Birchcliff Energy Ltd.
Annual Report 2016

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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 B I R C H C L I F F E N E R G Y L T D . 2 0 1 6 A n n u a l R e p o r t 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 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 T A B L E O F C O N T E N T S 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 i t c u d o r P y l i a D e g 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 t c u d o r P y l i a D e g a r e v A l a u n n 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 G GG E G MONTNEY/D CF R11W6 R10W6 R9W6 R8W6 R7W6 KK C K C K K K K K LG F A G F F L G K K LG C F F L LL L F F GC G J LGG GK G L I K E EC F F F K K OIG DEEP BASIN EDGE GG L G C FC F F F F K G K G CC K GGG KK G GC GG G G K GK G K G G G K KK C KK K GGC A K K KK F F K F C C F F F F F C F C C K CKC C G J G " A A G G G G K F C C A A A A K F " " " " C C C E E CC E E E E E E K C E E E G E E E E E F E E EF E E E L D E L GA A A A KC F FF F F F F F F F F F G F F F F C F F F E F F FF F J C F F CC F F F F FF K F F F F F F F F FF F F C F F F F F F C E GF E F F F F F F C F F C F F C E F F LL F C F G F E F E F F E E F E F E E C E F F F F F F G E E F F F C K E F E Gordondale Gas Plant F F FF F F F F C F " F F FF F F F F F C E E E F F E E A B E E F FK " E E E F E F G C F F E CK CC FF E C E E F E E E PC Gas Plant K F C FF G C A E E A B E E F E I F F A F " F F F F F GG E G G G E CC G C EE LL G G K I K I G G G E E G L G CC C GCG F F F C F F F F C C " A A F F F " F F F F F F F F F F A F F F F F K F F F F A F G F F F F F F F F F F A A F F K F " GL K F F F FK AF F F F F F F G F F A F A C F F A F A A F A B " F F F FC F F F DKC F F F F G G F A F A F F F A A F F A F F F " F F F C F F F A A F F KF F F F C F F F F F F F F F CK F F F F F F F F F F F F F F GG F G F F F F J F F F F F F F F F K K F F F K CF F F F F K F F F CC F F F F K F C C F F A C F F C F F F F F CD F F F C CK F F F C C C " " C F C KK C F FF G C F C F F F F F F C F B F F F CC F F CC F F CC F CC F F F F F F F F C L GG F F C G T81 T80 T79 T78 T77 T76 A L L F C F F F F CFC GC C F F F C K 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 C C 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 GG E G Gordondale Team Highlight Map KK K C C K K K K K R12W6 R11W6 R10W6 R9W6 R8W6 R7W6 KK K F F F C C C FC F F F F K C CKC F F C F F F " A A F F F " CF F L G K K C LG F F LL L L F F G GC LGG G I L E F K J GK K GG L K F EC F G K G G G K G K G K KK KK C GGC K A LG F A F G G CC K GGG KK G GC G GG G K GK G G E E G K K F E G G G C Gordondale Gas Plant G G LL C C C E E E E E C K CC E E G GG " E F F F F " " F F FF F F F G F F F F F F F F C E F F FF F C J F F CC F F F F F K F F F F F F F F F F F F F C F F F C GF F F F F F F F F C F F F C F C F F F F F C F E F E F F E E F E E F E E F C F F F F E E G F F F K C E E F FF F F F F F C F F F FF F F F F F F F F FK F C G F F FF E F E E C F FF C A A B " " E E E E A B E E E E CK " CC C E E F C E E E E E E E F E E CC C GCG F C C A A A A E E E E E E G " F E E E E E EF E E E L D E A A GA L A KC " A A CC F A F F F F K G F F F F K F F GL K F F F K AF F F F F F F F F A A C F F A " F PC Gas Plant E F F A E K I G F F F F F F F F KF A A F F F F F C F F F F F F F F F F F F F F F A A F FC F F F F F A F A " F C F F F F F F F A A F F A F F F F F F F CK F C C F F C A F F C " CK F F F F F F F F GG F G F F F F F F F F F F F F F F F F F K K F K CF F F CC K F F F J F F F F F F F F F F F K C F B F F F EE LL A F CC CC F F F CC F CC F F F F F F F C F L GG F F C G C G J G G G K K I I G G G E E G G L MONTNEY/DOIG D L L F C E E P B A S I N E D G E L E G E N D G C C Gordondale Non-Confidential Land Birchcliff Non-Confidential Land Birchcliff Vertical Producers Birchcliff Horizontal Producers F 2017 Capital Program 2016 Capital Program T80 T79 T78 T77 T76 T75 T74 27 F F CD F F F C F F F F C C C C F C F F F F KK C G " C F C F F F F F F F F 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 T75 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. 72 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. 73 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. 76 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. 78 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”. 79 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. 81 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. 99 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. 100 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 101 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. 102 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. 103 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 104 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. 105 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. 106 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. 107 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. 117 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 B I R C H C L I F F E N E R G Y L T D . 2 0 1 6 A n n u a l R e p o r t 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 I R C H C L I F F E N E R G Y L T D . 2 0 1 6 A n n u a l R e p o r t 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

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