CORPORATE INFORMATION
OFFICERS
MANAGEMENT TEAM (con’t)
BANKERS
A. Jeffery Tonken
President & Chief Executive Officer
Robert (Bob) Grisack
Land Manager
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
James W. Surbey
Vice-President, Corporate Development
DIRECTORS
Larry A. Shaw (Chairman)
Calgary, Alberta
Kenneth N. Cullen
Calgary, Alberta
Dennis A. Dawson
Calgary, Alberta
Rebecca Morley
Calgary, Alberta
A. Jeffery Tonken
President & Chief Executive Officer
Calgary, Alberta
MANAGEMENT TEAM
Gates Aurigemma
Manager, General Accounting
Perry Billard
Asset Manager – Worsley
Robyn Bourgeois
General Counsel
Jesse Doenz
Controller & Investor Relations Manager
George Fukushima
Manager of Engineering
Andrew Fulford
Surface Land Manager
BirchcliffEnergy.com
Paul Messer
Manager of IT
Tyler Murray
Land Manager
Bruce Palmer
Manager of Geology
Bill Partridge
Engineering Lead
Brian Ritchie
Asset Manager – Gordondale
Michelle Rodgerson
Office Manager
Jeff Rogers
Facilities Manager
Randy Rousson
Drilling & Completions Manager
Vic Sandhawalia
Manager of Financial Accounting,
Taxation & Insurance
Ryan Sloan
Health, Safety & Environment Manager
Hue Tran
Joint Venture & Marketing Manager
Theo van der Werken
Asset Manager - Pouce Coupe
SOLICITORS
Borden Ladner Gervais LLP
Calgary, Alberta
AUDITORS
KPMG LLP,
Chartered Professional Accountants
Calgary, Alberta
RESERVES EVALUATORS
Deloitte LLP
Calgary, Alberta
McDaniel & Associates Consultants Ltd.
Calgary, Alberta
The Bank of Nova Scotia
HSBC Bank Canada
National Bank of Canada
Canadian Imperial Bank of Commerce
Bank of Montreal
The Toronto-Dominion Bank
Alberta Treasury Branches
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
ANNUAL & SPECIAL MEETING
The Annual & Special Meeting of
Shareholders will be held at
3:00 p.m. on Thursday, May 11, 2017,
in the McMurray Room at the Calgary
Petroleum Club, 319 - 5th Avenue S.W.,
Calgary, Alberta
2016 Annual Report 136
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GAINING GROUND, FORGING A STRONG FUTURE.
BIRCHCLIFF ENERGY LTD.
Suite 1000, 600 – 3rd Avenue S.W.
Calgary, Alberta T2P 0G5
Phone: 403-261-6401
BirchcliffEnergy.com
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F I N A N C I A L A N D O P E R A T I O N A L H I G H L I G H T S
Three months ended
December 31,
Twelve months ended
December 31,
2016
2015
2016
2015
4,656
289,587
7,830
60,750
60.75
3.31
29.50
24.23
24.24
(1.82)
(4.54)
(2.42)
15.46
(1.19)
(1.40)
(0.02)
12.85
(0.12)
(7.73)
(0.15)
(0.06)
0.17
(1.72)
(0.16)
(0.92)
2.16
(0.18)
1.98
135,457
71,806
0.27
0.27
12,085
11,085
0.04
0.04
264,042
279,881
263,396
268,974
1,000
875
62,482
572,517
27,495
600,012
3,530
211,127
1,727
40,445
49.36
2.67
47.98
20.28
20.28
(0.94)
(4.16)
(2.31)
12.87
(2.01)
(1.80)
-
9.06
(0.21)
(9.66)
(0.15)
(0.06)
1.80
-
(0.24)
(3.05)
(2.51)
(0.26)
(2.77)
75,476
33,697
0.22
0.22
(9,322)
(10,322)
(0.07)
(0.07)
152,308
167,817
152,308
153,627
1,000
875
33,533
622,074
21,538
643,612
3,729
247,373
4,279
49,236
51.40
2.41
31.23
18.73
18.73
(1.16)
(4.18)
(2.38)
11.01
(1.19)
(1.68)
0.04
8.18
(0.14)
(8.29)
(0.14)
(0.06)
(0.53)
(0.52)
(0.19)
0.34
(1.35)
(0.22)
(1.57)
337,586
147,443
0.74
0.73
(24,335)
(28,335)
(0.14)
(0.14)
264,042
279,881
199,581
202,686
4,000
3,500
762,030
572,517
27,495
600,012
3,707
201,418
1,673
38,950
53.68
2.90
50.76
22.31
22.32
(0.81)
(4.54)
(2.45)
14.52
(1.61)
(1.60)
-
11.31
(0.23)
(10.35)
(0.16)
(0.06)
0.52
-
(0.25)
(1.64)
(0.86)
(0.28)
(1.14)
317,304
160,756
1.06
1.04
(12,160)
(16,160)
(0.11)
(0.11)
152,308
167,817
152,286
154,078
4,000
3,500
247,207
622,074
21,538
643,612
OPERATING
Average daily production
Light oil – (bbls)
Natural gas – (Mcf)
NGLs – (bbls)
Total – (per boe) (6:1)
Average sales price ($ CDN)(1)
Light oil – (per bbl)
Natural gas – (Mcf)
NGLs – (per bbl)
Total – (per boe) (6:1)
NETBACK AND COST ($ per boe at 6:1)
Petroleum and natural gas revenue(1)
Royalty expense
Operating expense
Transportation and marketing expense
Netback
General & administrative expense, net
Interest expense
Realized gain (loss) on financial instruments
Funds flow netback
Stock-based compensation expense, net
Depletion and depreciation expense
Accretion expense
Amortization of deferred financing fees
Gain (loss)on sale of assets
Unrealized loss on financial instruments
Dividends on Series C preferred shares
Income tax recovery (expense)
Net income (loss)
Dividends on Series A preferred shares
Net income (loss) to common shareholders
FINANCIAL
Petroleum and natural gas revenue ($000s)(1)
Funds flow from operations ($000s)
Per common share – basic ($)
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 Series A preferred shares ($000s)
Dividends on Series C preferred shares ($000s)
Capital expenditures, net ($000s)
Revolving term credit facilites ($000s)
Adj. working capital deficit ($000s)
Total debt ($000s)
(1) Excludes the effect of hedges using financial instruments.
BCE-5313_GateFold_Cover_Mar22_PRINTER_CLIENT_REVISIONS.indd 2
T H A N K Y O U
TEAM BIRCHCLIFF
Jeffrey Akeroyd
Bradley Alexander
Karen Allen
Laura Armstrong
Camille Ashton
Rainer Augsten
Gates Aurigemma
Bryce Baloun
Alan Basnett
Angela Belbeck
Charmaine Belley
Tyrus Bender
Tim Berg
Perry Billard
Daniel Blattler
Angela Boire
Deborah Borthwick
Myles Bosman
Jeff Boswell
Robyn Bourgeois
David Boyle
Wayne Brown
James Burke
Madison Burns
Dave Campbell
Chris Carlsen
Alex Carlson
Caitlin Carrigy
Ann Ceccanese
Robert Charchuk
Matthew Chorney
Dave Christensen
Benjamin Christenson
Bob Clark
Wendy Clay
Dallas Cline
Laura Conroy
Mike Cordingley
Kenneth Cullen
Krystal Dafoe
Chelsea Daku
Dennis Dawson
Claire Denley
Allan Dixon
Jesse Doenz
Joe Doenz
Keifer Dolen
Kelly Dolen
Terrance Dyck
Emily Ebbels
Tim Etcheverry
Laura Ferguson
Jaryn Flower-Phillips
Grant Friesen
Marshall Fritz
George Fukushima
Andy Fulford
Carrie Fyfe
Alexandra Gatza
Bruno Geremia
Melina Geremia
Melodie Gilker
Chad Goddard
Jolanda Goertzen
David Graham
Lee Grant
Hannah Grigore
Bob Grisack
Tania Haberlack-Dolan
Mike Hale
Samuel Hampton
Theresa Hannouche
Trevor Harley
Richard Harris
Wanda Hiebert
Lorna Hildebrand
Warren Hingley
Paul Hirsekorn
Janet Hogan
Jasen Holmstrom
Daryl Hudak
Dave Humphreys
Derek Jamieson
Anna Johnson
David Johnson
Stacy Johnson
Julie Johnson
Dustin Kelm
Ryan Kennedy
Gregory Kilgour
Phyllis Kinzner
Diane Knoblauch
Heather Kwiatkowski
Dani Laird
Calvin Leithead
Kristen Lewicki
Michael Lillejord
Scott Lundquis
Thomas Lundquist
Joe Lyste
Scott MacDermott
John MacGillivray
Dallas MacLean
Darcy MacLeod
Mary MacNeill
Curtis Mah
Janice Malainey
Maggie Malapad
Valerie Martin
Kevin Matiasz
John Matijevich
Jeff McAndrews
Deb McFee
Angie McGonigal
Ryan McIntosh
Marc McIntosh
Darin McLarty
Jerilyn McLeod
Dani McPhee
Richard Melling
John (Bill) Melnyk
Paul Messer
Melissa Meyers
Alfred Michetti
Emelyia Moghaddami
Tyler Montpellier
Ronald Morgan
Rebecca Morley
Stephen Morton
Shaun Moskalyk
Steve Mueller
Daniel Mullin
McKenzie Murdoch
Ed Murphy
Tyler Murray
Kody Naka
Sarah Nance
Matteo Niccoli
Michael Ng
Tam Nguyen
Marcel Njongwe
Tyler Ollenberger
Christopher Olson
Philomena Paisley
Bruce Palmer
Bill Partridge
Dean Paterson
Brenda Pearson
Paul Picco
Allan Pickel
Landon Poffenroth
Andrei Popescu
Lindsay Postma
Glenn Power
Shoni Proctor
Dale Richardson
Brian Ritchie
Michelle Rodgerson
Jeff Rogers
Sherri Rosia
Randy Rousson
Jared Rousson
Todd Sajtovich
Lee Sallenbach
Victor Sandhawalia
Wade Schultz
Sadeq Shahamat
Dan Sharp
Larry Shaw
Amy Short
Nicholas Sizer
Ryan Sloan
Dwayne Spelay
Ben Stevenson
Darby Stolk
Lindsay Sturrock
Tracey Suchlandt
Jim Surbey
Jeff Tonken
Gillian Topping
Hue Tran
Tammy Tran
Rebecca Van De Riet
Theo van der Werken
Kara Vance
Kris Veach
Greg Vreim
Linda Wang
Matt Weiss
David Wetta
Jonathan White
Chris Wurz
John Yeo
Deirdre Yuzwa
2016 Annual Report 135
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Overview
Message to Shareholders
Executive Team
Management Team
Our History
Five Year Plan
2016 Accomplishments & 2017 Key Objectives
Peace River Arch
Resource Plays
Montney/Doig Resource Play
Charlie Lake Light Oil Resource Play
2016 Year-End Reserves
Responsibility
Management’s Discussion & Analysis
Financial Statements
Notes to the Financial Statements
Glossary
Presentation of Oil and Gas Reserves
Non-GAAP Measures
Advisories
Team Birchcliff
Corporate Information
02
04
06
08
10
12
14
16
18
20
28
30
40
43
93
99
124
126
129
130
135
136
This Annual Report contains forward-looking information within the meaning of applicable securities laws. Such forward-looking information is based upon certain expectations and assumptions and actual
results may differ materially from those expressed or implied by such forward-looking information. For further information regarding the forward-looking information contained herein, see “Advisories – Forward-
Looking Information” in this Annual Report. In addition, this Annual Report contains references to “funds flow”, “funds flow from operations”, “funds flow per common share”, “netback”, “operating netback”, “funds
flow netback”, “total cash costs” and “total debt”, which do not have standardized meanings prescribed by generally accepted accounting principles (“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, 2016 (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 and Mcfe amounts have been calculated by
using the conversion ratio of 1 bbl of oil to 6 Mcf of natural gas.
O V E R V I E W
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.
We had record annual average production in 2016 of 49,236 boe/d, which represents a 26%
increase over our 2015 annual average production of 38,950 boe/d.
Our strategy is to continue to develop and expand our two very large resource plays in the Peace
River Arch, the Montney/Doig Resource Play and the Charlie Lake Light Oil Resource Play, while
maintaining low capital costs and operating costs. These resource plays are large enough to
provide us with an extensive inventory of repeatable, low-cost drilling opportunities that we
expect will provide production and reserves growth for many years.
At December 31, 2016, 295 (289.7 net) Montney/Doig horizontal wells have been successfully
drilled and cased on Birchcliff’s lands. The majority of natural gas from these wells is processed
through our 100% owned and operated natural gas plant located in the Pouce Coupe area of
Alberta (the “PC Gas Plant”). The PC 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 per boe. Since the PC Gas Plant first became operational in March
2010, we have seen a significant reduction in our operating and processing costs to $0.25/Mcfe
for natural gas processed at the PC Gas Plant.
We continue to execute on our business strategy of operating essentially all of our high working
interest production, which is surrounded by large contiguous blocks of high working interest
lands where we own and/or control the infrastructure. Our operatorship, land position and
infrastructure ownership give us a competitive advantage over our competitors 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.
At March 15, 2017, Birchcliff had an enterprise value of approximately $2.5 billion.
2
Birchcliff Energy Ltd. B Y T H E N U M B E R S
At December 31, 2016
Operated production
Average working interest in undeveloped land
93%
99%
99%
295
New drilling initiated and controlled
Horizontal wells drilled on the
Montney/Doig Resource Play
289.7
NET
3
2016 Annual Report G A I N I N G G R O U N D , F O R G I N G A S T R O N G F U T U R E
MESSAGE TO SHAREHOLDERS
Dear Fellow Shareholder,
2016 was a very successful year for Birchcliff. By almost any
measurement, ratio or efficiency metric used by industry,
Birchcliff enjoyed top tier performance.
It seems like a very long time ago, but if you dial back our
corporate clock to January of 2016, the oil and gas markets
were collapsing along with oil and natural gas prices. A number
of our industry peers were forced to cut their budgets, lay off
employees and hunker down for what looked to be a prolonged
downturn. Banks were putting pressure on many companies as
their borrowing covenants were being breached. In addition, the
Government of Alberta was completing a royalty review which
increased the uncertainty for those considering investment in
our industry. It was truly a very challenging situation. Birchcliff’s
stock bottomed out at $2.85, less than when we started the
company 12 years earlier at $3.00 per share.
I am pleased to report that our Executive Team reacted very
quickly to the downturn and exhibited the leadership that our
shareholders, our directors and our staff expected of our Team.
In January 2016, we reduced our capital expenditure program
to match our funds flow and proceeds from property
dispositions. This would have the effect of not creating
additional debt. We froze staff salaries, including the Executives.
The Executive salaries remain frozen in 2017. We continued our
excellent relationship with our banking syndicate and were not
pressured by our Banks, like many of our industry peers, as a
result of our relationships, quality assets and the fact that we do
not have any financial covenants on our credit facilities. We did
not lay off a single person at Birchcliff as we continue to believe
that our people are our best asset. We hunkered down and got
the most out of every dollar we spent. We announced top
decile 2015 year end results in February of 2016 and patiently
waited for the cycle to end. We believe that when industry
reduces its drilling, supply will ultimately fall and commodity
prices will eventually recover.
The hard work and results from the previous 12 years of
focusing on the Pouce Coupe area paid off when we announced
on June 21, 2016 that we had entered into an agreement to
purchase production and related assets from a senior producer
for $625 million in the Gordondale area of Alberta, right next
door to our existing Pouce Coupe properties. Concurrent with
the announcement, Birchcliff raised $690.8 million by way of
a bought deal and private placement equity issues at $6.25 per
share. The equity issues closed July 13, 2016 and the acquisition
closed on July 28, 2016.
The result of the acquisition was that we were able to
add approximately 26,000 boe/d of production on lands
immediately adjacent to our own, significantly reduce our
total debt and debt ratios, significantly increase our future
opportunities, our market cap and our enterprise value and
solidify a land position of some 261 net sections of mostly
contiguous Montney/Doig lands.
As you may be aware, Birchcliff drilled 8 Montney wells in
the fourth quarter of 2016, 6 in Gordondale and 2 in Pouce
Coupe that did not come on production until recently. The
very successful early test results from these wells were
released on February 8, 2017, which confirmed our view
that the Montney D2 interval is oil prone with a strong
production profile. In addition, the test results confirmed
that the Montney D1 interval and Pouce Coupe wells would
react positively to new drilling technologies that Birchcliff
was introducing to these wells.
I do not intend to review the 2016 highlights in this message as
the details can be found throughout this report and were released
on February 8, 2017, capping off an excellent year for Birchcliff.
OUTLOOK
If ever the Executive Team was excited about Birchcliff’s future,
it is today. We strengthened our company in 2016 by increasing
production to record levels, we decreased our total debt to
$600 million, and we reduced our per unit operating costs, G&A
costs and interest costs, while adding significant oil and natural
gas drilling opportunities through the Gordondale Acquisition.
We expect our 2017 fourth quarter average production will
average between 80,000 to 82,000 boe/d, essentially doubling
production from the fourth quarter of 2015. We currently have
approximately half our expected 2017 natural gas production
hedged at $3.46/Mcf, protecting our 2017 funds flow and
capital expenditures.
In addition, we have recently added alternative sales points for
our natural gas by entering into firm agreements to transport
our natural gas eastward to Dawn with TransCanada Pipelines
and south through the Alliance Pipeline.
Simply put we are more focused, better financed, we reduced our
total debt and we have added more production and lands to
what was already a very large contiguous land base on the
Montney/Doig Resource Play.
We are now focused on methodically delivering 130,000 boe/d
of production by the end of 2021, while continuing to be one of
the most profitable producers in our industry with a focus on
low costs and high netbacks, while delivering top tier finding
and development costs and strong recycle ratios.
We have our best asset in place, which is our people. We have
not left our map sheet which allows us to continue to develop
4
Birchcliff Energy Ltd. and exploit our vast knowledge base of the Montney/Doig
Resource Play, which is one of our biggest advantages in our
highly competitive industry.
I must mention Seymour Schulich who has supported us
through thick and thin. When the stock came tumbling down
he bought more at very low levels and continued to voice
support for our team. He, like everyone else, has enjoyed the
positive results from our Gordondale transaction, but he was
there when it really counted.
Thank you to our shareholders for your support.
I must also thank our staff for not panicking in early 2016
but rather digging in with the Executive Team and ultimately
delivering excellent results to our shareholders.
Our directors have shown the Executive phenomenal support
as they watched the year unfold. On behalf of the Executive,
I thank them for their input and savvy business advice.
I want to especially thank Ken Cullen, who will be retiring in
2017 and will not be seeking re-election this year to our board.
Ken is a true friend and trusted advisor who has been a long-time
supporter of Birchcliff. Ken, we all thank you for your years of
service on our board and we wish you well in the next chapter
of your life.
In addition, after helping us get Birchcliff started and putting
in over 12 years of hard work, Jim Surbey will be retiring as
Vice President, Corporate Development and Corporate
Secretary on June 30, 2017. Jim has been an extremely
valuable and integral member of the Birchcliff team since
inception. His strong leadership, expertise and insight have
helped shape the company to where it is today. Although
Jim will be missed as a member of our Executive Team, we
believe that given his knowledge and expertise, he will make
an excellent addition to our Board of Directors and will help
us continue Birchcliff’s success.
We believe that 2017 will be another great year for Birchcliff,
with many obstacles to overcome, however we are
enthusiastically up to the challenge.
With respect,
A. Jeffery Tonken
President & Chief Executive Officer
March 15, 2017
“ 2016 was a very successful year
for Birchcliff. By almost any
measurement, ratio or efficiency
metric used by industry, Birchcliff
enjoyed top tier performance.”
5
2016 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
BRUNO GEREMIA
Vice-President &
Chief Financial Officer
JEFF TONKEN
President &
Chief Executive Officer
6
Birchcliff Energy Ltd. 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.
DAVE HUMPHREYS
Vice-President,
Operations
JIM SURBEY
Vice-President,
Corporate Development
CHRIS CARLSEN
Vice-President,
Engineering
7
2016 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
Our management team and our people are Birchcliff’s best asset. Birchcliff’s management
team is comprised of talented, high performing individuals who are driven to help Birchcliff
succeed. With guidance from our executive team, Birchcliff’s management team is
instrumental in executing our business strategy and managing our day-to-day operations.
1
2
3
4
5
6
7
8
9
1. JEFF ROGERS Facilities Manager
6. PERRY BILLARD Asset Manager – Worsley
2. RANDY ROUSSON Drilling & Completions Manager
7. BRUCE PALMER Manager of Geology
3. RYAN SLOAN Health, Safety & Environment Manager
8. GATES AURIGEMMA Manager, General Accounting
4. ROBYN BOURGEOIS General Counsel
9. VICTOR SANDHAWALIA Manager of Financial Accounting,
5. WAYNE BROWN Production Manager
Taxation & Insurance
8
Birchcliff Energy Ltd. 10
11
12
13
14
15
16
17
18
19
10. ANDREW FULFORD Surface Land Manager
15. BILL PARTRIDGE Engineering Lead
11. GEORGE FUKUSHIMA Manager of Engineering
16. HUE TRAN Joint Venture & Marketing Manager
12. BRIAN RITCHIE Asset Manager – Gordondale
17. JESSE DOENZ Controller & Investor Relations Manager
13. THEO VAN DER WERKEN Asset Manager – Pouce Coupe
18. PAUL MESSER Manager of Information Technology
14. MICHELLE RODGERSON Office Manager
19. ROBERT (BOB) GRISACK Land Manager
9
2016 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 $3.5 billion in capital, primarily in the Montney/Doig
Resource Play and the Charlie Lake Light Oil Resource Play. These investments have
generated $2.8 billion in revenue, paid $275 million in royalties to Albertans and delivered
$1.5 billion in funds flow from operations, all of which has been re-invested.
The following describes the major events in our history:
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 6, 2004
Birchcliff incorporated as
a private corporation
JULY 21, 2005
Common shares commenced trading
on the TSX
2004
MARCH 4, 2008
Rig released first Charlie Lake
horizontal light oil well drilled by
Birchcliff utilizing multi-stage
fracture stimulation technology
in the Worsley area
JANUARY 18, 2005
Completed Scout amalgamation and equity
financing of $60 million
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
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
SEPTEMBER 27, 2007
Completed acquisition of the Worsley
Property on the Charlie Lake Light Oil
Resource Play for $270 million
10
Birchcliff Energy Ltd. At December 31, 2016, 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
$5.8 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 the Gordondale Acquisition
for approximately $613.5 million.
The Gordondale Assets included high
working interest operated production
and a large contiguous land base on
the Montney/Doig Resource Play which
is immediately adjacent to Birchcliff’s
existing Pouce Coupe properties
OCTOBER 2, 2012
Phase III of the PC Gas Plant
commenced operations with a
combined processing capacity
of 150 MMcf/d
2016
SEPTEMBER 1, 2014
Completed construction of
Phase IV of the PC Gas Plant
with a combined processing
capacity of 180 MMcf/d
DECEMBER 31, 2016
295 (289.7 net) Montney/Doig
horizontal wells successfully
drilled to date
MARCH 20, 2010
Phase I of the PC Gas Plant
commenced operations with a
processing capacity of 30 MMcf/d
NOVEMBER 2, 2010
Phase II of the PC Gas Plant
commenced operations with a
combined processing capacity of
60 MMcf/d
11
2016 Annual Report P L A N N I N G F O R O U R F U T U R E
FIVE YEAR PLAN
In late 2016, we finalized our 2021 Five Year Plan (the “Five Year Plan”), which contemplates
controlled sustainable growth and targets an exit production rate of approximately
106,000 boe/d for 2018 and an exit production rate of approximately 130,000 boe/d for
2021. Assuming the production targets and commodity prices set forth in the table below
are realized, Birchcliff expects to generate significant free funds flow over the five year
period while paying a common share dividend and maintaining financial flexibility.
The Five Year Plan targets the following production rates and is based on the commodity prices set forth below(1):
2017
2018
2019
2020
2021
Approximate
Annual Average
Production (boe/d)
Year-over-year
Annual Average
Production Growth
Approximate Oil
and Liquids - % of
Annual Average
72,000(2)
45%
23%
91,000
26%
23%
105,000
16%
23%
110,000
4%
23%
125,000
13%
23%
(1) For additional assumptions surrounding the Five Year Plan, please see “Advisories – Forward-Looking Information”.
(2) Represents the mid-point of our 2017 guidance.
12
Birchcliff Energy Ltd. K E Y E L E M E N T S :
F I V E
YEAR
PLAN
Approximate Exit
Production (boe/d)
Light Oil – WTI
Cushing (US$/bbl)
Natural Gas –
AECO – C Daily
(CDN$/GJ)
Controlled Growth
80,000
55.00
3.00
Maintain a Top Tier Balance Sheet and
Financial Flexibility
106,000
55.00
3.00
106,000
55.00
3.00
124,000
55.00
3.00
130,000
55.00
3.00
Pay a Sustainable Quarterly Dividend
to Common Shareholders
Focus on Existing Resource Plays
Ownership and Control of Lands
and Infrastructure
Focus on Operational Excellence
13
2016 Annual Report P R O D U C I N G R E S U L T S
2016 ACCOMPLISHMENTS
Achieved record annual
average production of
49,236 boe/d
Achieved record quarterly
average production of
60,750 boe/d in Q4 2016
2016 record low total cash
costs of $10.59/boe
Delivered significant reserves
growth in all categories
Completed the Gordondale
Acquisition for $613.5MM,
after closing adjustments and
equity financings for total gross
proceeds of $690.8MM
Exited the year in excellent
financial position with total debt
of $600MM at December 31, 2016
compared to credit facilities
totaling $950MM
Drilled 22 wells, consisting of 14 Montney/Doig horizontal wells at Pouce Coupe, 6 Montney/
Doig horizontal wells at Gordondale, 1 Charlie Lake horizontal well at Worsley and 1 water
disposal well, all at 100% working interest
2017 KEY OBJECTIVES
Exit the year with
production in excess of
80,000 boe/d
Drill, case, complete and bring on
production of 46 wells consisting
of 32 Montney/Doig horizontal
wells at Pouce Coupe and
14 Montney/Doig horizontal
wells at Gordondale all at 100%
working interest
Bring on Phase V of the PC Gas Plant
in October 2017, increasing processing
capacity from 180 MMcf/d to 260
MMcf/d and continue to work toward
future expansions of the PC Gas Plant
Continue to focus on full cycle
profitability while paying a
sustainable quarterly dividend
to common shareholders
14
Birchcliff Energy Ltd. We believe that 2017 will be
another great year for Birchcliff,
with many obstacles to overcome,
however we are enthusiastically
up to the challenge.
- J E F F T O N K E N ,
President & Chief Executive Officer
15
2016 Annual Report O N E C O R E A R E A
16
Birchcliff Energy Ltd. Our operations are concentrated within our one core area, the Peace
River Arch, which is centred 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 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. There is an
abundance of prolific resource plays, related in part to the proximity of the area to the Deep Basin, where generation and trapping
of hydrocarbons preferentially occurs. The Peace River Arch provides all-season access that allows us to drill, equip and tie-in
wells on an almost continuous basis. In addition, Birchcliff has excellent control of and/or access to infrastructure in the Peace
River Arch, which helps us to control our costs and expand our production.
17
2016 Annual Report L O W - R I S K D E V E L O P M E N T
RESOURCE PLAYS
We are focused on two established resource plays within the
Peace River Arch: the Montney/Doig Resource Play and the
Charlie Lake Light Oil Resource Play.
ESTABLISHED RESOURCE PLAYS
We characterize our resource plays as plays that have regionally extensive, continuous, low permeability hydrocarbon accumulations or
systems that usually require intensive stimulation to produce. The production characteristics of these plays include steep initial declines
that rapidly trend to much lower decline rates, yielding long-life production and reserves. Resource plays exhibit a statistical distribution
of estimated ultimate recoveries and therefore provide a repeatable distribution of drilling opportunities. As more wells are drilled into
a resource play, there is a substantial decrease in both the geological and technical risks. Our resource plays are ideally suited for the
application of horizontal drilling and multi-stage fracture stimulation technology.
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
Charlie Lake
Boundary Lake
Subcrop
Halfway
Doig
Montney
Kiskatinaw
Exshaw
Wabamun
Duvernay
Leduc
Beaverhill Lake/
Granite Wash
PreCambrian
Graben Complex
DRILLED
MONTNEY/DOIG
HORIZONTAL WELLS
at December 31, 2016 with a
295
99%
SUCCESS RATE
18
Birchcliff Energy Ltd.
BIRCHCLIFF OPERATIONS IN THE PEACE RIVER ARCH
The Montney/Doig Resource Play and the Charlie Lake Light Oil Resource Play are managed by three technical teams at Birchcliff:
the Pouce Coupe Team, the Gordondale Team and the Worsley Team.
Birchcliff Resource Plays in the Peace River Arch
Peejay
Currant
Clear Prairie
BC AB
Osborn
Charlie
Buick
Rigel
Boundary
Lake North
Clear Hills
Worsley
CHARLIE LAKE
LIGHT OIL
RESOURCE PLAY
Hines
Worsley
Team
Dixonville
Gerry Lake
Flatrock
Boundary
Lake
Hill
Cecil
Clayhurst
Parkland
Doe
Bear
Canyon
Dawson
Pouce
Coupe
Balsam
Bonanza
Mulligan
Gordondale
Hamelin
Creek
Dunvegan
Whitelaw
Tangent
Sunrise
Mirage
Belloy
Progress
Gordondale
Team
Rycroft
Pouce Coupe
South
Pouce Coupe
Team
Valhalla
Saddle
Hills
Peoria
Eaglesham
MONTNEY/DOIG
RESOURCE PLAY
Grande
Prairie
Kakut-Woking
Teepee
Bezanson
Sturgeon Lake
L E G E N D
Birchcliff Pouce Coupe Non-Confidential Land
Birchcliff Gordondale Non-Confidential Land
Birchcliff Worsley Non-Confidential Land
Birchcliff Facility
PC Gas Plant
Elmworth
Wapiti
Gold Creek
Ante Creek
19
2016 Annual Report
A S I G N I F I C A N T P O S I T I O N I N A W O R L D C L A S S P L A Y
MONTNEY/DOIG RESOURCE PLAY
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. Birchcliff’s Montney/Doig Resource Play contains three
primary producing regions: Pouce Coupe, Gordondale and Elmworth.
There are a number of attributes that the Montney/Doig Resource Play has that contributes 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: Canadian Discovery, RBC Rundle, 2013
20
Birchcliff Energy Ltd. GEOLOGY
The Montney/Doig Resource Play in Birchcliff’s core areas of
operations is approximately 300 m (1,000 feet) thick. The play
has a large areal extent covering in excess of 50,000 square
miles. Another very important attribute is the mineralogy
of the reservoir. The Montney/Doig is composed of a high
percentage of hard minerals and a very low percentage of soft
minerals including clays 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 very low terminal declines and large estimated
ultimate recoveries of the play. Unlike most shale gas plays
that are predominantly shale, the Montney/Doig is classified
by Birchcliff as a hybrid resource play because it is comprised
of gas saturated rock with both tight silt and sand reservoir
rock interlayered with shale gas 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
gas in-place.
These rock properties result in high recovery factors.
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 formation and the Doig formation.
Due to the complexity of the geology, not all of the same
intervals are present in all areas of the play trend. We have
divided the geologic column in our area into six drilling
intervals from youngest (top) to 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.
Birchcliff Montney/Doig Resource Play Full Development Plan: Hexastack
300m
BASAL DOIG
MONTNEY D5
MONTNEY D4
MONTNEY D3
MONTNEY D2
MONTNEY D1
MONTNEY C
60m
300m
1600m
1600m
As of December 31, 2016
DRILLING INTERVAL:
BASAL DOIG/UPPER MONTNEY
Mature Developed/Commercial
67 Producing Wells
MONTNEY D4
Mature Developed/Commercial
9 Producing Wells
MONTNEY D3
0 Producing Wells
MONTNEY D2
Mature Developed/Commercial
4 Producing Wells
MONTNEY D1
Mature Developed/Commercial
214 Producing Wells
MONTNEY C
New Exploration Success
1 Producing Well
L E G E N D
Mature Developed/Commercial
New Exploration Success
Future Potential
21
2016 Annual Report OUR OPERATIONS
In 2016, the Montney/Doig Resource Play accounted for:
At December 31, 2016, 295 (289.7 net) Montney/Doig
horizontal wells have been successfully drilled and cased on
Birchcliff’s lands (which includes 87 (81.8 net) wells acquired
in the Gordondale Acquisition), consisting of 67 wells in the
Basal Doig/Upper Montney interval, 9 wells in the Montney
D4 interval, 4 wells in the Montney D2 interval, 214 wells in
the Montney D1 interval and 1 well in the Montney C interval.
The Montney D2 interval was a major focus for Birchcliff
in 2016. The Gordondale Assets had one well drilled in
this interval in 2014. We have significantly increased our
confidence in the ultimate commerciality of the D2 interval
based upon the previous technical work that was done on
the Gordondale Assets by the prior owner, publicly available
information resulting from industry activity on the Montney
D2 interval, our own technical expertise developed in our
Pouce Coupe Montney operations and recent completion
results in the Gordondale area.
42%
In 2016, approximately 96% of our natural gas production,
42% of our light oil production and 97% of our NGLs
production came from the wells drilled on the Montney/Doig
97%
Resource Play. In 2016, production from the Montney/Doig
Resource Play averaged approximately 45,311 boe/d.
42%
42%
97%
Total Corporate
97%
Oil Production
96%
Total Corporate
96%
NGLs Production
92%
84%
81%
Total Corporate
Natural Gas Production
75%
70%
96%
65%
58%
60,000
50,000
40,000
30,000
20,000
10,000
)
d
/
e
o
b
(
n
o
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o
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P
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l
i
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a
r
e
v
A
l
a
u
n
n
A
51%
0
2009
2010
2011
2012
2013
2014
2015
2016
Montney/Doig Production
Total Corporate Production
Corporate Production Breakdown
Corporate 2P Reserves Breakdown
60,000
50,000
40,000
30,000
20,000
10,000
)
d
/
e
o
b
(
n
o
i
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e
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A
51%
0
92%
84%
81%
75%
70%
65%
58%
2009
2010
2011
2012
2013
2014
2015
2016
1,000
900
800
700
600
500
400
300
200
100
0
)
e
o
b
M
M
(
s
e
v
r
e
s
e
R
P
2
94%
90%
89%
86%
84%
83%
80%
75%
2009
2010
2011
2012
2013
2014
2015
2016
Montney/Doig Production
Total Corporate Production
Montney/Doig 2P Reserves
Total Corporate 2P Reserves
22
1,000
900
800
700
600
500
400
300
200
100
0
)
e
o
b
M
M
(
s
e
v
r
e
s
e
R
P
2
94%
90%
89%
86%
84%
83%
80%
75%
2009
2010
2011
2012
2013
2014
2015
2016
Montney/Doig 2P Reserves
Total Corporate 2P Reserves
Birchcliff Energy Ltd.
SIGNIFICANT FUTURE DRILLING OPPORTUNITIES
At December 31, 2016, Birchcliff held 441.2 sections of land that have potential for the Montney/Doig Resource Play. Of these lands,
433.9 (406.6 net) sections have potential for the Basal Doig/Upper Montney interval, 395.4 (383.9 net) sections have potential
for the Montney D1 interval, 399.9 (388.4 net) sections have potential for the Montney D2 interval and 328.1 (319.3 net) sections have
potential for the Montney D4 interval. At December 31, 2016, Birchcliff’s total land holdings on these four intervals was 1,557.3
(1,498.2 net) sections. Assuming full development of four horizontal wells per section per drilling interval, Birchcliff has 5,992.8
net existing horizontal wells and potential net future horizontal drilling locations in respect of the Basal Doig/Upper Montney,
Montney D1, Montney D2 and Montney D4 intervals at December 31, 2016. With 295 (289.7 net) horizontal locations drilled at
the end of 2016, there remains 5,703.1 potential net future horizontal drilling locations at December 31, 2016, up from 3,367.3 at
year end 2015. This does not include any potential net future horizontal drilling locations for the other two prospective Montney
intervals, the Montney C and the Montney D3.
Substantial upside exists with respect to the 5,992.8 net existing horizontal wells and potential net future horizontal drilling
locations. The 2016 Consolidated Reserves Report attributed proved reserves to 721.7 net existing wells and potential net future
horizontal drilling locations (of which 435.0 net wells are potential future drilling locations) and proved plus probable reserves
to 974.4 net existing wells and potential net future horizontal drilling locations (of which 687.7 net wells are potential future
drilling locations). The remaining 5,018.4 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.
Birchcliff Montney/Doig Multi-Layer Opportunity
Elmworth
2
1
3
Pouce Coupe
Gordondale
4
5
6
6
Basal Doig
Montney D5
Montney D4
Montney D3
Montney D2
Montney D1
Montney C
Hydrocarbon Pore Volume
Existing Wells
Proposed Locations
Gordondale
6
Pouce
Coupe
5
4
3
2
Elmworth
1
23
2016 Annual Report Pouce Coupe Team
Birchcliff was active in the Pouce Coupe area during 2016, drilling a total of 14 (14.0 net) Montney/Doig horizontal natural gas
wells consisting of 2 Basal Doig/Upper Montney, 10 Montney D1 and 2 Montney D4 wells, all of which were successful. All
horizontal wells drilled in 2016 utilized multi-stage fracture stimulation technology. Of these wells, 2 were brought on production
and tested in February 2017.
Pouce Coupe Team Highlight Map
R13W6
BC/AB
R12W6
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L E G E N D
Pouce Coupe Non-Confidential Land
Birchcliff Non-Confidential Land
Birchcliff Vertical Producers
A
F
F
Birchcliff Horizontal Producers
F
F
2017 Capital Program
2016 Capital Program
24
T75
G
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2017 OUTLOOK
A large portion of Birchcliff’s 2017 capital
expenditure program will be directed
towards our Pouce Coupe area, including
the drilling of 32 (32.0 net) wells,
consisting of 22 Montney D1 horizontal
natural gas wells, 7 Basal Doig/Upper
Montney horizontal natural gas wells
and 3 Montney D4 horizontal natural gas
wells. In addition to the drilling program,
Birchcliff will continue to invest in future
expansions of the PC Gas Plant.
T74
T73
T72
T71
Birchcliff Energy Ltd. THE PC GAS PLANT
Our 100% owned and operated PC Gas Plant located in 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 fraction of the costs borne by others who rely
on third-party processing. The PC 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 PC Gas Plant. During 2010, we constructed
Phases I and II of our PC Gas Plant with 60 MMcf/d of natural
gas processing capacity. In 2012, processing capacity at the
PC Gas Plant was increased to 150 MMcf/d (Phase III) and to
180 MMcf/d in 2014 (Phase IV).
THE PC GAS PLANT IS
100%
OWNED AND OPERATED
enabling us to process natural gas at
a fraction of the costs borne by others
who rely on third-party processing.
25
2016 Annual Report In 2017, approximately $27.3 million will be directed towards
the completion of the field construction of the Phase V
expansion of the PC Gas Plant which will increase processing
capacity from 180 MMcf/d to 260 MMcf/d. Field installation
commenced January 2017 and it is expected that Phase V will
be on-stream in October 2017. The completion of Phase V will
be timed to coincide with the drilling of additional Montney/
Doig horizontal natural gas wells to fill or partially fill the
expanded PC Gas Plant, so that operational momentum will
not be lost and ensuring capital is only spent when required.
In addition, approximately $26.0 million in 2017 will be
directed towards the procurement and fabrication of the major
components required for the Phase VI expansion of the PC Gas
Plant which will increase processing capacity from 260 MMcf/d
to 340 MMcf/d. The engineering and licensing work has been
completed for the Phase VI expansion of the PC Gas Plant and
Birchcliff currently expects that Phase VI will be on-stream in
October 2018.
Birchcliff has started the planning and initial work to further
expand the capacity of the PC Gas Plant from 340 MMcf/d to
490 MMcf/d in 2019 and by a further 100 MMcf/d for a total
processing capacity of 590 MMcf/d. Birchcliff’s current plans
for this expansion include a deep-cut capability and an on-stream
date in mid-2019 for 150 MMcf/d of the additional capacity,
with the balance of the expansion to start-up in 2020.
Our goal is to continue to expand the processing capacity of
the PC Gas Plant and fill it with natural gas produced from our
Montney/Doig horizontal wells.
PHASE V EXPANSION OF THE PC GAS PLANT
WILL BRING PROCESSING CAPACITY TO
260 MMCF/D
(from 180 MMCF/D) with an expected
on-stream date of October 2017
26
ELMWORTH OPERATIONS
In the fourth quarter of 2014, Birchcliff drilled its first
successful Montney/Doig horizontal exploration well in
the Montney D4 interval in the Elmworth area. Birchcliff
subsequently drilled its second successful horizontal
exploration well in the Elmworth area in the Montney D4
interval in the first quarter of 2015, which was brought on
production in June 2015.
As part of Birchcliff’s future growth plans for its Montney/
Doig Resource Play, Birchcliff is continuing to prove up the
play in the Elmworth area and intends to construct and
operate a 100% owned and operated natural gas plant in
the Elmworth area (the “Elmworth Gas Plant”). This plant
is currently planned to be on-stream in the fall of 2021 and
have a processing capacity of 40 MMcf/d. Birchcliff has
commenced the preliminary planning for this plant and a
critical requirement is a nearby acid gas disposal well which
Birchcliff drilled in the first quarter of 2015. In the second
and third quarters of 2015, Birchcliff conducted successful
injectivity tests on the well. Birchcliff received regulatory
approval for this acid gas well in August 2016.
Gordondale Team
On July 28, 2016, Birchcliff completed the Gordondale
Acquisition. The Gordondale Assets included high working
interest operated production and a large contiguous land
base which is immediately adjacent to Birchcliff’s existing
Pouce Coupe properties. Subsequent to the completion of the
Gordondale Acquisition, Birchcliff established a new technical
team to manage the Gordondale Assets, which devoted
significant time analyzing how to best optimize the assets
and identifying cost savings initiatives. In addition, Birchcliff
commenced its drilling program in the Gordondale area and
drilled a total of 6 (6.0 net) Montney horizontal oil and natural
gas wells in the area (3 Montney D2 horizontal oil wells and
3 Montney D1 horizontal liquids-rich natural gas wells) in
the fourth quarter of 2016. All 6 of these wells were recently
completed and tested inline. Birchcliff also drilled 1 (1.0 net)
water disposal well in the Gordondale area in 2016 to reduce
water transportation and disposal costs.
2017 OUTLOOK
Birchcliff expects to be active in the Gordondale area during 2017
and our planned 2017 capital expenditure program contemplates
the drilling of 14 (14.0 net) wells in the Gordondale area consisting
of 7 Montney D1 wells and 7 Montney D2 wells.
Birchcliff Energy Ltd. G
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Gordondale Team Highlight Map
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Gordondale Non-Confidential Land
Birchcliff Non-Confidential Land
Birchcliff Vertical Producers
Birchcliff Horizontal Producers
F
2017 Capital Program
2016 Capital Program
T80
T79
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T77
T76
T75
T74
27
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2016 Annual Report
D E P E N D A B L E L I G H T O I L P R O D U C T I O N
CHARLIE LAKE LIGHT OIL RESOURCE PLAY
Birchcliff’s Charlie Lake Light Oil Resource Play is centred approximately 150 km north of
Grande Prairie, Alberta and contains two primary producing regions: Worsley and Progress.
The Charlie Lake Light Oil Resource Play is described by
Birchcliff as a regionally extensive variety of restricted to
nearshore marine facies. The Charlie Lake reservoirs are
heterogeneous and consist of varying quantities of laminated
and dolomitic, silty to fine-grained sandstones. The reservoir
intervals typically exhibit porosity in the order of 8% to 15%
and net reservoir thickness of 3 to 30 m. A critical component
of the play is the main trapping mechanism, comprised of
a regional hydrodynamic trap setting up a large regional
hydrocarbon column and oil pool.
At December 31, 2016, Birchcliff has successfully drilled and
cased 61 (61.0 net) horizontal wells on the Charlie Lake Light
Oil Resource Play, 59 wells in the Worsley area and 2 wells in
the Progress area.
Horizontal wells on the Charlie Lake Light Oil Resource Play
that utilize multi-stage fracture stimulation technology are
generally drilled to a measured depth of 2,500 to 3,500 m
and deliver initial productivity rates of 100 to 750 boe/d.
In 2016, 4% of our natural gas production, 57% of our light
oil production and 2% of our NGLs production came from the
wells drilled on the Charlie Lake Light Oil Resource Play, with
production primarily from the oil rich Charlie Lake formation.
In 2016, production from the Charlie Lake Light Oil Resource
Play averaged approximately 3,754 boe/d.
Worsley Team
CHARLIE LAKE LIGHT OIL RESOURCE PLAY –
WORSLEY AREA
We entered the Charlie Lake Light Oil Resource Play through
the acquisition of the Worsley Property in September 2007.
The Worsley Property is located approximately 150 km
north of Grande Prairie, which is in close proximity to our
other assets. The Worsley Property is characterized by large
contiguous blocks of mainly 100% working interest lands
containing a very large Charlie Lake light oil pool. Essentially
all of the production is operated by Birchcliff and the related
infrastructure is owned by Birchcliff.
When we acquired the Worsley Property in September 2007,
the previous operator had started a pilot waterflood project.
Subsequently, Birchcliff significantly expanded the waterflood
and the results have been very positive, adding significant
reserves by increasing the recovery factor.
28
Another important initiative of ours has been to expand and
delineate the Worsley pool and we have been very successful. At
December 31, 2016, Deloitte estimated that the Worsley Charlie
Lake light oil pool had 38.9 MMboe of proved plus probable
reserves and 20.4 MMboe of proved reserves, as compared to
reserves estimated at 15.1 MMboe on a proved plus probable basis
and 11.3 MMboe on a proved basis at the time of acquisition.
Due to low oil prices during 2016, drilling activities on our
Worsley Charlie Lake Light Oil Resource Play were limited to the
drilling of 1 (1.0 net) Charlie Lake horizontal light oil well in the
Worsley area that continued 18 sections of land and delineated
the pool to the northeast. Additional activities during 2016
included the conversion of two wells in the waterflood area to
injectors to further enhance the waterflood scheme.
The majority of the production from the Worsley Charlie Lake
Light Oil Resource Play flows through our 100% owned and
operated Worsley oil battery and gas plant, which is located in the
core of the Worsley area. Clean oil is trucked from the Worsley
facility to truck terminals located in the towns of High Prairie,
Valleyview and Gordondale, Alberta and Taylor, British Columbia,
to be transported on the Pembina Peace pipeline to Edmonton.
At December 31, 2016, Birchcliff held 214.5 (197.2 net) sections
of land in the Worsley Charlie Lake Light Oil Resource Play.
CHARLIE LAKE LIGHT OIL RESOURCE PLAY –
PROGRESS AREA
In the fourth quarter of 2014, Birchcliff drilled its first
successful 100% working interest Charlie Lake horizontal
exploration well in the Progress area, which was brought
on production in December 2014. In the second quarter of
2015, Birchcliff drilled its second successful 100% working
interest Charlie Lake horizontal light oil well in its Progress
area, which was brought on production in August 2015.
At December 31, 2016, Birchcliff held 28 (27.5 net) sections
of land in the Progress area on the Charlie Lake Light Oil
Resource Play.
In 2016, the Charlie Lake Light Oil Resource Play
accounted for:
2%
2%
57%
Total Corporate
Oil Production
Birchcliff Energy Ltd. Birchcliff Development Areas on the Charlie Lake Light Oil Resource Play
R13
R12
R11
R10
R9
R8
R7
R6
R5
R4
R3
R2
R1W6
WORSLEY
DEVELOPMENT AREA
2016 Validation
2016 CHARLIE LAKE
LIGHT OIL WELL
L E G E N D
Birchcliff Non-Confidential Land
Charlie Lake Land Sales since Jan 2008 > $1500/ha
Birchcliff Recent Wells
Charlie Lake Producing Wells
Play
Fairway
PROGRESS
DEVELOPMENT AREA
CHARLIE LAKE
LIGHT OIL WELLS
R13
R12
R11
R10
R9
R8
R7
R6
R5
R4
R3
R2
R1W6
T90
T89
T88
T87
T86
T85
T84
T83
T82
T81
T80
T79
T78
T77
T76
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29
2016 Annual Report S I G N I F I C A N T R E S E R V E S G R O W T H I N A L L C A T E G O R I E S
2016 YEAR-END RESERVES
Birchcliff retained two independent qualified reserves evaluators, Deloitte and 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 Gordondale Assets, representing approximately 76% of the assigned
total proved plus probable reserves and 73% of the total proved plus probable future net revenue discounted at 10%. McDaniel
evaluated the reserves attributable to the Gordondale Assets, representing approximately 24% of the assigned total proved plus
probable reserves and 27% of the total proved plus probable future net revenue discounted at 10%.
The reserves data set forth below at December 31, 2016 is based upon the evaluation by Deloitte with an effective date of
December 31, 2016 as contained in the report of Deloitte dated February 3, 2017 (the “2016 Deloitte Reserves Report”) and the
evaluation by McDaniel with an effective date of December 31, 2016 as contained in the report of McDaniel dated February 8,
2017 (the “2016 McDaniel Reserves Report”), which are contained in the consolidated report of Deloitte with an effective date
of December 31, 2016 (the “2016 Consolidated Reserves Report”). Deloitte prepared the 2016 Consolidated Reserves Report
by consolidating the properties evaluated by Deloitte in the 2016 Deloitte Reserves Report with the properties evaluated by
McDaniel in the 2016 McDaniel Reserves Report, in each case using Deloitte’s forecast price and cost assumptions effective
December 31, 2016 (the “2016 Deloitte Price Forecast”). Hedging gains and losses have been incorporated into the Consolidated
Reserves Report.
Deloitte also prepared an evaluation of Birchcliff’s reserves effective December 31, 2015 (the “2015 Deloitte Reserves Report”)
and reserves data contained herein at December 31, 2015 is based upon such report. The price forecast used in such evaluation
was Deloitte’s forecast price and cost assumptions effective December 31, 2015 (the “2015 Deloitte Price Forecast”).
The 2016 Deloitte Reserves Report, the 2016 McDaniel Reserves Report, the 2016 Consolidated Reserves Report and the
2015 Deloitte Reserves Report were prepared in accordance with the standards contained in the COGE Handbook and NI 51-101
in effect at the relevant time.
Numbers presented in the tables below may not total due to rounding.
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, 2016, which is available on the System for Electronic Document Analysis and
Retrieval (www.sedar.com).
RESERVES SUMMARY
The following table summarizes the estimates of Birchcliff’s gross reserves at December 31, 2016 and December 31, 2015,
estimated using the forecast price and cost assumptions in effect at the applicable reserves evaluation date:
Summary of Gross Reserves
(Forecast Prices and Costs)
Reserves Category
Proved Developed Producing
Total Proved
Probable
Total Proved Plus Probable
30
Dec 31, 2016
(MMboe)
Dec 31, 2015
(MMboe)
Increase from
Dec 31, 2015
165.5
548.5
331.9
880.5
102.1
351.2
221.7
572.9
62%
56%
50%
54%
Birchcliff Energy Ltd. Corporate
Corporate Reserves
1,000
900
800
700
600
500
400
300
200
100
0
)
e
o
b
M
M
(
s
e
v
r
e
s
e
R
PDP
TP
2P
2010
2011
2012
2013
2014
2015
2016
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, 2016, estimated using the 2016 Deloitte Price Forecast:
Montney
Summary of Reserves at December 31, 2016
(Forecast Prices and Costs)(1)
900,000
800,000
700,000
Proved
)
)
e
e
o
o
b
b
M
M
(
(
s
s
e
e
v
v
r
r
e
e
s
s
e
e
R
R
600,000
Developed
Producing
500,000
Developed
Non-Producing
Undeveloped
400,000
Total Proved
Probable
300,000
Total Proved
Plus Probable
200,000
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)
12,618.3
10,722.4
28,107.7
25,546.5
772,961.6
707,425.5
19,377.2
14,467.0
165,507.0
147,351.4
PDP
1,971.0
1,736.4
11,328.6
10,400.4
16,276.5
14,898.2
286.7
195.1
6,858.5
TP
6,148.0
17,202.7
14,796.2
19,957.5
18,478.0
1,952,217.2
1,744,899.5
30,259.7
24,396.4
376,158.3 333,088.8
2P
31,791.9
27,255.0
59,393.8
54,424.9
2,741,455.3
2,467,223.2
49,923.6
39,058.5 548,523.8 486,588.1
26,655.8
22,186.7
62,289.1
56,862.9
1,532,149.2
1,321,933.2
39,544.5
30,455.0 331,940.0 282,441.0
58,447.7
49,441.7
121,682.9
111,287.8 4,273,604.6
3,789,156.4
89,468.2
69,513.5 880,463.8 769,029.2
(1) “Gross” means Birchcliff’s working interest (operating or non-operating) share before the deduction of royalties and without including any royalty interests of Birchcliff. “Net” means Birchcliff’s
working interest (operating or non-operating) share after the deduction of royalty obligations, plus Birchcliff’s royalty interests in reserves.
100,000
0
2010
2011
2012
2013
2014
2015
2016
31
PDP
TP
2P
Worsley
)
e
o
b
M
(
s
e
v
r
e
s
e
R
45,000
40,000
35,000
30,000
25,000
20,000
15,000
10,000
5,000
0
2010
2011
2012
2013
2014
2015
2016
2016 Annual Report
NET PRESENT VALUE OF FUTURE NET REVENUE
The following table sets forth the net present value of future net revenue attributable to Birchcliff’s reserves at December 31,
2016, estimated using the 2016 Deloitte Price Forecast, before deducting future income tax expenses and calculated at various
discount rates:
Summary of Net Present Value of Future Net Revenue at December 31, 2016
(Forecast Prices and Costs)
Reserves Category
Proved
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved
Probable
Total Proved Plus Probable
Net Present Value of Future Net Revenue Before Income Taxes Discounted At (%/year)
0
(MM$)
5
(MM$)
10
(MM$)
15
(MM$)
20
(MM$)
Unit Value
Discounted
at 10%/yr
($/boe)
3,503.2
176.2
6,659.1
10,338.4
7,488.7
17,827.2
2,457.0
1,877.4
121.8
3,593.3
6,172.1
3,364.7
9,536.8
91.5
2,085.6
4,054.5
1,756.4
5,810.8
1,521.6
72.5
1,255.3
2,849.3
1,011.5
3,860.7
1,284.7
59.4
758.6
2,102.7
622.0
2,724.7
12.74
14.89
6.26
8.33
6.22
7.56
32
Birchcliff Energy Ltd. PRICING ASSUMPTIONS
The following table sets forth the forecast price and cost assumptions used in the 2016 Consolidated Reserves Report:
2016 Deloitte Price Forecast
Crude Oil
Natural Gas
NGLs
WT I at
Cushing
Oklahoma
($US/bbl)
Edmonton
City Gate
($CDN/bbl)
Natural
Gas at
AECO
($CDN/Mcf)
Year
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
(%)
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2036+
55.00
58.15
62.40
69.00
75.75
82.80
84.45
86.15
87.85
89.65
91.40
93.25
95.10
97.00
98.95
100.95
102.95
105.00
107.10
109.25
2%/yr
68.90
71.15
74.70
79.90
84.05
92.25
94.10
95.95
97.90
99.85
101.85
103.90
105.95
108.10
110.25
112.45
114.70
117.00
119.35
121.70
2%/yr
3.25
3.35
3.50
3.55
3.70
3.90
4.15
4.50
4.70
4.85
5.00
5.10
5.20
5.30
5.40
5.50
5.65
5.75
5.85
5.95
9.10
9.45
9.80
10.00
10.30
11.00
11.65
12.50
13.10
13.55
14.00
14.30
14.60
14.90
15.15
15.50
15.80
16.10
16.40
16.75
13.80
21.35
29.85
31.95
33.60
36.90
37.60
38.35
39.15
39.90
40.70
41.55
42.35
43.20
44.05
44.95
45.85
46.75
47.70
48.65
41.35
42.70
44.85
47.95
50.45
55.35
56.50
57.60
58.75
59.95
61.15
62.35
63.60
64.85
66.15
67.50
68.85
70.20
71.65
73.05
2%/yr
2%/yr
2%/yr
2%/yr
68.90
71.15
74.70
79.90
84.05
92.25
94.10
95.95
97.90
99.85
101.85
103.90
105.95
108.10
110.25
112.45
114.70
117.00
119.35
121.70
2%/yr
0.740
0.760
0.780
0.810
0.850
0.850
0.850
0.850
0.850
0.850
0.850
0.850
0.850
0.850
0.850
0.850
0.850
0.850
0.850
0.850
0.850
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/yr
33
2016 Annual Report RECONCILIATION OF CHANGES IN RESERVES
The following table sets forth a reconciliation of Birchcliff’s gross reserves at December 31, 2016 set forth in the 2016 Consolidated
Reserves Report, using the 2016 Deloitte Price Forecast, to Birchcliff’s gross reserves at December 31, 2015 set forth in the 2015
Deloitte Reserves Report, using the 2015 Deloitte Price Forecast:
Reconciliation of Gross Reserves from December 31, 2015 to December 31, 2016
(Forecast Prices and Costs)
Factors
GROSS TOTAL PROVED
Light Crude Oil
and Medium
Crude Oil
(Mbbls)
Conventional
Natural Gas
(MMcf)
Shale Gas
(MMcf)
NGLs
(Mbbls)
Oil Equivalent
(Mboe)
Opening balance December 31, 2015
18,534.0
59,094.7
1,839,366.7
16,301.2
351,245.4
Discoveries
Extensions & Improved Recovery
Technical Revisions
Acquisitions
Dispositions
Economic Factors
Production(1)
Closing balance December 31, 2016
GROSS TOTAL PROBABLE
0.0
359.3
375.8
14,450.5
(474.0)
(82.2)
(1,371.4)
31,792.0
0.0
695.4
(194.9)
11,707.8
(5,834.0)
(1,140.8)
(4,934.4)
0.0
413,357.8
195,709.6
385,468.9
(4,971.4)
(1,047.9)
(86,428.3)
59,393.8
2,741,455.4
0.0
2,883.8
996.9
31,511.3
(197.5)
(20.1)
(1,552.0)
49,923.6
0.0
72,252.0
33,958.5
112,157.9
(2,472.4)
(467.1)
(18,150.5)
548,523.8
Opening balance December 31, 2015
17,468.1
64,897.0
1,093,750.0
11,117.5
221,693.4
Discoveries
Extensions & Improved Recovery
Technical Revisions
Acquisitions
Dispositions
Economic Factors
Production(1)
0.0
268.8
(1,107.6)
10,527.7
(470.0)
(31.3)
0.0
0.0
353.0
(2,370.3)
2,566.1
(2,723.9)
(432.8)
0.0
0.0
88,360.9
63,326.4
309,674.2
(22,749.7)
(212.6)
0.0
0.0
771.7
2,561.1
25,705.5
(603.8)
(7.4)
0.0
0.0
15,826.2
11,612.9
88,273.3
(5,319.4)
(146.3)
0.0
Closing balance December 31, 2016
26,655.7
62,289.1
1,532,149.2
39,544.6
331,940.0
GROSS TOTAL PROVED PLUS PROBABLE
Opening balance December 31, 2015
36,002.1
123,991.7
2,933,116.7
27,418.7
572,938.9
Discoveries
Extensions & Improved Recovery
Technical Revisions
Acquisitions
Dispositions
Economic factors
Production(1)
Closing balance December 31, 2016
0.0
628.1
(731.8)
24,978.2
(944.0)
(113.5)
(1,371.4)
58,447.7
0.0
1,048.4
(2,565.2)
14,273.9
(8,557.9)
(1,573.6)
(4,934.4)
0.0
501,718.7
259,036.0
695,143.1
(27,721.1)
(1,260.5)
(86,428.3)
121,682.9
4,273,604.6
0.0
3,655.5
3,558.0
57,216.8
(801.3)
(27.5)
(1,552.0)
89,468.2
0.0
88,078.1
45,571.3
200,431.2
(7,791.8)
(613.4)
(18,150.5)
880,463.8
(1) Represents the independent qualified reserves evaluators’ estimates of actual production for the year ended December 31, 2016 before year-end results were available.
34
Birchcliff Energy Ltd. Positive technical revisions, which did not require any increase to FDC, can be attributed to Deloitte’s assignment of new
Montney/Doig terminal declines within Pouce Coupe and Elmworth, which is based on the historical performance of the
Birchcliff and industry offsetting Montney/Doig wells and the improved performance of Birchcliff’s producing wells. These
positive technical revisions accounted for 43% of the proved developed producing reserves additions, 33% of the proved
reserves additions, 53% of the probable reserves additions and 36% of the proved plus probable reserves additions, when
excluding the reserves additions attributable to the Gordondale Acquisition.
Acquisitions, which was comprised of the Gordondale Acquisition, accounted for 69% of the proved developed producing reserves
additions, 52% of the proved reserves additions, 80% of the probable reserves additions and 62% of the proved plus probable
reserves additions.
Birchcliff was also able to add significant “Extensions” primarily resulting from Montney D1 type curve upgrades in two sub
areas and additional locations added in Pouce Coupe due to increased geological confidence and continued delineation on the
Montney/Doig Resource Play.
FUTURE DEVELOPMENT COSTS
Changes in forecast FDC occur annually as a result of development activities, acquisition and disposition activities and capital cost
estimates that reflect the independent reserves evaluators’ best estimate of what it will cost to bring the proved and proved plus
probable reserves on production.
The following table sets forth the independent reserves evaluators’ estimated FDC to bring the proved and proved plus probable
reserves on production:
Future Development Costs
(Forecast Prices and Costs)
2017
2018
2019
2020
2021
Thereafter
Total undiscounted
Proved
(MM$)
322.7
527.5
534.0
374.2
491.8
250.9
2,501.1
Proved Plus Probable
(MM$)
386.0
657.7
709.0
511.3
640.6
1,245.5
4,150.1
FDC for total proved reserves increased to $2.50 billion at December 31, 2016 from $1.81 billion at December 31, 2015. FDC for
total proved plus probable reserves increased to $4.15 billion at December 31, 2016 from $3.09 billion at December 31, 2015.
The increases in FDC for both proved and proved plus probable reserves are largely due to the reserves associated with the
Gordondale Assets which were acquired pursuant to the Gordondale Acquisition and the associated capital required to develop
such reserves ($346 million on a proved basis and $674 million on a proved plus probable basis). In addition, the increases in
FDC are also due to the FDC associated with the increase in Montney/Doig potential net future drilling locations in each category
of reserves from Birchcliff’s 2016 drilling program and additional locations added in Pouce Coupe due to increased geological
confidence and continued delineation on the Montney/Doig Resource Play.
35
2016 Annual Report The FDC for both proved and proved plus probable reserves are primarily the capital costs required to drill, complete, equip and
tie-in undeveloped locations. The estimates of FDC on a proved basis also include approximately $181 million for the expansion of
the PC Gas Plant to 420 MMcf/d of total throughput. The estimates of FDC on a proved plus probable basis include approximately
$261 million for the expansion of the PC Gas Plant to 500 MMcf/d of total throughput. The FDC for the expansions of the PC Gas
Plant also include the costs of the related gathering pipelines, sales pipeline expansion and compression.
The following table sets forth the average cost to drill, complete, equip and tie-in a multistage fractured horizontal well as
estimated by Deloitte and McDaniel:
Average Well Cost, as Estimated by
Deloitte or McDaniel
Pouce Coupe(1)
Gordondale(2)
December 31, 2016
(MM$)
December 31, 2015
(MM$)
4.5
5.7
4.4
N/A
(1) Estimated by Deloitte. Up slightly compared to 2015 due to optimized well layouts resulting in more full length wells, as well as an increase in the deeper Montney D1 reserves locations.
(2) Estimated by McDaniel.
RESERVES REPLACEMENT
The following table sets forth Birchcliff’s 2016 reserves replacement ratios:
Reserves Category
Proved Developed Producing
Proved
Proved Plus Probable
(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 2016 reserves life index:
Reserves Category
Proved Developed Producing
Total Proved
Total Proved Plus Probable
2016 Reserves Replacement(1)
452%
1,195%
1,807%
2016 Reserves Life Index(1)
6.3 years
20.9 years
33.5 years
(1) Based on a forecast production rate of 72,000 boe/d for 2017, which represents the mid-point of Birchcliff’s annual average production guidance range for 2017. Please see “Advisories –
Oil and Gas Metrics” for a description of the methodology used to calculate reserves life index.
36
Birchcliff Energy Ltd. RESERVES ON THE MONTNEY/DOIG RESOURCE PLAY
The following table summarizes the estimates of reserves attributable to Birchcliff’s horizontal wells on the Montney/Doig Resource
Play as contained in the 2016 Consolidated Reserves Report and the number of horizontal wells to which reserves were attributed:
Montney/Doig Resource Play Reserves Data(1)(2)
Shale Gas
(Bcf)
Light Crude Oil
and Medium Crude
Oil Combined
(Mbbls)
NGLs
(Mbbls)
Total
(Mboe)
Existing Horizontal Wells
and Future Horizontal
Well Locations
(Gross)
(Net)
2016
2015
2016
2015
2016
2015
2016
2015
2016
2015
2016
2015
764.1
525.8
6,036.5
597.8
18,572.5
4,154.7
151,964.1
92,379.7
281
185
275.7
184.9
Reserves
Category
Proved
Developed
Producing
Total Proved
2,734.5
1,842.0
14,400.5
736.1 48,808.2
14,020.3
518,965.8
321,752.4
736
516
721.7
505.2
Total
Proved Plus
Probable
4,274.8
2,945.7
25,307.2
1,313.8
87,687.7
24,551.9
825,454.6
516,821.4
1,000
723
974.4 698.8
(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, 2016, the estimated FDC for Birchcliff’s reserves on its Montney/Doig Resource Play is $0.9 million on a proved developed producing basis (as compared to $0.0 million
at December 31, 2015), $2,277.5 million on a proved basis (as compared to $1,623.7 million at December 31, 2015) and $3,680.9 million on a proved plus probable basis (as compared to
$2,667.7 million at December 31, 2015).
The following table sets forth the number of existing and potential future drilling locations by drilling interval to which proved plus
probable reserves were assigned in the Consolidated Reserves Report:
Existing and Potential Future Drilling Locations by Interval at December 31, 2016
Gross Number of
Horizontal Well Locations
Net Number of
Horizontal Well Locations
Average Proved Plus
Probable Reserves plus
Cumulative Production
(Bcfe)
Existing
Potential
Future
Existing
Potential
Future
Existing
Potential
Future
67
9
1
152
57
1
287
251
42
22
332
64
2
713
65.5
9.0
1.0
148.2
57.0
1.0
281.7
238.9
42.0
20.6
325.2
64.0
2.0
692.7
4.54
4.69
6.66
6.58
6.48
4.12
4.37
5.29
7.58
6.11
6.52
2.66
Interval
Basal Doig / Upper Montney
Montney D4
Montney D2
Montney D1 Gas
Montney D1 Oil
Montney C
Total(1)
(1) At December 31, 2016, Birchcliff had 287 (281.7 net) existing horizontal well locations; proved developed producing reserves were only assigned to 281 (275.7 net) well locations as six
wells were not producing at December 31, 2016. In addition, Birchcliff drilled 8 (8.0 net) Montney/Doig wells late in 2016 that had no reserves assigned at December 31, 2016, for a total
of 295 (289.7 net) wells drilled and cased as at December 31, 2016.
37
2016 Annual Report Corporate
Corporate
1,000
1,000
900
900
800
800
700
700
600
600
500
500
400
400
300
300
200
200
100
100
0
0
)
e
o
b
)
e
M
o
b
M
(
M
s
M
e
(
v
r
s
e
e
s
v
e
r
R
e
s
e
R
900,000
900,000
800,000
800,000
700,000
700,000
600,000
600,000
500,000
500,000
400,000
400,000
300,000
300,000
200,000
200,000
100,000
100,000
0
0
)
)
e
e
o
o
b
b
)
)
e
e
M
M
o
o
(
(
b
b
M
M
s
s
e
e
(
(
v
v
r
r
s
s
e
e
e
e
s
s
v
v
e
e
r
r
e
e
R
R
s
s
e
e
R
R
2010
2010
2011
2011
2012
2012
2013
2013
2014
2014
2015
2015
2016
2016
Montney
Montney
Montney/Doig Reserves
2010
2010
2011
2011
2012
2012
2013
2013
2014
2014
2015
2015
2016
2016
RESERVES ON THE CHARLIE LAKE LIGHT OIL RESOURCE PLAY – WORSLEY AREA
At December 31, 2016, Deloitte estimated that in the Worsley Charlie Lake light oil pool, Birchcliff had 7.6 MMboe of proved
developed producing reserves, 20.4 MMboe of proved reserves and 38.9 MMboe proved plus probable reserves.
Worsley
Worsley
Worsley Reserves
)
e
o
b
)
e
M
o
(
b
M
s
e
(
v
r
s
e
e
s
v
e
r
e
R
s
e
R
45,000
45,000
40,000
40,000
35,000
35,000
30,000
30,000
25,000
25,000
20,000
20,000
15,000
15,000
10,000
10,000
5,000
5,000
0
0
38
2010
2010
2011
2011
2012
2012
2013
2013
2014
2014
2015
2015
2016
2016
PDP
PDP
TP
TP
2P
2P
PDP
PDP
TP
TP
2P
2P
PDP
PDP
TP
TP
2P
2P
Birchcliff Energy Ltd.
2016 FINDING AND DEVELOPMENT COSTS
During 2016, Birchcliff’s F&D costs were $165.5 million and its FD&A costs were $759.0 million.
The following table sets forth Birchcliff’s estimates of its F&D costs per boe and FD&A costs per boe for 2016, 2015 and 2014,
excluding and including FDC:
Excluding FDC ($/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(2)(3)(4)
F&D – Proved
F&D – Proved Plus Probable
FD&A – Proved
FD&A – Proved Plus Probable
2016
$6.42
$1.57
$1.25
$9.32
$3.53
$2.33
$4.89
$4.43
$6.73
$5.58
2015
$8.11
$3.09
$2.06
$7.79
$2.96
$2.02
$2.41
$1.55
$2.28
$1.32
2014
$13.40
$8.29
$5.96
$12.81
$6.03
$4.19
$13.51
$12.57
$11.56
$10.45
Three Year
Average
$9.41
$3.46
$2.53
$9.82
$3.90
$2.62
$5.76
$5.00
$6.71
$5.59
(1) Please see “Advisories – Oil and Gas Metrics” for a description of the methodology used to calculate F&D and FD&A costs.
(2) 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.
(3) Includes the 2015 decrease in FDC from 2014 of $56.5 million on a proved basis and $85.4 million on a proved plus probable basis.
(4) Includes the 2014 increase in FDC from 2013 of $413.0 million on a proved basis and $671.9 million on a proved plus probable basis.
2016 RECYCLE RATIOS
The following table shows Birchcliff’s recycle ratios for operating and funds flow netbacks for 2016 and 2015, 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
F&D – Proved
FD&A – Proved
F&D – Proved Plus Probable
FD&A – Proved Plus Probable
Operating Netback(1)
Recycle Ratio
Funds Flow Netback(1)
Recycle Ratio
2016
2015
2016
2015
1.7
1.2
7.0
3.1
8.8
4.7
2.3
1.6
2.5
2.0
1.8
1.9
4.7
4.9
7.0
7.2
6.0
6.4
9.3
11.0
1.3
0.9
5.2
2.3
6.6
3.5
1.7
1.2
1.8
1.5
1.4
1.5
3.7
3.8
5.5
5.6
4.7
5.0
7.3
8.6
(1) Please see “Advisories” for a description of the methodology used to calculate F&D costs, FD&A costs and recycle ratios.
During 2016, the average WTI price of crude oil was US$43.32/bbl and the average price of natural gas at AECO was CDN$2.16/Mcf.
The operating netback was $11.01/boe in 2016, as compared to $14.52/boe in 2015. Funds flow netback was $8.18/boe in 2016,
as compared to $11.31/boe in 2015.
39
2016 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 its 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 environmental incident should it arise and we rigorously
conduct exercises and training for our staff.
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). The COR Health and Safety Auditing and the
COR Safety Program requires a commitment to continuous
improvement in the health, safety and environment management
practices, including sound planning and implementation. The
program is audited externally every three years and internally
every other year.
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 AER 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 pipeline Asset Integrity Coordinator
make use of databases and associated work tracking systems
to ensure that all integrity tasks (inspections, pigging, etc.)
are scheduled and completed according to 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 try to use recycled water for fracing operations.
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.
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 First Nations 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 2016, 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, we have helped raise
approximately $930,000 to support STARS Air Ambulance
in the Grande Prairie area, which is an important partner
in trauma care for the Grande Prairie region. Each year,
40
Birchcliff Energy Ltd. Birchcliff raises funds for the United Way and 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 where we operate.
TO DATE, BIRCHCLIFF HAS HELPED RAISE
$930,000
to support STARS AIR AMBULANCE in
the Grande Prairie area.
41
2016 Annual Report FINANCIALS
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 15, 2017. This MD&A and the audited financial statements with respect to the three and twelve months ended
December 31, 2016 (the “Reporting Periods”) as compared to the three and twelve months ended December 31, 2015 (the
“Comparable Prior Periods”) have 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 related
notes for the year ended December 31, 2016. All dollar amounts are expressed in Canadian currency, unless otherwise stated.
This MD&A uses “funds flow”, “funds flow from operations”, “funds flow per common share”, “netback”, “operating netback”,
“estimated operating netback”, “operating margin”, “total cash costs”, “adjusted working capital deficit” and “total debt”, which
do not have standardized meanings prescribed by generally accepted accounting principles (“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 information within the meaning of applicable Canadian securities laws. Such forward-
looking information is based upon certain expectations and assumptions and actual results may differ materially from those
expressed or implied by such forward-looking information. For further information regarding the forward-looking information
contained herein, including the assumptions underlying such forward-looking information, see “Advisories – Forward-Looking
Information” 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”
in this MD&A.
ABOUT BIRCHCLIFF
Birchcliff is a Calgary, Alberta based intermediate oil and natural gas company with operations concentrated in its one core area,
the Peace River Arch of Alberta, which is centred northwest of Grande Prairie, Alberta. Birchcliff’s common shares are listed for
trading on the Toronto Stock Exchange (the “TSX”) under the symbol “BIR” and are included in the S&P/TSX Composite Index.
Additional information relating to the Corporation, including its Annual Information Form for the financial year ended December 31,
2016, is available on the SEDAR website at www.sedar.com and on the Corporation’s website at www.birchcliffenergy.com.
HIGHLIGHTS FOR 2016
The year 2016 marked the completion of a transformational transaction for Birchcliff. On July 28, 2016, Birchcliff closed the
acquisition of significant petroleum and natural gas properties and related assets located in the Gordondale area of Alberta (the
“Gordondale Assets”) from a senior producer (the “Gordondale Acquisition”). The Gordondale Assets include high working interest
operated production and a large contiguous land base which is adjacent to Birchcliff’s existing Pouce Coupe properties. The
purchase price for the Gordondale Acquisition was $613.5 million, after closing adjustments and other related costs.
The Gordondale Acquisition was funded through a bought deal financing of 107,520,000 subscription receipts of the Corporation
(“Subscription Receipts”) at a price of $6.25 per Subscription Receipt (the “Public Offering”) and a private placement of 3,000,000
Subscription Receipts at a price of $6.25 per Subscription Receipt (the “Concurrent Private Placement”). The Public Offering
and the Concurrent Private Placement (collectively, the “Financings”) closed concurrently on July 13, 2016 and the aggregate gross
proceeds of $690.8 million were held in escrow pending completion of the Gordondale Acquisition. On July 28, 2016, Birchcliff
closed the Gordondale Acquisition and each Subscription Receipt was exchanged for one common share of the Corporation for
no additional consideration. The aggregate gross proceeds of the Financings were released from escrow to pay the balance of the
purchase price for the Gordondale Acquisition and the balance of the fees payable to the underwriters of the Public Offering, with
the remaining aggregate net proceeds applied to reduce indebtedness under the Corporation’s extendible revolving credit facilities
(the “Credit Facilities”).
43
2016 Annual Report Highlights for 2016 also include the following:
• Record annual average production of 49,236 boe/d, a 26% increase from 2015 annual average production of
38,950 boe/d.
• Funds flow of $147.4 million ($0.74/basic common share), an 8% decrease from $160.8 million ($1.06/basic
common share) in 2015.
• Net loss to common shareholders of $28.3 million ($0.14/basic common share), as compared to the net loss to
common shareholders of $16.2 million ($0.11/basic common share) in 2015.
• Operating costs of $4.18/boe, an 8% decrease from $4.54/boe in 2015.
• Long-term bank debt at December 31, 2016 was $572.5 million, an 8% decrease from $622.1 million at
December 31, 2015. Total debt at December 31, 2016 was $600.0 million, a 7% decrease from $643.6 million
at December 31, 2015.
• Net capital expenditures of $148.5 million, excluding the Gordondale Acquisition, and net capital expenditures of
$762.0 million, including the Gordondale Acquisition.
•
In connection with the closing of the Gordondale Acquisition, the Credit Facilities were amended to increase the
borrowing base to $950 million from $750 million.
Highlights for the fourth quarter of 2016 include the following:
• Record quarterly average production of 60,750 boe/d, a 50% increase from 40,445 boe/d in the fourth quarter
of 2015.
• Funds flow of $71.8 million ($0.27/basic common share), a 113% increase from $33.7 million ($0.22/basic
common share) in the fourth quarter of 2015.
• Net income to common shareholders of $11.1 million ($0.04/basic common share), as compared to the net loss
to common shareholders of $10.3 million ($0.07/basic common share) in the fourth quarter of 2015.
• Operating costs of $4.54/boe, a 9% increase from $4.16/boe in the fourth quarter of 2015.
• Net capital expenditures of $62.5 million.
2017 OUTLOOK
Birchcliff’s 2017 capital expenditure program of $355 million (the “2017 Capital Program”) includes total drilling and development
capital of $229.8 million and facilities and infrastructure capital of $85.6 million. The 2017 Capital Program contemplates the
drilling, completing, equipping and bringing on production of a total of 46 (46.0 net) wells and also includes the remaining portion
of the capital associated with the completion, equipping and/or bringing on production of 10 wells drilled in 2016. Accordingly, it
is expected that a total of 56 (56.0 net) wells will be brought on production during 2017.
Birchcliff expects its annual average production in 2017 to be between 70,000 and 74,000 boe/d and its fourth quarter average
production in 2017 to be 80,000 to 82,000 boe/d.
Birchcliff has entered into natural gas hedging contracts for 187,600 GJ/d (163,600 Mcf/d) at an average AECO price of
CDN$3.02/GJ ($3.46/Mcf) for 2017. Birchcliff has also entered into financial swaps for 1,500 bbls/d of crude oil at an average
price of CDN$69.90/bbl for the period from January 1, 2017 to December 31, 2017. With approximately 50% of the Corporation’s
forecast 2017 natural gas production hedged, the Corporation expects to fully fund the 2017 Capital Program out of internally
generated funds flow. This assumes a forecast average WTI price of US$55.00/bbl of oil and a forecast average AECO price of
CDN$3.00/GJ of natural gas during 2017 and that the Corporation’s production targets for 2017 are achieved.
Birchcliff’s Board of Directors approved a quarterly dividend policy for the Corporation’s common shares in November 2016. On
March 1, 2017, the Board of Directors declared the first dividend payable under this policy in respect of the quarter ending March
31, 2017 in the amount of $0.025 per common share. This dividend is payable on March 31, 2017 to shareholders of record at
the close of business on March 15, 2017 and has been designated as an “eligible dividend” for the purposes of the Income Tax Act
(Canada).
Birchcliff’s 2016 results showcased it as one of the industry leading low-cost producers and finders of natural gas, oil and NGLs
in the Peace River Arch of Alberta. The Corporation is focused on executing the 2017 Capital Program and completing the Phase
V and VI expansions of its 100% owned and operated natural gas plant located in the Pouce Coupe area (the “PC Gas Plant”), all
with the goal of producing in excess of 100,000 boe/d by the end of 2018.
See “Advisories – Forward-Looking Information”.
44
Birchcliff Energy Ltd. 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)
Funds flow from operations ($000s)
Per common share – basic ($)
Per common share – diluted ($)
Net income (loss) ($000s)
Net income (loss) to common shareholders ($000s)
Per common share – basic ($)
Per common share – diluted ($)
Capital expenditures, net ($000s)
Operating costs ($ per boe)
Total assets ($000s)
Adjusted working capital deficit ($000s)
Non-revolving term credit facilities ($000s)
Revolving term credit facilities ($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
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 ($000s)
Per Series C preferred share ($)
(1) Excludes the effect of hedges using financial instruments.
2016
49,236
337,586
51.40
2.41
31.23
18.73
2015
38,950
317,304
53.68
2.90
50.76
22.31
2014
33,734
472,888
92.39
4.74
85.13
38.39
147,443
160,756
300,498
0.74
0.73
(24,335)
(28,335)
(0.14)
(0.14)
762,030
4.18
2,710,457
27,495
-
572,517
600,012
264,042
279,881
199,581
202,686
2,000
4,000
2.00
2,000
3,500
1.75
1.06
1.04
(12,160)
(16,160)
(0.11)
(0.11)
247,207
4.54
2,025,373
21,538
-
622,074
643,612
152,308
167,817
152,286
154,078
2,000
4,000
2.00
2,000
3,500
1.75
2.03
1.97
114,304
110,304
0.75
0.72
450,932
5.22
1,918,680
76,712
129,476
339,557
545,745
152,214
166,302
147,764
152,243
2,000
4,000
2.00
2,000
3,500
1.75
In 2016, annual average production was 49,236 boe/d, up 26% from 2015 and up 46% from 2014. These production increases were
largely attributed to the production volumes acquired pursuant to the Gordondale Acquisition, as well as the success of Birchcliff’s
capital drilling program since 2014 which resulted in increased incremental production from new Montney/Doig horizontal natural gas
wells producing to the PC Gas Plant.
Birchcliff generated lower funds flow in 2016 as compared to the prior two years. This was largely due to a lower average sales price of
$18.73/boe in 2016, down 16% from 2015 and down 51% from 2014, primarily offset by the production volumes acquired pursuant to
the Gordondale Acquisition. Realized oil wellhead prices averaged $51.40/bbl in 2016, down 4% from 2015 and down 44% from 2014.
Realized natural gas wellhead prices averaged $2.41/Mcf in 2016, down 17% from 2015 and down 49% from 2014. The decline in the
corporate realized sales price is primarily due to a supply/demand imbalance of oil and natural gas that has resulted in above average
inventory levels in North America over the last two years.
Birchcliff recorded a net loss to common shareholders of $28.3 million ($0.14/basic common share) in 2016 as compared to a net loss
to common shareholders of $16.2 million ($0.11/basic common share) in 2015 and net income to common shareholders of $110.3
million ($0.75/basic common share) in 2014. The change from the net income position in 2014 was largely due to the year-over-year
decreases in funds flow from operations resulting from lower average commodity prices and higher depletion expense resulting from
increased production volumes and was also impacted by gains and losses on the sale of assets recorded in the last three years.
45
2016 Annual Report Net capital expenditures in 2016 were significantly higher as compared to 2015 and 2014, primarily due to the Gordondale
Acquisition that was completed in July 2016 for cash consideration of $613.5 million, after closing adjustments and other related
costs. Excluding the Gordondale Acquisition, capital expenditures have generally decreased year-over-year as a result of general
economic conditions and depressed commodity prices. 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 Montney/Doig horizontal natural gas wells that
have been tied into the PC Gas Plant; (ii) the Phase V expansion of the PC Gas Plant (including related wells and infrastructure) which
will increase the natural gas processing capacity from 180 MMcf/d to a licensed processing capacity of 260 MMcf/d; and (iii) the
Gordondale Acquisition.
FUNDS FLOW FROM OPERATIONS
($000s)
Funds flow from operations
Per common share – basic ($)
Per common share – diluted ($)
Three months ended
December 31,
Twelve months ended
December 31,
2016
71,806
0.27
0.27
2015
2016
2015
33,697
147,443
160,756
0.22
0.22
0.74
0.73
1.06
1.04
Funds flow increased from the three month Comparable Prior Period largely due to higher average realized commodity prices and
the production volumes acquired pursuant to the Gordondale Acquisition. During the three month Reporting Period, realized oil
prices increased 23% and realized natural gas prices increased 24% from the Comparable Prior Period. Birchcliff’s production for
the three month Reporting Period averaged 60,750 boe/d, an increase of 50% from the Comparable Prior Period.
Funds flow decreased from the twelve month Comparable Prior Period largely due to lower average realized commodity prices,
primarily offset by the production volumes acquired pursuant to the Gordondale Acquisition. During the twelve month Reporting
Period, realized oil prices were down 4% and realized natural gas prices were down 17% from the twelve month Comparable Prior
Period. Birchcliff’s production for the twelve month Reporting Period averaged 49,236 boe/d, an increase of 26% from the twelve
month Comparable Prior Period.
The following table provides a breakdown of total cash costs on a per boe basis and the percentage change period-over-period:
($/boe)
Royalty expense
Operating expense
Transportation and marketing expense
General & administrative expense, net
Interest expense
Total cash costs
Three months ended
December 31,
2015 % Change
0.94
4.16
2.31
2.01
1.80
11.22
94%
9%
5%
(41%)
(22%)
1%
Twelve months ended
December 31,
2015 % Change
0.81
4.54
2.45
1.61
1.60
11.01
43%
(8%)
(3%)
(26%)
5%
(4%)
2016
1.16
4.18
2.38
1.19
1.68
10.59
2016
1.82
4.54
2.42
1.19
1.40
11.37
46
Birchcliff Energy Ltd. On a per boe basis, total cash costs for the three month Reporting Period increased 1% compared to the Comparable Prior Period,
primarily driven by higher royalty, operating and transportation and marketing expenses associated with the Gordondale Assets
and partially offset by lower general and administrative and interest expenses.
On a per boe basis, total cash costs for the twelve month Reporting Period were down 4% from the twelve month Comparable
Prior Period, primarily driven by lower operating, transportation and marketing and general and administrative expenses and
partially offset by higher royalty and interest expenses.
See “Discussion of Operations” in this MD&A for further details regarding the period-over-period movement in commodity prices,
production volumes and cash costs discussed above.
NET INCOME (LOSS) TO COMMON SHAREHOLDERS
($000s)
Net income
Net income to common shareholders(1)
Per common share – basic ($)
Per common share – diluted ($)
Three months ended
December 31,
Twelve months ended
December 31,
2016
12,085
11,085
0.04
0.04
2015
2016
(9,322)
(24,335)
(10,322)
(28,335)
(0.07)
(0.07)
(0.14)
(0.14)
2015
(12,160)
(16,160)
(0.11)
(0.11)
(1) Net income (loss) to common shareholders is calculated by adjusting net income (loss) for 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.
For the three month Reporting Period, Birchcliff realized net income to common shareholders of $11.1 million compared to a net
loss to common shareholders of $10.3 million in the Comparable Prior Period. The change to a net income position was primarily
due to higher funds flow from operations, offset by an increase in aggregate depletion costs resulting from production volumes
acquired pursuant to the Gordondale Acquisition and a $9.6 million non-cash “marked to market” unrealized loss recorded in the
three month Reporting Period in respect of Birchcliff’s commodity risk management contracts outstanding at December 31, 2016.
For the twelve month Reporting Period, Birchcliff realized a net loss to common shareholders of $28.3 million compared to
the net loss to common shareholders of $16.2 million in the Comparable Prior Period. The increase in the net loss to common
shareholders from the twelve month Comparable Prior Period was largely due to lower funds flow from operations, a $10.9 million
non-cash loss on the sale of assets in the Progress area that was completed in the second quarter of 2016 and a $9.4 million
unrealized loss on risk management contracts recorded in the twelve month Reporting Period.
The net loss in the Comparable Prior Periods included a non-cash deferred income tax expense adjustment in the amount of
$7.8 million that was recorded in the second quarter of 2015 as a result of the 2015 change in the Alberta corporate income tax
rate from 10% to 12% and non-cash deferred income tax expense adjustment in the amount of $10.2 million that was recorded
in the three month Comparable Prior Period in connection with the denial of the Veracel tax pools by the Tax Court of Canada
(the “Trial Court”). For more information on these deferred income tax adjustments in 2015, see “Income Taxes” in this MD&A.
47
2016 Annual Report PC GAS PLANT NETBACKS
During the twelve month Reporting Period, Birchcliff processed approximately 68% of its total corporate natural gas production
and 59% of its total corporate production through the PC Gas Plant, with an average plant and field operating cost of $0.25/Mcfe
($1.49/boe). The estimated operating netback at the PC Gas Plant was $1.90/Mcfe ($11.38/boe), resulting in an operating margin
of 75% in 2016.
The following table details Birchcliff’s annual net production and estimated operating netback for wells producing to the PC Gas
Plant, on a production month basis:
Average daily production, net to Birchcliff:
Natural gas (Mcf)
Oil & NGLs (bbls)
Total boe
Sales liquids yield (bbls/MMcf)
% of corporate natural gas production
% of corporate production
AECO – C daily ($/Mcf)
Netback and cost:
Petroleum and natural gas revenue (1)
Royalty expense
Operating expense (2)
Transportation and marketing expense
Estimated operating netback
Operating margin
(1) Excludes the effect of hedges using financial instruments.
(2) Represents plant and field operating costs.
Twelve months ended
December 31, 2016
Twelve months ended
December 31, 2015
168,444
960
29,034
5.7
68%
59%
$/boe
15.21
(0.38)
(1.49)
(1.96)
$11.38
75%
$2.69
$/Mcfe
3.17
(0.11)
(0.31)
(0.31)
$2.44
77%
163,641
1,287
28,560
7.9
81%
73%
$/boe
19.03
(0.63)
(1.90)
(1.88)
$14.62
77%
$2.16
$/Mcfe
2.54
(0.06)
(0.25)
(0.33)
$1.90
75%
The decrease in the percentage of corporate natural gas production and corporate production producing to the PC Gas Plant for the
twelve month Reporting Period is primarily due to the liquids-rich production acquired pursuant to the Gordondale Acquisition.
DISCUSSION OF OPERATIONS
The following table sets forth Birchcliff’s P&NG revenues, production and percentage of production and sales price by product category:
Three months ended
December 31, 2016
Three months ended
December 31, 2015
Light oil (bbls)
Natural gas (Mcf)
NGLs (bbls)(2)
Total
Revenue(1)
($000s)
Average
Daily
Production
26,018
88,135
21,254
4,656
289,587
7,830
(%)
8
79
13
Total P&NG sales (boe)
135,407
60,750
100
Royalty revenue
P&NG revenues
50
135,457
Average
($/unit)
60.75
3.31
29.50
24.23
0.01
Total
Revenue
($000s)
16,032
51,792
7,625
75,449
27
24.24
75,476
Average
Daily
Production
3,530
211,127
1,727
(%)
9
87
4
40,445
100
Average
($/unit)
49.36
2.67
47.98
20.28
-
20.28
(1) Excludes the effect of hedges using financial instruments.
(2) NGLs prices are Birchcliff’s realized prices adjusted for fractionation costs associated with the Gordondale Assets.
48
Birchcliff Energy Ltd.
Twelve months ended
December 31, 2016
Twelve months ended
December 31, 2015
Light oil (bbls)
Natural gas (Mcf)
NGLs (bbls)(2)
Total P&NG sales (boe)
Royalty revenue
P&NG revenues
70,144
218,432
48,901
337,477
109
337,586
Total
Revenue(1)
($000s)
Average
Daily
Production
Average
($/unit)
Total
Revenue
($000s)
Average
Daily
Production
3,729
247,373
4,279
(%)
8
83
9
51.40
72,636
2.41
213,494
31.23
18.73
-
30,991
317,121
183
18.73
317,304
3,707
201,418
1,673
(%)
10
86
4
Average
($/unit)
53.68
2.90
50.76
22.31
0.01
22.32
49,236
100
38,950
100
(1) Excludes the effect of hedges using financial instruments.
(2) NGLs prices are Birchcliff’s realized prices adjusted for fractionation costs associated with the Gordondale Assets.
The increase in P&NG revenues from the three month Comparable Prior Period was largely attributable to increased production
volumes acquired pursuant to the Gordondale Acquisition and higher average realized commodity prices in the three month
Reporting Period.
The increase in P&NG revenues from the twelve month Comparable Prior Period was largely attributable to increased production
volumes acquired pursuant to the Gordondale Acquisition and offset by lower average realized commodity prices in the twelve
month Reporting Period.
Petroleum and Natural Gas Revenues
Production
Production averaged 60,750 boe/d in the three month Reporting Period and 49,236 boe/d in the twelve month Reporting Period,
a 50% and 26% increase, respectively, from the Comparable Prior Periods. The increase in production from the Comparable Prior
Periods was largely due to the production volumes acquired pursuant to the Gordondale Acquisition and incremental production
added from new Montney/Doig horizontal natural gas wells, partially offset by natural production declines. Birchcliff’s quarterly
average production for the three month Reporting Period was slightly below its guidance of 62,000 to 63,000 boe/d and its
annual average production for the twelve month Reporting Period was within its guidance of 49,000 to 51,000 boe/d. Birchcliff’s
production was adversely impacted by transportation service curtailments on TransCanada’s NGTL System and by unplanned
downtime and maintenance activities in its Worsley area during the three month Reporting Period.
The production volumes acquired from the Gordondale Assets averaged approximately 22,631 boe/d in the three month Reporting
Period and reflect the first full quarter of production from the Gordondale Assets. The Gordondale Assets increased Birchcliff’s
average daily production for the twelve month Reporting Period by approximately 9,806 boe/d, which includes production from
July 28, 2016 to December 31, 2016.
Production attributed to the Gordondale Assets has been naturally declining since the Corporation acquired the assets in
July 2016. No new Montney horizontal oil and gas wells were brought on-stream in the Gordondale area in 2016. In the three
month Reporting Period, Birchcliff drilled and cased its first wells in the Gordondale area acquired pursuant to the Gordondale
Acquisition, consisting of six 100% wells (three Montney D2 horizontal oil wells and three Montney D1 horizontal liquids-rich
natural gas wells). These wells were brought on-stream in the first quarter of 2017.
Production consisted of approximately 79% natural gas, 8% light oil and 13% NGLs in the three month Reporting Period as
compared to 87% natural gas, 9% light oil and 4% NGLs in the Comparable Prior Period. Production consisted of 83% natural
gas, 8% light oil and 9% in the twelve month Reporting Period as compared to 86% natural gas, 10% light oil and 4% NGLs in
the Comparable Prior Period. The decrease in corporate natural gas weighting in the Reporting Periods is attributed to the
production volumes acquired pursuant to the Gordondale Acquisition, which also resulted in the increase in the corporate NGLs
weighting in the three month Reporting Period. Production from the Gordondale Assets during the three month Reporting
Period consisted of approximately 59% natural gas, 13% light oil and 28% NGLs in the three month Reporting Period. The higher
weighting of NGLs is a reflection of the liquids-rich nature of the Montney/Doig Resource Play in the Gordondale area.
49
2016 Annual Report
Commodity prices
Birchcliff sells the majority of its light crude oil on a spot basis and the majority of its natural gas production for prices based
on the AECO natural gas spot price. The average realized price 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 and transportation and product quality differentials.
The average benchmark prices for crude oil are impacted by global and regional events that dictate the level of supply and
demand for these commodities. The principal benchmark trading exchanges that Birchcliff compares its oil price to are the WTI
oil spot price and the Canadian Edmonton Par spot price. The differential between the WTI oil spot price and Canadian Edmonton
Par spot 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 lack of pipeline infrastructure connecting to key consuming
oil markets.
Canadian AECO 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, changing demographics, economic
growth, underground storage levels, net import and export markets, pipeline takeaway capacity, cost of competing fuels, drilling
and completion rates and efficiencies in extracting natural gas from North American natural gas basins.
The following table sets forth the average benchmark prices and Birchcliff’s average realized sales price:
Average benchmark prices:
Light oil – WTI Cushing ($USD/bbl)
Light oil – Edmonton Par ($/bbl)
Natural gas – AECO – C daily ($/MMbtu)(1)
Exchange rate – (USD$/CDN$)
Birchcliff’s average realized sales price(2):
Light oil ($/bbl)
Natural gas ($/Mcf)
NGLs ($/bbl)
Average corporate realized sales price ($/boe)
(1) $1.00/MMbtu = $1.00/Mcf based on a standard heat value Mcf.
(2) Excludes the effect of hedges using financial instruments.
Three months ended
December 31,
Twelve months ended
December 31,
2016
2015
2016
2015
49.29
61.66
3.09
1.33
60.75
3.31
29.50
24.23
42.18
53.78
2.46
1.34
49.36
2.67
47.98
20.28
43.32
53.90
2.16
1.33
51.40
2.41
31.23
18.73
48.80
57.76
2.69
1.29
53.68
2.90
50.76
22.31
The average corporate realized sales price was $24.23/boe for the three month Reporting Period, a 19% increase from the
Comparable Prior Period. This increase was largely due to higher oil and natural gas spot prices in the three month Reporting
Period and a higher average realized sales price attributable to the liquids-rich Gordondale Assets.
The average corporate realized sales price was $18.73/boe for the twelve month Reporting Period, a 16% decrease from the
twelve month Comparable Prior Period. This decrease was largely due to a lower average spot price for AECO natural gas and
WTI USD oil which resulted from a supply/demand imbalance for these commodities in North America during the twelve month
Reporting Period. This was partially offset by a higher average realized sales price attributable to the liquids-rich Gordondale
Assets in the three month Reporting Period.
The Gordondale Assets received a higher average realized sales price compared to the Corporation’s largest producing asset
(the PC Gas Plant and related wells and infrastructure), largely as a result of higher volume weighting of NGLs produced in the
Gordondale area which received a higher value on a per boe basis than the Corporation’s natural gas sales. The higher weighting
of NGLs in the total corporate production mix improved Birchcliff’s overall average realized sales price. During the three month
Reporting Period, the average realized oil and natural gas sales price for the Gordondale Assets was approximately $25.67/boe as
compared to $24.23/boe on a corporate basis.
With respect to the Gordondale Assets, NGLs (ethane, propane, butane) are substantially recovered from the raw natural gas
stream at a third-party deep cut natural gas processing facility which reduces the heat content value and realized sales price of
natural gas from the area. During the three month Reporting Period, Birchcliff’s heat content value for the Gordondale Assets
was 39.1 MJ/m3 as compared to the corporate average of approximately 40.1 MJ/m3.
50
Birchcliff Energy Ltd. During the Reporting Periods, the average realized NGLs price on a corporate basis was lower than the Comparable Prior Periods
primarily due to increased production weighting of ethane, propane and butane in the Reporting Periods, which typically receive
a price below condensate (C5+). During the Comparable Prior Periods, NGLs were comprised of substantially all condensate (C5+).
Birchcliff’s realized corporate natural gas sales price at the wellhead averaged $3.31/Mcf for the three month Reporting Period
and $2.41/Mcf for the twelve month Reporting Period which were higher than the average posted benchmark price for the
Reporting Periods. Birchcliff receives premium pricing for its natural gas production due to its high heat content from its
properties in the Pouce Coupe area. The following table sets forth Birchcliff’s average realized sales price and heat content
premium from its natural gas production:
AECO – C daily ($/MMbtu)(1)
Heat content premium
Average realized natural gas sales price ($/Mcf)
(1) $1.00/MMbtu = $1.00/Mcf based on a standard heat value Mcf.
Commodity Price Risk Management
Three months ended
December 31,
Twelve months ended
December 31,
2016
3.09
0.22
3.31
2015
2.46
0.21
2.67
2016
2.16
0.25
2.41
2015
2.69
0.21
2.90
The Corporation maintains an ongoing commodity price risk management program in order to reduce volatility in its financial
results and to protect a portion of its funds flow, its capital expenditure programs and its dividend payments. As a part of this, the
Corporation utilizes various financial derivative and physical delivery sales contracts. The Board has authorized the Corporation
to hedge such portion of its forecast production as is permitted by the Corporation’s Credit Facilities, which permit the Corporation to
hedge up to 65% of its forecast production over the following four fiscal quarters for terms not exceeding three years.
Birchcliff’s strategy for 2017 is to hedge approximately 50% of its estimated annual average natural gas production and up to
50% of its oil production using a combination of financial derivatives and physical sales contracts, depending on its outlook for
commodity prices. As at March 15, 2017, the Corporation has hedged approximately 50% of its forecast natural gas production
for 2017 and approximately 20% of its forecast oil production. Birchcliff has committed under its financial and physical sales
contracts to the sale of 187,600 GJ/d of natural gas in 2017 at an estimated average wellhead price of $3.46/Mcf ($3.02/GJ).
Financial derivative contracts
As at December 31, 2016, the Corporation had the following financial derivatives in place:
Product
Type of
contract
Notional quantity
Term(1)
Contract price
Natural Gas
Financial swap
40,000 GJ/d
Natural Gas
Financial swap
20,000 GJ/d
Natural Gas
Financial swap
10,000 GJ/d
Natural Gas
Financial swap
10,000 GJ/d
Crude oil
Financial swap
1,500 bbls/d
January 1, 2017 –
December 31, 2017
January 1, 2017 –
December 31, 2017
October 1, 2017 –
December 31, 2017
October 1, 2017 –
December 31, 2017
January 1, 2017 –
December 31, 2017
AECO CDN $2.97/GJ
AECO CDN $2.98/GJ
AECO CDN $3.35/GJ
AECO CDN $3.40/GJ
WTI CDN $69.90/bbl
Fair value liabilities(2)
Fair value
($000s)
4,345
2,042
19
(17)
3,044
9,433
(1) Transactions with common terms and the same counterparty have been aggregated and presented at the weighted average price, where applicable.
(2) 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 “marked to market” fair value basis at December 31, 2016, 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.
51
2016 Annual Report The fair value liabilities of the Corporation’s financial derivative contracts at December 31, 2016 was $9.4 million. As of December 31,
2016, if the future strip prices for AECO natural gas had been CDN$0.10/GJ higher, with all other variables held constant, the after
tax net loss in 2016 would have increased by $2.4 million. As of December 31, 2016, if the future strip prices for WTI crude oil
had been CDN$1.00/bbl higher, with all other variables held constant, the after tax net loss in 2016 would have increased by
$0.4 million.
The following table provides a summary of the realized and unrealized gains (losses) on the Corporation’s financial derivative
contracts:
Three months ended
December 31,
Twelve months ended
December 31,
2016
2015(1)
2016
2015(1)
Realized gain (loss) on derivatives
Unrealized (loss) on derivatives
($000s)
(134)
(9,603)
($/boe)
(0.02)
(1.72)
($000s)
($/boe)
($000s)
($/boe)
($000s)
($/boe)
-
-
-
-
802
(9,433)
0.04
(0.52)
-
-
-
-
(1) During 2015, the Corporation did not have any financial derivative contracts in place.
There were no financial derivative contracts entered into subsequent to December 31, 2016.
Physical delivery sales contracts
As at December 31, 2016 the Corporation had the following physical delivery sales contracts in place:
Product
Natural Gas
Type of
contract
Fixed price
Volume
20,000 GJ/d
Natural Gas
Fixed price
20,000 GJ/d
Natural Gas
Fixed price
20,000 GJ/d
Natural Gas
Fixed price
10,000 GJ/d
Natural Gas
Fixed price
50,000 GJ/d
Natural Gas
Fixed price
10,000 GJ/d
Term(1)
Contract price
January 1, 2017 –
December 31, 2017
January 1, 2017 –
December 31, 2017
January 1, 2017 –
December 31, 2017
January 1, 2017 –
December 31, 2017
January 1, 2017 –
December 31, 2017
October 1, 2017 –
December 31, 2017
AECO CDN$2.99/GJ
AECO CDN$2.98/GJ
AECO CDN$3.00/GJ
AECO CDN$3.00/GJ
AECO CDN$3.05/GJ
AECO CDN$3.35/GJ
(1) Transactions with common terms and the same counterparty have been aggregated and presented at the weighted average price, where applicable.
There were no physical delivery sales contracts entered into subsequent to December 31, 2016. The Corporation’s physical
delivery sales contracts are considered normal executory sales contracts and are not recorded at fair value.
52
Birchcliff Energy Ltd. Royalties
The following table details Birchcliff’s royalty expense:
Oil & natural gas royalties ($000s)(1)
Oil & natural gas royalties ($/boe)
Effective royalty rate (%)(2)
Three months ended
December 31,
Twelve months ended
December 31,
2016
10,177
1.82
8%
2015
3,499
0.94
5%
2016
20,911
1.16
6%
2015
11,548
0.81
4%
(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.
Birchcliff’s aggregate royalty expense in the three month Reporting Period increased from the Comparable Prior Period primarily
due to increased oil and NGLs production from the Gordondale Assets and higher average realized commodity prices during the
three month Reporting Period and the effect these higher prices have on the sliding scale royalty calculation under the previous
Alberta Royalty Framework (the “Previous Framework”).
Birchcliff’s aggregate royalty expense in the twelve month Reporting Period increased from the Comparable Prior Period primarily
due to increased oil and NGLs production attributable to the Gordondale Assets, partially offset by lower average realized commodity
prices during the twelve month Reporting Period and the effect these lower prices have on the sliding scale royalty calculation.
The increase in the effective royalty rates from the Comparable Prior Periods were due to higher NGLS weighting from the
Gordondale Assets which generally have higher sliding scale royalty rates under the Previous Framework. During the three month
Reporting Period, the effective royalty rate for the Gordondale Assets was approximately 13%.
The Government of Alberta announced a new Modernized Royalty Framework (the “MRF”) on January 29, 2016 and on April 21, 2016
provided additional royalty details and technical formulas for the MRF. Production from wells drilled prior to January 1, 2017 will
continue under the Previous Framework for 10 years before transitioning to the MRF. Wells drilled after January 1, 2017 will pay
a 5% flat royalty until revenues exceed a normalized well cost allowance, which will be based on vertical well depth, lateral length
(for horizontal wells) and total proppant used in the fracking of the well, after which royalty rates will range between 5% and 40%
depending on commodity prices.
On July 12, 2016, the Government of Alberta announced that operators could apply to opt into the MRF prior to the implementation
date of January 1, 2017, and thus gain earlier access to the new program. In 2016, Birchcliff applied for early access to the MRF
and received approval from the Alberta Energy Regulator (the “AER”) for six wells.
53
2016 Annual Report Operating Costs
The following table provides a breakdown of Birchcliff’s operating costs:
Three months ended
December 31,
Twelve months ended
December 31,
2016
2015
2016
2015
($/boe)
($000s)
($/boe)
($000s)
Field operating costs
Recoveries
Field operating costs, net
Expensed workovers and other
Operating costs
($000s)
25,786
(429)
25,357
28
25,385
4.61
(0.08)
4.53
0.01
4.54
15,711
(385)
15,326
143
15,469
4.22
76,706
($/boe)
4.26
($000s)
65,281
(0.10)
(1,700)
(0.09)
(1,500)
4.12
0.04
4.16
75,006
245
75,251
4.17
0.01
4.18
63,781
730
64,511
($/boe)
4.59
(0.10)
4.49
0.05
4.54
On an aggregate basis, operating costs increased in the Reporting Periods as compared to the Comparable Prior Periods largely
due to additional operating, processing and service costs associated with the production volumes acquired pursuant to the
Gordondale Acquisition.
On a per unit basis, operating costs during the Reporting Periods were reduced by the continued cost benefits achieved from
processing incremental volumes of natural gas at the PC Gas Plant, lower service costs resulting from reduced industry activity
and various cost reductions and infrastructure optimization initiatives implemented by the Corporation, and were increased by the
higher operating cost structure associated with the Gordondale Assets. The Gordondale Assets have a higher cost structure
primarily resulting from higher NGLs production weighting and additional fees incurred to process natural gas from the Gordondale
Assets at third party deep cut facilities. During the three month Reporting Period, the operating costs for the liquids-rich
Gordondale Assets averaged approximately $6.11/boe as compared to $4.54/boe on a corporate basis. Birchcliff is currently
working on reducing the overall operating cost structure of the Gordondale Assets.
On a production month basis, operating costs averaged approximately $1.49/boe at the PC Gas Plant during the twelve month
Reporting Period, down 22% from $1.90/boe in the Comparable Prior Period.
Transportation and Marketing Expenses
The following table details Birchcliff’s transportation and marketing expenses:
Three months ended
December 31,
Twelve months ended
December 31,
2016
2015
2016
2015
Transportation and marketing expenses
($000s)
13,489
($/boe)
($000s)
($/boe)
($000s)
($/boe)
($000s)
2.42
8,603
2.31
42,989
2.38
34,804
($/boe)
2.54
The increase in aggregate transportation and marketing costs from the Comparable Prior Periods was largely due to an increase in
trucking and pipeline transportation costs associated with production from the Gordondale Acquisition and increased firm service
commitments on TransCanada’s NGTL System, partially offset by lower oil trucking service costs resulting from reduced industry
activity in the Reporting Periods. Transportation and marketing expenses for the Gordondale Assets for the three month Reporting
Period were $2.42/boe.
54
Birchcliff Energy Ltd. Operating Netbacks
The following table details Birchcliff’s net production and operating netback for the Montney/Doig Resource Play, the Worsley
Charlie Lake Light Oil Resource Play and on a corporate basis:
Montney/Doig Resource Play
Average daily production, net:
Natural gas (Mcf)
Oil & NGLs (bbls)
Total boe
% of corporate production(1)
Netback and cost ($/boe):
Petroleum and natural gas revenue(2)
Royalty expense
Operating expense, net of recoveries
Transportation and marketing expense
Operating netback
Worsley Charlie Lake Light Oil Resource Play
Average daily production, net:
Natural gas (Mcf)
Oil & NGLs (bbls)
Total boe
% of corporate production(1)
Netback and cost ($/boe):
Petroleum and natural gas revenue(2)
Royalty expense
Operating expense, net of recoveries
Transportation and marketing expense
Operating netback
Total Corporate
Average daily production, net:
Natural gas (Mcf)
Oil & NGLs (bbls)
Total boe
Netback and cost ($/boe)
Petroleum and natural gas revenue(2)
Royalty expense
Operating expense, net of recoveries
Transportation and marketing expense
Operating netback
Three months ended
December 31,
Twelve months ended
December 31,
2016
2015
2016
2015
281,680
195,262
237,439
186,260
10,842
57,789
95%
23.38
(1.74)
(4.05)
(2.26)
15.33
3,360
1,523
2,082
3%
47.73
(3.58)
(16.44)
(6.80)
20.91
289,587
12,484
60,750
24.23
(1.82)
(4.54)
(2.42)
15.45
1,929
34,473
85%
17.89
(0.61)
(2.92)
(1.85)
12.51
8,054
2,708
4,050
10%
37.41
(3.12)
(11.10)
(5.99)
17.20
5,737
45,311
92%
17.48
(1.08)
(3.53)
(2.14)
10.73
5,318
2,037
2,923
6%
37.19
(2.19)
(11.80)
(6.19)
17.01
211,127
247,373
5,257
8,007
40,445
49,236
20.28
(0.94)
(4.16)
(2.31)
12.87
18.73
(1.16)
(4.18)
(2.38)
11.01
1,846
32,890
84%
19.43
(0.47)
(3.22)
(1.94)
13.80
8,497
2,819
4,236
11%
40.58
(2.89)
(10.48)
(6.06)
21.15
201,418
5,380
38,950
22.32
(0.81)
(4.54)
(2.45)
14.52
(1) Production from Birchcliff’s other conventional oil and natural gas properties were not individually significant during the Reporting Periods and Comparable Prior Periods.
(2) Excludes the effect of hedges using financial instruments.
55
2016 Annual Report Montney/Doig Resource Play
Birchcliff’s production from the Montney/Doig Resource Play was 57,789 boe/d in the three month Reporting Period and 45,311
boe/d in the twelve month Reporting Period, a 68% and 38% increase, respectively, from the Comparable Prior Periods. This
increase was largely due to the production volumes associated with the Gordondale Assets which, on average for the periods,
accounted for approximately 39% and 22% of the total production from the Montney/Doig Resource Play during the three and
twelve month Reporting Periods, respectively.
Birchcliff’s recoveries of NGLs from its Montney/Doig Resource Play were 38.5 bbls/MMcf in the three month Reporting Period
and 24.2 bbls/MMcf in the twelve month Reporting Period as compared to 9.9 bbls/MMcf in the Comparable Prior Periods.
Of the 38.5 bbls/MMcf of NGLs produced in the three month Reporting Period, approximately 19.6 bbls/MMcf (51%) were high
value oil and condensate (C5+). Of the 24.2 bbls/MMcf of NGLs produced in the twelve month Reporting Period, approximately
14.4 bbls/MMcf (60%) were high value oil and condensate (C5+). The increase in NGLs recoveries during the Reporting Periods
can be attributed to the NGLs production volumes acquired pursuant to the Gordondale Acquisition. Any NGLs not recovered
from the raw natural gas stream increases the heat content value of Birchcliff’s sales gas and the realized price.
Birchcliff’s operating netback from the Montney/Doig Resource Play was $15.33/boe ($2.56/Mcfe) in the three month Reporting
Period and $10.73/boe ($1.79/Mcfe) in the twelve month Reporting Period, an increase of 23% and a decrease of 22%,
respectively, from the Comparable Prior Periods.
The increase in the operating netback from the three month Comparable Prior Period was largely due to higher realized prices
received for Birchcliff’s oil and natural gas production offset by higher per boe royalties, operating and transportation and
marketing costs mainly associated with the Gordondale Assets.
The decrease in the operating netback from the twelve month Comparable Prior Period was largely due to lower realized prices
received for Birchcliff’s oil, natural gas and NGLs production and higher per boe royalties, operating and transportation and
marketing expenses mainly associated with the Gordondale Assets.
The Gordondale Assets have a higher cost structure primarily resulting from higher production weighting to oil and NGLs and
additional fees incurred to process natural gas from the Gordondale Assets at third party deep cut facilities.
Worsley Charlie Lake Light Oil Resource Play
Birchcliff’s production from the Worsley Charlie Lake Light Oil Resource Play was 2,082 boe/d in the three month Reporting Period
and 2,923 boe/d in the twelve month Reporting Period, a decrease of 49% and 31%, respectively, from the Comparable Prior Periods.
The decrease in production was largely due to the fact that no new wells were drilled during 2016, as well as natural declines
and unplanned downtime resulting from pipeline integrity issues and maintenance activities in the Worsley area. The decrease in
production was partially offset by production optimization initiatives in the Worsley field that were ongoing during 2016.
Birchcliff’s operating netback from the Worsley Charlie Lake Light Oil Resource Play was $20.91/boe in the three month Reporting
Period and $17.01/boe in the twelve month Reporting Period, an increase of 22% and a decrease of 20%, respectively, from the
Comparable Prior Periods. The increase in the three month Reporting Period was largely due to higher average realized commodity
prices received for Birchcliff’s production offset by increased operating costs as compared to the three month Comparable Prior
Period. The decrease in the twelve month Reporting Period was largely due to lower average realized commodity prices received
for Birchcliff’s production and higher operating costs as compared to the twelve month Comparable Prior Period.
56
Birchcliff Energy Ltd. Administrative Expenses
The components of Birchcliff’s net administrative expenses are detailed in the table below:
Cash:
Salaries and benefits(1)
Other(2)
Operating overhead recoveries
Capitalized overhead(3)
General & administrative expenses, net
General & administrative expenses, net per boe
Non-cash:
Stock-based compensation
Capitalized stock-based compensation(3)
Stock-based compensation, net
Stock-based compensation, net per boe
Administrative expenses, net
Administrative expenses, net per boe
Three months ended
December 31,
Twelve months ended
December 31,
2016
2015
2016
2015
($000s)
(%)
($000s)
(%)
($000s)
(%)
($000s)
(%)
10,056
2,856
12,912
(35)
78
22
100
(1)
12,036
3,041
15,077
(47)
80
20
100
(1)
25,576
12,449
38,025
(154)
67
33
100
(1)
27,067
12,297
39,364
(232)
(6,234)
(48)
(7,536)
(50)
(16,382)
(42)
(16,308)
6,643
$1.19
1,583
(903)
680
$0.12
7,323
$1.31
51
100
(57)
43
7,494
$2.01
1,694
(921)
773
$0.21
8,267
$2.22
49
21,489
57
22,824
$1.19
$1.61
100
(54)
46
6,053
(3,575)
2,478
$0.14
23,967
$1.33
100
(59)
41
7,732
(4,526)
3,206
$0.23
26,030
$1.84
69
31
100
(1)
(41)
58
100
(59)
41
(1) Includes salaries, benefits and bonuses paid to officers and employees of the Corporation.
(2) Includes costs such as rent, legal, tax, insurance, minor computer hardware and software and other general business expenses incurred by the Corporation.
(3) Includes a portion of general and administrative costs and stock-based compensation directly attributable to the exploration and development activities of the Corporation which have
been capitalized.
On a per boe basis, net administrative expenses have decreased in the Reporting Periods compared to the Comparable Prior
Periods primarily due to the disproportionate increase in production volumes as a result of the Gordondale Acquisition as
compared to general and administrative expense.
A summary of the Corporation’s outstanding stock options is presented below:
Outstanding at beginning of period
Granted
Exercised
Forfeited
Expired
Outstanding, end of period
(1) Determined on a weighted average basis.
Twelve months ended
December 31, 2016
Twelve months ended
December 31, 2015
Number
12,569,238
3,356,000
(1,209,363)
(120,400)
(1,695,700)
12,899,775
Exercise
price(1)
7.80
3.90
(6.28)
(6.78)
Number
11,147,672
3,358,500
(93,333)
(699,201)
(11.46)
(1,144,400)
6.45
12,569,238
Exercise
price(1)
8.45
6.62
(6.26)
(9.70)
(9.66)
7.80
At December 31, 2016, there were also 2,939,732 performance warrants outstanding with an exercise price of $3.00 which expire on
January 31, 2020.
Each stock option and performance warrant entitles the holder to purchase one common share at the applicable exercise price.
57
2016 Annual Report Depletion and Depreciation Expenses
Depletion and depreciation (“D&D”) expenses are 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 production in the period. The Corporation determines its D&D expenses on a field area basis.
The following table details Birchcliff’s D&D expenses:
Three months ended
December 31,
Twelve months ended
December 31,
2016
2015
2016
2015
Depletion and depreciation expenses
($000s)
43,184
($/boe)
($000s)
($/boe)
($000s)
($/boe)
($000s)
7.73
35,949
9.66
149,369
8.29
147,163
($/boe)
10.35
D&D expenses for the Reporting Periods were higher on an aggregate basis from the Comparable Prior Periods mainly due to
the increased production volumes acquired pursuant to the Gordondale Acquisition.
On a per boe basis, D&D expenses decreased from the Comparable Prior Periods mainly as a result of the significant reserves
added in both Birchcliff’s Pouce Coupe and Gordondale areas (pursuant to the Gordondale Acquisition) in 2016. Included in the
depletion calculation for 2016 were 880.5 MMboe of proved plus probable reserves and $4.15 billion of future development
costs required to recover those reserves as estimated by the Corporation’s independent qualified reserves evaluators effective
December 31, 2016.
Asset impairment assessment
The Corporation reviews its petroleum and natural gas assets for impairment in accordance with International Accounting
Standards (“IAS”) 36 under International Financial Reporting Standards (“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 took into consideration all available information, including, but not limited
to: geographical proximity; geological similarities (i.e. reservoir characteristic, production profiles); degree of shared infrastructure;
independent versus interdependent cash flows; operating structure; 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 recoverable 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.
Birchcliff performed an impairment assessment of its petroleum and natural gas assets on a CGU basis and determined that there
were no impairment triggers identified at December 31, 2016. As a result, an impairment test was not required at December 31, 2016.
58
Birchcliff Energy Ltd. Finance Expenses
The components of the Corporation’s finance expenses are set forth in the table below:
Three months ended
December 31,
Twelve months ended
December 31,
2016
2015
2016
2015
($000s)
($/boe)
($000s)
($/boe)
($000s)
($/boe)
($000s)
($/boe)
Cash:
Interest on credit facilities
7,822
1.40
6,713
1.80
30,305
1.68
22,861
1.60
Non-cash:
Accretion on decommissioning obligations
Amortization of deferred financing fees
Finance expenses
813
330
8,965
0.15
0.06
1.61
570
235
7,518
0.15
0.06
2.01
2,547
1,088
33,940
0.14
0.06
1.88
2,235
919
26,015
0.16
0.06
1.82
The increase in the aggregate interest expense from the Comparable Prior Periods was largely due to higher average effective
interest rates offset by lower average outstanding total credit facilities balance during the Reporting Periods. The effective 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 the trailing four quarter EBITDA as calculated in accordance with the agreement governing the Corporation’s
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 details the Corporation’s effective interest rates under its credit facilities:
Effective interest rates:
Revolving working capital facility
Revolving syndicated term credit facility
Non-revolving term credit facility(1)
Three months ended
December 31,
Twelve months ended
December 31,
2016
2015
2016
2015
5.2%
5.2%
-
4.7%
4.0%
-
5.2%
4.7%
-
4.7%
4.0%
4.0%
(1) During the second quarter of 2015, Birchcliff’s then existing credit facilities, including the non-revolving term credit facility, were consolidated into the Credit Facilities (as defined herein).
Accordingly, the Corporation did not have an outstanding non-revolving term credit facility during the Reporting Periods.
Birchcliff’s average outstanding total credit facilities balance was approximately $599 million and $632 million, respectively, in
the three and twelve month Reporting Periods as compared to $625 million and $655 million in the Comparable Prior Periods,
calculated as the simple average of the month-end amounts. The decreases from the Comparable Prior Periods are primarily
due to the fact that the remaining aggregate net proceeds of the Financings were used to reduce indebtedness under the Credit
Facilities. See “Capital Resources and Liquidity” in this MD&A.
Gain (Loss) on Sale of Assets
The following table details Birchcliff’s gain and loss on sales of assets:
Three months ended
December 31,
Twelve months ended
December 31,
2016
2015
2016
2015
($000s)
($/boe)
($000s)
($/boe)
($000s)
($/boe)
($000s)
Gain (loss) on sale of assets
945
0.17
6,683
1.80
(9,489)
(0.53)
7,339
($/boe)
0.52
During the second quarter of 2016, Birchcliff completed the disposition of certain non-core miscellaneous petroleum and natural
gas properties and related assets and interests in the Progress area (the “Progress Disposition”) that were producing from the
Halfway formation. The cash consideration was $19.0 million, after customary closing adjustments. The Progress Disposition
closed in April 2016 and represented approximately 600 boe/d of production (60% light oil) and 4,135 net acres of land. As a
result of the Progress Disposition, Birchcliff recorded a loss on sale of assets of approximately $10.9 million ($8.0 million, net of
tax) for the twelve month Reporting Period.
59
2016 Annual Report In November 2016, Birchcliff completed the disposition of minor assets in the Gordondale area of Alberta for cash consideration
of approximately $1.1 million. These assets did not have any reserves attributed to them. As a result of the disposition, Birchcliff
recorded a gain on the sale of approximately $1.1 million ($0.8 million, net of tax) in the Reporting Periods.
All 2016 dispositions noted above were considered non-core asset dispositions as they collectively represented less than 1% of
both Birchcliff’s 2016 production and proved plus probable reserves at December 31, 2016 and therefore were not significant to
the Corporation’s financial results and operational performance.
Income Taxes
The components of income tax expense (recovery) 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,
2016
4,433
750
5,183
$0.92
2015
10,552
750
11,302
$3.05
2016
(9,126)
3,000
(6,126)
($0.34)
2015
20,232
3,000
23,232
$1.64
The income tax expense for the Comparable Prior Periods included: (i) a non-cash, deferred income tax expense in the amount of
$7.8 million that was recorded in the second quarter of 2015 as a result of the 2015 change in the Alberta corporate income tax
rate from 10% to 12%; and (ii) a non-cash deferred income tax expense in the amount of $10.2 million that was recorded in the
fourth quarter of 2015 in respect of the Veracel tax pool (see further detail in the “Veracel tax pools” section below).
After excluding the effects of the above noted tax adjustments for the Comparable Prior Periods, Birchcliff recorded a deferred
income tax expense of $4.4 million for the three month Reporting Period and a deferred income tax recovery of $9.1 million for
the twelve month Reporting Period as compared to a deferred income tax expense of approximately $0.4 million and $2.2 million
in the Comparable Prior Periods. The increase in deferred income tax expense from the three month Comparable Prior Period was
a result of a higher net income before tax recorded in the three month Reporting Period. The deferred income tax recovery in the
twelve month Reporting Period was a result of a net loss before tax position in that period.
The Corporation’s estimated income tax pools were $2.1 billion at December 31, 2016. 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
Financing costs and other
Estimated income tax pools(1)
Tax pools as at
December 31, 2016
621,237
248,550
263,509
337,649
615,043
23,069
2,109,057
(1) Excludes Veracel tax pools of $39.3 million which were reassessed by the Canada Revenue Agency.
Veracel tax pools
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
Transaction”). The Veracel tax pools in dispute totalled $39.3 million. Birchcliff appealed the Reassessment to 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). 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 appeal was heard in January 2017
and the Corporation is currently awaiting a decision.
60
Birchcliff Energy Ltd.
CAPITAL EXPENDITURES
The following table sets forth a summary of the Corporation’s capital expenditures:
($000s)
Land
Seismic
Workovers
Drilling and completions
Well equipment and facilities
Finding and development capital
Acquisitions
Dispositions
Finding, development and acquisition capital
Administrative assets
Net capital expenditures, (cash)
Three months ended
December 31,
Twelve months ended
December 31,
2016
1,057
253
1,770
40,039
17,597
60,716
1,958
2015
3,468
355
1,213
32,024
6,346
2016
4,529
1,203
3,809
89,111
66,839
2015
9,261
3,542
6,015
160,091
78,146
43,406
165,491
257,055
-
614,273
-
(1,473)
(10,281)
(20,720)
(10,947)
61,201
1,281
33,125
759,044
246,108
408
2,986
1,099
62,482
33,533
762,030
247,207
In the twelve month Reporting Period, Birchcliff had total capital expenditures of $168.5 million (finding and development capital
plus administrative assets) and net capital expenditures of $148.5 million (net of acquisitions and dispositions), in each case
excluding the $613.5 million Gordondale Acquisition. These capital expenditure amounts were slightly above Birchcliff’s guidance
of $164 million total capital expenditures and $145 million net capital expenditures.
During the twelve month Reporting Period, Birchcliff had net capital expenditures totalling $762.0 million which included
$613.5 million (81%) on the Gordondale Acquisition (net of adjustments), $54.7 million (7%) on the drilling and completion of
Montney/Doig horizontal natural gas wells in Pouce Coupe, $16.8 million (2%) on the drilling of Montney horizontal oil and natural
gas wells in Gordondale and $27.6 million (4%) on the field construction of Phase V of the PC Gas Plant which will increase
processing capacity from 180 MMcf/d to 260MMcf/d. Field installation of Phase V commenced in January 2017 and it is expected
that it will be commissioned and operational in October 2017. Also included in the twelve month Reporting Period was the cash
consideration of $19.0 million for the Progress Disposition.
In the twelve month Reporting Period, Birchcliff drilled a total of 22 (22.0 net) wells, consisting of 14 (14.0 net) Montney/Doig
horizontal natural gas wells in the Pouce Coupe area, 6.0 (6.0 net) Montney horizontal oil and natural gas wells in the Gordondale
area, 1 (1.0 net) water disposal well in the Gordondale area and 1 (1.0 net) Charlie Lake horizontal light oil well in the Worsley area.
Birchcliff had net capital expenditures totalling $62.5 million in the three month Reporting Period which included $17.9 million
(29%) on the drilling and completion of Montney/Doig horizontal natural gas wells in Pouce Coupe and $16.4 million (27%) on the
drilling of Montney horizontal oil and natural gas wells in Gordondale.
In the three month Reporting Period, Birchcliff drilled a total of 9 (9.0 net) wells consisting of 2 (2.0 net) Montney/Doig horizontal
natural gas wells in Pouce Coupe, 6 (6.0 net) Montney horizontal oil and natural gas wells in Gordondale and 1 (1.0 net) water
disposal well in Gordondale.
The remaining capital during the Reporting Periods was spent on land and seismic, infrastructure and expansion projects in the
Montney/Doig Resource Play and the Worsley Charlie Lake Light Oil Resource Play and on other oil and gas exploration and
development projects in the Peace River Arch.
61
2016 Annual Report CAPITAL RESOURCES AND LIQUIDITY
Liquidity and Capital Resources
The Corporation generally relies on its funds flow from operations 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 on-going capital expenditure programs and protect
its balance sheet.
The following table sets forth a summary of the Corporation’s capital resources:
($000s)
Funds flow from operations
Changes in non-cash working capital from operations
Decommissioning expenditures
Exercise of stock options
Issue of common shares
Share issue costs
Financing fees paid on credit facilities
Dividends paid on preferred shares
Net change in non-revolving term credit facilities(1)
Net change in revolving term credit facilities
Prepaid expenses on acquisition
Changes in non-cash working capital from investing
Capital resources
Three months ended
December 31,
Twelve months ended
December 31,
2016
71,806
19,248
(480)
6,060
51
(8)
-
2015
2016
33,697
147,443
11,336
(5,586)
(247)
(1,343)
-
-
-
-
7,597
690,801
(27,589)
(795)
(1,875)
(1,875)
(7,500)
2015
160,756
(11,066)
(893)
585
-
-
(940)
(7,500)
-
-
-
(129,970)
(62,269)
(4,923)
(49,540)
283,340
-
29,949
62,482
-
(1,206)
(4,455)
9,738
33,533
762,020
-
(47,102)
247,210
(1) During the second quarter of 2015, Birchcliff’s then existing credit facilities, including the non-revolving term credit facility, were consolidated into the Credit Facilities (as defined herein).
Accordingly, the Corporation did not have an outstanding non-revolving term credit facility during the Reporting Periods.
Birchcliff’s funds flow from operations depends on a number of factors, including, but not limited to, commodity prices,
production and sales volumes, operating expenses, royalties and foreign exchange rates. The Corporation has been closely
monitoring commodity prices and its capital spending and in response to continued low commodity prices, has taken proactive
measures with a view to ensuring liquidity and financial flexibility in the current environment.
On July 13, 2016, the Corporation closed the Financings for aggregate gross proceeds of approximately $690.8 million. On July 28,
2016, Birchcliff closed the Gordondale Acquisition and the aggregate gross proceeds of the Financings were used to pay the
balance of the purchase price for the Gordondale Acquisition and the balance of the fees payable to the underwriters of the Public
Offering, with the remaining aggregate net proceeds applied to reduce indebtedness under the Corporation’s Credit Facilities. In
addition, the borrowing base under the Credit Facilities was increased to $950 million from $750 million in connection with the
closing of the Gordondale Acquisition. As a result of the completion of the Gordondale Acquisition and the Financings, Birchcliff
has not only positioned itself for future growth but has also significantly improved its financial position. As of December 31, 2016,
the balance outstanding under the Credit Facilities (excluding adjusted working capital deficit) was $573 million as compared to
$622 million at December 31, 2015. See “Bank Debt”.
The 2017 Capital Program is set at approximately $355 million and is expected to be fully funded out of internally generated
funds flow, which assumes a forecast average WTI price of US$55.00/bbl of oil and a forecast average AECO price of CDN$3.00/
GJ of natural gas during 2017. Birchcliff has hedged approximately 50% of its 2017 forecast natural gas production at $3.02/GJ
to help protect its funds flow and capital expenditure programs. Birchcliff has also entered into financial swaps for 1,500 bbls/d of
crude oil at an average price of CDN$69.90/bbl for 2017. See “Commodity Price Risk Management”.
Management does not foresee any liquidity issues with respect to the operation of Birchcliff’s oil and natural gas business in
2017 and expects that the Corporation will be able to meet its future obligations as they become due. Should commodity prices
deteriorate materially, Birchcliff may adjust the 2017 Capital Program accordingly and/or consider the potential sale of non-core
assets to fund planned growth. See “Advisories”.
62
Birchcliff Energy Ltd. Working Capital
The Corporation’s adjusted working capital deficit increased to $27.5 million at December 31, 2016 from a $21.5 million deficit at
December 31, 2015. The deficit at the end of the Reporting Periods is largely comprised of costs incurred from the drilling of new
wells in Pouce Coupe and Gordondale during the three month Reporting Period.
At December 31, 2016, the major component of Birchcliff’s current assets was revenue to be received from its marketers in
respect of December 2016 production (72%), which was subsequently received in January 2017. In contrast, current liabilities
largely consisted of trade payables (45%) and accrued capital and operating costs (39%). Birchcliff routinely assesses the financial
strength of its marketers and joint venture partners. 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 primarily due to the timing of such items, as well as due to the size and timing of the Corporation’s net capital expenditures,
volatility in commodity prices and changes in revenue, among other things. Birchcliff manages any adjusted working capital
deficit using funds flow from operations and advances under the Credit Facilities. Any adjusted working capital deficit position
will not reduce the amount available under the Credit Facilities. Management believes that its funds flow from operations and
available credit under the Credit Facilities will be sufficient to fund the Corporation’s planned capital expenditures for 2017 and
to meet its current and future working capital requirements in 2017.
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.
In connection with the closing of the Gordondale Acquisition, the Credit Facilities were amended to increase the borrowing base
to $950 million from $750 million. After giving effect to the increase in the borrowing base, the Credit Facilities are comprised of:
(i) an extendible revolving syndicated term credit facility of $900 million (the “Syndicated Credit Facility”); and (ii) an extendible
revolving working capital credit facility of $50 million (the “Working Capital Facility”). The maturity date of the Credit Facilities
is May 11, 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.
Total debt, including the adjusted working capital deficit, was $600.0 million at December 31, 2016 as compared to $643.6 million
at December 31, 2015. A significant portion of the funds drawn under the Credit Facilities in the Reporting Periods was used to
pay costs relating to the drilling and completion of Montney/Doig horizontal natural gas wells in Pouce Coupe including related
facilities and infrastructure and the exploration and development of the Montney/Doig Resource Play and the Worsley Charlie
Lake Light Oil Resource Play.
The following table sets forth the Corporation’s unused Credit Facilities:
As at, ($000s)
Maximum borrowing base limit(1):
Non-revolving term credit facilities
Principal amount utilized:
Drawn revolving term credit facilities(2)
Outstanding letters of credit(3)
Unused credit
% unused credit
December 31,
2016
December 31,
2015
950,000
800,000
(580,770)
(630,037)
(12,310)
(242)
(593,080)
(630,279)
356,920
38%
169,721
21%
(1) The Credit Facilities are subject to a semi-annual review of the borrowing base limit, which limit is directly impacted by the value of Birchcliff’s petroleum and natural gas reserves.
On July 28, 2016, in connection with the closing of the Gordondale Acquisition, the borrowing base was increased to $950 million thus increasing the unused credit available to Birchcliff.
(2) The drawn amounts are not reduced for unamortized costs and fees applicable to the Credit Facilities.
(3) Letters of credit are issued to various service providers. In connection with the closing of the Gordondale Acquisition, the Corporation issued a letter of credit for $12 million to secure its
obligations under various midstream and marketing arrangements. The letter of credit has reduced the amount available under the Working Capital Facility from $50 million to approximately
$38 million. There were no amounts drawn on the letters of credit during the years ended December 31, 2016 and December 31, 2015.
63
2016 Annual Report 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, 2016:
($000s)
Accounts payable and accrued liabilities
Drawn revolving term credit facilities(1)
Operating leases(2)
Capital commitments(3)
Firm transportation, processing and fractionation(4)
2017
92,115
-
3,206
36,128
36,315
-
580,770
4,117
16,849
105,179
Estimated contractual obligations(5)
167,764
706,915
-
-
13,625
-
294,158
307,783
-
-
29,317
-
294,980
324,297
2018
2019 - 2021
Thereafter
(1) The maturity date of the Credit Facilities is May 11, 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.
(2) The Corporation is committed under an existing operating lease relating to its office premises, beginning December 1, 2007 and expiring on November 30, 2017. On December 2, 2015,
the Corporation entered into an operating lease commitment relating to a new office premise beginning February 1, 2018 and expiring on January 31, 2028. The commitment amount under
the new 10 year office lease is estimated to be $47.1 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.
(3) Includes drilling commitments and facility spending commitments relating to the Phase V and VI expansions of the PC Gas Plant.
(4) As a result of the Gordondale Acquisition, Birchcliff’s firm transportation, processing and fractionation obligations have increased.
(5) 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, 2016 to be approximately $267 million and will be incurred as follows: 2017 - $2.5 million, 2018 - $2.0 million and $262.5 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 June 30, 2020, have not been included in this table as they are not contractual obligations of the
Corporation at the end of the Reporting Periods. 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.
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 expenses or general and administrative expenses 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
Comparable Prior Periods.
OUTSTANDING SHARE INFORMATION
At March 14, 2017, 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 summarizes the common shares issued by the Corporation:
Balance at December 31, 2014
Exercise of options
Balance at December 31, 2015
Exercise of options
Issuance of common shares(1)
Balance at December 31, 2016
Exercise of options
Balance at March 14, 2017
Common shares
152,214,206
93,333
152,307,539
1,209,363
110,525,000
264,041,902
98,800
264,140,702
(1) On July 13, 2016, the Corporation issued 110,520,000 Subscription Receipts at a price of $6.25 per Subscription Receipt for gross proceeds of approximately $690.8 million. On July 28, 2016,
the Corporation issued 110,520,000 common shares pursuant to the exchange of 110,520,000 Subscription Receipts in connection with the closing of the Gordondale Acquisition. In December
2016, the Corporation issued 5,000 common shares at a price of $10.11 per common share on a private placement basis.
As at March 14, 2017, the Corporation had the following securities outstanding: 264,140,702 common shares; 2,000,000 Series
A Preferred Shares; 2,000,000 Series C Preferred Shares; 17,067,475 stock options to purchase an equivalent number of common
shares; and 2,939,732 performance warrants to purchase an equivalent number of common shares.
64
Birchcliff Energy Ltd. On November 30, 2016, the Board of Directors declared a quarterly cash dividend of $1.0 million or $0.50 per Series A Preferred
Share and $0.875 million or $0.4375 per Series C Preferred Share for the calendar quarter ending December 31, 2016. In 2016,
cash dividends totalled $4.0 million or $2.00 per Series A Preferred Share (2015 - $4.0 million or $2.00 per Series A) and $3.5
million or $1.75 per Series C Preferred Share (2015 - $3.5 million or $1.75 per Series C). These preferred share dividends have been
designated as “eligible dividends” for the purposes of the Income Tax Act (Canada).
Birchcliff’s Board of Directors approved a quarterly dividend policy for the Corporation’s common shares in November 2016.
On March 1, 2017, the Board of Directors declared the first dividend payable under this policy in respect of the quarter ending
March 31, 2017 in the amount of $0.025 per common share. This dividend is payable on March 31, 2017 to shareholders of record
on March 15, 2017 and has been designated as an “eligible dividend” for the purposes of the Income Tax Act (Canada).
SUMMARY OF QUARTERLY RESULTS
The following are the quarterly results of the Corporation for the eight most recently completed quarters:
Quarter ending,
Dec. 31,
2016
Sep. 30,
2016
Jun. 30,
2016
Mar. 31,
2016
Dec. 31,
2015
Sep. 30,
2015
Jun. 30,
2015
Mar. 31,
2015
Average daily production (boe)
60,750
54,538
39,513
41,958
40,445
38,433
38,489
38,416
Realized natural gas price ($/Mcf)(1)
Realized oil price ($/bbl)(1)
Total revenues ($000s)(1)
Operating costs ($/boe)
3.31
60.75
2.53
52.12
1.48
51.20
1.99
36.93
2.67
49.36
3.12
52.91
2.86
64.93
2.98
47.66
135,457
97,365
47,261
57,503
75,476
82,011
82,791
77,026
4.54
4.65
3.45
3.71
4.16
4.39
4.53
5.11
Capital expenditures, net ($000s)
62,482
599,716
35,972(3)
63,860
33,533
50,013
65,122
98,539
Funds flow from operations ($000s)
71,806
41,675
13,267
20,695
33,697
44,587
45,752
36,720
Per common share – basic ($)
Per common share – diluted ($)
0.27
0.27
0.18
0.18
0.09
0.09
0.14
0.13
0.22
0.22
Net income (loss) ($000s)
12,085
(1,064)
(23,321)
(12,035)
(9,322)
Net income (loss) to common shareholders ($000s)(2)
11,085
(2,064)
(24,321)
(13,035)
(10,322)
Per common share – basic ($)
Per common share – diluted ($)
0.04
0.04
(0.01)
(0.01)
(0.16)
(0.16)
(0.09)
(0.09)
(0.07)
(0.07)
0.29
0.29
4,815
3,815
0.03
0.02
0.30
0.30
0.24
0.24
(4,174)
(3,479)
(5,174)
(4,479)
(0.03)
(0.03)
(0.03)
(0.03)
Total assets ($ million)
2,710
2,704
2,059
2,053
2,025
2,022
2,009
1,983
Long-term bank debt ($000s)
572,517
634,534
709,510
647,359
622,074
626,839
599,998
536,570
Total debt ($000s)
600,012
612,080
715,651
690,138
643,612
640,751
632,306
610,170
Dividends on pref. shares - Series A ($000s)
1,000
1,000
1,000
1,000
1,000
1,000
1,000
1,000
Dividends on pref. shares - Series C ($000s)
Pref. shares outstanding - Series A (000s)
Pref. shares outstanding - Series C (000s)
Common shares outstanding (000s)
875
2,000
2,000
875
2,000
2,000
875
2,000
2,000
875
2,000
2,000
875
2,000
2,000
875
2,000
2,000
875
2,000
2,000
875
2,000
2,000
Basic
Diluted
264,042
263,065
152,308
152,308
152,308
152,308
152,294
152,284
279,881
279,826
169,089
169,239
167,817
168,112
168,181
168,108
Wtd. average common shares outstanding (000s)
Basic
Diluted
263,396
229,287
152,308
152,308
152,308
152,303
152,289
152,243
268,974
234,295
154,279
153,418
153,627
153,916
154,650
154,215
(1) Excludes the effect of financial hedges using financial instruments.
(2) Reduced for the Series A Preferred Share dividends paid in the period.
(3) Includes a $31.25 million deposit paid in connection with the Gordondale Acquisition.
65
2016 Annual Report Average daily production volumes in the three month Reporting Period increased from the previous seven quarters largely due to
production volumes acquired pursuant to the Gordondale Acquisition and incremental production added from new Montney/Doig
horizontal natural gas wells, partially offset by natural production declines from those wells.
Quarterly variances in revenues, funds flow from operations and net income are primarily due to fluctuations in commodity prices
and production volumes. Oil and gas revenues and funds flow in the three month Reporting Period are higher than the previous
seven quarters largely due to higher average realized oil and natural gas prices and increased production volumes associated
with the Gordondale Assets. Net income has increased primarily in response to changes in funds flow from operations offset by
other non-cash adjustments including depletion expense, non-recurring tax expenses and gains and losses on the sale of assets
recognized in the period.
In general, capital expenditures have fluctuated over the past eight quarters primarily as a result of the timing of the Corporation’s
development capital expenditures. Capital expenditures are also impacted by commodity prices and market conditions, as well as
the timing of acquisitions and dispositions.
During the third quarter of 2016, Birchcliff closed the Gordondale Acquisition which significantly increased capital expenditures
compared to the other quarters. The Gordondale Acquisition was funded primarily through the Financings. At the closing of the
Gordondale Acquisition, the aggregate gross proceeds of the Financings were released from escrow to pay the balance of the
purchase price for the Gordondale Acquisition and the balance of the fees payable to the underwriters of the Public Offering.
The remaining aggregate net proceeds were applied to reduce indebtedness under the Corporation’s Credit Facilities, which
resulted in a lower total debt balance at the end of the three month Reporting Period compared to the previous seven quarters.
In connection with the closing of the Gordondale Acquisition, each Subscription Receipt was exchanged for one common share of
the Corporation and a total of 110,520,000 common shares of the Corporation were issued, which increased both the common
shares and weighted average common shares outstanding compared to previous quarters.
POTENTIAL TRANSACTIONS
Within its focus area, the Corporation is continually reviewing potential property 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 property acquisitions
and dispositions and corporate merger and acquisition opportunities. The Corporation is not committed to any such potential
transaction and cannot be reasonably confident that it can complete any such potential transaction until appropriate legal
documentation has been signed by the relevant parties.
CONTROLS AND PROCEDURES
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, 2016 and have concluded that
the Corporation’s DC&P were effective at December 31, 2016.
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.
66
Birchcliff Energy Ltd. 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 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, 2016 and have concluded that the Corporation’s ICFR was effective at December 31,
2016. There were no changes in the Corporation’s ICFR that occurred during the period beginning on October 1, 2016 and ended
on December 31, 2016 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 a negative downturn in
commodity prices or 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, a significant adverse effect on the financial and operational
performance of a CGU or 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
67
2016 Annual Report 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 Disclosures
for Oil and Gas Activities and the Canadian Oil and Gas Evaluation Handbook.
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.
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 as a result of
such differing interpretations.
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 balance sheet
date could be impacted.
68
Birchcliff Energy Ltd. FUTURE ACCOUNTING PRONOUNCEMENTS
In January 2016, the IASB issued IFRS 16 Leases. The standard will be effective for annual periods beginning on or after January 1,
2019. Early adoption is permitted, provided IFRS 15 Revenue from Contracts with Customers, has been applied, or is applied at
the same date as IFRS 16. Birchcliff is currently evaluating the impact of adopting IFRS 16 on the financial statements.
In April 2016, the IASB issued amendments to IAS 7 Statement of Cash Flows for annual periods beginning on or after January 1,
2017, with earlier application permitted. The amendments require entities to provide disclosures that enable users of financial
statements to evaluate changes in liabilities arising from financing activities, including both changes arising from cash flows and
non-cash changes. Birchcliff is currently evaluating the impact of the amendments on the financial statements.
On May 28, 2014, the IASB issued IFRS 15 Revenue From Contracts With Customers replacing IAS 11 Construction Contracts,
IAS 18 Revenue and several revenue-related interpretations. IFRS 15 contains a single model that applies to contracts with
customers and two approaches to recognizing revenue: at a point in time or over time. The model features a contract-based
five-step analysis of transactions to determine whether, how much and when revenue is recognized. IFRS 15 is effective for annual
periods beginning on or after January 1, 2018, with earlier adoption permitted. Birchcliff is currently assessing the impact of adopting
IFRS 15; however, it anticipates that this standard will not have a material impact on the Corporation’s financial statements.
On July 24, 2014, the IASB issued the final version of IFRS 9 Financial Instruments to replace IAS 39 Financial Instruments:
Recognition and Measurement. IFRS 9 aligns hedge accounting more closely with risk management. The new standard does not
fundamentally change the types of hedging relationships or the requirement to measure and recognize ineffectiveness. However,
under the new standard, more hedging strategies that are used for risk management will qualify for hedge accounting. IFRS 9
is effective for years beginning on or after January 1, 2018. As the Corporation does not currently apply hedge accounting it
anticipates that this standard will not have a material impact on the Corporation’s financial statements.
RISK FACTORS AND RISK MANAGEMENT
The Corporation’s operations are exposed to a number of risks, some that impact the oil and natural gas industry as a whole and
others that are unique to the Corporation. The impact of any risk or a combination of risks may adversely affect the Corporation’s
business, financial condition, results of operations, prospects, cash flows and reputation, which may reduce or restrict the
Corporation’s ability to pay dividends and may materially affect the market price of the Corporation’s securities.
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.
Financial Risks and Risks Relating to Economic Conditions
Commodity price volatility
The Corporation’s revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend
substantially on prevailing prices for oil and natural gas. Prices for oil and natural gas are subject to wide 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, production and policies, including (without limitation) the ability of the Organization of the
Petroleum Exporting Countries (“OPEC”) to set, maintain and reduce production levels in order to influence prices for crude oil;
• 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 liquids;
the production and storage levels of North American natural gas and crude oil and the supply and price of imported oil;
the ability, considering regulation, taxation, and market demand, to export oil and liquefied natural gas and NGLs from
North America;
69
2016 Annual Report •
the availability, proximity and capacity of gathering, transportation, processing and/or refining facilities in regional or
localized areas that may affect the realized price 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 greenhouse gas (“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, OPEC actions, sanctions imposed on certain oil
producing nations by other countries and ongoing credit and liquidity concerns. Volatile oil, NGLs 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
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 funds 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.
The Corporation’s financial performance also depends on revenues from the sale of commodities which differ in quality and
location from underlying commodity prices quoted on financial exchanges. Of particular importance are the price differentials
between the Corporation’s realized prices for light/medium oil and natural gas and quoted market prices. Not only are these
discounts influenced by regional supply and demand factors, they are also influenced by other factors such as transportation
costs, capacity and interruptions and the quality of the oil and natural gas produced, all of which are beyond the Corporation’s
control. Oil and natural gas producers in North America currently receive significantly discounted prices for some of their
production due to regional constraints on the ability to transport and sell such production to international markets. Additionally,
limited natural gas and NGLs processing capacity may result in producers not realizing the full price for liquids associated with
their natural gas production. A failure to resolve such constraints may result in continued reduced commodity prices received by
oil and natural gas producers such as the Corporation.
The Corporation’s reserves at December 31, 2016 are estimated using forecast prices and costs. These prices are above
current crude oil and natural gas prices. If crude oil and natural gas prices stay at current levels, 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. In addition,
lower commodity prices have restricted, and are anticipated to continue to restrict, the Corporation’s cash flow. The Corporation’s
capital expenditure plans are impacted by the Corporation’s cash flow. If commodity prices deteriorate and the Corporation
reduces its capital expenditures, the Corporation may not be able to replace its production with additional reserves and both its
production and reserves could be reduced on a year-over-year basis.
Birchcliff conducts an assessment of the carrying value of its assets to the extent required by IFRS. If forecasted oil or natural
gas prices decline, the carrying value of the Corporation’s assets could be subject to downward revision, and the Corporation’s
earnings could be adversely affected by any reduction in such carrying value.
Weakness in the oil and gas industry
Recent market events and conditions, including global excess oil and natural gas supply, recent actions taken by OPEC, slowing
growth in China and other emerging economies, market volatility and disruptions in Asia, 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 gas companies and a decrease in confidence in the oil and gas industry.
Recent changes in the Canadian federal government and, in the case of Alberta, at the provincial level have resulted in uncertainty
surrounding regulatory, tax, royalty changes and environmental regulation that have been announced or may be implemented.
70
Birchcliff Energy Ltd. In addition, the difficulty or inability to obtain the necessary approvals and other delays to build pipelines and other facilities to
provide better access to markets for the oil and gas industry in western Canada has led to additional downward price pressure on
crude oil and natural gas produced in western Canada and uncertainty and reduced confidence in the oil and gas industry in western
Canada. Given the current market conditions and the lack of confidence in the Canadian oil and gas industry, the Corporation may
have difficulty raising additional funds or if it is able to do so, it may be on unfavourable and/or highly dilutive terms.
Substantial capital 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. If the Corporation’s future revenues or reserves decline,
the Corporation may have limited ability to expend the capital necessary to undertake or complete future drilling programs.
There can be no assurance that debt or equity financing, or cash generated by operations will be available or sufficient to meet
these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable
to the Corporation. Moreover, future activities may require the Corporation to alter its capitalization significantly. The inability of
the Corporation to access sufficient capital for its operations could have a material adverse effect on the Corporation’s financial
condition, results of operations or prospects.
Additional funding requirements and access to credit
Due to the nature of the Corporation’s business, it is necessary from time to time for the Corporation to access other sources
of capital beyond its internally generated cash flow in order to fund its acquisition, exploration and development activities.
The Corporation obtains some of this necessary capital by incurring debt; therefore, the Corporation is dependent to a certain
extent on the continued availability to the Corporation of credit. The continued availability of credit to the Corporation is primarily
dependent on the state of the economy and the health of the banking industry in Canada and the United States. There is a risk
that if the economy and banking industry experienced unexpected or prolonged deterioration, the Corporation’s access to credit
may contract or disappear altogether. The Corporation tries to mitigate this risk by dealing with reputable lenders and tries to
structure its lending agreements to give it the most flexibility possible should these situations arise. However, situations that
give rise to credit tightening or disappearing are largely beyond the Corporation’s control.
Due to the conditions in the oil and natural gas industry and/or global economic volatility, the Corporation may from time to time
have restricted access to capital and increased borrowing costs. The current conditions in the oil and natural gas industry have
negatively impacted the ability of oil and natural gas companies to access additional financing. Failure to obtain such 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. Continued depressed oil and natural gas prices have caused decreases, and may cause
further decreases, in the Corporation’s revenues from its production, which may affect its ability to expend the necessary capital
to replace its reserves or to maintain its production. To the extent that external sources of capital become limited, unavailable or
available on onerous terms, the 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 oil and natural gas 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. Failure
to obtain any financing necessary for the Corporation’s capital expenditure plans may result in a delay in the development of the
Corporation’s properties.
The Corporation is also dependent, to a certain extent, on continued access to equity capital markets. The Common Shares
are listed on the TSX and management maintains an active investor relations program. In addition to the other factors outlined
herein, continued access to capital is dependent on the Corporation’s ability to continue to perform at a level that meets
market expectations.
Issuance of debt
From time to time, the Corporation may enter into transactions to acquire assets or shares of other entities. These transactions
may be financed in whole or in part with debt, which may increase the Corporation’s debt levels above industry standards for
oil and natural gas companies 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.
71
2016 Annual Report Credit facilities
The amount authorized under the Credit Facilities is dependent on the borrowing base determined by the Corporation’s lenders.
At December 31, 2016, the borrowing base limit under the Credit Facilities was $950 million and long-term bank debt was
$572.5 million. 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, applicable discount rate and other factors to determine the Corporation’s
borrowing base. A material decline 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, the lenders are able to request one additional borrowing base
redetermination in between scheduled redeterminations and the borrowing base may 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 eliminate this excess.
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 May 11, 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 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 default under the Credit Facilities, which could result in the Corporation being required
to repay amounts owing thereunder. Even if the Corporation is able to obtain new financing, 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. 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.
Dividends
The declaration and payment of dividends in any quarter 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.
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Birchcliff Energy Ltd. Dividends may be reduced or suspended during periods of lower funds 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 funds flow 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 funds flow to finance capital expenditures or acquisitions or to repay existing
debt as it becomes due, 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.
See “Dividend and Distribution Policy” in the Annual Information Form for the financial year ended December 31, 2016.
Hedging
From time to time, the Corporation may enter into agreements that fix the prices on its oil and natural gas production to offset
the risk of revenue losses if commodity prices decline. However, to the extent that the Corporation engages in fixed price risk
management activities to protect it from commodity price declines, the Corporation may also be prevented from realizing the
full benefits of commodity price increases above the prices established by the Corporation’s hedging contracts. In addition,
the Corporation’s hedging arrangements may expose it to the risk of financial loss in certain circumstances, including instances
in which:
• production falls short of the hedged volumes;
•
•
there is a widening of price-basis differentials between delivery points for production and the delivery point assumed
in the hedge arrangement;
the counterparties to the hedging arrangements or other price risk management contracts fail to perform under those
arrangements; or
• a sudden unexpected event materially increases oil and natural gas prices.
Similarly, from time to time the Corporation may enter into agreements to fix the exchange rate of Canadian dollars to United
States dollars in order to offset the risk of revenue losses if the Canadian dollar increases in value compared to the United States
dollar. However, if the exchange rate is fixed and the Canadian dollar declines in value compared to the United States dollar, the
Corporation will not benefit from the declining exchange rate.
Credit risk
The Corporation may be exposed to third-party credit risk through its contractual arrangements with its current or future joint
venture partners, marketers of its petroleum and natural gas production and other parties. In 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 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 assurances by prepaying anticipated expenses or
posting letters of credit, which would decrease the Corporation’s available liquidity.
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2016 Annual Report 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.
Future Canadian/United States exchange rates could also 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 a credit risk
associated with counterparties with which the Corporation may contract. The Corporation has not hedged any of its foreign
exchange risk at the date hereof. See “– 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 price 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 any particular time and the production therefrom, will decline over time as such existing 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 participations uneconomic. There is also no assurance that the Corporation will discover or acquire further
commercial quantities of oil and natural gas. In addition, 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 as well as from wells that are productive
but do not produce sufficient petroleum substances to return a profit after drilling, completion, operating and other costs.
Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs.
Drilling hazards, environmental damage and various field operating conditions could greatly increase the cost of operations
and adversely affect the production from successful wells. Field operating conditions include, but are not limited to, delays in
obtaining governmental approvals or consents, shut-ins of wells resulting from extreme weather conditions, insufficient storage
or transportation capacity or geological and mechanical conditions. While diligent well supervision and effective maintenance
operations can contribute to maximizing production rates over time, it is not possible to eliminate production delays and declines
from normal field operating conditions, which can negatively affect revenue and cash flow levels to varying degrees.
Oil and natural gas exploration, development and production operations are subject to all the risks and hazards typically
associated with such operations, including, but not limited to, fire, explosion, blowouts, cratering, sour gas releases, spills and
other environmental hazards. These typical risks and hazards could result in substantial damage to oil and natural gas wells,
production facilities, other property, the environment and personal injury. Particularly, the 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 all the risks typically associated with such operations, including
encountering unexpected formations or pressures, premature decline of reservoirs and the invasion of water into producing
formations. Losses resulting from the occurrence of any of these risks may have a material adverse effect on the Corporation’s
business, financial condition, results of operations and prospects. The Corporation also remains subject to the risk that the
production rate of a significant well may decrease in an unpredictable and uncontrollable manner, which could result in a decrease
in the Corporation’s overall production and associated cash flows.
74
Birchcliff Energy Ltd. As is standard industry practice, the Corporation is not fully insured against all risks, nor are all risks insurable. Although the
Corporation maintains liability insurance in an amount that it considers consistent with industry practice, liabilities associated
with certain risks could exceed policy limits or not be covered. In either event, the Corporation could incur significant costs.
See “– Other Risks – Insurance”.
Project risks
The Corporation manages a variety of small and large projects in the conduct of its business. Project delays may delay expected
revenues from operations. Significant project cost over-runs could make a project uneconomic. The Corporation’s ability to
execute projects and market oil and natural gas depends upon numerous factors beyond the Corporation’s control, including:
•
•
•
•
•
•
•
•
•
the availability of processing capacity;
the availability and proximity of pipeline capacity;
the availability of storage capacity;
the availability of, and the ability to acquire, water supplies needed for drilling and hydraulic fracturing at a reasonable cost
and in accordance with applicable environmental regulations;
the Corporation’s ability to dispose of water used or removed from strata;
the supply of and demand for oil and natural gas;
the availability of alternative fuel sources;
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.
Gathering and processing facilities and pipeline systems
The Corporation primarily delivers its products through gathering and processing facilities and pipeline systems, some of which
it does not own. The amount of oil and natural gas that the Corporation can produce and sell is subject to the accessibility,
availability, proximity and capacity of these gathering and processing facilities and pipeline systems. A lack of availability of
capacity in any of the gathering and processing facilities and pipeline systems 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. Although
pipeline expansions are ongoing, the lack of firm pipeline capacity continues to affect the oil and natural gas industry and limit the
ability to produce and market oil and natural gas production. In addition, the pro-rationing of capacity on pipeline systems within
Alberta 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. Any significant change in market factors or other conditions affecting these infrastructure systems
and facilities, as well as any delays in constructing new infrastructure systems and facilities could harm the Corporation’s business
and, in turn, the Corporation’s financial condition, results of operations and cash flows. The federal government has signaled
that it plans to review the National Energy Board approval process for large projects. This may cause the timeframe for project
approvals to increase for current and future applications.
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 causing 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 for sale.
75
2016 Annual Report Uncertainty of reserves estimates
There are numerous uncertainties inherent in estimating quantities of oil, natural gas and NGLs reserves and the future net
revenue attributed to such reserves, including many factors beyond the control of the Corporation. 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, initial production rates, production
decline rates, ultimate reserves recovery, the timing and amount of capital expenditures, the success of future development
activities, future commodity prices, 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 those reasons,
estimates of the economically recoverable oil, natural gas and NGLs reserves attributable to any particular group of properties,
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 substantially. 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.
Estimates with respect to reserves that may be developed and produced in the future are often based upon volumetric calculations
and upon analogy to similar types of reserves rather than actual production history. Recovery factors and drainage areas were
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, which may be substantial.
In accordance with applicable securities laws in Canada, the Corporation’s independent qualified reserves evaluators have used
forecast prices and costs in estimating the Corporation’s 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
evaluations prepared by the Corporation’s independent qualified reserves evaluators in respect of the Corporation’s oil and gas
properties effective December 31, 2016, and such variations could be material. Such evaluations are based in part on the expected
success of the Corporation’s forecast operations. The reserves and estimated future net revenue to be derived therefrom and
contained in the evaluations may be reduced to the extent that such activities do not achieve the expected level of success.
Costs and availability of equipment and services
Oil and natural gas exploration and development activities are dependent on the availability of drilling and related equipment
(typically leased from third parties) and skilled personnel trained to use such equipment in the areas where such activities will be
conducted. Demand for such limited equipment and skilled personnel, or access restrictions, may affect the availability of such
equipment and skilled personnel to the Corporation and may delay exploration and development activities.
During times of high commodity prices for oil and natural gas, there is a risk of substantially increased costs of operations, which
impacts both the amount of capital required to perform operations and the netback the Corporation achieves from its production
sales. Although the Corporation strives for continuous improvement in its planning, operations and procurement of materials,
unexpected changes in the market for such equipment and services could negatively affect the Corporation’s business, financial
condition, results of operations and prospects.
Hydraulic fracturing
Some of the Corporation’s operations use 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 and improved upon for many years, there has been increased focus
on 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.
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Birchcliff Energy Ltd. 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 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, capital and operating costs, inclement weather, seasonal restrictions, drilling results,
additional geological, geophysical and reservoir information that is obtained, production rate recovery, gathering system and
transportation constraints, net prices 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 the Corporation has identified
will ever be drilled or if the Corporation will be able to produce oil, NGLs or natural gas from these or any other potential future
drilling locations. As such, the Corporation’s actual drilling activities may differ materially from those presently identified, which
could adversely affect the Corporation’s business.
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 prices, 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. Any of these factors could materially adversely
affect the Corporation’s financial and operational results.
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 enjoy technological advantages and may in the future allow them to implement 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, 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 energy generation devices could reduce the demand for oil, natural gas and other
liquid hydrocarbons. The Corporation cannot predict the impact of 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.
Health, safety and environment
Health, safety and environmental risks influence the workforce, operating costs and the establishment of regulatory standards.
These risks include, but are not limited to, encountering unexpected formations or pressures; premature declines of reservoirs;
blow-outs; equipment failures; human error or wilful misconduct by field workers; other accidents such as, cratering, sour
gas releases, uncontrollable flows of oil, natural gas or well fluid spills; adverse weather conditions; pollution; fires; and
other environmental risks. The Corporation provides staff with the training and resources they need to complete work safely
77
2016 Annual Report and effectively; incorporates hazard assessment and risk management as an integral part of everyday operations; monitors
performance to ensure its operations comply with legal obligations and internal standards; and identifies and manages
environmental liabilities associated with its existing asset base. The Corporation has a site inspection program and a corrosion
risk management program designed to ensure compliance with environmental laws and regulations. The Corporation carries
insurance to cover a portion of property losses, liability to third parties and business interruption resulting from unusual events.
The Corporation is subject to the risk that the unexpected failure of its equipment used in drilling, completing or producing wells
or in transporting production could result in release of fluid substances that pollute or contaminate lands at or near its facilities,
which could result in significant liability to the Corporation for costs of clean up, remediation and reclamation of contaminated
lands. The Corporation conducts its operations with due regard for the potential impact on the environment. This includes hiring
skilled personnel, providing adequate training to all staff involved with operations, and by retaining expert advice and assistance
to deal with environmental remediation and reclamation work where such expertise is needed.
Seasonality
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 and municipalities and provincial transportation departments may enforce road bans
that restrict the movement of rigs and other heavy equipment, all of which may result in limited access and a reduction in or
cessation of operations. In addition, certain oil and gas producing areas 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. In addition, extreme
cold weather and heavy snowfall and rainfall may restrict the Corporation’s ability to access it properties and cause operational
difficulties. 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 rises during cold winter months and hot summer months.
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 licences or leases may have a material adverse effect on the business,
financial condition, results of operations and prospects of the Corporation. To mitigate this risk, the Corporation carefully monitors
its undeveloped land position and plans operations in order to keep key licences and leases from terminating or expiring.
Competition
The oil and natural gas industry is highly competitive in all of its phases. The Corporation competes with numerous other entities
for land, acquisitions of reserves, access to drilling and service rigs and other equipment, access to transportation and skilled
technical and operating personnel among other things. 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.
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 significant governmental regulation in Alberta, 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.
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 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 may face
unexpected risks or alternatively, significantly increase the Corporations exposure to one or more existing risk factors, which may
in turn result in the Corporation’s future operational and financial conditions being adversely affected.
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Birchcliff Energy Ltd. Information security and cybersecurity
Birchcliff relies heavily on information technology, such as computer hardware and software systems, in order to properly operate
its business. 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 systems, the operation
of such systems could be interrupted or result in the loss, corruption, or release of data. In addition, information systems could
be damaged or interrupted by natural disasters, force majeure events, telecommunications failures, power loss, acts of war or
terrorism, computer viruses, malicious code, physical or electronic security breaches, intentional or inadvertent user misuse or
error, or similar events or disruptions. Any of these or other events could cause interruptions, delays, loss of critical and/or
sensitive data or similar effects, which could have a material adverse impact on the protection of intellectual property, and
confidential and proprietary information, and on Birchcliff’s business, financial condition, results of operations and cash flows.
In the ordinary course of business, the Corporation collects, uses and stores sensitive data, including intellectual property,
proprietary business information and personal information of Birchcliff’s employees and third parties. Despite Birchcliff’s security
measures, Birchcliff’s information systems, technology and infrastructure may be vulnerable to attacks by hackers and/or
cyberterrorists or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise
information used or stored on the Corporation’s systems and/or networks and, as a result, the information could be accessed,
publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings,
liability under laws that protect the privacy of personal information, regulatory penalties or other negative consequences, including
disruption to Birchcliff’s operations and damage to Birchcliff’s reputation, which could have a material adverse effect on
Birchcliff’s business, financial condition, results of operations and cash flows.
Although to date the Corporation has not experienced any material losses relating to cyber attacks or other information security
breaches, there can be no assurance that the Corporation will not incur such losses in the future.
Environmental, Regulatory and Political Risks
Environmental
All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation
pursuant to a variety of federal, provincial and local laws and regulations. Environmental legislation provides for, among other
things, restrictions and prohibitions on the spill, release or emission of various substances produced in association with certain
oil and 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 will be in material compliance with current applicable environmental legislation, no
assurance can be given that environmental laws will not result in a curtailment of production or a material increase in the costs
of production, development or exploration activities or otherwise have a material adverse effect on the Corporation’s business,
financial condition, results of operations and prospects.
Political and economic events may significantly affect the scope and timing of climate change measures that are put in place.
Some of the Corporation’s facilities may be subject to existing or future provincial or federal climate change regulations to manage
emissions and there can be no assurance that the compliance costs will be immaterial. 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 also “ – Climate Change Regulation”.
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2016 Annual Report Regulatory
Various levels of governments impose extensive controls and regulations on oil and natural gas operations (including exploration,
development, production, pricing, marketing and transportation). Governments may regulate or intervene with respect to
exploration and production activities, prices, taxes, royalties and the exportation of oil and natural gas. 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 of existing regulations affecting the oil and natural gas industry could reduce demand
for crude oil and natural gas and increase the Corporation’s costs, either of which may have a material adverse effect on the
Corporation’s business, financial condition, results of operations and prospects. In order to conduct oil and natural gas operations,
the Corporation will require 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.
Royalty regimes
The Corporation’s cash flows are directly affected by changes to royalty regimes. The Government of Alberta receives royalties
on the production of hydrocarbons from lands in which they own the mineral rights. On January 29, 2016, the Government of
Alberta announced the MRF based on recommendations of the Royalty Review Advisory Panel. The MRF will apply to all
conventional wells spud on or after January 1, 2017. Wells spud prior to January 1, 2017 will continue to operate under the
Previous Framework. Wells spud between July 13, 2016 and December 31, 2016 may elect to opt-in to the MRF if certain criteria
are met. After December 31, 2026, all wells will be subject to the MRF.
Under the MRF, royalties are determined on a “revenue-minus-costs” basis, with the cost component based on a drilling and
completion cost allowance formula for each well, which is dependent on the true vertical depth of the well, total lateral length
of the well and the total proppant placed. The formula is based on the industry’s average drilling and completion costs as
determined by the Alberta Department of Energy (the “ADOE”) on an annual basis. Producers pay a flat royalty rate of 5% of gross
revenue from each well that is subject to the MRF until the well reaches payout. Payout for a well is the point at which cumulative
revenues from the well equals the drilling and completion cost allowance for the well set by the ADOE. After payout, producers
pay an increased post-payout royalty on revenues determined by reference to the then current commodity prices of the various
hydrocarbons. Once production in a mature well drops below a threshold level where the rate of production is too low to sustain
the full royalty burden, its royalty rate will move to a sliding scale (based on volume and commodity prices) with a minimum
royalty rate of 5%.
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. Further changes to the royalty regime in
Alberta, changes to how the existing royalty regime is interpreted and applied by the Government of Alberta or an increase in
disclosure obligations for the Corporation could have a significant impact on the Corporation’s financial condition, results of
operations, prospects and cash flows. An increase in the royalty rates in Alberta would reduce the Corporation’s earnings and
could make future capital expenditures or existing operations less economic or uneconomic.
Climate change regulation
The Corporation’s exploration and production facilities and other operations and activities emit GHG. Various federal and
provincial governments have announced intentions to regulate GHG emissions and other air pollutants. Some of these regulations
are in effect while others remain in various phases of review, discussion or implementation, as discussed in further detail below.
Uncertainties exist relating to the timing and effects of these regulations. Additionally, lack of certainty regarding how any future
federal legislation will harmonize with provincial regulations makes it difficult to accurately determine the cost estimate of climate
change legislation compliance with certainty.
Alberta
As part of its efforts to reduce GHG emissions, the Government of Alberta introduced legislation to address GHG emissions:
the Climate Change and Emissions Management Act (Alberta) enacted on December 4, 2003 and amended through the
Climate Change and Emissions Management Amendment Act (Alberta), which received royal assent on November 4, 2008. The
accompanying regulations include the Specified Gas Emitters Regulation (“SGER”), which imposes GHG limits, and the Specified
Gas Reporting Regulation, which imposes GHG emissions reporting requirements. SGER applies to facilities emitting more than
100,000 tonnes of GHG emissions in 2003 or any subsequent year (“Regulated Emitters”) and requires reductions in GHG
emissions intensity (e.g. the quantity of GHG emissions per unit of production) from emissions intensity baselines established in
accordance with SGER.
80
Birchcliff Energy Ltd. On June 25, 2015, the Government of Alberta renewed SGER for a period of two years with significant amendments while
Alberta’s newly formed Climate Advisory Panel conducted a comprehensive review of the province’s climate change policy.
Regulated Emitters are required to reduce their emissions intensity by 2% from their baseline in the fourth year of commercial
operation, 4% of their baseline in the fifth year, 6% of their baseline in the sixth year, 8% of their baseline in the seventh year,
10% of their baseline in the eighth year, and, as of January 1, 2017, 20% of their baseline in the ninth or subsequent years.
A Regulated Emitter can meet its emissions intensity targets through a combination of the following: (i) producing its products
with lower carbon inputs; (ii) purchasing emissions offset credits from non-regulated emitters (generated through activities that
result in emissions reductions in accordance with established protocols); (iii) purchasing emissions performance credits from
other Regulated Emitters that earned credits through the reduction of their emissions below the 100,000 tonne threshold;
(iv) cogeneration compliance adjustments; and (v) by contributing to the Climate Change and Emissions Management Fund at a
rate of $30 per tonne of GHG emissions.
On November 22, 2015, as a result of the Climate Advisory Panel’s Climate Leadership report, the Government of Alberta announced
its Climate Leadership Plan. The Climate Leadership Plan includes certain initiatives that the Government will implement to
address climate change, including: (i) the complete phase-out of coal-fired sources of electricity by 2030; (ii) implementing an
Alberta economy-wide price on GHG emissions of $30 per tonne; (iii) reducing oil sands emissions to a province-wide total of 100
megatonnes per year, with certain exceptions for cogeneration power sources and new upgrading capacity; and (iv) reducing methane
emissions from oil and gas activities by 45% by 2025. On June 7, 2016, the Climate Leadership Implementation Act (Alberta) (the
“CLIA”) was passed into law. The CLIA enacted the Climate Leadership Act (Alberta) (the “CLA”) introducing a carbon tax on all sources
of GHG emissions, subject to certain exemptions. The CLA received royal assent on June 13, 2016 and came into force on January 1,
2017. The Climate Leadership Regulation (“CL Regulation”), which provides further detail in respect of the carbon levy regime set out
in the CLA, was released on November 3, 2016, and also came into force on January 1, 2017.
The CLA and the CL Regulation impose registration, payment, remittance, reporting and administrative obligations on applicable
persons throughout the fuel supply chain. Pursuant to the CLA, an initial economy-wide carbon levy of $20 per tonne of GHG
emissions was implemented on January 1, 2017, increasing to $30 per tonne in January of 2018. The application of the carbon
levy depends on the type and quantity of fuel purchased and how such fuel is used by the purchaser. With certain exemptions,
all fuel consumption, including gasoline and natural gas, will be subject to the carbon levy. Activities integral to oil and gas
production processes are exempt until 2023. The Corporation currently expects that its operations will have minimal direct carbon
levy exposure until 2023. It is not known what will occur in 2023 when the current exemptions are expected to end. In addition,
under the CLA and the CL Regulation, facilities subject to SGER are exempt from the carbon levy. Regulated Emitters will remain
subject to the SGER framework until the end of 2017 and are exempt from paying the carbon levy on fuels used in operations
until this time. Upon the expiry of SGER, the Government of Alberta intends to transition to a proposed Carbon Competitiveness
Regulation, in which sector specific output-based carbon allocations will be used to ensure competitiveness. Details of such
proposed regulation have not yet been released.
Federal
As a signatory to the United Nations Framework Convention on Climate Change (the “UNFCCC”) and a participant to the
Copenhagen Agreement (a non-binding agreement created by the UNFCCC), the Government of Canada announced on January 29,
2010 that it would seek a 17% reduction in GHG emissions from 2005 levels by 2020; however, these GHG emission reduction
targets were not binding. Canada and 193 other countries that are members of the UNFCCC met in Paris, France in December,
2015, and signed the Paris Agreement on climate change. The stated objective of the Paris Agreement is to hold “the increase
in global average temperature to well below 2 degrees Celcius above pre-industrial levels and to pursue efforts to limit the
temperature increase to 1.5 degrees Celcius”. Signatory countries agreed to meet every five years to review their individual
progress on GHG emissions reductions and to consider amendments to individual country targets, which are not legally binding.
Canada is required to report and monitor its GHG emissions, though details of how such reporting and monitoring will take place
have yet to be determined. Additionally, the Paris Agreement contemplates that, by 2020, the parties will develop a new market-
based mechanism related to carbon trading. As a result of the UNFCCC adopting the Paris Agreement on December 12, 2015,
which Canada ratified on October 3, 2016, the Government of Canada implemented new GHG emission reduction targets of a
30% reduction from 2005 levels by 2030.
In addition, on December 9, 2016, the Government of Canada formally announced the Pan-Canadian Framework on Clean Growth
and Climate Change. As a result, the federal government will implement a Canada-wide carbon pricing scheme beginning in 2018.
This may be implemented through either a cap and trade system or a carbon tax regime at the option of each province or territory.
The federal government will impose a price on carbon of $10 per tonne on any province or territory which fails to implement its
own system by 2018. This amount will increase by $10 annually until it reaches $50 per tonne in 2022 at which time the program
will be reviewed. For those provinces, including Alberta, which have already established a carbon tax or a cap and trade regime, or
both, the national price on carbon will likely have little additional impact in the short-term.
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2016 Annual Report Impact on the Corporation
Adverse impacts to the Corporation’s business as a result of comprehensive GHG legislation or regulations 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.
The Corporation is not currently considered a Regulated Emitter under SGER in respect of any of its facilities. However, should any
of the Corporation’s facilities emit 100,000 tonnes or more of GHG per year, such facilities will be subject to the GHG reduction
targets and reporting requirements under SGER. It is likely that the PC Gas Plant will become a Regulated Emitter later in 2017
upon completion of the Phase V expansion, which is currently scheduled to be completed in October 2017. The Corporation
currently expects that the costs will not be material to the Corporation.
Beyond existing legal requirements, the extent and magnitude of any adverse impacts of any additional programs or additional
regulations cannot be reliably or accurately estimated at this time because specific legislative and regulatory requirements have
not been finalized and uncertainty exists with respect to the additional measures being considered and the time frames for
compliance. Additional changes to climate change legislation may adversely affect the Corporation’s business, financial condition,
results of operations and cash flows which cannot be reliably or accurately estimated at this time.
Liability management programs
In Alberta, the AER administers the Licensee Liability Rating Program (the “LLR Program”) which is a liability management
program governing most conventional upstream oil and gas wells, facilities and pipelines. The Oil and Gas Conservation Act
(Alberta) (the “OGCA”) establishes an orphan fund (the “Orphan Fund”) to pay the costs to suspend, abandon, remediate and
reclaim a well, facility or pipeline included in the LLR Program if a licensee or working interest participant becomes defunct or
is unable to meet its obligations. The Orphan Fund is administered by the Orphan Well Association (the “OWA”) and is funded
by licensees in the LLR Program (including Birchcliff) through a levy administered by the AER. The LLR Program is designed
to minimize the risk to the Orphan Fund posed by unfunded liability of licensees and to prevent the taxpayers of Alberta from
incurring costs to suspend, abandon, remediate and reclaim wells, facilities or pipelines.
The LLR Program requires a licensee whose deemed liabilities exceed its deemed assets to provide the AER with a security deposit.
The ratio of deemed liabilities to deemed assets is assessed once each month and failure to post the required security deposit may
result in the initiation of enforcement action by the AER. Although the Corporation does not have to currently post security under the
existing LLR Program, changes to the ratio of the Corporation’s deemed assets to deemed liabilities or changes to the requirements
of the LLR Program may result in the requirement for security to be posted in the future.
In May 2016, the Alberta Court of Queen’s Bench issued a decision in the case of Redwater Energy Corporation (Re), 2016 ABQB 278
(“Redwater”). The Court found that there was an operational conflict between the abandonment and reclamation provisions of
the OGCA and the Bankruptcy and Insolvency Act (Canada) and that receivers and trustees of insolvent parties have the right to
disclaim or renounce uneconomic oil and gas assets within insolvency proceedings. Accordingly, these wells and facilities become
“orphans” to be remediated by the OWA. The Alberta Court of Appeal heard the appeal of the Redwater decision on October 11, 2016,
with the Court reserving its decision.
In response to the Redwater decision, the AER issued Bulletin 2016-16: Licensee Eligibility—Alberta Energy Regulator Measures
to Limit Environmental Impacts Pending Regulatory Changes to Address the Redwater Decision (“Bulletin 16”) on June 20, 2016, which
provided that the following interim measures will govern pending the earlier of the outcome of Redwater or the implementation
of appropriate regulatory measures:
(i) The AER will consider and process all applications for licence eligibility under Directive 067: Applying for Approval to Hold
EUB Licences as non-routine and may exercise its discretion to refuse an application or impose terms and conditions on a
licencee eligibility approval if appropriate in the circumstances.
(ii) For holders of existing but previously unused licence eligibility approvals, prior to approval of any application (including
licence transfer applications), the AER may require evidence that there have been no material changes since approving
the licence eligibility. This may include evidence that the holder continues to maintain adequate insurance and that the
directors, officers, and/or shareholders are substantially the same as when licence eligibility was originally granted.
(iii) As a condition of transferring existing AER licences, approvals, and permits, the AER will require all transferees to
demonstrate that they have a liability management rating (“LMR”), being the ratio of a licensee’s deemed assets to deemed
liabilities, of 2.0 or higher immediately following the transfer.
82
Birchcliff Energy Ltd. The AER subsequently issued Bulletin 2016-21: Revision and Clarification on Alberta Energy Regulator’s Measures to Limit
Environmental Impacts Pending Regulatory Changes to Address the Redwater Decision (“Bulletin 21”) on July 8, 2016. In Bulletin
21, the AER stated that an LMR of 1.0 is not sufficient to ensure that licensees will be able to address their obligations throughout
the life cycle of energy development; therefore transferees must either demonstrate an LMR of 2.0 or higher or provide other
evidence that the transferee will be able to meet with obligations with an LMR of less than 2.0. Bulletin 21 did provide the AER
with additional flexibility to permit licensees to acquire additional AER-licensed assets if:
(i) the licensee already has an LMR of 2.0 or higher;
(ii) the acquisition will improve the licensee’s LMR to 2.0 or higher; or
(iii) the licensee is able to satisfy the AER by other means that they will be able to meet their obligations throughout the life
cycle of energy development with an LMR of less than 2.0.
The LLR 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 gas assets must be in compliance with the LLR Program (both before and after the transfer of the assets)
for the applicable regulatory agency to allow for the transfer of such assets. While the impact on Birchcliff of any legislative,
regulatory or policy decisions as a result of the Redwater decision and its pending appeal cannot be reliably or accurately
estimated, any cost recovery or other measures taken by applicable regulatory bodies may impact Birchcliff and materially and
adversely affect, among other things, Birchcliff’s business, financial condition, results of operations and cash flows. There remains
a great deal of uncertainty as to what new regulatory measures will be developed.
In addition, because of the current economic environment, the number of orphaned wells in Alberta has increased significantly
and, accordingly, the aggregate value of the abandonment and reclamation liabilities assumed by the OWA has increased and may
continue to increase. The OWA may seek funding for such liabilities from industry participants, including the Corporation, through
an increase in its annual levy, further changes to regulations or other means.
Political uncertainty
Political events throughout the world that cause disruptions in the supply of oil continuously affect the marketability and
price of oil and natural gas acquired or discovered by the Corporation. Conflicts, or conversely peaceful developments, arising
outside of Canada, including changes in political regimes or the parties in power, 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
net production revenue.
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. During the recent presidential campaign in the United States a
number of election promises were made and the new American administration has begun taking steps to implement certain of
these promises. Included in the actions that the administration has discussed are the renegotiation of the terms of the
North American Free Trade Agreement, withdrawal of the United States from the Trans-Pacific Partnership, imposition of a tax
on the importation of goods into the United States, reduction of regulation and taxation in the United States, and introduction
of laws to reduce immigration and restrict access into the United States for citizens of certain countries. It is presently unclear
exactly what actions the new administration in the United States will implement, and if implemented, how these actions may
impact Canada and in particular the oil and gas industry. Any actions taken by the new United States administration may have a
negative impact on the Canadian economy and on the businesses, financial conditions, results of operations and the valuation of
Canadian oil and gas companies, including the Corporation.
In addition to the political disruption in the United States, in 2016 the citizens of the United Kingdom voted to withdraw from
the European Union and the Government of the United Kingdom has begun taking steps to implement such withdrawal. 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 conditions and ultimately the market value of the Corporation’s securities.
83
2016 Annual Report Other Risks
Volatility of market price of securities
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. 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. Market price fluctuations
in the Corporation’s securities may be due to the Corporation’s operating results failing to meet the expectations of securities
analysts or investors in any quarter, downward revision in securities analysts’ estimates, governmental regulatory action, adverse
change in general market conditions or economic trends or acquisitions, dispositions or other material public announcements by
the Corporation or its competitors, along with a variety of additional factors, including, without limitation, those set forth under
“Advisories – Forward-Looking Information”. In addition, the market price for securities in the stock markets, including the TSX,
has recently experienced significant price and trading fluctuations. These fluctuations have resulted in volatility in the market
prices of securities that are often unrelated or disproportionate to changes in operating performance. 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. These broad market fluctuations may
adversely affect the market prices of the Corporation’s securities, and, as such, the price 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. The Corporation does not have “key person” insurance in effect for the
Corporation. 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 personnel necessary for the development and
operation of its business. Shareholders must rely upon the ability, expertise, judgment, discretion, integrity and good faith of the
Corporation’s management.
Failure to realize anticipated benefits of acquisitions and dispositions
The Corporation makes acquisitions and dispositions of properties and other assets in the ordinary course of business. Typically,
once an 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 unforeseen 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 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 gas, future operating costs, future capital expenditures and royalties and other government
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 may
require substantial management effort, time and resources, diverting management’s focus from other strategic opportunities and
operational matters.
Management continually assesses the value of the Corporation’s assets and may dispose of non-core assets so that the
Corporation can focus its efforts and resources more efficiently. Depending on the state of the market, there is a risk that certain
non-core assets could realize less than their carrying value in the Corporation’s financial statements.
84
Birchcliff Energy Ltd. Title to assets
Although title reviews may be conducted prior to the purchase of oil and natural gas producing properties or the commencement
of drilling wells, such reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise to defeat the
Corporation’s ownership claim. The actual interest of the Corporation in properties may accordingly vary from the Corporation’s
records. If a title defect does exist, it is possible that the Corporation may lose all or a portion of the properties to which the title
defect relates, which may have a material adverse effect on the Corporation’s business, financial condition, results of operations
and prospects. There may be valid challenges to title or legislative changes, which affect the Corporation’s title to the oil and
natural gas properties the Corporation controls that could impair the Corporation’s activities on them and result in a reduction of
the revenue received by the Corporation.
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. An inability of the Corporation to effectively deal with this growth could have a material adverse impact on its
business, financial condition, results of operations and prospects.
Insurance
The Corporation obtains insurance in accordance with industry standards to address business risks. However, such insurance
has limitations on liability that may not be sufficient to cover the full extent of such liabilities. In addition, certain risks may not
in all circumstances be insurable or, in certain circumstances, the Corporation may elect not to obtain insurance to deal with
specific risks due to high premiums associated with such insurance or other reasons. The payment of such 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 its business, financial condition,
results of operations or 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, related to personal injuries,
property damage, property tax, land rights, access rights, the environment 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 proceeding, the proceeding 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.
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.
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 auditor discovers 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.
85
2016 Annual Report 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, whether by re-characterization of exploration and
development expenditures or otherwise, 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.
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.
Negative impact of additional sales or issuances of securities
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
Any dividends will be declared in Canadian dollars and converted to foreign denominated currencies at the spot exchange rate at
the time of payment. As a consequence, investors may be 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.
86
Birchcliff Energy Ltd. Forward-looking information may prove inaccurate
Shareholders and prospective investors are cautioned not to place undue reliance on the Corporation’s forward-looking
information. By its nature, forward-looking information involves 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 information 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 information are found
under the heading “Advisories – Forward-Looking Information” in this MD&A.
ABBREVIATIONS
The abbreviations set forth below have the following meanings:
AECO
bbl
bbls/d
boe
boe/d
GJ
GJ/d
m3
Mcf
Mcf/d
Mcfe
MJ
MMboe
MMbtu
MMcf
MMcf/d
NGLs
P&NG
WTI
000s
$000s
physical storage and trading hub for natural gas on the TransCanada Alberta transmission system
which is the delivery point for various benchmark Alberta index prices
barrel
barrels per day
barrels of oil equivalent
barrels of oil equivalent per day
gigajoule
gigajoules per day
cubic metres
thousand cubic feet
thousand cubic feet per day
thousand cubic feet of gas equivalent
megajoules
millions barrels of oil equivalent
million British thermal units
million cubic feet
million cubic feet per day
natural gas liquids
petroleum and natural gas
West Texas Intermediate oil at Cushing, Oklahoma, the benchmark for North America crude oil pricing
thousands
thousands of dollars
87
2016 Annual Report NON-GAAP MEASURES
This MD&A uses “funds flow”, “funds flow from operations”, “funds flow per common share”, “netback”, “operating netback”,
“estimated operating netback”, “operating margin”, “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.
“Funds flow” and “funds flow from operations” denote cash flow from operating activities before the effects of decommissioning
expenditures and changes in non-cash working capital. “Funds flow per common share” denotes funds flow divided by the basic
or diluted weighted average number of common shares outstanding for the period. Management believes that funds flow, funds
flow from operations and 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, pay dividends on preferred
shares and repay debt. The following table provides a reconciliation of cash flow from operating activities, as determined in
accordance with IFRS, to funds flow from operations:
($000s)
Cash flow from operating activities
Adjustments:
Decommissioning expenditures
Change in non-cash working capital
Funds flow from operations
Three months ended
December 31,
Twelve months ended
December 31,
2016
90,574
2015
2016
2015
44,786
140,514
148,797
480
247
(19,248)
(11,336)
1,343
5,586
893
11,066
71,806
33,697
147,443
160,756
“Netback” and “operating netback” denote petroleum and natural gas revenue less royalties, less operating expenses and less
transportation and marketing expenses. “Estimated operating netback” of the PC Gas Plant (and the components thereof) is
based upon certain cost allocations and accruals directly attributable to the PC Gas Plant and related wells and infrastructure
on a production month basis. All netbacks are calculated on a per boe basis, unless otherwise indicated. Management believes
that netback, operating netback and estimated operating netback assist 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 operating netback for the Reporting Periods and Comparable Prior Periods:
Petroleum and natural gas revenue
Royalty expense
Operating expense
Transportation and marketing expense
Operating Netback
Three months ended
December 31,2016
Three months ended
December 31,2015
($000s)
135,457
(10,177)
(25,385)
(13,489)
86,406
($/boe)(1)
($000s)
24.24
75,476
(1.82)
(3,499)
(4.54)
(15,469)
(2.42)
(8,603)
15.46
47,905
($/boe)(1)
20.28
(0.94)
(4.16)
(2.31)
12.87
(1) All per boe figures are calculated by dividing each aggregate financial amount by the production (boe) in the respective period.
88
Birchcliff Energy Ltd. Petroleum and natural gas revenue
Royalty expense
Operating expense
Transportation and marketing expense
Operating netback
Twelve months ended
December 31,2016
Twelve months ended
December 31,2015
($000s)
337,586
(20,911)
(75,251)
(42,989)
198,435
($/boe)(1)
($000s)
($/boe)(1)
18.73
317,304
(1.16)
(11,548)
(4.18)
(64,511)
(2.38)
(34,804)
11.01
206,441
22.32
(0.81)
(4.54)
(2.45)
14.52
(1) All per boe figures are calculated by dividing each aggregate financial amount by the production (boe) in the respective period.
“Operating margin” for the PC Gas Plant is calculated by dividing the estimated operating netback for the period by the petroleum
and natural gas revenue for the period. Management believes that operating margin assists management and investors in
assessing the profitability and efficiency of the PC Gas Plant and Birchcliff’s ability to generate operating cash flows (equal to
petroleum and natural gas revenue less royalties, less operating expenses and less transportation and marketing expenses).
“Total cash costs” are comprised of royalty, operating, transportation and marketing, general and administrative and interest
expenses. Total cash costs are calculated on a per boe 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 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 IFRS, to adjusted working capital deficit:
As at, ($000s)
Working capital deficit
Fair value of financial instruments
Adjusted working capital deficit
December 31,
2016
December 31,
2015
36,928
(9,433)
27,495
21,538
-
21,538
“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 IFRS, to total debt:
As at, ($000s)
Revolving term credit facilities
Adjusted working capital deficit
Total debt
December 31,
2016
December 31,
2015
572,517
27,495
600,012
622,074
21,538
643,612
89
2016 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 to 1 bbl and an Mcfe conversion ratio of 1 bbl to 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.
Conversion from GJ to Mcf – Wellhead Price
Birchcliff receives premium pricing for its natural gas production due to its high heat content from its properties. With respect to
Birchcliff’s natural gas hedging contracts in 2017, the prices have been presented in both AECO CDN $/GJ and $/Mcf, with the
latter representing the average expected natural gas wellhead price under contract. The conversion from GJ to Mcf is based on
an expected corporate average natural gas heat content value of 40.69 MJ/m3 in 2017.
MMbtu Pricing Conversions
$1.00 per MMbtu equals $1.00 per Mcf based on a standard heat value Mcf.
Operating Costs
References in this MD&A to “operating costs” exclude transportation and marketing costs.
Capital Expenditures
“Total capital expenditures” denotes finding and development costs (which includes land, seismic, workovers, drilling and
completions and well equipment and facilities) plus administrative expenses. Unless otherwise stated, “net capital expenditures”
denotes finding and development costs plus administrative expenses plus acquisition costs, less any dispositions.
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, 2016. Such evaluations 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”). Further information regarding the Corporation’s reserves can be found in the Corporation’s Annual
Information Form for the financial year ended December 31, 2016.
Certain terms used herein are defined in NI 51-101 and 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 Information
Certain statements contained in this MD&A constitute forward-looking statements and information (collectively referred to as
“forward-looking information”) within the meaning of applicable Canadian securities laws. Such forward-looking information
relates to future events or Birchcliff’s future performance. All information other than historical fact may be forward-looking
information. Such forward-looking information is often, but not always, identified by the use of words such as “seek”, “plan”,
“expect”, “project”, “intend”, “believe”, “anticipate”, “estimate”, “estimated”, “forecast”, “potential”, “proposed”, “predict”, “budget”,
“continue”, “targeting”, “may”, “will”, “could”, “might”, “should” and other similar words and expressions. This information involves
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 information. Birchcliff believes that the expectations reflected in the forward-looking
information are reasonable in the current circumstances but no assurance can be given that these expectations will prove to be
correct and such forward-looking information included in this MD&A should not be unduly relied upon.
In particular, this MD&A contains forward-looking information relating to the following: Birchcliff’s plans and other aspects
of its anticipated future operations, focus, objectives, strategies, opportunities, priorities and goals; the 2017 Capital Program,
including planned capital expenditures and capital allocation, Birchcliff’s plan to drill a total of 46 (46.0 net) wells and Birchcliff’s
expectation that it will fully fund the 2017 Capital Program out of funds flow; Birchcliff’s proposed exploration and development
90
Birchcliff Energy Ltd. activities and the timing thereof, including wells to be drilled and brought on production; Birchcliff’s production guidance,
including estimates of its annual average production and fourth quarter average production rates for 2017 and its goal of
producing in excess of 100,000 boe/d by the end of 2018; the performance characteristics of Birchcliff’s oil and natural gas
properties and expected results from its assets; proposed expansions of the PC Gas Plant, including the anticipated processing
capacities of the PC Gas Plant after such expansions and the anticipated timing thereof; Birchcliff’s hedging strategy and the
use of risk management techniques; estimates of reserves and future development costs; 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 statements that the Corporation may seek additional capital in the form of debt and/or equity
or dispose of non-core properties to fund its on-going capital expenditure programs and protect its balance sheet, that should
commodity prices deteriorate materially, the Corporation may adjust the 2017 Capital Program and/or consider the potential
sale of non-core assets, management’s expectation that the Corporation will be able to meet its future obligations as they
become due, management’s belief that its funds flow from operations and available credit facilities will be sufficient to fund
the Corporation’s planned growth and to meet its working capital requirements in 2017 and the Corporation’s expectation
that counterparties will be able to meet their financial obligations; Birchcliff’s financial flexibility; estimates of contractual and
decommissioning obligations; projections of commodity prices and costs and supply and demand for crude oil and natural gas;
treatment under governmental regulatory regimes and tax laws and the future impact of regulatory measures, including under
SGER and climate change legislation; and expectations regarding the Corporation’s ability to raise capital and to continually add
to reserves through acquisitions and development. Information relating to reserves is forward-looking as it 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.
With respect to forward-looking information contained in this MD&A, assumptions have been made regarding, among other
things: Birchcliff’s ability to continue to develop the Gordondale Assets and obtain the anticipated benefits therefrom; prevailing
and future commodity prices and differentials, currency exchange rates, interest rates, inflation rates, royalty rates and tax rates;
expected funds flow from operations; Birchcliff’s future debt levels; the state of the economy and the exploration and production
business; the economic and political environment in which Birchcliff operates; the regulatory framework regarding royalties,
taxes and environmental laws; the sources of funding for Birchcliff’s capital expenditure programs and other activities; anticipated
timing and results of capital expenditures; the sufficiency of budgeted capital expenditures to carry out planned operations;
future operating, transportation, marketing and general and administrative costs; the performance of existing and future wells,
well production rates and well decline rates; well drainage areas; success rates for future drilling; reserves and resource volumes
and Birchcliff’s ability to replace and expand oil and gas reserves through acquisition, development or exploration; the impact of
competition on Birchcliff; the availability of, demand for and cost of labour, services and materials; Birchcliff’s ability to access
capital; the ability to obtain financing on acceptable terms; the ability to obtain any necessary regulatory approvals in a timely
manner; the ability of Birchcliff to secure adequate transportation for its products; Birchcliff’s ability to market oil and gas; and the
availability of hedges on terms acceptable to Birchcliff.
In addition to the foregoing assumptions, Birchcliff has made the following assumptions with respect to certain forward-looking
information contained in this MD&A:
• With respect to statements regarding the 2017 Capital Program, such program is based on the following commodity price
and exchange rate assumptions during 2017: an annual average WTI price of US$55.00 per barrel of oil; an AECO price of
CDN$3.00 per GJ of natural gas; and an exchange rate of CDN$/US$ of 1.29. With respect to statements that the 2017
Capital Program is expected to be fully funded out of internally generated funds, such statements assume that: the 2017
Capital Program will be carried out as currently contemplated; the production targets and commodity price assumptions
set forth herein are achieved; and Birchcliff’s forecast commodity mix is achieved.
• With respect to statements regarding 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 Birchcliff’s production guidance, the key assumptions are that: the Corporation’s capital expenditure
programs 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.
91
2016 Annual Report • With respect to statements regarding proposed expansions of the PC Gas Plant, including the anticipated processing
capacities of the PC Gas Plant after such expansions and the anticipated timing of such expansions, the key assumptions
are that: future drilling is successful; there is sufficient labour, services and equipment available; Birchcliff will have access
to sufficient capital to fund those projects; the key components of the plant will operate as designed; and commodity
prices and general economic conditions will warrant proceeding with the construction of such facilities and the drilling of
associated wells.
• With respect to estimates of reserves volumes, the key assumption is the validity of the data used by the Corporation’s
independent qualified reserves evaluators in their reserves evaluations.
Birchcliff’s actual results, performance or achievements could differ materially from those anticipated in the forward-looking
information as a result of both known and unknown risks and uncertainties including, but not limited to: the failure to realize
the anticipated benefits of acquisitions and dispositions, including the Gordondale Acquisition; unforeseen difficulties in
integrating acquired assets into Birchcliff’s operations; variances in Birchcliff’s actual capital costs, operating costs and
economic returns from those anticipated; 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; operational risks and liabilities inherent in oil and natural gas
operations; uncertainties associated with estimating oil and natural gas reserves and resources; the accuracy of oil and natural
gas reserves estimates and estimated production levels as they are affected by exploration and development drilling and
estimated decline rates; geological, technical, drilling, construction and processing problems; uncertainty of geological and
technical data; uncertainties related to Birchcliff’s future potential drilling locations; fluctuations in the costs of borrowing;
changes in tax laws, crown royalty rates, environmental laws and incentive programs relating to the oil and natural gas industry
and other actions by government authorities, including changes to the royalty and carbon tax regimes and the imposition or
reassessment of taxes; 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 ability to satisfy obligations under Birchcliff’s firm
marketing and transportation arrangements; the inability to secure adequate production transportation for Birchcliff’s products;
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; potential delays or changes in plans with respect to
exploration or development projects or capital expenditures; stock market volatility; loss of market demand; environmental
risks, claims and liabilities; incorrect assessments of the value of acquisitions and exploration and development programs;
shortages in equipment and skilled personnel; the absence or loss of key employees; uncertainties associated with the outcome
of litigation or other proceedings involving Birchcliff; uncertainty that development activities in connection with its assets
will be economical; competition for, among other things, capital, acquisitions of reserves, undeveloped lands, equipment and
skilled personnel; uncertainties associated with credit facilities; counterparty credit risk; risks associated with Birchcliff’s
hedging program and the risk that hedges on terms acceptable to Birchcliff may not be available; and risks associated with the
declaration and payment of dividends, including the discretion of the Board to declare dividends.
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 under the heading “Risk Factors and
Risk Management” in this MD&A and in other reports filed with Canadian securities regulatory authorities from time to time.
Any future-orientated financial information and financial outlook information (collectively, “FOFI”) contained in this MD&A, as
such terms are defined by applicable securities laws, is provided for the purpose of providing information about management’s
current expectations and plans relating to the future and is subject to the same assumptions, risk factors, limitations and
qualifications as set forth in the above paragraphs. FOFI contained in this MD&A was made as of the date of this MD&A and
Birchcliff disclaims any intention or obligation to update or revise any FOFI contained in this MD&A, whether as a result of new
information, future events or otherwise, unless required by applicable law. Readers are cautioned that any FOFI contained herein
should not be used for purposes other than those for which it has been disclosed herein.
Management has included the above summary of assumptions and risks related to forward-looking information 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 information contained in this MD&A is expressly qualified by the foregoing cautionary statements. The
forward-looking information contained in this MD&A is made as of the date of this MD&A. Birchcliff is not under any duty to
update or revise any of the forward-looking information except as expressly required by applicable securities laws.
92
Birchcliff Energy Ltd. MANAGEMENT’S REPORT
To the Shareholders of Birchcliff Energy Ltd.
The annual financial statements of Birchcliff Energy Ltd. for the year ended December 31, 2016 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”
(signed) “A. Jeffery Tonken”
Bruno P. Geremia,
A. Jeffery Tonken,
Vice-President and Chief Financial Officer
President and Chief Executive Officer
Calgary, Canada
March 15, 2017
93
2016 Annual Report
INDEPENDENT AUDITORS’ REPORT
TO THE SHAREHOLDERS OF BIRCHCLIFF ENERGY LTD.
We have audited the accompanying financial statements of Birchcliff Energy Ltd., which comprise the statements of financial
position as at December 31, 2016 and December 31, 2015, the statements of net loss and comprehensive loss, changes in
shareholders’ equity and cash flows for the years then ended, and notes, comprising a summary of significant accounting
policies and other explanatory information.
Management’s Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of these financial statements in accordance with
International Financial Reporting Standards, 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.
Auditors’ Responsibility
Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in
accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical
requirements and plan and perform the audit to obtain reasonable assurance about whether the financial statements are free
from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements.
The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the financial
statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity’s
preparation and fair presentation of the financial statements 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 entity’s internal control. An audit also
includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by
management, as well as evaluating the overall presentation of the financial statements.
We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our
audit opinion.
Opinion
In our opinion, the financial statements present fairly, in all material respects, the financial position of Birchcliff Energy Ltd. as
at December 31, 2016 and December 31, 2015, and its financial performance and its cash flows for the years then ended in
accordance with International Financial Reporting Standards.
(signed) “KPMG LLP”
Chartered Professional Accountants
Calgary, Canada
March 15, 2017
94
Birchcliff Energy Ltd. BIRCHCLIFF ENERGY LTD.
STATEMENTS OF FINANCIAL POSITION
(Expressed in thousands of Canadian dollars)
As at December 31,
ASSETS
Current assets:
Cash
Accounts receivable (Note 16)
Prepaid expenses and deposits
Non-current assets:
Exploration and evaluation (Note 5)
Petroleum and natural gas properties and equipment (Note 6)
Total assets
LIABILITIES
Current liabilities:
Accounts payable and accrued liabilities
Fair value of financial instruments (Note 16)
Non-current liabilities:
Revolving term credit facilities (Note 7)
Decommissioning obligations (Note 8)
Deferred income taxes (Note 9)
Capital securities (Note 10)
Total liabilities
SHAREHOLDERS’ EQUITY
Share capital (Note 10)
Common shares
Preferred shares (perpetual)
Contributed surplus
Retained earnings
Total shareholders’ equity and liabilities
Commitments (Note 17)
The accompanying notes are an integral part of these financial statements.
Approved by the Board
(signed) “Larry A. Shaw”
Larry A. Shaw
Director
(signed) “A. Jeffery Tonken”
A. Jeffery Tonken
Director
2016
2015
47
62,572
2,001
64,620
53
2,645,784
2,645,837
2,710,457
92,115
9,433
101,548
572,517
133,470
99,599
48,916
854,502
956,050
1,464,567
41,434
63,847
184,559
1,754,407
2,710,457
57
23,410
2,579
26,046
247
1,999,080
1,999,327
2,025,373
47,584
-
47,584
622,074
92,504
116,171
48,606
879,355
926,939
783,481
41,434
60,625
212,894
1,098,434
2,025,373
95
2016 Annual Report
BIRCHCLIFF ENERGY LTD.
STATEMENTS OF NET LOSS
AND COMPREHENSIVE LOSS
(Expressed in thousands of Canadian dollars, except per share information)
Years Ended December 31,
REVENUE
Petroleum and natural gas sales
Royalties
Net revenue from oil and natural gas sales
Realized gain on financial instruments (Note 16)
Unrealized (loss) on financial instruments (Note 16)
EXPENSES
Operating (Note 11)
Transportation and marketing
Administrative, net (Note 12)
Depletion and depreciation (Note 6)
Finance (Note 13)
Dividends on capital securities (Note 10)
(Gain) loss on sale of assets (Note 6)
Net income (loss) before taxes
Income tax recovery (expense) (Note 9)
NET LOSS AND COMPREHENSIVE LOSS
Net loss per common share (Note 10)
Basic
Diluted
The accompanying notes are an integral part of these financial statements.
2016
2015
337,586
(20,911)
316,675
802
(9,433)
308,044
75,251
42,989
23,967
149,369
33,940
3,500
9,489
338,505
(30,461)
6,126
(24,335)
($0.14)
($0.14)
317,304
(11,548)
305,756
-
-
305,756
64,511
34,804
26,030
147,163
26,015
3,500
(7,339)
294,684
11,072
(23,232)
(12,160)
($0.11)
($0.11)
96
Birchcliff Energy Ltd. BIRCHCLIFF ENERGY LTD.
STATEMENTS OF CHANGES IN
SHAREHOLDERS’ EQUITY
(Expressed in thousands of Canadian dollars)
Share Capital
Common
Shares
Preferred
Shares
Contributed
Surplus
As at December 31, 2014
782,671
41,434
Dividends on perpetual preferred shares
Exercise of stock options
Stock-based compensation
Net loss and comprehensive loss
As at December 31, 2015
Issue of common shares (Note 10)
Share issue costs, net of tax (Note 10)
Dividends on perpetual preferred shares (Note 10)
Exercise of stock options (Note 10)
Stock-based compensation (Note 12)
Net loss and comprehensive loss
-
810
-
-
783,481
690,801
(20,143)
-
10,428
-
-
Retained
Earnings
229,054
(4,000)
-
-
(12,160)
212,894
-
-
(4,000)
-
-
Total
1,106,277
(4,000)
585
7,732
(12,160)
1,098,434
690,801
(20,143)
(4,000)
7,597
6,053
53,118
-
(225)
7,732
-
-
-
-
(2,831)
6,053
-
(24,335)
(24,335)
-
-
-
-
-
-
-
-
-
-
41,434
60,625
As at December 31, 2016
1,464,567
41,434
63,847
184,559
1,754,407
The accompanying notes are an integral part of these financial statements.
97
2016 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 and comprehensive income
Adjustments for items not affecting operating cash:
Unrealized loss on financial instruments
Depletion and depreciation
Stock-based compensation
Finance
(Gain) loss on sale of assets
Income tax expense (recovery)
Interest paid (Note 13)
Dividends on capital securities
Decommissioning expenditures
Changes in non-cash working capital (Note 18)
FINANCING
Exercise of stock options
Issue of common shares
Share issue costs
Financing fees paid on credit facilities
Dividends on perpetual preferred shares
Dividends on capital securities
Net change in non-revolving term credit facilities
Net change in revolving term credit facilities
INVESTING
Petroleum and natural gas properties and equipment
Exploration and evaluation assets
Acquisition of petroleum and natural gas properties (Note 6)
Sale of petroleum and natural gas properties and equipment
Sale of exploration and evaluation assets
Changes in non-cash working capital (Note 18)
Net change in cash
Cash, beginning of year
CASH, END OF YEAR
The accompanying notes are an integral part of these financial statements.
98
2016
2015
(24,335)
(12,160)
9,433
149,369
2,478
33,940
9,489
(6,126)
(30,305)
3,500
(1,343)
(5,586)
140,514
7,597
690,801
(27,589)
(795)
(4,000)
(3,500)
-
(49,540)
612,974
(168,431)
(46)
(614,273)
20,720
-
8,532
-
147,163
3,206
26,015
(7,339)
23,232
(22,861)
3,500
(893)
(11,066)
148,797
585
-
-
(940)
(4,000)
(3,500)
(129,970)
283,340
145,515
(258,041)
(113)
-
10,887
60
(47,102)
(753,498)
(294,309)
(10)
57
47
3
54
57
Birchcliff Energy Ltd. BIRCHCLIFF ENERGY LTD.
NOTES TO THE FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2016
(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 15, 2017.
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 IASB as at and for the years ended December 31, 2016 and December 31, 2015. 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 stock-based 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 petroleum and natural gas is recognized when volumes are delivered and title passes to an external
party at contractual delivery points and are recorded gross of transportation charges incurred by the Corporation. The costs
associated with the delivery, including transportation and production-based royalty expenses, are recognized in the same
period in which the related revenue is earned and recorded.
(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.
(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.
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2016 Annual Report (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.
(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.
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Birchcliff Energy Ltd. 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
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
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2016 Annual Report 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 obligations,
amortization of deferred charges and impairment losses (if any) recognized on financial assets. Interest income is recognized
as it is earned.
(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, 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 and accounts receivable 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.
• 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.
(ii) Derivative financial instruments
Derivatives may be used by the Corporation to manage economic exposure to market risk relating to commodity
prices. 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 and published forward price curves as at the balance sheet date, using the remaining
contracted oil and natural gas volumes and a risk-free interest rate (based on published government rates). 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.
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Birchcliff Energy Ltd. 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
(i)
Impairment of financial assets
Financial assets are assessed at each reporting date to determine whether there is any objective evidence that
they are impaired. A financial asset is considered to be impaired if objective evidence indicates that one or more
events have had a negative effect on the estimated future cash flows of that asset. An impairment loss in respect
of a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the
present value of the estimated future cash flows discounted at the original effective interest rate.
Significant financial assets are tested for impairment on an individual basis. The remaining financial assets are
assessed collectively in groups that share similar credit risk characteristics. Impairment losses are recognized in
profit or loss. An impairment loss is reversed if the reversal can be related objectively to an event occurring after the
impairment loss was recognized.
(ii) Impairment of non-financial assets
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.
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.
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2016 Annual Report (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) Capital Securities
The issuance of Series C Preferred Shares, which are presented as “capital securities” on the statements 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.
(o) 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.
(p) 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 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.
(q) 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
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Birchcliff Energy Ltd. 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.
(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:
(i)
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.
(ii) 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 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.
(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.
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2016 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 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) 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.
(v) 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 balance sheet date could be impacted.
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Birchcliff Energy Ltd. 4. CHANGES IN ACCOUNTING POLICIES
Future Accounting Pronouncements
In January 2016, the IASB issued IFRS 16 Leases. The standard will be effective for annual periods beginning on or after January 1,
2019. Early adoption is permitted, provided IFRS 15 Revenue from Contracts with Customers, has been applied, or is applied at
the same date as IFRS 16. Birchcliff is currently evaluating the impact of adopting IFRS 16 on the financial statements.
In April 2016, the IASB issued amendments to IAS 7 Statement of Cash Flows for annual periods beginning on or after January 1,
2017, with earlier application permitted. The amendments require entities to provide disclosures that enable users of financial
statements to evaluate changes in liabilities arising from financing activities, including both changes arising from cash flows and
non-cash changes. Birchcliff is currently evaluating the impact of the amendments on the financial statements.
In May 2014, the IASB issued IFRS 15 Revenue From Contracts With Customers replacing IAS 11 Construction Contracts,
IAS 18 Revenue and several revenue-related interpretations. IFRS 15 contains a single model that applies to contracts with
customers and two approaches to recognizing revenue: at a point in time or over time. The model features a contract-based
five-step analysis of transactions to determine whether, how much and when revenue is recognized. IFRS 15 is effective for
annual periods beginning on or after January 1, 2018, with earlier adoption permitted. Birchcliff is currently assessing the
impact of adopting IFRS 15; however, it anticipates that this standard will not have a material impact on the Corporation’s
financial statements.
In July 2014, the IASB issued the final version of IFRS 9 Financial Instruments to replace IAS 39 Financial Instruments:
Recognition and Measurement. IFRS 9 aligns hedge accounting more closely with risk management. The new standard does
not fundamentally change the types of hedging relationships or the requirement to measure and recognize ineffectiveness.
However, under the new standard, more hedging strategies that are used for risk management will qualify for hedge
accounting. IFRS 9 is effective for years beginning on or after January 1, 2018. As the Corporation does not currently apply
hedge accounting it anticipates that this standard will not have a material impact on the Corporation’s financial statements.
5. EXPLORATION AND EVALUATION ASSETS
The continuity for exploration and evaluation (“E&E”) assets are as follows:
($000s)
As at December 31, 2014
Additions
Disposals
Lease expiries
As at December 31, 2015
Additions
Lease expiries(2)
As at December 31, 2016
E&E(1)
2,235
117
(1)
(2,104)
247
46
(240)
53
(1) 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 2016 and 2015.
(2) For the year ended December 31, 2016, the Corporation incurred an expense of approximately $0.24 million related to lease expiries on undeveloped land that has been included
as a loss on sale of assets in profit or loss.
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2016 Annual Report 6. PETROLEUM AND NATURAL GAS PROPERTIES AND EQUIPMENT
The continuity for petroleum and natural gas (“P&NG”) properties and equipment are as follows:
($000s)
Cost:
As at December 31, 2014
Additions
Dispositions
As at December 31, 2015
Additions
Acquisitions(1)
Dispositions(2)
P&NG
Assets
Corporate
Assets
2,325,501
10,220
267,711
(4,862)
2,588,350
190,546
634,345
(37,005)
749
-
10,969
2,981
-
-
Total
2,335,721
268,460
(4,862)
2,599,319
193,527
634,345
(37,005)
As at December 31, 2016(3)
3,376,236
13,950
3,390,186
Accumulated depletion and depreciation:
As at December 31, 2014
Depletion and depreciation expense
As at December 31, 2015
Depletion and depreciation expense(4)
Dispositions(2)
As at December 31, 2016
Net book value:
As at December 31, 2015
As at December 31, 2016(5)
(449,409)
(143,181)
(592,590)
(147,837)
5,206
(735,221)
(6,464)
(1,185)
(7,649)
(1,532)
-
(455,873)
(144,366)
(600,239)
(149,369)
5,206
(9,181)
(744,402)
1,995,760
2,641,015
3,320
4,769
1,999,080
2,645,784
(1) In July 2016, Birchcliff acquired certain petroleum and natural gas properties, interests and related assets primarily located in the Gordondale area of Alberta. See “Business
Combination” below.
(2) Consists largely of non-core asset dispositions in the Progress, Grande Prairie and Gordondale areas with combined net book values of $31.4 million for net proceeds of $19.9 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) Future development costs required to develop and produce proved plus probable reserves totalled $4.1 billion at the end of 2016 (2015 – $3.1 billion) and are included in the depletion
expense calculation.
(5) Birchcliff performed an impairment assessment of its P&NG assets on a CGU basis and determined there were no impairment triggers identified at the end of the reporting periods. As
a result, no impairment test was required as at December 31, 2016.
108
Birchcliff Energy Ltd.
Business Combination
On July 28, 2016, Birchcliff acquired significant petroleum and natural gas properties and related assets located in the
Gordondale area of Alberta from Encana Corporation (the “Gordondale Acquisition”). The assets acquired were immediately
adjacent to Birchcliff’s existing Pouce Coupe properties. The Gordondale Acquisition resulted in a significant increase in
production and processing capacity, along with allowing the Corporation to leverage operational synergies created from
having ownership in key assets.
The cash purchase price of approximately $613.5 million (after adjustments) for the Gordondale Acquisition was primarily
funded through the issuance of 110,520,000 subscription receipts at a price of $6.25 (see Note 10, “Capital Stock”).
Results from operations are included in the Corporation’s financial statements from the closing date of the transaction. The
Gordondale Acquisition has been accounted for using the purchase method based on fair values as set forth below:
($000s)
Fair value of net assets acquired:
Prepaid expenses
Petroleum and natural gas properties and equipment
Decommissioning obligations
Total
Consideration:
Cash consideration
1,206
632,387
(20,072)
613,521
613,521
The fair value attributed to the petroleum and natural gas properties and equipment acquired was supported by an
independent reserve engineering report using proved plus probable reserves discounted at a rate based on what a market
participant would pay as well as market metrics for similar assets. The fair value of decommissioning obligations was initially
estimated using a credit-adjusted rate of 7%.
Included in the statements of net loss and comprehensive loss for the year ended December 31, 2016 are the following
amounts relating to the Gordondale Acquisition since July 28, 2016:
($000s)
Petroleum and natural gas revenue
Net income and comprehensive income
84,789
10,530
If the Gordondale Acquisition had occurred on January 1, 2016, the pro-forma results of petroleum and natural gas sales and
net loss and comprehensive loss for the year ended December 31, 2016 is set forth below:
($000s)
Petroleum and natural gas sales
Net loss and comprehensive loss
As
Stated
337,586
(24,335)
Gordondale
Acquisition
Pro Forma
December 31, 2016
95,740
(4,072)
433,326
(28,407)
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
2016
2015
569,000
607,000
11,770
23,037
580,770
630,037
(6,621)
(1,632)
(6,347)
(1,616)
572,517
622,074
109
2016 Annual Report On July 28, 2016, in connection with the closing of the Gordondale Acquisition, the Corporation’s extendible revolving credit
facilities (the “Credit Facilities”) were amended to increase the borrowing base to $950 million from $750 million. After giving
effect to the increase in the borrowing base, the Credit Facilities are comprised of: (i) an extendible revolving syndicated term
credit facility of $900 million (the “Syndicated Credit Facility”); and (ii) an extendible revolving working capital credit facility of
$50 million (the “Working Capital Facility”).
The Credit Facilities allow for prime rate loans, London Inter Bank Offered Rate (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, stock-based 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.
The maturity dates of the Credit Facilities are May 11, 2018. 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.
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 covenants.
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 $266.9 million
(December 31, 2015 – $159.9 million) and is expected to be incurred between 2017 and 2068. A risk-free rate of 2.36%
(December 31, 2015 – 2.26%) and an inflation rate of 2.0% (December 31, 2015 – 2.0%) were used to calculate the fair
value of the decommissioning obligations.
A reconciliation of the decommissioning obligations is set forth below:
As at December 31, ($000s)
Balance, beginning
Obligations incurred
Obligations acquired(1)
Obligations divested
Change in discount rate on acquisition(1)
Changes in estimated future cash flows(2)
Accretion expense
Actual expenditures
Balance, ending
2016
92,504
2,772
20,072
(1,579)
22,599
(4,102)
2,547
(1,343)
2015
85,824
2,086
-
(1,170)
-
4,422
2,235
(893)
133,470
92,504
(1) The decommissioning obligations acquired in the Gordondale Acquisition were initially recognized using a credit-adjusted discount rate of 7%. They were subsequently revalued using
the risk-free rate noted above resulting in the change in discount rate on acquisition of $22.6 million with the offset to petroleum and natural gas properties and equipment.
(2) Changes in estimated future cash flows largely due to the revision in both the risk-free discount rate and abandonment and reclamation cost and date estimates for Birchcliff’s oil and
natural gas wells and facilities.
110
Birchcliff Energy Ltd. 9. INCOME TAXES
Included in the income tax recovery for the year ended December 31, 2016 is a deferred income tax recovery totalling $9.1 million
(2015 – $20.2 million expense) and a Part VI.I dividend tax totalling $3.0 million (2015 – $3.0 million) resulting from preferred
share dividends paid during the period. For the purposes of determining the current income tax, the Corporation applied a
combined Canadian federal and provincial income tax rate of 27% in 2016 (2015 – 26%). For the purposes of determining the
deferred income tax, the Corporation applied a combined Canadian federal and provincial effective income tax rate of 27% in
2016 (2015 – 27%).
The components of income tax recovery (expense) are set forth below:
Years ended December 31, ($000s)
Net income (loss) before taxes
Computed expected income tax recovery (expense)
Decrease (increase) in taxes resulting from:
Non-deductible stock-based compensation
Non-deductible dividends on capital securities
Non-deductible expenses
Increase in Alberta corporate income tax rates
Denial of the Veracel tax pools reassessment(1)
Other
Income tax recovery (expense)
(1) Refer to Note 19.
The components of 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
Deferred income tax assets:
Decommissioning obligations
Risk management contracts - liability
Share issue costs
Non-capital losses
Deferred income tax liabilities
2016
(30,461)
2015
11,072
8,224
(2,879)
(844)
(945)
(147)
-
-
(162)
6,126
(1,025)
(910)
(93)
(7,759)
(10,208)
(358)
(23,232)
2016
2015
309,741
256,004
441
293
436
376
(36,037)
(24,976)
(2,547)
(6,041)
-
(520)
(166,251)
(115,149)
99,599
116,171
111
2016 Annual Report 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 - liability
Share issue costs
Non-capital losses
($000s)
P&NG and E&E assets
Deferred financing fees
Capital securities
Decommissioning obligations
Share issue costs
Non-capital losses
Balance
Jan. 1, 2016
256,004
436
376
(24,976)
-
(520)
(115,149)
116,171
Recognized in
Profit or Loss
Recognized
in Equity
Balance
Dec. 31, 2016
53,737
5
(83)
(11,061)
(2,547)
1,925
(51,102)
(9,126)
Balance
Jan. 1, 2015
185,007
321
426
(21,456)
(885)
(67,472)
95,941
-
-
-
-
-
(7,446)
-
(7,446)
309,741
441
293
(36,037)
(2,547)
(6,041)
(166,251)
99,599
Recognized in
Profit or Loss
Balance
Dec. 31, 2015
70,997
115
(50)
(3,520)
365
(47,677)
20,230
256,004
436
376
(24,976)
(520)
(115,149)
116,171
As at December 31, 2016, the Corporation had approximately $2.1 billion (2015 - $1.5 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 $615 million that expire between 2026 and 2036. 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.
112
Birchcliff Energy Ltd.
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 - Jan 1
Issue of common shares
Exercise of stock options
Outstanding at end of period
Series A Preferred Shares (perpetual)(1):
Outstanding at beginning of period - Jan 1
Outstanding at end of period
2016
2015
152,308
110,525
1,209
264,042
152,214
-
94
152,308
2,000
2,000
2,000
2,000
(1) 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; and three common share purchase warrants of Birchcliff (the “preferred warrants”). Each preferred warrant provided the right to purchase one common share
until August 8, 2014, at an exercise price of $8.30 per common share.
The Series A Preferred Shares pay cumulative dividends of $2.00 per Series A Preferred Share per annum, payable quarterly if, as and when declared by Birchcliff’s Board of Directors,
for the initial five year period ending September 30, 2017. 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 are redeemable at $25.00 per preferred share at the option of the Corporation on September 30, 2017 and on September 30 in
every fifth year thereafter. Holders of the Series A Preferred Shares have 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 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.
113
2016 Annual Report
On and 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, 2016 (2015 – 2,000,000).
Issue of Common Shares
On July 13, 2016, in connection with the Gordondale Acquisition, Birchcliff closed a bought deal financing of 107,520,000
subscription receipts of the Corporation (“Subscription Receipts”) at a price of $6.25 per Subscription Receipt for gross
proceeds of $672.0 million (the “Public Offering”) and a concurrent private placement of 3,000,000 Subscription Receipts
at a price of $6.25 per Subscription Receipt for gross proceeds of $18.8 million (the “Concurrent Private Placement”). Gross
proceeds from the Public Offering and the Concurrent Private Placement were $690.8 million.
On July 28, 2016, Birchcliff closed the Gordondale Acquisition and each Subscription Receipt was exchanged for one
common share of the Corporation for no additional consideration. The net proceeds of $663.2 million, after fees payable to
the underwriters of the Public Offering, were used to pay the balance of the purchase price for the Gordondale Acquisition,
and the remaining balance was used to reduce indebtedness under the Corporation’s Credit Facilities. Birchcliff recognized
a deferred income tax benefit of $7.5 million in respect of share issue costs related to the Public Offering and Concurrent
Private Placement totalling approximately $27.6 million.
Dividends
On November 30, 2016, the Board of Directors declared a quarterly cash dividend of $1.0 million or $0.50 per Series A Preferred
Share and $0.875 million or $0.4375 per Series C Preferred Share for the calendar quarter ending December 31, 2016.
In 2016, cash dividends totalled $4.0 million or $2.00 per Series A Preferred Share (2015 - $4.0 million or $2.00 per Series A)
and $3.5 million or $1.75 per Series C Preferred Share (2015 - $3.5 million or $1.75 per Series C).
Both dividends are designated as an eligible dividend for the purposes of the Income Tax Act (Canada).
Per Common Share
The following table sets forth the computation of net loss per common share:
Years ended December 31,
Net loss ($000s)
Dividends on Series A Preferred Shares ($000s)
Net loss to common shareholders ($000s)
Weighted average common shares (000s):
Weighted average basic common shares outstanding
Effects of dilutive securities
Weighted average diluted common shares outstanding(1)
Net loss per common share
Basic
Diluted
2016
24,335
4,000
28,335
2015
12,160
4,000
16,160
199,581
152,286
-
-
199,581
152,286
$0.14
$0.14
$0.11
$0.11
(1) As the Corporation reported a loss for the twelve months ended December 31, 2016, the basic and diluted weighted average shares outstanding are the same for the period.
The weighted average diluted common shares outstanding as of December 31, 2016 excludes 15,839,507 common shares issuable pursuant to outstanding stock options and
performance warrants that are anti-dilutive in the twelve month reporting period (December 31, 2015 – 15,508,970).
114
Birchcliff Energy Ltd. 11. OPERATING EXPENSES
The Corporation’s operating expenses include all costs with respect to day-to-day well and facility operations.
Processing recoveries related to joint ventures reduces operating expenses. 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
12. 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:
Stock-based compensation
Capitalized stock-based compensation(3)
Stock-based compensation, net
Administrative expenses, net
2016
76,705
(1,700)
75,005
246
2015
65,281
(1,500)
63,781
730
75,251
64,511
2016
2015
25,576
12,449
38,025
(154)
27,067
12,297
39,364
(232)
(16,382)
(16,308)
21,489
22,824
6,053
7,732
(3,575)
(4,526)
2,478
3,206
23,967
26,030
(1) Includes salaries, benefits and bonuses paid to officers and employees 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 stock-based compensation directly attributable to the exploration and development activities of the Corporation
which have been capitalized.
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)
Executive Officers and Directors compensation
2016
6,206
1,588
7,794
2015
6,175
2,284
8,459
(1) Includes salaries for the executive officers, directors’ fees for the independent directors and benefits earned by executive officers and directors comprising of: the Chairman of the
Board, the President and Chief Executive Officer, the Vice-President of Exploration and Chief Operating Officer, the Vice-President and Chief Financial Officer, the Vice-President of
Operations, the Vice-President of Engineering, the Vice-President of Corporate Development and the independent directors.
(2) Represents the amortization of stock-based compensation expense in the year associated with options granted to the executive officers and directors participating in the Corporation’s
Amended and Restated Stock Option Plan.
115
2016 Annual Report 13. FINANCE EXPENSES
The components of finance expenses are set forth below:
Years ended December 31, ($000s)
Cash:
Interest on credit facilities
Non-cash:
Accretion on decommissioning obligations
Amortization of deferred financing fees
Finance expenses
14. SHARE-BASED PAYMENTS
Stock Options
2016
2015
30,305
22,861
2,547
1,088
2,235
919
33,940
26,015
At December 31, 2016, the Corporation’s Amended and Restated Stock Option Plan (the “Option Plan”) permitted the grant of
options in respect of a maximum of 26,404,190 (December 31, 2015 – 15,230,754) common shares. At December 31, 2016,
there remained available for issuance options in respect of 13,504,415 (December 31, 2015 – 2,661,516) common shares. For
stock options exercised during 2016, the weighted average common share trading price on the Toronto Stock Exchange was
$7.70 (December 31, 2015 – $6.42) per common share.
A summary of the outstanding stock options is set forth below:
Outstanding, December 31, 2014
Granted(1)
Exercised
Forfeited
Expired
Outstanding, December 31, 2015
Granted(1)
Exercised
Forfeited
Expired
Outstanding, December 31, 2016(1)
(1) Each stock option granted entitles the holder to purchase one common share at the exercise price.
Number
11,147,672
3,358,500
(93,333)
(699,201)
(1,144,400)
12,569,238
3,356,000
(1,209,363)
(120,400)
(1,695,700)
12,899,775
Weighted Average
Exercise Price ($)
8.45
6.62
(6.26)
(9.70)
(9.66)
7.80
3.90
(6.28)
(6.78)
(11.46)
6.45
The weighted average fair value per option granted during 2016 was $1.40 (December 31, 2015 – $2.14). In determining the
stock-based compensation expense for options issued during 2016, the Corporation applied a weighted average estimated
forfeiture rate of 12% (December 31, 2015 – 13%).
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
2016
0.6%
4.0
2015
0.7%
4.0
45.3%
40.8%
116
Birchcliff Energy Ltd.
A summary of the stock options outstanding and exercisable under the Option Plan at December 31, 2016 is set forth below:
Exercise Price
Awards Outstanding
Awards Exercisable
Weighted
Average
Remaining
Contractual
Life
2.98
2.28
2.68
2.30
2.52
Weighted
Average
Exercise
Price
$4.16
$7.52
$9.96
$12.31
$6.45
Weighted
Average
Remaining
Contractual
Life
0.32
1.83
2.57
2.30
1.56
Weighted
Average
Exercise
Price
$5.96
$7.68
$9.99
$12.31
$7.40
Quantity
1,233,033
5,187,252
129,331
2,000
6,551,616
Low
$3.35
$6.01
$9.01
$12.01
High
$6.00
$9.00
$12.00
$12.31
Quantity
4,252,200
8,440,575
204,000
3,000
12,899,775
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, 2016
(December 31, 2015 – 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.
15. 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 growth 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 the year ended December 31, 2016.
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
2016
2015
950,000
800,000
(580,770)
(630,037)
(12,310)
(242)
(593,080)
(630,279)
356,920
169,721
(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.
On July 28, 2016, in connection with the closing of the Gordondale Acquisition, the borrowing base was increased to $950 million.
(2) Letters of credit are issued to various service providers. In connection with the Gordondale Acquisition, the Corporation issued a letter of credit for $12 million to secure its obligations
under various midstream and marketing arrangements. The aforementioned letter of credit has reduced the amount available under the Working Capital Facility from $50 million to
approximately $38 million. There were no amounts drawn on the letters of credit during 2016 and 2015.
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2016 Annual Report
The capital structure of the Corporation is as follows:
As at December 31, ($000s)
Shareholders’ equity(1)
Capital securities
2016
2015
Change
1,754,407
1,098,434
48,916
48,606
Shareholders’ equity & capital securities
1,803,323
1,147,040
57%
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
Capital
75%
64%
27,495
21,538
580,770
630,037
608,265
651,575
(7%)
25%
36%
2,411,588
1,798,615
34%
(1) Shareholders’ equity is defined as share capital plus contributed surplus plus retained earnings, less any deficit.
(2) Of the 75%, approximately 70% relates to common capital stock and 5% relates to preferred capital stock.
(3) Working capital deficit is defined as current assets less current liabilities (excluding fair value of financial instruments).
16. FINANCIAL RISK MANAGEMENT
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 instrument fails to
meet its contractual obligation, and arises principally from Birchcliff’s receivables from its oil and natural gas marketers.
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 balance sheet 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(2)
Accounts receivable
2016
47,021
373
15,178
2015
22,181
1,229
-
62,572
23,410
(1) At December 31, 2016, approximately 15% was due from one marketer (2015 – 24%, one marketer). During 2016, the Corporation received 20%, 12%, 12%, 10%, and 10% of its
revenue, respectively, from five core marketers (2015 – 20%, 18%, 15%, 15%, 13% and 12% of its revenue, respectively, from six core marketers).
(2) Primarily includes $6.3 million receivable for leasehold improvements and a $4.5 million receivable for the final statement of adjustments respecting the Gordondale Acquisition.
118
Birchcliff Energy Ltd. 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 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
2016
59,733
2,420
142
40
237
2015
22,569
289
332
91
129
62,572
23,410
At December 31, 2016, approximately $0.2 million or 0.4% (2015 – $0.1 million or 0.6%) 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 accounts receivable represents the maximum credit exposure. Should Birchcliff determine that the
ultimate collection of a financial instrument is in doubt, it will provide the necessary provision in its allowance for doubtful
accounts with a corresponding charge to profit or loss. If the Corporation subsequently determines an account is uncollectible,
the account is written off with a corresponding charge to the allowance for doubtful accounts. Birchcliff did not have an
allowance for doubtful accounts balance at December 31, 2016 and December 31, 2015.
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.
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 2016 (2015 - $800 million) which are reviewed annually by its lenders (see Note 7). The principal
amount drawn under the Corporation’s total credit facilities at December 31, 2016 was $593.1 million (2015 – $630.3 million)
and $356.9 million in unused credit was available at the end of 2016 (2015 – $169.7 million) to fund future obligations.
119
2016 Annual Report The following table lists the Corporation’s financial liabilities at December 31, 2016 in the period they are due:
($000s)
Accounts payable and accrued liabilities
Drawn revolving credit facilities
Fair value of financial instruments
Financial liabilities
Market Risk
2017
92,115
-
9,433
101,548
2018
-
580,770
-
580,770
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.
Financial derivative contracts
During 2016, 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, 2016, the Corporation had the following financial derivatives in place:
Product
Type of
contract
Notional
quantity
Term(1)
Contract price
Fair value
($000s)
Natural Gas
Financial swap
40,000 GJ/d
Natural Gas
Financial swap
20,000 GJ/d
Natural Gas
Financial swap
10,000 GJ/d
Natural Gas
Financial swap
10,000 GJ/d
Crude oil
Financial swap
1,500 bbls/d
Fair value liabilities
January 1, 2017 –
December 31, 2017
January 1, 2017 –
December 31, 2017
October 1, 2017 –
December 31, 2017
October 1, 2017 –
December 31, 2017
January 1, 2017 –
December 31, 2017
AECO CDN $2.97/GJ
4,345
AECO CDN $2.98/GJ
2,042
AECO CDN $3.35/GJ
AECO CDN $3.40/GJ
WTI CDN $69.90/bbl
19
(17)
3,044
9,433
(1) Transactions with common terms and the same counterparty have been aggregated and presented at the weighted average price, where applicable.
The fair value liability of the Corporation’s financial derivative contracts at December 31, 2016 was $9.4 million (2015 – NIL).
As of December 31, 2016, if the future strip prices for AECO natural gas had been CDN$0.10/GJ higher, with all other variables
held constant, the after tax net loss in 2016 would have increased by $2.4 million. As of December 31, 2016, if the future strip
prices for WTI crude oil had been CDN$1.00/bbl higher, with all other variables held constant, after tax net loss in 2016 would
have increased by $0.4 million.
120
Birchcliff Energy Ltd. The following table provides a summary of the realized gain and unrealized loss on financial derivative contracts:
Years ended December 31, ($000s)
Realized gain on derivatives
Unrealized (loss) on derivatives
2016
802
(9,433)
2015(1)
-
-
(1) During 2015, the Corporation did not have any financial derivative contracts in place.
There were no financial derivative contracts entered into subsequent to December 31, 2016.
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, 2016, the
Corporation had the following physical sales contracts in place:
Product
Natural Gas
Type of
contract
Fixed price
Volume
20,000 GJ/d
Natural Gas
Fixed price
20,000 GJ/d
Natural Gas
Fixed price
20,000 GJ/d
Natural Gas
Fixed price
10,000 GJ/d
Natural Gas
Fixed price
50,000 GJ/d
Natural Gas
Fixed price
10,000 GJ/d
Term(1)
Contract price
January 1, 2017 –
December 31, 2017
January 1, 2017 –
December 31, 2017
January 1, 2017 –
December 31, 2017
January 1, 2017 –
December 31, 2017
January 1, 2017 –
December 31, 2017
October 1, 2017 –
December 31, 2017
AECO CDN$2.99/GJ
AECO CDN$2.98/GJ
AECO CDN$3.00/GJ
AECO CDN$3.00/GJ
AECO CDN$3.05/GJ
AECO CDN$3.35/GJ
(1) Transactions with common terms and the same counterparty have been aggregated and presented at the weighted average price, where applicable.
There were no physical delivery sales contracts entered into subsequent to December 31, 2016.
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 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, 2016 and 2015.
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 2016 would have changed after-tax net income by approximately $4.6 million
(2015 - $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 considers this risk to
be limited and thus does not enter into contracts to mitigate its interest rate risk. The Corporation had no interest rate swap
contracts in place as at or during the years ended December 31, 2016 and 2015.
121
2016 Annual Report Fair Value of Financial Instruments
Birchcliff’s financial instruments include cash, accounts receivable, 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.
• 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, 2016 are set forth below:
($000s)
Loans and receivables:
Cash
Accounts receivable
Other liabilities:
Accounts payable and accrued liabilities
Fair value of financial derivatives(1)
Capital Securities
Drawn revolving credit facilities
(1) Financial derivative contracts are fair valued based on level 2.
17. COMMITMENTS
Carrying
Value
Fair
Value
47
62,572
92,115
9,433
48,916
572,517
47
62,572
92,115
9,433
50,400
572,517
The Corporation enters into contracts and commitments in the normal course of operations. The following table lists
Birchcliff’s commitments at December 31, 2016:
($000s)
Operating leases(1)
Capital commitments(2)
Firm transportation, processing and fractionation(3)
Commitments
2017
3,206
36,128
36,315
75,649
2018
4,117
16,849
105,179
126,145
2019 - 2021
Thereafter
13,625
-
294,158
307,783
29,317
-
294,980
324,297
(1) The Corporation is committed under its existing operating lease relating to its office premises beginning December 1, 2007 which expires on November 30, 2017. On December 2,
2015, the Corporation entered into an operating lease commitment relating to a new office premise beginning February 1, 2018 and expiring on January 31, 2028. The commitment
amount under the new 10 year office lease is estimated to be $47.1 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 drilling commitments and facility spending commitments relating to the Phase V and VI expansions of the PC Gas Plant.
(3) As a result of the Gordondale Acquisition, Birchcliff’s firm transportation, processing and fractionation obligations have increased as at December 31, 2016.
122
Birchcliff Energy Ltd.
18. 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
19. CONTINGENT LIABILITY
2016
2015
(39,162)
577
11,521
(967)
44,531
(65,556)
(3,000)
(3,166)
2,946
(58,168)
(5,586)
(11,066)
8,532
2,946
(47,102)
(58,168)
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, which includes approximately $16.2 million in non-capital losses,
$15.6 million in scientific research and experimental development expenditures and $7.5 million in investment tax credits.
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). Birchcliff appealed the Trial Decision
to the Federal Court of Appeal. The appeal was held in January 2017 and the Corporation is currently awaiting a decision.
While management continues to believe that its tax position is supportable, in the fourth quarter of 2015 Birchcliff recorded a
deferred income tax expense in the amount of $10.2 million as a result of the Trial Decision being rendered. This Trial Decision
did not result in any cash taxes payable by Birchcliff.
123
2016 Annual Report GLOSSARY
Capitalized terms not otherwise defined in this Annual Report shall have the following meanings:
“2015 Deloitte Price Forecast”
has the meaning set forth under the heading “2016 Year-End Reserves”.
“2015 Deloitte Reserves Report”
has the meaning set forth under the heading “2016 Year-End Reserves”.
“2016 Consolidated Reserves Report”
has the meaning set forth under the heading “2016 Year-End Reserves”.
“2016 Deloitte Price Forecast”
means Deloitte’s December 31, 2016 forecast price and cost assumptions set out
under the heading “2016 Year-End Reserves”.
“2016 Deloitte Reserves Report”
has the meaning set forth under the heading “2016 Year-End Reserves”.
“2016 McDaniel Reserves Report”
has the meaning set forth under the heading “2016 Year-End Reserves”.
“Birchcliff”, “our”, “its”, “us” or “we”
means Birchcliff Energy Ltd.
“Charlie Lake Light Oil Resource Play”
means Birchcliff’s Charlie Lake formation light oil resource play located northwest of
Grande Prairie, Alberta.
“COGE Handbook”
“Deloitte”
“GAAP”
means the Canadian Oil and Gas Evaluation Handbook maintained by the Society of
Petroleum Evaluation Engineers (Calgary Chapter), as amended from time to time.
means Deloitte LLP, independent qualified reserves evaluators of Calgary, Alberta.
means generally accepted accounting principles.
“Gordondale Acquisition”
means the acquisition of the Gordondale Assets, which closed on July 28, 2016.
“Gordondale Assets”
“McDaniel”
means the petroleum and natural gas properties, interests and related assets primarily
located in the Gordondale area in the Province of Alberta acquired pursuant to the
Gordondale Acquisition.
means McDaniel & Associates Consultants Ltd., independent qualified reserves
evaluators of Calgary, Alberta.
“Montney/Doig Resource Play”
means Birchcliff’s Montney and Doig formations resource play located northwest of
Grande Prairie, Alberta.
“NI 51-101”
“PC Gas Plant”
“TSX”
“Western Canadian
Sedimentary Basin”
“working interest”
means National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities.
means Birchcliff’s 100% owned and operated natural gas plant located in the
Pouce Coupe area.
means the Toronto Stock Exchange.
means the vast sedimentary basin underlying Western Canada that is the source of most
of Western Canada’s current oil and gas production.
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.
“Worsley Charlie Lake Light Oil
Resource Play”
“Worsley Property”
means Birchcliff’s Charlie Lake Light Oil Resource Play located near Worsley, Alberta.
means certain oil and natural gas assets in the Worsley area that were acquired by
Birchcliff in September 2007.
124
Birchcliff Energy Ltd. ABBREVIATIONS AND CONVERSIONS
Abbreviations
The abbreviations set forth below have the following meanings:
Oil and Natural Gas Liquids
bbl
bbls
Mbbls
NGLs
Natural Gas
GJ
Mcf
MMcf
MMcf/d
Other
AECO
Bcfe
boe
boe/d
F&D
FD&A
FDC
km
m
m3
Mboe
MMboe
Mcfe
MM$
WTI
000s
$000s
barrel
barrels
thousand barrels
natural gas liquids
gigajoule
thousand cubic feet
million cubic feet
million cubic feet per day
physical storage and trading hub for natural gas on the TransCanada Alberta transmission system
which is the delivery point for various benchmark Alberta index prices
billion cubic feet of gas equivalent
barrels of oil equivalent
barrels of oil equivalent per day
finding and development
finding, development and acquisition
future development costs
kilometres
metres
cubic metres
thousand barrels of oil equivalent
million barrels of oil equivalent
thousand cubic feet of gas equivalent
millions of dollars
West Texas Intermediate oil at Cushing, Oklahoma, the benchmark for North American crude oil pricing
thousands
thousands of dollars
Conversions
The following table sets forth certain Standard Imperial Units and International System of Units conversions:
From
Mcf
m3
bbls
acres
sections
sections
To
m3
cubic feet
cubic metres
hectares
acres
hectares
Multiply By
28.174
35.494
0.159
0.405
640
256
125
2016 Annual Report CONVENTIONS
Certain terms used herein but not defined are defined in NI 51-101, CSA Staff Notice 51-324 – Revised Glossary to NI 51-101
Standards of Disclosure for Oil and Gas Activities (“CSA Staff Notice 51-324”) and/or the COGE Handbook and, unless the context
otherwise requires, shall have the same meanings in this Annual Report as in NI 51-101, CSA Staff Notice 51-324 or the COGE
Handbook, as the case may be. Unless otherwise indicated, references in this Annual Report to “$”, “CDN$” or “dollars” are to
Canadian dollars and references to “US$” are to United States dollars. All financial information contained in this Annual Report has
been presented in accordance with Canadian GAAP. Words importing the singular number only include the plural, and vice versa,
and words importing any gender include all genders.
PRESENTATION OF OIL AND GAS RESERVES
Deloitte prepared the 2016 Consolidated Reserves Report, the 2016 Deloitte Reserves Report and the 2015 Deloitte Reserves
Report. McDaniel prepared the 2016 McDaniel Reserves Report. In addition, Deloitte or its predecessors prepared reserves
evaluations in respect of Birchcliff’s oil and natural gas properties effective December 31, 2014, 2013, 2012, 2011, 2010 and
2009. 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, including many factors beyond the control of Birchcliff. 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, initial production rates, production decline rates, ultimate reserves
recovery, the timing and amount of capital expenditures, the success of future development activities, future commodity prices,
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 those reasons, estimates of the economically recoverable
oil, natural gas and NGLs reserves attributable to any particular group of properties, 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 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.
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. Estimates of future net revenue, whether calculated
without discount or using a discount rate, do not represent fair market value. In this Annual Report, all references to “reserves”
are to Birchcliff’s gross company reserves unless otherwise stated.
The information set forth in this Annual Report relating to Birchcliff’s reserves, future net revenues and future development
costs constitutes forward-looking information which is subject to certain risks and uncertainties. See “Advisories – Forward-
Looking Information”.
For further information regarding the risks and uncertainties associated with Birchcliff’s reserves, please see Birchcliff’s Annual
Information Form for the year ended December 31, 2016.
126
Birchcliff Energy Ltd. RESERVE 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.
DEVELOPMENT AND PRODUCTION STATUS OF RESERVES
Each of the reserves categories (proved and probable) may be divided into developed and undeveloped categories:
•
“Developed reserves” are those reserves that are expected to be recovered from existing wells and installed facilities or, if
facilities have not been installed, that would involve a low expenditure (e.g., when compared to the cost of drilling a well)
to put the reserves on production. The developed category may be subdivided into producing and non-producing.
o
o
“Developed producing reserves” are those reserves that are expected to be recovered from completion intervals open
at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been
on production, and the date of resumption of production must be known with reasonable certainty.
“Developed non-producing reserves” are those reserves that either have not been on production, or have previously
been on production but are shut-in and the date of resumption of production is unknown.
•
“Undeveloped reserves” are those reserves expected to be recovered from known accumulations where a significant
expenditure (e.g., when compared to the cost of drilling a well) is required to render them capable of production. They
must fully meet the requirements of the reserves category (proved and probable) to which they are assigned.
In multi-well pools it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to
subdivide the developed reserves for the pool between developed producing and developed non-producing. This allocation should
be based on the estimator’s assessment as to the reserves that will be recovered from specific wells, facilities, and completion
intervals in the pool and their respective development and production status.
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.
127
2016 Annual Report INTEREST IN RESERVES, PRODUCTION, WELLS AND PROPERTIES
“Gross” means:
(a) in relation to Birchcliff’s interest in production or reserves, its “company gross reserves”, which are 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.
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).
128
Birchcliff Energy Ltd. NON-GAAP MEASURES
This Annual Report uses “funds flow”, “funds flow from operations”, “funds flow per common share”, “netback”, “operating netback”,
“total cash costs” 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 details on these non-GAAP measures, please see “Non-GAAP Measures” in the MD&A.
In addition, this Annual Report uses “funds flow netback”. Funds flow netback denotes petroleum and natural gas revenue less
royalties, less operating expenses, less transportation and marketing expenses, less net general and administrative expenses, less
interest expenses and less any realized losses (plus realized gains) on financial instruments and plus any other cash income sources.
Funds flow netback has been calculated on a per boe basis, unless otherwise indicated. Management believes that 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 operating netback
and funds flow netback for the twelve months ended December 31, 2016 and 2015:
Petroleum and natural gas revenue
Royalty expense
Operating expense
Transportation and marketing expense
Operating Netback
General & administrative expense, net
Interest expense
Realized gain on financial instruments
Funds Flow Netback
Twelve months ended
December 31,2016
Twelve months ended
December 31,2015
($000s)
337,586
(20,911)
(75,251)
(42,989)
198,435
(21,489)
(30,305)
802
147,443
($/boe)(1)
($000s)
($/boe)(1)
18.73
317,304
(1.16)
(11,548)
(4.18)
(64,511)
(2.38)
(34,804)
11.01
206,441
(1.19)
(22,824)
(1.68)
(22,861)
0.04
-
8.18
160,756
22.32
(0.81)
(4.54)
(2.45)
14.52
(1.61)
(1.60)
-
11.31
(1) All per boe figures are calculated by dividing each aggregate financial amount by the production (boe) in the respective period.
129
2016 Annual Report ADVISORIES
CURRENCY
All amounts in this Annual Report are stated in Canadian dollars unless otherwise specified.
BOE, MCFE AND BCFE CONVERSIONS
Boe amounts have been calculated by using the conversion ratio of 6 Mcf of natural gas to 1 bbl of oil and Mcfe and Bcfe amounts
have been calculated by using the conversion ratio of 1 bbl of oil to 6 Mcf of natural gas. Boe, Mcfe and Bcfe amounts may be
misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 bbl or an Mcfe/Bcfe 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.
CONVERSION FROM GJ TO MCF – WELLHEAD PRICE
Birchcliff receives premium pricing for its natural gas production due to its high heat content from its properties. With respect to
Birchcliff’s natural gas hedging contracts in 2017, the prices have been presented in $/Mcf, which have been converted from the
price under contract of $/GJ and represent the average expected natural gas wellhead price under contract. The conversion from
GJ to Mcf is based on an expected corporate average natural gas heat content value of 40.69 MJ/m3 in 2017.
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. 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 and should not be used to make comparisons. Such metrics have been included herein to
provide readers with additional measures to evaluate Birchcliff’s performance; however, such measures are not reliable indicators
of Birchcliff’s future performance and future performance may not compare to Birchcliff’s performance in previous periods and
therefore such metrics 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, 2016 by 72,000 boe/d, which production rate represents the mid-point of Birchcliff’s annual average
production guidance range for 2017. 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 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 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 acquisition
and dispositions. FD&A costs are calculated in the same manner as F&D costs but include the effect of acquisitions
and dispositions.
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 Birchcliff’s independent qualified
reserves evaluators, effective December 31 of such year.
130
Birchcliff Energy Ltd. 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 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 5,992.8 net
existing horizontal wells and potential net future horizontal drilling locations identified herein, 721.7 are proved locations, 974.4 are
proved plus probable locations and 5,018.4 are unbooked locations.
Proved locations and probable locations are proposed drilling locations identified in the 2016 Consolidated Reserves Report that
have proved and/or probable reserves, as applicable, attributed to them in the 2016 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 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 2016 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, capital and operating costs, inclement weather, seasonal restrictions, drilling results, additional geological, geophysical
and reservoir information that is obtained, production rate recovery, gathering system and transportation constraints, 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 or if Birchcliff will be able to
produce oil, NGLs or natural gas from these or any other potential drilling locations. 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 derisked by drilling existing wells in relative 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 therefore there is 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.
OPERATING COSTS
References in this Annual Report to “operating costs” exclude transportation and marketing costs.
PAYMENT OF DIVIDENDS
The declaration and payment of dividends in any quarter and the amount of such dividends, if any, 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
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) 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.
TEST RESULTS AND INITIAL PRODUCTION RATES
References in this Annual Report to production test rates, initial test production rates and other short-term production rates are
useful in confirming the presence of hydrocarbons; however, such rates are not determinative of the rates at which such wells
will continue to produce and decline thereafter and are not indicative of the long-term performance or of the ultimate recovery of
such wells. Additionally, such rates may also include recovered “load oil” or “load water” fluids used in well completion stimulation.
While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for Birchcliff.
A pressure transient analysis or well-test interpretation has not been carried out in respect of all wells. Accordingly, Birchcliff cautions
that the test results should be considered to be preliminary.
131
2016 Annual Report FORWARD LOOKING INFORMATION
Certain statements contained in this Annual Report constitute forward-looking statements and information (collectively
referred to as “forward-looking information”) within the meaning of applicable Canadian securities laws. Such forward-looking
information relates to future events or Birchcliff’s future performance. All information other than historical fact may be forward-
looking information. Such forward-looking information is often, but not always, identified by the use of words such as “seek”,
“plan”, “expect”, “project”, “intend”, “believe”, “anticipate”, “estimate”, “estimated”, “forecast”, “potential”, “proposed”, “predict”,
“budget”, “continue”, “targeting”, “may”, “will”, “could”, “might”, “should” and other similar words and expressions. This information
involves 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 information. Birchcliff believes that the expectations reflected in the forward-
looking information are reasonable in the current circumstances but no assurance can be given that these expectations will prove
to be correct and such forward-looking information included in this Annual Report should not be unduly relied upon.
In particular, this Annual Report contains forward-looking information relating to the following: Birchcliff’s plans and other
aspects of its anticipated future operations, focus, objectives, strategies, opportunities and goals, including its key objectives
for 2017; Birchcliff’s competitive position; expectations regarding future demand for oil and natural gas and commodity prices;
Birchcliff’s focus on delivering 130,000 boe/d of production by the end of 2021, while continuing to be one of the most profitable
producers in the industry with a focus on low costs and high netbacks and delivering top tier F&D costs and strong recycle ratios;
Birchcliff’s 2017 capital expenditure program, including planned capital expenditures and capital allocation and Birchcliff’s plan to
drill a total of 46 wells; Birchcliff’s production guidance, including estimates of its annual average production and exit production
rates; estimates of reserves and the net present values of future net revenue associated with Birchcliff’s reserves; price forecasts;
FDC; reserves life index; performance characteristics of Birchcliff’s oil and natural gas properties, expected results from its assets
and the potential of Birchcliff’s resource plays, including statements that Birchcliff’s resource plays are large enough to provide it
with an extensive inventory of repeatable and low-cost drilling opportunities that is expected to provide production and reserves
growth for many years; potential future drilling locations and opportunities; Birchcliff’s proposed exploration and development
activities and the timing thereof, including wells to be drilled and brought on production; proposed expansions of the PC Gas
Plant, including the anticipated processing capacities of the PC Gas Plant after such expansions and the anticipated timing and
costs associated with such expansions; Birchcliff’s future growth plans for the Elmworth area, including Birchcliff’s intention to
construct and operate the Elmworth Gas Plant and the anticipated processing capacity and timing of such plant; statements
regarding the sustainability of dividends; the Five Year Plan, including the production targets and commodity mix forecast by the
plan, the focus of, objectives of and anticipated results of the plan and statements that Birchcliff expects to generate significant
free funds flow over the five year period, while paying a common share dividend and maintaining financial flexibility. In addition,
forward-looking information in this Annual Report includes the forward-looking information identified in the MD&A under the
heading “Advisories - Forward-Looking Information”. Information relating to reserves is forward-looking as it 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.
With respect to forward-looking information contained in this Annual Report, assumptions have been made regarding, among
other things: Birchcliff’s ability to continue to develop the Gordondale Assets and obtain the anticipated benefits therefrom;
prevailing and future commodity prices and differentials, currency exchange rates, interest rates, inflation rates, royalty rates and
tax rates; expected funds flow from operations; Birchcliff’s future debt levels; the state of the economy and the exploration and
production business; the economic and political environment in which Birchcliff operates; the regulatory framework regarding
royalties, taxes and environmental laws; the sources of funding for Birchcliff’s capital expenditure programs and other activities;
anticipated timing and results of capital expenditures; the sufficiency of budgeted capital expenditures to carry out planned
operations; results of future operations; future operating, transportation, marketing and general and administrative costs; the
performance of existing and future wells, well production rates and well decline rates; well drainage areas; success rates for future
drilling; reserves and resource volumes and Birchcliff’s ability to replace and expand oil and gas reserves through acquisition,
development or exploration; the impact of competition on Birchcliff; the availability of, demand for and cost of labour, services
and materials; Birchcliff’s ability to access capital; the ability to obtain financing on acceptable terms; the ability to obtain any
necessary regulatory approvals in a timely manner; the ability of Birchcliff to secure adequate transportation for its products;
Birchcliff’s ability to market oil and gas; and the availability of hedges on terms acceptable to Birchcliff.
132
Birchcliff Energy Ltd. In addition to the foregoing assumptions, Birchcliff has made the following assumptions with respect to certain forward-looking
information contained in this Annual Report:
• With respect to Birchcliff’s production guidance, the key assumptions are that: Birchcliff’s capital expenditure programs
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.
• 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.
• 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 proposed expansions of the PC Gas Plant, including the anticipated processing
capacities of the PC Gas Plant after such expansions and the anticipated timing of such expansions, the key assumptions
are that: future drilling is successful; there is sufficient labour, services and equipment available; Birchcliff will have access to
sufficient capital to fund those projects; the key components of the plant will operate as designed; and commodity prices
and general economic conditions will warrant proceeding with the construction of such facilities and the drilling
of associated wells.
• With respect to statements regarding Birchcliff’s intention to construct and operate the Elmworth Gas Plant, including
the anticipated processing capacity of such plant and the anticipated timing thereof, the key assumptions are that: future
drilling in the Elmworth area is successful; the acid gas disposal well drilled by Birchcliff is capable of handling the volumes
of acid gas to be produced at the plant and complies with all regulatory requirements; there is sufficient labour, services
and equipment available; Birchcliff will have access to sufficient capital to fund the Elmworth Gas Plant; and commodity
prices and general economic conditions warrant proceeding with the construction of the Elmworth Gas Plant and the
drilling of associated wells.
• With respect to the Five Year Plan:
o The plan is based on the following commodity price and exchange rate assumptions over the five year period: an
average forecast WTI price of approximately US$55.00/bbl of oil; an average forecast AECO price of approximately
CDN$3.00/GJ of natural gas; and an exchange rate of CDN$/US$ of 1.29.
o The forecast production contained in the plan is subject to similar assumptions as Birchcliff’s other production guidance
as set forth herein, as well as assumptions regarding future commodity prices and exchange rates, the number of
wells drilled over the five year period and the processing capacity and timing of the construction and commissioning
of future facilities of Birchcliff.
o The plan forecasts that approximately 375 wells are drilled over the five year period. The number of wells forecast
to be drilled under the plan is subject to similar assumptions regarding the drilling of future wells as set forth herein.
The actual number of wells drilled may fluctuate significantly depending on, among other things, the production
performance of wells drilled.
o The plan assumes that the Phase V expansion of the PC Gas Plant (for a total combined processing capacity of 260
MMcf) is operational in October 2017, that the Phase VI expansion of the PC Gas Plant (for a total combined processing
capacity of 340 MMcf/d) is operational in October 2018, that the Phase VII expansion of the PC Gas Plant (for a total
combined processing capacity of 420 MMcf/d) is operational by October 2017 and that the Elmworth Gas Plant (with a
processing capacity of 40 MMcf/d) is operational by October 2021.
o With respect to statements that Birchcliff is expected to generate significant free funds flow over the five year period,
the statement assumes that the production targets and commodity price assumptions set forth herein are achieved.
These statement also assumes that the commodity mix of natural gas, oil and NGLs forecast by Birchcliff is achieved.
133
2016 Annual Report Birchcliff’s actual results, performance or achievements could differ materially from those anticipated in the forward-looking
information as a result of both known and unknown risks and uncertainties including, but not limited to: the failure to realize
the anticipated benefits of acquisitions and dispositions; unforeseen difficulties in integrating acquired assets into Birchcliff’s
operations; variances in Birchcliff’s actual capital costs, operating costs and economic returns from those anticipated; 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;
operational risks and liabilities inherent in oil and natural gas operations; uncertainties associated with estimating oil and natural
gas reserves and resources; the accuracy of oil and natural gas reserves estimates and estimated production levels as they are
affected by exploration and development drilling and estimated decline rates; geological, technical, drilling, construction and
processing problems; uncertainty of geological and technical data; uncertainties related to Birchcliff’s future potential drilling
locations; fluctuations in the costs of borrowing; changes in tax laws, crown royalty rates, environmental laws and incentive
programs relating to the oil and natural gas industry and other actions by government authorities, including changes to the
royalty and carbon tax regimes and the imposition or reassessment of taxes; 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
ability to satisfy obligations under Birchcliff’s firm marketing and transportation arrangements; the inability to secure adequate
production transportation for Birchcliff’s products; 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; potential
delays or changes in plans with respect to exploration or development projects or capital expenditures; stock market volatility;
loss of market demand; environmental risks, claims and liabilities; incorrect assessments of the value of acquisitions and
exploration and development programs; shortages in equipment and skilled personnel; the absence or loss of key employees;
uncertainties associated with the outcome of litigation or other proceedings involving Birchcliff; uncertainty that development
activities in connection with its assets will be economical; competition for, among other things, capital, acquisitions of reserves,
undeveloped lands, equipment and skilled personnel; uncertainties associated with credit facilities; counterparty credit risk;
risks associated with Birchcliff’s hedging program and the risk that hedges on terms acceptable to Birchcliff may not be available;
and risks associated with the declaration and payment of dividends, including the discretion of Birchcliff’s Board of Directors to
declare dividends.
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 from time to time.
Any future-orientated financial information and financial outlook information (collectively, “FOFI”) contained in this Annual Report,
as such terms are defined by applicable securities laws, is provided for the purpose of providing information about management’s
current expectations and plans relating to the future and is subject to the same assumptions, risk factors, limitations and
qualifications as set forth in the above paragraphs. FOFI contained in this Annual Report was made as of the date of this Annual
Report and Birchcliff disclaims any intention or obligation to update or revise any FOFI contained in this Annual Report, whether
as a result of new information, future events or otherwise, unless required by applicable law. Readers are cautioned that any
FOFI contained herein should not be used for purposes other than those for which it has been disclosed herein.
Management has included the above summary of assumptions and risks related to forward-looking information 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 information contained in this Annual Report is expressly qualified by the foregoing cautionary statements.
The forward-looking information contained in this Annual Report is made as of the date of this Annual Report. Birchcliff is not under
any duty to update or revise any of the forward-looking information except as expressly required by applicable securities laws.
134
Birchcliff Energy Ltd. F I N A N C I A L A N D O P E R A T I O N A L H I G H L I G H T S
Three months ended
December 31,
Twelve months ended
December 31,
2016
2015
2016
2015
4,656
289,587
7,830
60,750
60.75
3.31
29.50
24.23
24.24
(1.82)
(4.54)
(2.42)
15.46
(1.19)
(1.40)
(0.02)
12.85
(0.12)
(7.73)
(0.15)
(0.06)
0.17
(1.72)
(0.16)
(0.92)
2.16
(0.18)
1.98
135,457
71,806
0.27
0.27
12,085
11,085
0.04
0.04
264,042
279,881
263,396
268,974
1,000
875
62,482
572,517
27,495
600,012
3,530
211,127
1,727
40,445
49.36
2.67
47.98
20.28
20.28
(0.94)
(4.16)
(2.31)
12.87
(2.01)
(1.80)
-
9.06
(0.21)
(9.66)
(0.15)
(0.06)
1.80
-
(0.24)
(3.05)
(2.51)
(0.26)
(2.77)
75,476
33,697
0.22
0.22
(9,322)
(10,322)
(0.07)
(0.07)
152,308
167,817
152,308
153,627
1,000
875
33,533
622,074
21,538
643,612
3,729
247,373
4,279
49,236
51.40
2.41
31.23
18.73
18.73
(1.16)
(4.18)
(2.38)
11.01
(1.19)
(1.68)
0.04
8.18
(0.14)
(8.29)
(0.14)
(0.06)
(0.53)
(0.52)
(0.19)
0.34
(1.35)
(0.22)
(1.57)
337,586
147,443
0.74
0.73
(24,335)
(28,335)
(0.14)
(0.14)
264,042
279,881
199,581
202,686
4,000
3,500
762,030
572,517
27,495
600,012
3,707
201,418
1,673
38,950
53.68
2.90
50.76
22.31
22.32
(0.81)
(4.54)
(2.45)
14.52
(1.61)
(1.60)
-
11.31
(0.23)
(10.35)
(0.16)
(0.06)
0.52
-
(0.25)
(1.64)
(0.86)
(0.28)
(1.14)
317,304
160,756
1.06
1.04
(12,160)
(16,160)
(0.11)
(0.11)
152,308
167,817
152,286
154,078
4,000
3,500
247,207
622,074
21,538
643,612
OPERATING
Average daily production
Light oil – (bbls)
Natural gas – (Mcf)
NGLs – (bbls)
Total – (per boe) (6:1)
Average sales price ($ CDN)(1)
Light oil – (per bbl)
Natural gas – (Mcf)
NGLs – (per bbl)
Total – (per boe) (6:1)
NETBACK AND COST ($ per boe at 6:1)
Petroleum and natural gas revenue(1)
Royalty expense
Operating expense
Transportation and marketing expense
Netback
General & administrative expense, net
Interest expense
Realized gain (loss) on financial instruments
Funds flow netback
Stock-based compensation expense, net
Depletion and depreciation expense
Accretion expense
Amortization of deferred financing fees
Gain (loss)on sale of assets
Unrealized loss on financial instruments
Dividends on Series C preferred shares
Income tax recovery (expense)
Net income (loss)
Dividends on Series A preferred shares
Net income (loss) to common shareholders
FINANCIAL
Petroleum and natural gas revenue ($000s)(1)
Funds flow from operations ($000s)
Per common share – basic ($)
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 Series A preferred shares ($000s)
Dividends on Series C preferred shares ($000s)
Capital expenditures, net ($000s)
Revolving term credit facilites ($000s)
Adj. working capital deficit ($000s)
Total debt ($000s)
(1) Excludes the effect of hedges using financial instruments.
BCE-5313_GateFold_Cover_Mar22_PRINTER_CLIENT_REVISIONS.indd 2
T H A N K Y O U
TEAM BIRCHCLIFF
Jeffrey Akeroyd
Bradley Alexander
Karen Allen
Laura Armstrong
Camille Ashton
Rainer Augsten
Gates Aurigemma
Bryce Baloun
Alan Basnett
Angela Belbeck
Charmaine Belley
Tyrus Bender
Tim Berg
Perry Billard
Daniel Blattler
Angela Boire
Deborah Borthwick
Myles Bosman
Jeff Boswell
Robyn Bourgeois
David Boyle
Wayne Brown
James Burke
Madison Burns
Dave Campbell
Chris Carlsen
Alex Carlson
Caitlin Carrigy
Ann Ceccanese
Robert Charchuk
Matthew Chorney
Dave Christensen
Benjamin Christenson
Bob Clark
Wendy Clay
Dallas Cline
Laura Conroy
Mike Cordingley
Kenneth Cullen
Krystal Dafoe
Chelsea Daku
Dennis Dawson
Claire Denley
Allan Dixon
Jesse Doenz
Joe Doenz
Keifer Dolen
Kelly Dolen
Terrance Dyck
Emily Ebbels
Tim Etcheverry
Laura Ferguson
Jaryn Flower-Phillips
Grant Friesen
Marshall Fritz
George Fukushima
Andy Fulford
Carrie Fyfe
Alexandra Gatza
Bruno Geremia
Melina Geremia
Melodie Gilker
Chad Goddard
Jolanda Goertzen
David Graham
Lee Grant
Hannah Grigore
Bob Grisack
Tania Haberlack-Dolan
Mike Hale
Samuel Hampton
Theresa Hannouche
Trevor Harley
Richard Harris
Wanda Hiebert
Lorna Hildebrand
Warren Hingley
Paul Hirsekorn
Janet Hogan
Jasen Holmstrom
Daryl Hudak
Dave Humphreys
Derek Jamieson
Anna Johnson
David Johnson
Stacy Johnson
Julie Johnson
Dustin Kelm
Ryan Kennedy
Gregory Kilgour
Phyllis Kinzner
Diane Knoblauch
Heather Kwiatkowski
Dani Laird
Calvin Leithead
Kristen Lewicki
Michael Lillejord
Scott Lundquis
Thomas Lundquist
Joe Lyste
Scott MacDermott
John MacGillivray
Dallas MacLean
Darcy MacLeod
Mary MacNeill
Curtis Mah
Janice Malainey
Maggie Malapad
Valerie Martin
Kevin Matiasz
John Matijevich
Jeff McAndrews
Deb McFee
Angie McGonigal
Ryan McIntosh
Marc McIntosh
Darin McLarty
Jerilyn McLeod
Dani McPhee
Richard Melling
John (Bill) Melnyk
Paul Messer
Melissa Meyers
Alfred Michetti
Emelyia Moghaddami
Tyler Montpellier
Ronald Morgan
Rebecca Morley
Stephen Morton
Shaun Moskalyk
Steve Mueller
Daniel Mullin
McKenzie Murdoch
Ed Murphy
Tyler Murray
Kody Naka
Sarah Nance
Matteo Niccoli
Michael Ng
Tam Nguyen
Marcel Njongwe
Tyler Ollenberger
Christopher Olson
Philomena Paisley
Bruce Palmer
Bill Partridge
Dean Paterson
Brenda Pearson
Paul Picco
Allan Pickel
Landon Poffenroth
Andrei Popescu
Lindsay Postma
Glenn Power
Shoni Proctor
Dale Richardson
Brian Ritchie
Michelle Rodgerson
Jeff Rogers
Sherri Rosia
Randy Rousson
Jared Rousson
Todd Sajtovich
Lee Sallenbach
Victor Sandhawalia
Wade Schultz
Sadeq Shahamat
Dan Sharp
Larry Shaw
Amy Short
Nicholas Sizer
Ryan Sloan
Dwayne Spelay
Ben Stevenson
Darby Stolk
Lindsay Sturrock
Tracey Suchlandt
Jim Surbey
Jeff Tonken
Gillian Topping
Hue Tran
Tammy Tran
Rebecca Van De Riet
Theo van der Werken
Kara Vance
Kris Veach
Greg Vreim
Linda Wang
Matt Weiss
David Wetta
Jonathan White
Chris Wurz
John Yeo
Deirdre Yuzwa
2016 Annual Report 135
2017-03-22 6:36 PM
Fold in Panel 7.75” x 10.875”Back Panel 8.25” x 10.875”Front Panel 8.375” x 10.875”SPINE HEIGHT .375”BINDING AREAFOLD IN GUIDEREVISED FILE - MAR22 CORPORATE INFORMATION
OFFICERS
MANAGEMENT TEAM (con’t)
BANKERS
A. Jeffery Tonken
President & Chief Executive Officer
Robert (Bob) Grisack
Land Manager
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
James W. Surbey
Vice-President, Corporate Development
DIRECTORS
Larry A. Shaw (Chairman)
Calgary, Alberta
Kenneth N. Cullen
Calgary, Alberta
Dennis A. Dawson
Calgary, Alberta
Rebecca Morley
Calgary, Alberta
A. Jeffery Tonken
President & Chief Executive Officer
Calgary, Alberta
MANAGEMENT TEAM
Gates Aurigemma
Manager, General Accounting
Perry Billard
Asset Manager – Worsley
Robyn Bourgeois
General Counsel
Jesse Doenz
Controller & Investor Relations Manager
George Fukushima
Manager of Engineering
Andrew Fulford
Surface Land Manager
BirchcliffEnergy.com
Paul Messer
Manager of IT
Tyler Murray
Land Manager
Bruce Palmer
Manager of Geology
Bill Partridge
Engineering Lead
Brian Ritchie
Asset Manager – Gordondale
Michelle Rodgerson
Office Manager
Jeff Rogers
Facilities Manager
Randy Rousson
Drilling & Completions Manager
Vic Sandhawalia
Manager of Financial Accounting,
Taxation & Insurance
Ryan Sloan
Health, Safety & Environment Manager
Hue Tran
Joint Venture & Marketing Manager
Theo van der Werken
Asset Manager - Pouce Coupe
SOLICITORS
Borden Ladner Gervais LLP
Calgary, Alberta
AUDITORS
KPMG LLP,
Chartered Professional Accountants
Calgary, Alberta
RESERVES EVALUATORS
Deloitte LLP
Calgary, Alberta
McDaniel & Associates Consultants Ltd.
Calgary, Alberta
The Bank of Nova Scotia
HSBC Bank Canada
National Bank of Canada
Canadian Imperial Bank of Commerce
Bank of Montreal
The Toronto-Dominion Bank
Alberta Treasury Branches
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:
Fax:
Email: info@birchcliffenergy.com
780-864-4624
780-864-4628
TRANSFER AGENT
Computershare Trust Company of Canada
Calgary, Alberta and Toronto, Ontario
TSX: BIR, BIR.PR.A, BIR.PR.C
ANNUAL & SPECIAL MEETING
The Annual & Special Meeting of
Shareholders will be held at
3:00 p.m. on Thursday, May 11, 2017,
in the McMurray Room at the Calgary
Petroleum Club, 319 - 5th Avenue S.W.,
Calgary, Alberta
2016 Annual Report 136
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GAINING GROUND, FORGING A STRONG FUTURE.
BIRCHCLIFF ENERGY LTD.
Suite 1000, 600 – 3rd Avenue S.W.
Calgary, Alberta T2P 0G5
Phone: 403-261-6401
BirchcliffEnergy.com
2 0 1 6 A N N U A L R E P O R T
BCE-5313_GateFold_Cover_Mar22_PRINTER_CLIENT_REVISIONS.indd 1
2017-03-22 6:36 PM
Fold in Panel 7.75” x 10.875”Back Panel 8.25” x 10.875”Front Panel 8.375” x 10.875”SPINE HEIGHT .375”REVISED FILE - MAR22
CORPORATE INFORMATION
OFFICERS
MANAGEMENT TEAM (con’t)
BANKERS
A. Jeffery Tonken
President & Chief Executive Officer
Robert (Bob) Grisack
Land Manager
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
James W. Surbey
Vice-President, Corporate Development
DIRECTORS
Larry A. Shaw (Chairman)
Calgary, Alberta
Kenneth N. Cullen
Calgary, Alberta
Dennis A. Dawson
Calgary, Alberta
Rebecca Morley
Calgary, Alberta
A. Jeffery Tonken
President & Chief Executive Officer
Calgary, Alberta
MANAGEMENT TEAM
Gates Aurigemma
Manager, General Accounting
Perry Billard
Asset Manager – Worsley
Robyn Bourgeois
General Counsel
Jesse Doenz
Controller & Investor Relations Manager
George Fukushima
Manager of Engineering
Andrew Fulford
Surface Land Manager
BirchcliffEnergy.com
Paul Messer
Manager of IT
Tyler Murray
Land Manager
Bruce Palmer
Manager of Geology
Bill Partridge
Engineering Lead
Brian Ritchie
Asset Manager – Gordondale
Michelle Rodgerson
Office Manager
Jeff Rogers
Facilities Manager
Randy Rousson
Drilling & Completions Manager
Vic Sandhawalia
Manager of Financial Accounting,
Taxation & Insurance
Ryan Sloan
Health, Safety & Environment Manager
Hue Tran
Joint Venture & Marketing Manager
Theo van der Werken
Asset Manager - Pouce Coupe
SOLICITORS
Borden Ladner Gervais LLP
Calgary, Alberta
AUDITORS
KPMG LLP,
Chartered Professional Accountants
Calgary, Alberta
RESERVES EVALUATORS
Deloitte LLP
Calgary, Alberta
McDaniel & Associates Consultants Ltd.
Calgary, Alberta
The Bank of Nova Scotia
HSBC Bank Canada
National Bank of Canada
Canadian Imperial Bank of Commerce
Bank of Montreal
The Toronto-Dominion Bank
Alberta Treasury Branches
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:
Fax:
Email: info@birchcliffenergy.com
780-864-4624
780-864-4628
TRANSFER AGENT
Computershare Trust Company of Canada
Calgary, Alberta and Toronto, Ontario
TSX: BIR, BIR.PR.A, BIR.PR.C
ANNUAL & SPECIAL MEETING
The Annual & Special Meeting of
Shareholders will be held at
3:00 p.m. on Thursday, May 11, 2017,
in the McMurray Room at the Calgary
Petroleum Club, 319 - 5th Avenue S.W.,
Calgary, Alberta
2016 Annual Report 136
B
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A
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GAINING GROUND, FORGING A STRONG FUTURE.
BIRCHCLIFF ENERGY LTD.
Suite 1000, 600 – 3rd Avenue S.W.
Calgary, Alberta T2P 0G5
Phone: 403-261-6401
BirchcliffEnergy.com
2 0 1 6 A N N U A L R E P O R T
BCE-5313_GateFold_Cover_Mar22_PRINTER_CLIENT_REVISIONS.indd 1
2017-03-22 6:36 PM
Fold in Panel 7.75” x 10.875”Back Panel 8.25” x 10.875”Front Panel 8.375” x 10.875”SPINE HEIGHT .375”REVISED FILE - MAR22