.
“working interest”
means a percentage of ownership in an oil and gas property, obligating the owner to
share in the costs of exploration, development and operations and granting the owner
the right to share in production revenues after royalties are paid.
130
2018 Annual Report ABBREVIATIONS
AECO
bbl
bbls
bbls/d
Bcf
boe
boe/d
F&D
FD&A
FDC
G&A
GJ
GJ/d
HH
km
Mbbls
Mboe
Mcf
MM
MM$
MMBoe
MMBtu
MMcf
MMcf/d
MSW
NGLs
NYMEX
TCPL
WTI
000s
$000s
benchmark price for natural gas determined at the AECO ‘C’ hub in southeast Alberta
barrel
barrels
barrels per day
billion cubic feet
barrel of oil equivalent
barrel of oil equivalent per day
finding and development
finding, development and acquisition
future development costs
general and administrative
gigajoule
gigajoules per day
Henry Hub
kilometres
thousand barrels
thousand barrels of oil equivalent
thousand cubic feet
millions
millions of dollars
million barrels of oil equivalent
million British thermal units
million cubic feet
million cubic feet per day
price for mixed sweet crude oil at Edmonton, Alberta
natural gas liquids
New York Mercantile Exchange
TransCanada PipeLines Limited
West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma, for crude oil of
standard grade
thousands
thousands of dollars
CONVENTIONS
Certain terms used herein are defined in NI 51-101, CSA Staff Notice 51-324 or the COGE Handbook and, unless the context
otherwise requires, shall have the same meanings in this Annual Report as in NI 51-101, CSA Staff Notice 51-324 or the COGE
Handbook, as the case may be. Unless otherwise indicated, all information contained herein is given at or for the year ended
December 31, 2018. Unless otherwise indicated, all dollar amounts are expressed in Canadian dollars and all references to
“$”, “CDN$” or “dollars” are to Canadian dollars and all references to “US$” are to United States dollars. All financial information
contained in this Annual Report has been presented in accordance with GAAP. Words importing the singular number only
include the plural, and vice versa, and words importing any gender include all genders.
131
2018 Annual Report NON-GAAP MEASURES
This Annual Report uses “adjusted funds flow”, “adjusted funds flow per common share”, “free funds flow”, “operating netback”,
“adjusted working capital deficit” and “total debt”. These measures do not have standardized meanings prescribed by GAAP
and therefore may not be comparable to similar measures presented by other companies where similar terminology is used.
Management believes that these non-GAAP measures assist management and investors in assessing Birchcliff’s profitability,
efficiency, liquidity and overall performance. For further information regarding these non-GAAP measures, please see
“Non-GAAP Measures” in the MD&A.
In addition, this Annual Report uses “adjusted funds flow netback” which denotes petroleum and natural gas revenue less royalty
expense, less operating expense, less transportation and other expense, less net G&A expense, less interest expense and less any
realized losses (plus realized gains) on financial instruments and plus any other cash income sources. Birchcliff previously referred
to adjusted funds flow netback as “funds flow netback”. Adjusted funds flow netback has been calculated on a per unit basis.
Management believes that adjusted funds flow netback assists management and investors in assessing Birchcliff’s profitability
and its operating results on a per unit basis to better analyze its performance against prior periods on a comparable basis.
The following table provides a breakdown of Birchcliff’s adjusted funds flow netback for the periods indicated:
Petroleum and natural gas revenue
Royalty expense
Operating expense
Transportation and other expense
Operating netback(1)
General & administrative expense, net
Interest expense
Realized gain (loss) on financial
instruments
Other income
Adjusted funds flow netback(1)
($000s)
154,720
(6,763)
(24,677)
(28,567)
94,713
(7,618)
(7,438)
1,658
202
81,517
Three months ended
December 31,
Twelve months ended
December 31,
2018
($/boe)
($000s)
22.01
166,149
2017
($/boe)
22.55
($000s)
621,421
2018
($/boe)
($000s)
22.08
556,942
(0.96)
(9,271)
(1.26)
(38,306)
(1.36)
(28,727)
(3.51)
(28,460)
(3.86)
(99,104)
(3.52)
(110,486)
(4.07)
(25,883)
(3.52)
(103,547)
(3.68)
(71,224)
13.47
102,535
13.91
380,464
13.52
346,505
(1.08)
(1.06)
(9,451)
(7,131)
(1.28)
(24,602)
(0.87)
(26,504)
(0.97)
(27,969)
(0.99)
(28,374)
0.24
10,787
1.46
(15,771)
(0.56)
25,785
0.03
268
11.60
97,008
0.04
13.16
800
312,922
0.02
11.12
268
317,680
2017
($/boe)
22.45
(1.16)
(4.45)
(2.87)
13.97
(1.07)
(1.14)
1.03
0.02
12.81
(1) All per boe amounts are calculated by dividing each aggregate financial amount by the production (boe) in the respective period.
PRESENTATION OF OIL AND GAS RESERVES
Deloitte prepared the 2018 Consolidated Reserves Report, the 2017 Consolidated Reserves Report, the 2018 Deloitte Reserves
Report and the 2017 Deloitte Reserves Report. McDaniel prepared the 2018 McDaniel Reserves Report and the 2017 McDaniel
Reserves Report. In addition, Deloitte prepared reserves evaluations in respect of Birchcliff’s oil and natural gas properties
effective December 31, 2016 through to 2010. Such evaluations were prepared in accordance with the standards contained in
NI 51-101 and the COGE Handbook that were in effect at the relevant time. Reserves estimates stated herein are extracted from
the relevant evaluation.
There are numerous uncertainties inherent in estimating quantities of oil, natural gas and NGLs reserves and the future net
revenue attributed to such reserves. The reserves and associated future net revenue information set forth in this Annual Report
are estimates only. In general, estimates of economically recoverable oil, natural gas and NGLs reserves and the future net
revenue therefrom are based upon a number of variable factors and assumptions, such as historical production from the
properties, production rates, ultimate reserves recovery, the timing and amount of capital expenditures, marketability of oil,
natural gas and NGLs, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs,
all of which may vary materially from actual results. For these reasons, estimates of the economically recoverable oil, natural
gas and NGLs reserves attributable to any particular group of properties, the classification of such reserves based on risk of
recovery and estimates of future net revenue associated with reserves prepared by different engineers, or by the same
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2018 Annual Report engineer at different times, may vary substantially. Birchcliff’s actual production, revenues, taxes and development and
operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material.
It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to the
Corporation’s reserves estimated by the Corporation’s independent qualified reserves evaluators represent the fair market
value of those reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances
could be material. Actual oil, natural gas and NGLs reserves may be greater than or less than the estimates provided herein
and variances could be material. With respect to the disclosure of reserves contained herein relating to portions of Birchcliff’s
properties, the estimates of reserves and future net revenue for individual properties may not reflect the same confidence
level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. In this Annual Report,
all references to “reserves” are to Birchcliff’s gross company reserves unless otherwise stated.
The information relating to the Corporation’s reserves contains forward-looking statements and information, including
information relating to future net revenue. See “Advisories – Forward-Looking Statements”.
RESERVES CATEGORIES
Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from
known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical and engineering data; the
use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves
are classified according to the degree of certainty associated with the estimates:
•
•
“Proved reserves” are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely
that the actual remaining quantities recovered will exceed the estimated proved reserves.
“Probable reserves” are those additional reserves that are less certain to be recovered than proved reserves. It is equally
likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus
probable reserves.
INTEREST IN RESERVES, PRODUCTION, WELLS AND PROPERTIES
“Gross” means: (a) in relation to Birchcliff’s interest in production or reserves, Birchcliff’s working interest (operating or
non-operating) share before deduction of royalties and without including any royalty interests of Birchcliff; (b) in relation to
wells, the total number of wells in which Birchcliff has an interest; and (c) in relation to properties, the total area of properties
in which Birchcliff has an interest.
“Net” means: (a) in relation to Birchcliff’s interest in production or reserves, Birchcliff’s working interest (operating or
non-operating) share after deduction of royalty obligations, plus Birchcliff’s royalty interests in production or reserves;
(b) in relation to Birchcliff’s interest in wells, the number of wells obtained by aggregating Birchcliff’s working interest in each
of its gross wells; and (c) in relation to Birchcliff’s interest in a property, the total area in which Birchcliff has an interest
multiplied by the working interest owned by Birchcliff.
LEVELS OF CERTAINTY FOR REPORTED RESERVES
The qualitative certainty levels referred to in the definitions above are applicable to “individual reserves entities”, which refers
to the lowest level at which reserves calculations are performed, and to “reported reserves”, which refers to the highest level
sum of individual entity estimates for which reserves estimates are presented. Reported reserves should target the following
levels of certainty under a specific set of economic conditions:
•
•
•
at least a 90% probability that the quantities actually recovered will equal or exceed the estimated proved reserves;
at least a 50% probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus
probable reserves; and
at least a 10% probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus
probable plus possible reserves.
A quantitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable
to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates are
prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability.
In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.
133
2018 Annual Report FORECAST PRICES AND COSTS
“Forecast prices and costs” means future prices and costs that are: (a) generally accepted as being a reasonable outlook of the
future; (b) if, and only to the extent that, there are fixed or presently determinable future prices or costs to which Birchcliff is
legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a
contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in paragraph (a).
ADVISORIES
BOE CONVERSIONS
Boe amounts have been calculated by using the conversion ratio of 6 Mcf of natural gas to 1 bbl of oil. Boe amounts may be
misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 bbl is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. 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.
MMBTU PRICING CONVERSIONS
$1.00 per MMBtu equals $1.00 per Mcf based on a standard heat value Mcf.
OIL AND GAS METRICS
This Annual Report contains metrics commonly used in the oil and natural gas industry, including netbacks, reserves life index,
recycle ratio, reserves replacement, F&D costs and FD&A costs, which have been determined by Birchcliff as set out below.
These oil and gas metrics do not have any standardized meanings or standard methods of calculation and therefore may not be
comparable to similar measures presented by other companies where similar terminology is used. As such, they should not be
used to make comparisons. Management uses these oil and gas metrics for its own performance measurements and to provide
shareholders with measures to compare Birchcliff’s performance over time; however, such measures are not reliable indicators
of Birchcliff’s future performance, which may not compare to Birchcliff’s performance in previous periods, and therefore should
not be unduly relied upon.
• Reserves life index is calculated by dividing reserves estimated by Birchcliff’s independent qualified reserves evaluators
at December 31, 2018 by 77,000 boe/d, which production rate represents the mid-point of Birchcliff’s annual average
production guidance range for 2019. Reserves life index may be used as a measure of a company’s sustainability.
• Recycle ratios are calculated by dividing the average operating netback per boe or adjusted funds flow netback per boe,
as the case may be, by F&D costs and FD&A costs, as the case may be. Recycle ratios may be used as a measure of a
company’s profitability.
• Reserves replacement is calculated by dividing proved developed producing reserves, proved reserves or proved plus
probable reserves additions, as the case may be, before production by total production in the applicable period. Reserves
replacement ratios have been presented both including and excluding the effects of acquisitions and dispositions. Reserves
replacement may be used as a measure of a company’s sustainability and its ability to replace its proved developed
producing reserves, proved reserves or proved plus probable reserves, as the case may be.
• With respect to F&D and FD&A costs disclosed in this Annual Report:
o F&D costs both including and excluding FDC have been presented herein. F&D costs for each reserves category in
a particular period are calculated by taking the sum of: (i) exploration and development costs incurred in the period;
and (ii) where FDC has been included, the change during the period in FDC for the reserves category; divided by the
additions to the reserves category before production during the period. F&D costs exclude the effects of acquisitions
and dispositions. FD&A costs are calculated in the same manner as F&D costs but include the effects of acquisitions
and dispositions.
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2018 Annual Report o
In calculating the amounts of F&D and FD&A costs for a year, the changes during the year in estimated reserves and
estimated FDC are based upon the evaluations of Birchcliff’s reserves prepared by its independent qualified reserves
evaluators, effective December 31 of such year.
o The aggregate of the exploration and development costs incurred in the most recent financial year and any change
during that year in estimated FDC generally will not reflect total F&D costs related to reserves additions for that year.
o F&D and FD&A costs may be used as a measure of a company’s efficiency with respect to finding and developing
its reserves.
•
For information regarding netbacks, please see “Non-GAAP Measures”.
DRILLING LOCATIONS
This Annual Report discloses net existing horizontal wells and potential net future horizontal drilling locations in four
categories: (i) proved locations; (ii) proved plus probable locations; (iii) unbooked locations; and (iv) an aggregate total of (ii) and
(iii). Of the 6,746.4 net existing horizontal wells and potential net future horizontal drilling locations identified herein, 888.8
are proved locations, 1,121.8 are proved plus probable locations and 5,624.6 are unbooked locations. Proved locations and
probable locations are proposed drilling locations identified in the 2018 Consolidated Reserves Report that have proved
and/or probable reserves, as applicable, attributed to them in the 2018 Consolidated Reserves Report. Unbooked locations
are internal estimates based on Birchcliff’s prospective acreage and an assumption as to the number of wells that can be
drilled per section based on industry practice and internal technical analysis review. Unbooked locations have been identified
by management as an estimate of Birchcliff’s multi-year drilling activities based on evaluation of applicable geologic, seismic,
engineering, production and reserves information. Unbooked locations do not have proved or probable reserves attributed to
them in the 2018 Consolidated Reserves Report.
Birchcliff’s ability to drill and develop these locations and the drilling locations on which Birchcliff actually drills wells depends
on a number of uncertainties and factors, including, but not limited to, the availability of capital, equipment and personnel,
oil and natural gas prices, costs, inclement weather, seasonal restrictions, drilling results, additional geological, geophysical
and reservoir information that is obtained, production rate recovery, gathering system and transportation constraints, the
net price received for commodities produced, regulatory approvals and regulatory changes. As a result of these uncertainties,
there can be no assurance that the potential future drilling locations that Birchcliff has identified will ever be drilled and, if
drilled, that such locations will result in additional oil, NGLs and natural gas production and, in the case of unbooked locations,
additional reserves. As such, Birchcliff’s actual drilling activities may differ materially from those presently identified, which
could adversely affect Birchcliff’s business. While certain of the unbooked drilling locations have been de-risked by drilling
existing wells in relatively close proximity to such unbooked drilling locations, some of the other unbooked drilling locations
are farther away from existing wells, where management has less information about the characteristics of the reservoir and
there is therefore more uncertainty whether wells will be drilled in such locations and, if drilled, there is more uncertainty
that such wells will result in additional proved or probable reserves, resources or production.
CAPITAL EXPENDITURES
Unless otherwise stated, references in this Annual Report to: (i) “F&D capital” denotes capital for land, seismic, workovers, drilling
and completions and well equipment and facilities; and (ii) “total capital expenditures” denotes F&D capital plus acquisitions, less
any dispositions, plus administrative assets. Birchcliff previously referred to total capital expenditures as “net capital expenditures”
or “capital expenditures, net”.
PAYMENT OF DIVIDENDS
The declaration and payment of dividends and the amount of such dividends is subject to the discretion of Birchcliff’s Board
of Directors and may vary depending on a variety of factors and conditions existing from time to time, including fluctuations
in commodity prices, the financial condition of Birchcliff, production levels, results of operations, capital expenditure and
debt service requirements, contractual restrictions, hedging activities or programs, available investment opportunities,
Birchcliff’s business plan, strategies and objectives, the satisfaction of the solvency and liquidity tests imposed by the Business
Corporations Act (Alberta) for the declaration and payment of dividends and other factors that Birchcliff’s Board of Directors
may deem relevant. The payment of cash dividends to common shareholders in the future is not assured or guaranteed and
dividends may be reduced or suspended. Birchcliff’s dividend policy will be periodically reviewed by its Board of Directors and
no assurance or guarantee can be given that Birchcliff will maintain the dividend policy in its current form.
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2018 Annual Report FORWARD-LOOKING STATEMENTS
Certain statements contained in this Annual Report constitute forward-looking statements and forward-looking information
(collectively referred to as “forward-looking statements”) within the meaning of applicable Canadian securities laws. The
forward-looking statements contained in this Annual Report relate to future events or Birchcliff’s future plans, operations
or performance and are based on Birchcliff’s current expectations, estimates, projections, beliefs and assumptions. Such
forward-looking statements have been made by Birchcliff in light of the information available to it at the time the statements
were made and reflect its experience and perception of historical trends. All statements and information other than historical
fact may be forward-looking statements. Such forward-looking statements are often, but not always, identified by the use of
words such as “seek”, “plan”, “expect”, “project”, “intend”, “believe”, “anticipate”, “estimate”, “forecast”, “potential”, “proposed”,
“predict”, “budget”, “continue”, “targeting”, “may”, “will”, “could”, “might”, “should” and other similar words and expressions.
By their nature, forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause
actual results or events to differ materially from those anticipated in such forward-looking statements. Accordingly, readers are
cautioned not to place undue reliance on such forward-looking statements. Although Birchcliff believes that the expectations
reflected in the forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be
correct and Birchcliff makes no representation that actual results achieved will be the same in whole or in part as those set out
in the forward-looking statements.
In particular, this Annual Report contains forward-looking statements relating to the following: Birchcliff’s plans and other
aspects of its anticipated future financial performance, operations, focus, objectives, strategies, opportunities, priorities and
goals (including that Birchcliff’s strategy is to continue to develop and expand its Montney/Doig Resource Play in the Peace River
Arch, while maintaining low capital costs and operating costs); the performance and other characteristics of Birchcliff’s oil and
natural gas properties and expected results from its assets (including: that the Montney/Doig Resource Play provides Birchcliff
with an extensive inventory of repeatable, low-cost drilling opportunities targeting natural gas, oil and NGLs; and statements
regarding the potential or prospectivity of Birchcliff’s properties); statements that Birchcliff has the ability to grow when
commodity prices warrant doing so while also having the ability to maintain production in low commodity price environments;
statements regarding Birchcliff’s ability to control and expand its production and further reduce its operating costs; statements
that Birchcliff’s operatorship, land position and infrastructure ownership gives it a competitive advantage and supports
its low F&D costs and low operating cost structure, which helps Birchcliff to maximize its funds flow; Birchcliff’s market
diversification and hedging activities; Birchcliff’s transportation arrangements (including that an additional tranche of service
will become available on TCPL’s Canadian Mainline later in 2019 and the anticipated aggregate level of firm service on TCPL’s
Canadian Mainline that will be available on November 1, 2019); Birchcliff’s expectation that during 2019, 65% of its natural gas
production will be effectively sold at prices that are not based on AECO; statements that based on its 2019 budget, Birchcliff
expects to generate approximately $126 MM of free funds flow in 2019; statements that during 2019 Birchcliff’s focus will
continue to be on protecting its balance sheet, improving its already-low cost structure and paying a sustainable quarterly
dividend to its shareholders, while it maintains a prudent pace of development and continues to position Birchcliff
for future growth; Birchcliff’s guidance regarding its 2019 Capital Program and its proposed exploration and development
activities and the timing thereof (including: the number and types of wells to be drilled, completed and brought on production;
that the program targets an annual average production rate of 76,000 to 78,000 boe/d; estimates of capital expenditures and
capital allocation; the focus of, the objectives of and the anticipated results from the program; the financial and operational
flexibility of the 2019 Capital Program and that Birchcliff has the ability to accelerate or decelerate capital expenditures
depending on commodity prices and economic conditions; and the information set forth under the headings “Pouce Coupe
Team– 2019 Outlook” and “Gordondale Team – 2019 Outlook”); Birchcliff’s expectation that its 2019 capital expenditures will
be significantly less than its adjusted funds flow during 2019, which will help it to protect its balance sheet; the information
set forth under the heading “2019 Key Objectives”; estimates of potential future drilling locations; statements that Birchcliff
will continue to pilot technologies to achieve better well results; statements regarding the planned liquids-handling facility at
the Pouce Coupe Gas Plant (including: the capacity of the facility; the anticipated timing for the completion of the facility; and
that the facility will give Birchcliff the ability to grow its condensate production to 10,000 bbls/d in Pouce Coupe); statements
regarding dividends (including the sustainability of dividends and the timing of payment of dividends); the information under
the heading “2018 Year-End Reserves” and elsewhere as it relates to Birchcliff’s reserves (including: estimates of reserves and
the net present values of future net revenue associated with Birchcliff’s reserves; price forecasts; FDC; reserves life index;
forecast facility expansions; and Birchcliff's expectation that the Pouce Coupe Gas Plant will generate EPCs in respect to the
2018 financial year). In addition, forward-looking statements in this Annual Report include the forward-looking statements
identified in the MD&A under the heading "Advisories – Forward-Looking Statements". Statements relating to reserves are
forward-looking as they involves the implied assessment, based on certain estimates and assumptions, that the reserves
exist in the quantities predicted or estimated and that the reserves can profitably be produced in the future.
See “Presentation of Oil and Gas Reserves”.
136
2018 Annual Report With respect to the forward-looking statements contained in this Annual Report, assumptions have been made regarding,
among other things: prevailing and future commodity prices and differentials, currency exchange rates, interest rates,
inflation rates, royalty rates and tax rates; the state of the economy, financial markets and the exploration, development and
production business; the political environment in which Birchcliff operates; the regulatory framework regarding royalties,
taxes and environmental laws; the Corporation’s ability to comply with existing and future environmental, climate change and
other laws; future cash flow, debt and dividend levels; future operating, transportation, marketing, G&A and other expenses;
Birchcliff’s ability to access capital and obtain financing on acceptable terms; the timing and amount of capital expenditures
and the sources of funding for capital expenditures and other activities; the sufficiency of budgeted capital expenditures
to carry out planned operations; the successful and timely implementation of capital projects; results of future operations;
Birchcliff’s ability to continue to develop its assets and obtain the anticipated benefits therefrom; the performance of
existing and future wells, well production rates and well decline rates; success rates for future drilling; reserves and resource
volumes and Birchcliff’s ability to replace and expand reserves through acquisition, development or exploration; the impact
of competition on Birchcliff; the availability of, demand for and cost of labour, services and materials; the ability to obtain any
necessary regulatory or other approvals in a timely manner; the satisfaction by third parties of their obligations to Birchcliff;
the ability of Birchcliff to secure adequate processing and transportation for its products; Birchcliff’s ability to market oil and
gas; the availability of hedges on terms acceptable to Birchcliff; and natural gas market exposure. In addition to the foregoing
assumptions, Birchcliff has made the following assumptions with respect to certain forward-looking statements contained in
this Annual Report:
• Birchcliff’s 2019 guidance assumes the following commodity prices during 2019: an average WTI price of
US$56.00/bbl; an average WTI-MSW differential of $10.00/bbl; an average AECO price of $1.65/GJ; an average Dawn
price of $3.40/GJ; an average NYMEX HH price of US$3.00/MMBtu; and an exchange rate (CDN$ to US$1) of 1.32.
• With respect to estimates of 2019 capital expenditures, statements that 2019 F&D capital expenditures are expected
to be significantly less than adjusted funds flow and Birchcliff’s spending plans for 2019, such estimates, statements
and plans are based on the following:
o Estimates of capital expenditures and any allocation thereof assume that the 2019 Capital Program will be carried
out as currently contemplated.
o Statements that Birchcliff’s total F&D capital expenditures are expected to be significantly less than adjusted
funds flow assume that: the 2019 Capital Program will be carried out as currently contemplated; and the
production targets, commodity mix, natural gas market exposure and commodity price assumptions set forth
under the heading “2019 Outlook” in the MD&A are met.
o Birchcliff makes acquisitions and dispositions in the ordinary course of business. Any acquisitions and dispositions
completed could have an impact on Birchcliff’s capital expenditures, production, adjusted funds flow, free funds
flow, costs and total debt, which impact could be material.
o The amount and allocation of capital expenditures for exploration and development activities by area and
the number and types of wells to be drilled is dependent upon results achieved and is subject to review and
modification by management on an ongoing basis throughout the year. Actual spending may vary due to a variety
of factors, including commodity prices, economic conditions, results of operations and costs of labour, services
and materials. Birchcliff will monitor economic conditions and commodity prices and, where deemed prudent,
will adjust its capital programs to respond to changes in commodity prices and other material changes in the
assumptions underlying such programs.
• With respect to Birchcliff’s production guidance for 2019, such guidance assumes that: the 2019 Capital Program
will be carried out as currently contemplated; no unexpected outages occur in the infrastructure that Birchcliff relies
on to produce its wells and that any transportation service curtailments or unplanned outages that occur will be
short in duration or otherwise insignificant; the construction of new infrastructure meets timing and operational
expectations; existing wells continue to meet production expectations; and future wells scheduled to come on
production meet timing, production and capital expenditure expectations. Birchcliff’s production guidance may
be affected by acquisition and disposition activity and acquisitions and dispositions could occur that may impact
expected production.
• With respect to Birchcliff’s estimate of free funds flow for 2019, such estimate assumes that: the level of capital
spending for 2019 will be achieved; and the production targets, commodity mix, natural gas market exposure and
commodity price assumptions set forth under the heading "2019 Outlook" in the MD&A are met.
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2018 Annual Report • With respect to statements of future wells to be drilled and brought on production and estimates of potential future
drilling locations and opportunities, the key assumptions are: the continuing validity of the geological and other technical
interpretations performed by Birchcliff’s technical staff, which indicate that commercially economic volumes can be
recovered from Birchcliff’s lands as a result of drilling future wells; and that commodity prices and general economic
conditions will warrant proceeding with the drilling of such wells.
• With respect to statements regarding the future potential and prospectivity of properties and assets, such statements
assume: the continuing validity of the geological and other technical interpretations determined by Birchcliff’s technical
staff with respect to such properties; and that, over the long-term, commodity prices and general economic conditions
will warrant proceeding with the exploration and development of such properties.
• With respect to estimates of reserves volumes and the net present values of future net revenue associated with
Birchcliff’s reserves, the key assumption is the validity of the data used by Deloitte and McDaniel in their independent
reserves evaluations.
Birchcliff’s actual results, performance or achievements could differ materially from those anticipated in the forward-looking
statements as a result of both known and unknown risks and uncertainties including, but not limited to: general economic, market
and business conditions which will, among other things, impact the demand for and market prices of Birchcliff’s products and
Birchcliff’s access to capital; volatility of crude oil and natural gas prices; fluctuations in currency and interest rates; stock market
volatility; loss of market demand; an inability to access sufficient capital from internal and external sources; fluctuations in the
costs of borrowing; operational risks and liabilities inherent in oil and natural gas operations; the occurrence of unexpected events
such as fires, equipment failures and other similar events affecting Birchcliff or other parties whose operations or assets directly
or indirectly affect Birchcliff; uncertainty that development activities in connection with its assets will be economical;
uncertainties associated with estimating oil and natural gas reserves and resources; the accuracy of oil and natural gas reserves
estimates and estimated production levels; geological, technical, drilling, construction and processing problems; uncertainty of
geological and technical data; horizontal drilling and completions techniques and the failure of drilling results to meet expectations
for reserves or production; uncertainties related to Birchcliff’s future potential drilling locations; potential delays or changes in
plans with respect to exploration or development projects or capital expenditures, including delays in the completion of gas plants
and other facilities; the accuracy of cost estimates and variances in Birchcliff’s actual costs and economic returns from those
anticipated; incorrect assessments of the value of acquisitions and exploration and development programs; changes in tax
laws, Crown royalty rates, environmental laws, carbon tax regimes, incentive programs and other regulations that affect the oil
and natural gas industry and other actions by government authorities; an inability of the Corporation to comply with existing
and future environmental, climate change and other laws; the cost of compliance with current and future environmental laws;
political uncertainty and uncertainty associated with government policy changes; uncertainties and risks associated with pipeline
restrictions and outages to third-party infrastructure that could cause disruptions to production; the lack of available pipeline
capacity and an inability to secure adequate processing and transportation for Birchcliff’s products; the inability to satisfy
obligations under Birchcliff’s firm marketing and transportation arrangements or other agreements; shortages in equipment and
skilled personnel; the absence or loss of key employees; competition for, among other things, capital, acquisitions of reserves,
undeveloped lands, equipment and skilled personnel; management of Birchcliff’s growth; environmental risks, claims and
liabilities; uncertainties associated with the outcome of litigation or other proceedings involving Birchcliff; unforeseen title defects;
uncertainties associated with credit facilities and counterparty credit risk; non-performance or default by counterparties; risks
associated with Birchcliff’s risk management program and the risk that hedges on terms acceptable to Birchcliff may not be
available; risks associated with the declaration and payment of dividends, including the discretion of Birchcliff’s Board of Directors
to declare dividends and change the Corporation’s dividend policy; the failure to obtain any required approvals in a timely manner
or at all; the failure to realize the anticipated benefits of acquisitions and dispositions and the risk of unforeseen difficulties in
integrating acquired assets into Birchcliff’s operations; negative public perception of the oil and natural gas industry, including
transportation, hydraulic fracturing and fossil fuels; the Corporation’s reliance on hydraulic fracturing; the availability of insurance
and the risk that certain losses may not be insured; and breaches or failure of information systems and security (including risks
associated with cyber-attacks).
Readers are cautioned that the foregoing lists of factors are not exhaustive. Additional information on these and other risk factors
that could affect results of operations, financial performance or financial results are included in Birchcliff’s most recent Annual
Information Form and in other reports filed with Canadian securities regulatory authorities.
This Annual Report contains information that may constitute future-orientated financial information or financial outlook
information (collectively, “FOFI”) about Birchcliff’s prospective results of operations including, without limitation, adjusted funds
flow and free funds flow, all of which is subject to the same assumptions, risk factors, limitations and qualifications as set forth
above. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable
138
2018 Annual Report at the time of preparation, may prove to be imprecise or inaccurate and, as such, undue reliance should not be placed on FOFI.
Birchcliff’s actual results, performance and achievements could differ materially from those expressed in, or implied by, the FOFI.
Birchcliff has included the FOFI in order to provide readers with a more complete perspective on Birchcliff’s future operations
and Birchcliff’s current expectations relating to its future performance. Such information may not be appropriate for other
purposes and readers are cautioned that any FOFI contained herein should not be used for purposes other than those for which
it has been disclosed herein. FOFI contained herein was made as of the date of this Annual Report. Unless required by applicable
laws, Birchcliff does not undertake any obligation to publicly update or revise any FOFI statements, whether as a result of new
information, future events or otherwise.
Management has included the above summary of assumptions and risks related to forward-looking statements provided in
this Annual Report in order to provide readers with a more complete perspective on Birchcliff’s future operations. Readers are
cautioned that this information may not be appropriate for other purposes.
The forward-looking statements contained in this Annual Report are expressly qualified by the foregoing cautionary statements.
The forward-looking statements contained herein are made as of the date of this Annual Report. Unless required by applicable
laws, Birchcliff does not undertake any obligation to publicly update or revise any forward-looking statements, whether as a result
of new information, future events or otherwise.
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2018 Annual Report This page is left blank intentionally.
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2018 Annual Report CORPORATE INFORMATION
OFFICERS
MANAGEMENT CONT’D
RESERVES EVALUATORS
George Fukushima
Manager of Engineering
Andrew Fulford
Surface Land Manager
Paul Messer
Manager of IT
Tyler Murray
Mineral Land Manager
Bruce Palmer
Manager of Geology
Brian Ritchie
Asset Manager – Gordondale
Michelle Rodgerson
Manager, Human Resources &
Corporate Services
Jeff Rogers
Facilities Manager
Randy Rousson
Drilling & Completions Manager
Victor Sandhawalia
Manager of Finance
Ryan Sloan
Health, Safety & Environment Manager
Duane Thompson
Production Manager
Hue Tran
Business Development Manager
Theo van der Werken
Asset Manager – Pouce Coupe
AUDITORS
KPMG LLP,
Chartered Professional Accountants
Calgary, Alberta
A. Jeffery Tonken
President & Chief Executive Officer
Myles R. Bosman
Vice-President, Exploration & Chief
Operating Officer
Chris A. Carlsen
Vice-President, Engineering
Bruno P. Geremia
Vice-President & Chief Financial
Officer
David M. Humphreys
Vice-President, Operations
DIRECTORS
A. Jeffery Tonken (Chairman)
President & Chief Executive Officer
Calgary, Alberta
Dennis A. Dawson
Lead Independent Director
Calgary, Alberta
Debra A. Gerlach
Independent Director
Calgary, Alberta
Stacey E. McDonald
Independent Director
Calgary, Alberta
James W. Surbey
Non-Independent Director
Calgary, Alberta
MANAGEMENT
Gates Aurigemma
Manager, General Accounting
Robyn Bourgeois
General Counsel & Corporate
Secretary
Jesse Doenz
Controller & Investor Relations
Manager
birchcliffenergy.com
Deloitte LLP
Calgary, Alberta
McDaniel & Associates Consultants Ltd.
Calgary, Alberta
BANKERS
The Bank of Nova Scotia
HSBC Bank Canada
National Bank of Canada
Canadian Imperial Bank of Commerce
Bank of Montreal
The Toronto-Dominion Bank
ATB Financial
Business Development Bank of Canada
Wells Fargo Bank, N.A.,
Canadian Branch
United Overseas Bank Limited
ICICI Bank Canada
HEAD OFFICE
Suite 1000, 600 – 3rd Avenue S.W.
Calgary, Alberta T2P 0G5
Phone: 403-261-6401
403-261-6424
Fax:
SPIRIT RIVER OFFICE
5604 – 49th Avenue
Spirit River, Alberta T0H 3G0
Phone: 780-864-4624
Fax:
780-864-4628
Email: info@birchcliffenergy.com
TRANSFER AGENT
Computershare Trust Company
of Canada
Calgary, Alberta and
Toronto, Ontario
TSX: BIR, BIR.PR.A, BIR.PR.C
2018 Annual Report 142
THANK YOU TEAM BIRCHCLIFF
Jeffrey Akeroyd, Bradley Alexander, Karen Allen, Diana Almeida, Camille Ashton, Gates Aurigemma, Valerie Babkov, Angela Belbeck,
Tyrus Bender, Daniel Blattler, Calvin Bohdan, Angela Boire, Darryl Bolch, Deborah Borthwick, Myles Bosman, Jeff Boswell,
Robyn Bourgeois, David Boyle, Anthony Bozzi, Kenneth Bramhill, Wayne Brown, Madison Burns, Dave Campbell, Matthew Campbell,
Chris Carlsen, Alexandra Carlson, Caitlin Carrigy, Ann Ceccanese, Scott Cedergren, Matthew Chorney, Benjamin Christenson,
Wendy Clay, Dallas Cline, Jacob Cloutier, Kalen Conrad, Laura Conroy, Michael Cordingley, Loren Damer, Dennis Dawson,
Lara Cristina De Paula, Mark Dilworth, Jesse Doenz, Joseph Doenz, Kelly Dolen, Richard Dunn, Terrance Dyck, Darryl Easter,
Emily Ebbels, John Ennis, Timothy Etcheverry, Lindsay Fast, Laura Ferguson, Mikaela Fero, Grant Friesen, Marshall Fritz, Colin Fry,
George Fukushima, Andrew Fulford, Carrie Fyfe, Alexandra Gatza, Bruno Geremia, Melina Geremia, Debra Gerlach, Chad Goddard,
David Graham, Lee Grant, Hannah Grigore, Ryan Gugyelka, Rylan Gulka, Tania Haberlack-Dolan, Mike Hale, Samuel Hampton,
Theresa-Marie Hannouche, Trevor Harley, Wanda Hiebert, Lorna Hildebrand, Warren Hingley, Paul Hirsekorn, Leah Janet Hogan,
Jasen Holmstrom, Lory-Ann Hoppe, Daryl Hudak, Dave Humphreys, Derek Jamieson, Anna Johnson, David Johnson, Lorn Johnson,
Dustin Kelm, Phyllis Kinzner, Diane Knoblauch, Jesiah Kurjata, Danny Kutrowski, Anji Lawrence, Katherine Lazaruk, Calvin Leithead,
Kristen Lewicki, Ehsan Liaqat, Ryan Linsley, Scott Lundquist, Thomas Lundquist, Joseph Lyste, John Macgillivray, Dallas Maclean,
Darcy Macleod, Mary Macneill, Curtis Mah, Maggie Malapad, Arundeep Mann, Kevin Matiasz, John Matijevich, Drystan Mazur,
Stacey Mcdonald, Angela Mcgonigal, Marc Mcintosh, Ryan Mcintosh, Jerilyn Mcpherson, Richard Melling, Paul Messer,
Alfred Michetti, Derek Michetti, Emelyia Moghaddami, Thomas Moult, Steve Mueller, Mckenzie Murdoch, Tyler Murray, Kody Naka,
Sarah Nance, Michael Ng, Tam Nguyen, Matteo Niccoli, Christopher Olson, Tammy Page, Philomena Paisley, Bruce Palmer,
Dean Paterson, Chase Peirce, Jesse Peterson, Paul Picco, Allan Pickel, Landon Poffenroth, Austin Power, Glenn Power, Terrence Power,
Shoni Proctor, Evan Pugh, Kathryn Ramage, Brian Ritchie, Michelle Rodgerson, Blaine Rogers, Jeff Rogers, Sherri Rosia,
Jared Rousson, Randy Rousson, Todd Sajtovich, Lee Sallenbach, Victor Sandhawalia, Wade Schultz, Sadeq Shahamat, Daniel Sharp,
Amy Short, Ryan Sloan, Kiran Somanchi, Tanner St. Julian, Hilary Steinbach, Darby Stolk, Lindsay Sturrock, Tracey Suchlandt,
Jim Surbey, Tyson Suderman, Ryan Swanson, Conal Tackney, Duane Thompson, Jeff Tonken, Gillian Topping, Terry Tracey, Hue Tran,
Joshua Uy, Theo Van Der Werken, Kara Vance, Kris Veach, Greg Vreim, Linda Wang, Michael Warrick, Shelby Watson, Matthew Weiss,
David Wetta, Philip Wu, John Yeo, Kent Zahara, Michael Zimmerman
143
2018 Annual Report 2 0 1 8 A N N U A L R E P O R T
BIRCHCLIFF ENERGY LTD.
Suite 1000, 600 3rd Avenue S.W.
Calgary, Alberta T2P 0G5
Phone: 403-261-6401
birchcliffenergy.com