Asset Manager – Gordondale Bank of Montreal Michelle Rodgerson Manager of Human Resources & Corporate The Toronto-Dominion Bank Alberta Treasury Branches 2017 ANNUAL REPORT B I R C H C L I F F E N E R G Y L T D . 2 0 1 7 A n n u a l R e p o r t C O R P O R A T E I N F O R M A T I O N MANAGEMENT TEAM (cont’d) RESERVES EVALUATORS President & Chief Executive Officer Manager of Engineering OFFICERS A. Jeffery Tonken Myles R. Bosman Vice-President, Exploration & Chief Operating Officer Chris A. Carlsen Vice-President, Engineering Bruno P. Geremia Vice-President & Chief Financial Officer David M. Humphreys Vice-President, Operations DIRECTORS A. Jeffery Tonken (Chairman) President & Chief Executive Officer Calgary, Alberta Dennis A. Dawson Lead Independent Director Calgary, Alberta Debra A. Gerlach Independent Director Calgary, Alberta Rebecca J. Morley Independent Director Calgary, Alberta Larry A. Shaw Independent Director Calgary, Alberta James W. Surbey Non-Independent Director Calgary, Alberta MANAGEMENT TEAM Gates Aurigemma Manager, General Accounting Robyn Bourgeois General Counsel & Corporate Secretary Jesse Doenz Controller & Investor Relations Manager BirchcliffEnergy.com George Fukushima Andrew Fulford Surface Land Manager Paul Messer Manager of IT Tyler Murray Mineral Land Manager Bruce Palmer Manager of Geology Brian Ritchie Services Jeff Rogers Facilities Manager Randy Rousson Vic Sandhawalia Manager of Finance Ryan Sloan Health, Safety & Environment Manager Duane Thompson Production Manager Hue Tran Drilling & Completions Manager Business Development Manager Theo van der Werken Asset Manager – Pouce Coupe SOLICITORS Borden Ladner Gervais LLP Calgary, Alberta AUDITORS KPMG LLP, Calgary, Alberta Chartered Professional Accountants Deloitte LLP Calgary, Alberta Calgary, Alberta McDaniel & Associates Consultants Ltd. BANKERS The Bank of Nova Scotia HSBC Bank Canada National Bank of Canada Canadian Imperial Bank of Commerce 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 Fax: 403-261-6424 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 2017 Annual Report 138 BIRCHCLIFF ENERGY LTD. Suite 1000, 600 3rd Avenue S.W. Calgary, Alberta T2P 0G5 Phone: 403-261-6401 BirchcliffEnergy.com 2 0 1 7 A N N U A L R E P O R T INFORMATION FINANCIAL AND OPERATIONAL HIGHLIGHTS OPERATING Average daily production Light oil – (bbls) Natural gas – (Mcf) NGLs – (bbls) Total – boe Average sales price ($ CDN)(1) Light oil – (per bbl) Natural gas – (per Mcf) NGLs – (per bbl) Total – boe NETBACK AND COST ($/boe) Petroleum and natural gas revenue(1) Royalty expense Operating expense Transportation and marketing expense Operating netback General & administrative expense, net Interest expense Realized gain (loss) on financial instruments Other income Adjusted 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 gain (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) Adjusted funds flow ($000s) Per common share – basic ($) Per common share – diluted ($) Net income (loss) ($000s) Net income (loss) to common shareholders ($000s) Per common share – basic ($) Per common share – diluted ($) Common shares outstanding (000s) End of period – basic End of period – diluted Weighted average common shares for period – basic Weighted average common shares for period – diluted Dividends on common shares ($000s) Dividends on Series A preferred shares ($000s) Dividends on Series C preferred shares ($000s) Capital expenditures, net ($000s) Revolving term credit facilites ($000s) Adjusted working capital deficit ($000s) Total debt ($000s) Three months ended December 31, Twelve months ended December 31, 2017 2016 2017 2016 5,283 385,280 10,607 80,103 4,656 289,587 7,830 60,750 6,004 320,927 8,471 67,963 3,729 247,373 4,279 49,236 68.58 2.64 40.08 22.54 22.55 (1.26) (3.86) (3.52) 13.91 (1.28) (0.97) 1.46 0.04 13.16 (0.13) (7.86) (0.08) (0.05) 1.86 (1.86) (0.12) (1.42) 3.50 (0.14) 3.36 166,149 97,008 0.36 0.36 25,820 24,773 0.09 0.09 265,797 282,895 265,792 267,619 6,644 1,047 875 18,669 587,126 11,067 598,193 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 61.42 2.72 33.39 22.44 22.45 (1.16) (4.45) (2.87) 13.97 (1.07) (1.14) 1.03 0.02 12.81 (0.16) (7.48) (0.12) (0.06) (7.50) 0.22 (0.14) 0.54 (1.89) (0.17) (2.06) 556,942 317,680 1.20 1.19 (46,980) (51,027) (0.19) (0.19) 265,797 282,895 265,182 267,873 26,522 4,047 3,500 276,125 587,126 11,067 598,193 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 THANK YOU TEAM BIRCHCLIFF Jeffrey Akeroyd, Bradley Alexander, Karen Allen, Camille Ashton, Gates Aurigemma, Valerie Babkov, Bryce Baloun, Angela Michael Lillejord, Ryan Linsley, Thomas Lundquist, Scott Lundquist, Joe Lyste, John MacGillivray, Dallas MacLean, Darcy MacLeod, Belbeck, Charmaine Belley, Tyrus Bender, Daniel Blattler, Calvin Bohdan, Angela Boire, Darryl Bolch, Deborah Borthwick, Myles Mary MacNeill, Curtis Mah, Maggie Malapad, Arun Mann, Kevin Matiasz, John Matijevich, Deb McFee, Angie McGonigal, Marc Bosman, Jeff Boswell, Robyn Bourgeois, David Boyle, Wayne Brown, Madison Burns, Dave Campbell, Chris Carlsen, Alex Carlson, McIntosh, Ryan McIntosh, Dani McPhee, Jennifer McPherson, Jerilyn McPherson (McLeod), Richard Melling, Paul Messer, Alfred Caitlin Carrigy, Ann Ceccanese, Bhuwan Chauhan, Matthew Chorney, Benjamin Christenson, Wendy Clay, Dallas Cline, Kalen Michetti, Derek Michetti, Emelyia Moghaddami, Rebecca Morley, Amy Morris, Stephen Morton, Steve Mueller, McKenzie Murdoch, Conrad, Mike Cordingley, Loren Damer, Dennis Dawson, Lara de Paula, Jesse Doenz, Joe Doenz, Kelly Dolen, Terrance Dyck, Tyler Murray, Kody Naka, Sarah Nance, Michael Ng, Tam Nguyen, Matteo Niccoli, Christopher Olson, Laura O’Neill, Jason Orrock, Darryl Easter, Emily Ebbels, John (Cliff) Ennis, Tim Etcheverry, Lindsay Fast, Laura Ferguson, Kelsey Frechette, Grant Friesen, Philomena Paisley, Bruce Palmer, Bill Partridge, Dean Paterson, Jesse Peterson, Paul Picco, Allan Pickel, Landon Poffenroth, Taylor Marshall Fritz, George Fukushima, Andy Fulford, Carrie Fyfe, Alexandra Gatza, Melina Geremia, Bruno Geremia, Debra Gerlach, Poole, Andrei Popescu, Austin Power, Glenn Power, Shoni Proctor, Brian Ritchie, Michelle Rodgerson, Blaine Rogers, Jeff Rogers, Chad Goddard, David Graham, Lee Grant, Hannah Grigore, Ryan Gugyelka, Rylan Gulka, Tania Haberlack-Dolan, Mike Hale, Sherri Rosia, Randy Rousson, Jared Rousson, Todd Sajtovich, Lee Sallenbach, Victor Sandhawalia, Wade Schultz, Mohammad (Sadeq) Samuel Hampton, Trevor Harley, Richard Harris, Wanda Hiebert, Lorna Hildebrand, Warren Hingley, Jeremy Hingley, Paul Shahamat, Dan Sharp, Larry Shaw, Amy Short, Ryan Sloan, Kiran Somanchi, Hilary Steinbach, Darby Stolk, Lindsay Sturrock, Tracey Hirsekorn, Leah (Janet) Hogan, Jasen Holmstrom, Daryl Hudak, Dave Humphreys, Derek Jamieson, Anna Johnson, Julie Johnson, Suchlandt, Tyson Suderman, Jim Surbey, Theresa Sutton (Hannouche), Ryan Swanson, Duane Thompson, Jeff Tonken, Gillian Topping, Kathyrn (Katy) Josephs, Katrina Keable, Dustin Kelm, Gregory Kilgour, Phyllis Kinzner, Melissa Kinzner, Diane Knoblauch, Ashley Tammy Tran, Hue Tran, Theo van der Werken, Kara Vance, Kris Veach, Greg Vreim, Linda Wang, Michael Warrick, Shelby Watson, Matt Kozlowski Urch, Danny Kutrowski, Dani Laird, Anji Lawrence, Katherine Lazaruk, Heather Leahey, Calvin Leithead, Kristen Lewicki, Weiss, David Wetta, Philip Wu, John Yeo, Deirdre Yuzwa (1) Excludes the effects of hedges using financial instruments but includes the effects of fixed price physical delivery contracts. 2017 Annual Report 137 T A B L E O F C O N T E N T S 02 04 06 08 10 12 14 16 30 40 43 98 102 126 128 128 Overview Message to Shareholders Executive Team Management Team History 2017 Accomplishments & 2018 Key Objectives Peace River Arch Montney/Doig Resource Play 2017 Year-End Reserves Responsibility Management’s Discussion & Analysis Financial Statements Notes to the Financial Statements Glossary Non-GAAP Measures Presentation of Oil and Gas Reserves 130 Advisories 137 138 Team Birchcliff Corporate Information 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 “adjusted funds flow”, “adjusted funds flow per common share”, “netback”, “operating netback”, “estimated operating netback”, “adjusted funds flow netback”, “total cash costs” and “total debt”, which do not have standardized meanings prescribed by GAAP and therefore may not be comparable to similar measures presented by other companies where similar terminology is used. For further information, see “Non-GAAP Measures” in this Annual Report and in the management’s discussion and analysis for the year ended December 31, 2017 (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. CONTENTS 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. Our strategy is to continue to develop and expand our large Montney/Doig Resource Play in the Peace River Arch, while maintaining low capital costs and operating costs. Our Montney/Doig Resource Play provides us with an extensive inventory of repeatable, low decline, low-cost drilling opportunities targeting natural gas and oil and liquids. Birchcliff has the ability to grow when commodity prices warrant doing so while also having the ability to maintain production in a low commodity price environment. At December 31, 2017, 348 (342.8 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 “Pouce Coupe Gas Plant”). The Pouce Coupe Gas Plant is the cornerstone of our strategy to develop our Montney/Doig Resource Play, to control and expand our production in the play and to further reduce our operating costs per boe. 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 gives us a competitive advantage in our areas of operation and supports our low F&D costs and low operating cost structure, which helps us to maximize our adjusted 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 14, 2018, Birchcliff had an enterprise value of approximately $1.5 billion. 2 2017 Annual Report B Y T H E N U M B E R S As at December 31, 2017 91% 99% 99% 348 342.8 NET Average working interest in undeveloped land Operated production New drilling initiated and controlled Horizontal wells drilled on the Montney/Doig Resource Play 3 2017 Annual Report M E S S A G E T O S H A R E H O L D E R S Dear Fellow Shareholder, In 2017, Birchcliff achieved record average fourth quarter production of more than 80,000 boe/d, materially increased its cash flow and reserves, materially reduced its operating costs and did not increase total debt. This was accomplished in a challenging commodity price environment and was accomplished without issuing equity resulting in significant per share growth in a number of critical areas in 2017. Birchcliff had another excellent year as far as its business is concerned. However, as a result of weak commodity prices, lack of pipeline access to traditional and new sales markets, and the continued rise in taxes and other business costs, all of which was out of our control, our share performance was poor as investors left the energy space. We grew our production to record levels in 2017 and achieved annual average production of 67,963 boe/d, a 38% increase as compared to 2016. Our average production for the fourth quarter of 2017 was 80,103 boe/d, a 32% increase as compared to the fourth quarter of 2016 and a 23% increase as compared to the third quarter of 2017. Our proved developed producing reserves grew to approximately 198 MMboe at December 31, 2017, a 20% increase from December 31, 2016. In the third quarter of 2017, we brought our 80 MMcf/d Phase V expansion of our Pouce Coupe Gas Plant on-stream which increased the processing capacity of the plant to 260 MMcf/d from 180 MMcf/d. Our operating costs for the fourth quarter of 2017 were 10% lower than the third quarter of 2017 and 17% lower than the second quarter of 2017. We began paying a sustainable quarterly dividend to our common shareholders in 2017, with the first dividend being paid on March 31, 2017. We accomplished all of this while keeping our total debt flat as compared to year-end 2016. During 2017, we made the decision to dispose of various non-core assets so that we could focus on our premium-quality assets on our Montney/Doig Resource Play and strengthen our balance sheet. As a result, we disposed of various non-core assets during 2017 for total proceeds of approximately $148 million, which included the sale of our higher-cost Worsley Charlie Lake light oil pool. As a result of these asset sales, we became better focused and more financially resilient. Due to the recent issues at AECO and the extremely volatile prices we saw throughout the year, we actively pursued various profitable market diversification opportunities in order to reduce our exposure to AECO pricing. Our most significant example of this is that we entered into agreements for the firm service transportation of an aggregate of 175,000 GJ/d (approximately 152 MMcf/d) of natural gas on TCPL’s Canadian Mainline for a 10-year term, whereby natural gas is transported to the Dawn trading hub located 4 2017 Annual Report in Southern Ontario. The first tranche of this service (120,000 GJ/d) became available to Birchcliff on November 1, 2017, with additional tranches becoming available on November 1, 2018 (35,000 GJ/d) and November 1, 2019 (20,000 GJ/d). We expect that during 2018, approximately 34% of our 2018 forecast annual average natural gas production will be sold at prices that are not based on AECO, with 30% being sold at the Dawn daily index price. In summary, we strengthened Birchcliff by growing our production and reserves, maintained our total debt levels below $600 million, reduced our operating costs and focused our assets even further. We are more focused, better financed and we have added more production to our very large contiguous land base on our Montney/Doig Resource Play. OUTLOOK During 2018, our focus will be on protecting our balance sheet, improving our already-low cost structure and paying a sustainable quarterly dividend to our shareholders, while we maintain a prudent pace of development and continue to position Birchcliff for future growth. In light of current economic conditions, we are dedicated to continued strict capital discipline. The 2018 capital program contemplates the drilling of a total of 27.0 net wells during 2018 and targets an annual average production rate of 76,000 to 78,000 boe/d. This program reflects our long-term plan to continue the exploration and development of our low-cost natural gas, crude oil and liquids-rich assets on the Montney/Doig Resource Play and will direct capital investment to those projects with the most favourable rates of return. In particular, we will focus on the drilling of crude oil wells in Gordondale and a combination of liquids-rich and low-cost natural gas wells in Pouce Coupe. Our capital program has been designed with financial and operational flexibility with the potential to accelerate or decelerate capital expenditures throughout the year, depending on commodity prices and economic conditions. We expect that our 2018 capital expenditures will be less than our cash flow during 2018, which will help us to protect our balance sheet. I would like to thank our Board of Directors for their support and guidance throughout 2017. During 2017, we had two new additions to our Board. Firstly, Jim Surbey retired as our Vice-President, Corporate Development in June 2017 and he was elected as a member of our Board at our annual shareholders’ meeting held in May 2017. Secondly, Debbie Gerlach was appointed as a member of the Board in November 2017. Each of Jim and Debbie bring a wealth of knowledge and experience to the Board that will be invaluable to Birchcliff. I would also like to thank all of our staff for their excellent work and for helping us to deliver these strong results for 2017. Our staff are truly dedicated to help Birchcliff succeed and I believe that they are our best asset. Lastly, I would like to thank all of our shareholders for their continued support. We continue to strive to deliver long-term value for all of you. With respect, A. Jeffery Tonken President & Chief Executive Officer March 14, 2018 5 2017 Annual Report E X E C U T I V E T E A M The Strength of our Partnership Drawing on extensive backgrounds in the energy sector, our Executive Team brings a rich portfolio of skills and experience to Birchcliff’s business operations. JEFF TONKEN President & Chief Executive Officer MYLES BOSMAN Vice-President, Exploration & Chief Operating Officer 6 2017 Annual Report Under the oversight of our Board of Directors, our Executive Team collectively drives our day-to-day pursuit of operational excellence, while identifying and pursuing responsible growth opportunities. Deeply invested in our success and unified by a genuine sense of camaraderie, our Executive Team works together to provide effective leadership and strategic direction. BRUNO GEREMIA DAVE HUMPHREYS CHRIS CARLSEN Vice-President & Chief Financial Officer Vice-President, Operations Vice-President, Engineering 7 2017 Annual Report M A N A G E M E N T T E A M Our People Are Our 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, our management team is instrumental in executing our business strategy and managing our day-to-day operations. JEFF ROGERS Facilities Manager RANDY ROUSSON Drilling & Completions Manager RYAN SLOAN Health, Safety & Environment Manager ROBYN BOURGEOIS General Counsel & Corporate Secretary BRUCE PALMER Manager of Geology GATES AURIGEMMA Manager, General Accounting VICTOR SANDHAWALIA Manager of Finance ANDREW FULFORD Surface Land Manager 8 2017 Annual Report GEORGE FUKUSHIMA Manager of Engineering BRIAN RITCHIE Asset Manager – Gordondale THEO VAN DER WERKEN Asset Manager – Pouce Coupe MICHELLE RODGERSON Manager, Human Resources & Corporate Services HUE TRAN Business Development Manager JESSE DOENZ Controller & Investor Relations Manager PAUL MESSER Manager of Information Technology TYLER MURRAY Mineral Land Manager DUANE THOMPSON Production Manager 9 2017 Annual Report H I S T O R Y Building on Our Past Birchcliff was incorporated as a private corporation on July 6, 2004. Since our inception, we have invested approximately $3.8 billion in capital, primarily in the Montney/Doig Resource Play. These investments have generated $3.4 billion in revenue, paid $304 million in royalties to Albertans and delivered $1.6 billion in adjusted funds flow. The following describes the major events in our history: MAY 31, 2005 MARCH 20, 2010 Completed acquisition of properties in the Peace River Arch for $242.8 million, including a significant undeveloped land position on the Montney/Doig Resource Play JULY 21, 2005 Common shares commenced trading on the TSX Phase I of the Pouce Coupe Gas Plant commenced operations with a processing capacity of 30 MMcf/d NOVEMBER 2, 2010 Phase II of the Pouce Coupe Gas Plant commenced operations with a combined processing capacity of 60 MMcf/d JANUARY 19, 2005 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 Common shares commenced trading on the TSX Venture Exchange FEBRUARY 6, 2005 Rig released first Montney/Doig vertical exploration gas well drilled by Birchcliff in the Pouce Coupe area 2005 10 2017 Annual Report At December 31, 2017, 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 $5.1 billion as estimated by our independent qualified reserves evaluators. OCTOBER 2, 2012 Phase III of the Pouce Coupe Gas Plant commenced operations with a combined processing capacity of 150 MMcf/d JULY 13, 2016 Closed equity financings for total gross proceeds of $690.8 million JULY 28, 2016 Completed acquisition of assets in Gordondale for approximately $613.5 million OCTOBER 2, 2017 Announced the commencement of Phase V of the Pouce Coupe Gas Plant with a combined processing capacity of 260 MMcf/d SEPTEMBER 1, 2014 Completed construction of Phase IV of the Pouce Coupe Gas Plant with a combined processing capacity of 180 MMcf/d MARCH 31, 2017 Paid first quarterly dividend to common shareholders DECEMBER 31, 2017 348 (342.8 net) Montney/Doig horizontal wells successfully drilled to date 2017 11 2017 Annual Report 2 0 1 7 A C C O M P L I S H M E N T S Achieved record annual average production of 67,963 boe/d (38% growth year-over-year) Achieved record quarterly average production of 80,103 boe/d in Q4 2017 Delivered significant reserves growth year-over-year Paid first quarterly dividend to common shareholders Maintained balance sheet strength by preserving total debt levels compared to December 31, 2016 and exiting the year in excellent financial position with total debt of $598MM at December 31, 2017 compared to credit facilities totaling $950MM Reduced exposure to AECO natural gas market with commencement of 120,000 GJ/d of egress to the Dawn market beginning November 1, 2017 Drilled 54 wells, consisting of 37 Montney/Doig horizontal wells at Pouce Coupe, 16 Montney horizontal wells at Gordondale and 1 Montney/Doig vertical science and technology well at Pouce Coupe, all at 100% working interest 2 0 1 8 K E Y O B J E C T I V E S Preserve and protect the balance sheet by spending within adjusted funds flow Complete Phase VI of the Pouce Coupe Gas Plant in October 2018, increasing processing capacity from 260 MMcf/d to 340 MMcf/d Continued commitment to science and technology to drive operational excellence and further our learnings on field development planning Drill, case, complete and bring on production a total of 27 wells consisting of 14 Montney horizontal wells at Pouce Coupe and 13 Montney horizontal wells at Gordondale all at 100% working interest Exploration and delineation of the Montney D2 and C intervals in Pouce Coupe Optionality on commodity type allows us to focus on Gordondale oil & Pouce Coupe high condensate wells while limiting dry gas drilling in the current commodity environment to maximize our returns Continue to focus on full cycle profitability while paying a sustainable quarterly dividend to common shareholders Re-configure Phase V and Phase VI of the Pouce Coupe Gas Plant to provide for shallow-cut capability, thereby extracting additional liquids from our natural gas stream 12 2017 Annual Report WE HAVE OUR BEST ASSET IN PLACE, WHICH IS OUR PEOPLE.. - A. Jeffery Tonken President & Chief Executive Officer O N E C O R E A R E A PEACE RIVER ARCH P E A C E R I V E R A R C H 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 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, we have excellent control of and/or access to infrastructure in the Peace River Arch, which helps us to control our costs and expand our production. 2017 Annual Report 15 M O N T N E Y / D O I G R E S O U R C E P L A Y Low Risk Development We are focused on the Montney/Doig Resource Play within the Peace River Arch. ESTABLISHED MONTNEY/DOIG RESOURCE PLAY We characterize our Montney/Doig Resource Play as a regionally pervasive, continuous, low-permeability hydrocarbon accumulation or system that typically requires intensive stimulation to produce. The production characteristics of this play generally include steep initial declines that rapidly trend to much lower decline rates, yielding long-life production and reserves. The play exhibits a statistical distribution of estimated ultimate recoveries and therefore provides a repeatable distribution of drilling opportunities. Our Montney/Doig Resource Play is ideally suited for the application of horizontal drilling and multi-stage fracture stimulation technology. As more wells are drilled into a resource play, there is a substantial decrease in both the geological and technical risks. Over the past 13 years, we have worked to de-risk our Montney/Doig Resource Play by drilling both vertical and horizontal exploration wells in order to develop an in-depth understanding of the oil and gas pools, rock properties and petrophysical characteristics and reservoir parameters. We design, test and evaluate our drilling, completion and production technologies DRILLED 348 (342.8 net) MONTNEY/ DOIG HORIZONTAL WELLS At December 31, 2017 16 and practices to achieve continual improvements in productivity and expected ultimate recoveries in order to drive down capital and operating costs. Our pool delineation strategy de-risks future development and reduces future costs as new well pads and infrastructure are designed and built to support multiple horizontal well locations and increased production. 0 m 500 m 1000 m 1500 m 2000 m 2500 m 3000 m Surface Doe Creek Dunvegan Paddy/Cadotte Notikewin Falher Bluesky Gething Cadomin Nikanassin Nordegg Baldonnel Boundary Lake Subcrop Halfway Doig Montney Kiskatinaw Exshaw Wabamun Duvernay Leduc Beaverhill Lake/ Granite Wash PreCambrian Graben Complex Stratigraphic Column and Production Zones 2017 Annual Report BIRCHCLIFF OPERATIONS IN THE PEACE RIVER ARCH Our Montney/Doig Resource Play is managed by two technical teams at Birchcliff: the Pouce Coupe Team and the Gordondale Team. Birchcliff Montney/Doig Resource Play in the Peace River Arch BC AB Gordondale Team Pouce Coupe Team MONTNEY/DOIG RESOURCE PLAY TREND L E G E N D Birchcliff Pouce Coupe Non-Confidential Land Birchcliff Gordondale Non-Confidential Land Birchcliff Non-Core Non-Confidential Land Montney/Doig Deep Basin Edge Birchcliff Facility Pouce Coupe Gas Plant Gordandale Gas Plant DISCLAIMER: The IHS Markit reports, data and information referenced herein (the “IHS Markit Materials”) are the copyrighted property of IHS Markit Ltd. and its subsidiaries (“IHS Markit”) and represent data, research, opinions or viewpoints published by IHS Markit, and are not representations of fact. The IHS Markit Materials speak as of the original publication date thereof and not as of the date of this document. The information and opinions expressed in the IHS Markit Materials are subject to change without notice and IHS Markit has no duty or responsibility to update the IHS Markit Materials. Moreover, while the IHS Markit Materials reproduced herein are from sources considered reliable, the accuracy and completeness thereof are not warranted, nor are the opinions and analyses which are based upon it. IHS Markit is a trademark of IHS Markit. Other trademarks appearing in the IHS Markit Materials are the property of IHS Markit or their respective owners. Source: IHS Markit 17 2017 Annual Report Our Montney/Doig Resource Play is centred approximately 95 km northwest of Grande Prairie, Alberta, Canada and, in the opinion of Birchcliff, is one of the most sought after resource plays in North America. Birchcliff’s Montney/Doig Resource Play contains two key operating areas: Pouce Coupe and Gordondale. 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: RBC Rundle 18 2017 Annual Report GEOLOGY The Montney/Doig Resource Play in our core area 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. Birchcliff Montney/Doig Resource Play Full Development Plan: Hexastack 300m BASAL DOIG MONTNEY D5 MONTNEY D4 MONTNEY D3 MONTNEY D2 MONTNEY D1 MONTNEY C 1600m 1600m As of December 31, 2017 DRILLING INTERVAL: BASAL DOIG/UPPER MONTNEY Mature Developed/Commercial 69 Producing Wells MONTNEY D4 Mature Developed/Commercial 12 Producing Wells MONTNEY D3 0 Producing Wells MONTNEY D2 Mature Developed/Commercial 13 Producing Wells MONTNEY D1 Mature Developed/Commercial 244 Producing Wells MONTNEY C New Exploration Success 1 Producing Well L E G E N D Mature Developed/Commercial New Exploration Success Future Potential 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 and have low water to gas ratios. 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. 19 2017 Annual Report OUR OPERATIONS At December 31, 2017, 348 (342.8 net) Montney/Doig horizontal wells have been successfully drilled and cased on Birchcliff’s lands, consisting of 75 (73.5 net) wells in the Basal Doig/Upper Montney interval, 12 (12.0 net) wells in the Montney D4 interval, 13 (13.0 net) wells in the Montney D2 interval, 247 (243.3 net) wells in the Montney D1 interval and 1 (1.0 net) well in the Montney C interval. 2017 DRILLING AND COMPLETIONS We drilled a total of 54 (54.0 net) wells during 2017. Of the 54 (54.0 net) wells drilled during 2017, 16 (16.0 net) were Montney horizontal oil and natural gas wells drilled in the Gordondale area, 37 (37.0 net) were Montney/Doig horizontal natural gas wells drilled in the Pouce Coupe area and 1 (1.0 net) was a Montney/Doig vertical science and technology well drilled in the Pouce Coupe area. Of these 54 wells, a total of 51 (51.0 net) wells were brought on production during 2017. In addition, our 2017 capital program also included the capital associated with the completion, equipping and tie-in of 10 wells drilled in 2016, all of which were brought on production in the first quarter of 2017. Accordingly, a total of 61 (61.0 net) wells were brought on production during 2017. All wells drilled in 2017 were drilled on multi-well pads, which allows us to reduce our per well costs and our environmental footprint. In addition, we actively employ the evolving technology utilized by the industry regarding horizontal well drilling and the related multi-stage fracture stimulation technology. 2017 ACQUISITIONS AND DISPOSITIONS During 2017, we completed various asset sales for total proceeds of approximately $148 million (before adjustments) ($138 million in cash; $10 million in securities), representing forecast 2017 average production of approximately 3,600 boe/d. The proceeds from these asset sales were initially used to reduce indebtedness under our credit facilities, which was subsequently redrawn as needed to fund our capital expenditure program and for general corporate purposes. In addition, we also completed various minor acquisitions for total consideration of approximately $1.0 million. 20 2017 Annual Report Birchcliff Montney/Doig Multi-Layer Opportunity Elmworth Sinclair Glacier Pouce Coupe South Pouce Coupe North Gordondale Basal Doig Montney D5 Montney D4 Montney D3 Montney D2 Montney D1 TSE Montney C Hydrocarbon Pore Volume Bulk Volume Water SIGNIFICANT FUTURE DRILLING OPPORTUNITIES As at December 31, 2017, we held 349.4 sections of land that have potential for the Montney/Doig Resource Play. Of these lands, 348.4 (326.1 net) sections have potential for the Basal Doig/Upper Montney interval, 323.9 (317.0 net) sections have potential for the Montney D1 interval, 325.4 (318.5 net) sections have potential for the Montney D2 interval and 307.9 (301.6 net) sections have potential for the Montney D4 interval. As at December 31, 2017, our total land holdings on these four intervals were 1,305.6 (1,263.2 net) sections. Assuming full development of four horizontal wells per section per drilling interval, we have 5,052.8 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 as at December 31, 2017. With 348 (342.8 net) horizontal locations drilled at the end of 2017, there remains 4,710.0 potential net future horizontal drilling locations as at December 31, 2017, down from 5,703.1 at year end 2016. This decrease is primarily attributable to the sale of some non-core Montney/Doig lands that we disposed of during 2017. 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 5,052.8 net existing horizontal wells and potential net future horizontal drilling locations. Our consolidated reserves report effective December 31, 2017 attributed proved reserves to 846.0 net existing wells and potential net future horizontal drilling locations (of which 507.2 net wells are potential future drilling locations) and proved plus probable reserves to 1,070.0 net existing wells and potential net future horizontal drilling locations (of which 731.2 net wells are potential future drilling locations). The remaining 3,982.8 potential net future horizontal drilling locations have not yet had any proved or probable reserves attributed to them by our independent qualified reserves evaluators. 21 2017 Annual Report GORDONDALE TEAM We were active in the Gordondale area during 2017, drilling a total of 16 (16.0 net) Montney horizontal wells (9 Montney D2 oil, 5 Montney D1 oil and 2 Montney D1 liquids-rich natural gas wells), all of which were successful. All of these wells were brought on production in 2017. A large portion of our 2018 capital program is directed towards our Gordondale area, including the drilling of 13 (13.0 net) wells. Since we acquired our assets in Gordondale on July 28, 2016, we have drilled, completed and brought on production a total of 22 (22.0 net) wells in Gordondale, consisting of 12 (12.0 net) Montney D2 horizontal oil wells, 5 (5.0 net) Montney D1 horizontal oil wells and 5 (5.0 net) Montney D1 liquids-rich horizontal natural gas wells. When we first acquired our Gordondale assets, the average production for such assets was approximately 22,000 boe/d at the date of the acquisition. The 22 horizontal wells that we have drilled and brought on production have replaced the natural production declines and have significantly increased the production on our Gordondale assets (approximately 30,000 boe/d at 2017YE). UPDATE ON GORDONDALE MONTNEY D2 HORIZONTAL OIL WELLS The 12 Montney D2 horizontal wells that we have drilled, completed and brought on production to-date have significantly delineated, de-risked and proven the commerciality of the Montney D2 play. When we initially acquired the Gordondale assets, only one D2 well had been previously drilled on the acquired assets and there was only one other offsetting industry D2 well. In an effort to continuously improve our well performance and optimize our completions strategy, we have utilized three different completion systems on our Montney D2 wells drilled to-date, including open hole packers, cemented sleeves fracced with coil tubing and plug and perf technology. We continue to evaluate the production results and cost efficiencies of each system in order to optimize field development in Gordondale. Our Montney D2 horizontal well results are meeting our expectations. In addition, we were able to reduce the average drilling, completion, equipping and tie-in costs of our Montney D2 horizontal wells to approximately $5.3 million during 2017, which is approximately $1 million less than what we had initially budgeted at the time of our acquisition of the Gordondale assets. This has significantly improved the economics of our Montney D2 wells. 22 2017 Annual Report R12W6 R11W6 R10W6 R9W6 M O N T N E Y / D O I G D E E P A C C C E CC E E E E E C K E E E E E F F F F F E E G GG E B CC A K S I N GGG E D G KK E G F F F F F G F F F E F F F F J F F F F F F F F F F F F F F Gordondale Gas Plant Gordondale Gas Plant F F F C F F C F CC F F F F F K F F F F F F F F GFC F F F F F F F C F F F F F F F F C F F F FF C F K F F F F F F F F F F G E E E E E E F C F C C F E E E E E E F F F C F C E A E E E EE B E E E CK E E E F F F F C F F FF F F F F F FK C F F G F FF E F E C F FF C A A B E E E CC C E E E E E E F E E E E E EF E E E D L E A PC Gas Plant F F F F F CF A F A FC F F F Gordondale Team Highlight Map Source: IHS Markit GC G GGG G G G G G K K F E E E LL G G LL A F CC F CC F F F F CC CC F F F F F F F C L GG F F C G L E G E N D Gordondale Non-Confidential Land Birchcliff Non-Confidential Land Birchcliff Vertical Producers Birchcliff Horizontal Producers 2017 Capital Program 2016 Capital Program R7W6 R8W6 T80 T79 T78 T77 T76 2 0 1 8 G O R D O N D A L E I N V E S T M E N T We plan to invest approximately $90 million in Gordondale during 2018. Key focus areas for Gordondale in 2018 will be the drilling of crude oil wells, the delineation of the Montney D1 and D2 intervals and continuing to improve on our well results and completion techniques through completion system design and fracturing techniques. DRILLING AND DEVELOPMENT We plan to drill 13 (13.0 net) horizontal wells in the Gordondale area, consisting of 8 (8.0 net) Montney D2 horizontal oil wells and 5 (5.0 net) Montney D1 horizontal oil wells, all of which will be drilled on multi-well pads. 23 2017 Annual Report POUCE COUPE TEAM We were active in the Pouce Coupe area during 2017, drilling a total of 38 (38.0 net) wells and working towards the expansion of the Pouce Coupe Gas Plant. A large portion of our 2018 capital program is directed towards our Pouce Coupe area, including the drilling of 14 (14.0 net) wells and a continued investment in the Pouce Coupe Gas Plant. We are continuing to pursue condensate and other liquids in our Pouce Coupe area in several different Montney/Doig intervals. R13W6 R12W6 R11W6 R10W6 BC/AB T81 T80 T79 T78 T77 T76 M O NT N E Y/D O IG D E E P B A S I N E D G E Gordondale Gas Plant PC Gas Plant L E G E N D Pouce Coupe Non-Confidential Land Birchcliff Non-Confidential Land Birchcliff Vertical Producers Birchcliff Horizontal Producers 2018 Capital Program 2017 Capital Program Source: IHS Markit Pouce Coupe Team Highlight Map DRILLING, DEVELOPMENT AND IP60 MONTNEY D1 WELL RESULTS During 2017, we drilled a total of 37 (37.0 net) Montney/Doig horizontal natural gas wells in Pouce Coupe (27 Montney D1, 7 Basal Doig/Upper Montney and 3 Montney D4 wells). Of these 37 wells, 36 were brought on production in 2017. In addition, we drilled 1 (1.0 net) Montney/Doig vertical science and technology well in the third quarter of 2017. Our most recent pad at Pouce Coupe, which came on-stream in November 2017 at 16-15-77-12W6, has shown strong production rates on an IP60 day basis. The four well average IP60 production rate was 1,280 boe/d (6.2 MMcf/d of raw natural gas, 239 bbls/d of 54° API condensate (condensate gas ratio of approximately 38 bbls/MMcf) with an average flowing casing pressure on day 60 of 11.6 MPa. 24 2017 Annual Report UPDATE ON SCIENCE AND TECHNOLOGY MULTI-WELL PAD PROGRAM The purpose of our science and technology multi-well pad program in Pouce Coupe is to collect high quality and high value data from the vertical well and the straddling horizontal wells, which can be used to enhance our technical capabilities and understanding with respect to the drilling, completion and production from this multi-layer resource play. In the third quarter of 2017, we drilled the vertical science and technology well in Pouce Coupe. The well was drilled to the top of the Montney where we cut a full diameter core through the entire Montney section (approximately 300 metres). The extracted rock core has provided analytical data to increase our knowledge of rock properties, which we have incorporated in our petrophysical models, and helped us to more accurately represent the geology of the area. We are currently compiling all of the lab measurements and analytical data from this well. We are in the early stages of evaluating the data; however, the data we have received to date looks encouraging for the four different intervals to be developed in this area, being our two proven intervals (the Basal Doig/Upper Montney and the Montney D1) and our two relatively new intervals (the Montney D2 and the Montney C). We are very excited about the potential identified in the Montney D2 and the Montney C from the vertical well. We have utilized the learnings from the vertical well to finalize the planning on the execution of a science and technology multi-well pad program. The 2018 capital program contemplates drilling four wells from the multi-well pad (one Montney D2 well, one Montney C well and two Montney D1 wells). The Montney D2 well will be the first Montney D2 well drilled in Pouce Coupe and we see significant opportunity to build on the Montney D2 success we have had in Gordondale. The Montney C well will be the second Montney C well we have drilled in Pouce Coupe. The initial Montney C well that we drilled has been on production for three years and has shown a fairly flat production profile with a condensate ratio of approximately 15 bbls/MMcf. We believe that with our most recent engineered completion design this second Montney C well will outperform the existing Montney C well. In January 2018, we moved a drilling rig onto the pad and spudded the first of four wells on this pad. The first three wells (one Montney D1 well, one Montney D2 well and one Montney C well) have been rig released and we are currently drilling the fourth well (a Montney D1 well). We expect that all four wells will be completed in the second quarter of 2018 and brought on production in the third quarter of 2018. During the completion of the four horizontal wells, we intend to utilize the vertical well as a micro-seismic and tilt meter monitoring well to gain further insight into fracture parameters and complexity. In addition to the vertical well, we are planning to install a permanent fiber-optic cable within the horizontal portion of one of the Montney D1 horizontal wells, allowing further data to be collected on fracture parameters and ongoing production performance along the horizontal well length. 25 2017 Annual Report POUCE COUPE GAS PLANT Our 100% owned and operated Pouce Coupe Gas Plant located in the Pouce Coupe area of Alberta is strategically situated in the heart of our Montney/ Doig Resource Play, enabling us to process natural gas at a lower cost than that borne by others who rely on third-party processing. The Pouce Coupe Gas Plant is the cornerstone of our strategy to develop our Montney/Doig Resource Play, to control and expand our production on the play and to further reduce our operating costs on a per boe basis. In 2010, we began executing on our “build & fill” strategy with the construction of the Pouce Coupe Gas Plant. During 2010, we constructed Phases I and II of our Pouce Coupe Gas Plant with 60 MMcf/d of natural gas processing capacity. Processing capacity at the Pouce Coupe Gas Plant was subsequently increased to 150 MMcf/d (Phase III) in 2012, to 180 MMcf/d (Phase IV) in 2014 and to 260 MMcf/d (Phase V) in 2017. During 2018, we expect to complete the 80 MMcf/d Phase VI expansion of the Pouce Coupe Gas Plant which will increase the processing capacity from 260 MMcf/d to 340 MMcf/d. Field construction commenced in January 2018 and we currently anticipate that Phase VI will be brought on-stream in October 2018. Phase VI will allow for future growth and help us to reduce our operating costs on a per boe basis. The total estimated cost for the Phase VI expansion is approximately $52.4 million, of which $26.7 million has already been incurred. We estimate that an additional $25.7 million will be required during 2018 to complete construction as the fabrication of the components has been completed and much of the infrastructure that will be utilized by Phase VI was built in connection with Phase V which came on-stream in the third quarter of 2017. In effect, Phase VI is an add-on to Phase V for a relatively low expenditure as the cost of the additional 80 MMcf/d is only $0.655 million per MMcf/d of processing capacity. In addition, we are currently in the process of reconfiguring Phases V and VI to provide for shallow-cut processing capability when Phase VI comes on-stream. This shallow-cut processing capability will allow us to remove propane plus (“C3+”) natural gas liquids from the natural gas stream. As both phases will include shallow-cut capability, the combined 160 MMcf/d facility is expected to provide approximately 600 bbls/d of C3+ based on the current natural gas stream going through the Pouce Coupe Gas Plant. As we increase our focus on liquids-rich drilling opportunities, this will provide for the efficient processing of liquids-rich natural gas. This addition of shallow-cut capability is only expected to cost an additional $3.0 million which is included in the estimated cost for Phase VI. Given the 2018 drilling program and expected 2018 production levels, we will have excess capacity at the Pouce Coupe Gas Plant when Phase VI comes on-stream. In order to partially fill Phase VI, we currently plan on diverting some of our natural gas that is currently being processed at third-party facilities to Phase VI, which will also help us to reduce our operating costs. We believe that we will be able to fill this excess capacity over time as commodity prices improve and as we continue to drill liquids-rich natural gas wells. We had previously commenced the planning and initial work to further expand the processing capacity of the Pouce Coupe Gas Plant by 150 MMcf/d to 490 MMcf/d (Phase VII which was originally expected to come on-stream in late 2020) and by another 100 MMcf/d to 590 MMcf/d (Phase VIII which was originally expected to come on-stream in 2021). In light of current conditions, we have deferred making the decision to proceed with Phases VII or VIII. 26 2017 Annual Report THE POUCE COUPE GAS PLANT IS 100% OWNED AND OPERATED enabling us to process natural gas at a lower cost than that borne by others who rely on third-party processing. 2 0 1 8 P O U C E C O U P E I N V E S T M E N T We plan to invest approximately $142.3 million in Pouce Coupe during 2018. Key focus areas for Pouce Coupe in 2018 will be the drilling of liquids-rich natural gas wells to maximize the recovery of condensate and other natural gas liquids, the execution of our multi-well science and technology pad, the exploration of the Montney D2 and C intervals, the completion of the 80 MMcf/d Phase VI expansion of the Pouce Coupe Gas Plant, the addition of shallow-cut capability for Phases V and VI and continuing to improve on our well performance and completion techniques. DRILLING AND DEVELOPMENT We plan to drill 14 (14.0 net) horizontal wells in our Pouce Coupe area, consisting of 12 (12.0 net) Montney D1 horizontal liquids-rich and low-cost natural gas wells, 1 (1.0 net) Montney D2 horizontal liquids-rich natural gas well and 1 (1.0 net) Montney C horizontal liquids-rich natural gas well, all of which will be drilled on multi-well pads. FACILITIES AND INFRASTRUCTURE Approximately $25.7 million of the 2018 capital program will be directed towards the completion of the Phase VI expansion of the Pouce Coupe Gas Plant. Once this investment has been made, we expect that our facilities and infrastructure expenditures going forward will decrease significantly until a decision is made to build additional phases of the Pouce Coupe Gas Plant. 27 2017 Annual Report 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. This plant is currently planned to 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. Birchcliff had previously planned to have this proposed plant come onstream in the fall of 2021; however, given current commodity prices and industry conditions, Birchcliff has made the decision to delay the construction of this plant. 28 2017 Annual Report BY ALMOST ANY MEASUREMENT, RATIO OR EFFICIENCY METRIC USED BY INDUSTRY, BIRCHCLIFF ENJOYED TOP TIER PERFORMANCE. - A. Jeffery Tonken President & Chief Executive Officer 2 0 1 7 Y E A R - E N D R E S E R V E S Significant Reserves Growth Year-Over-Year We retained two independent qualified reserves evaluators, Deloitte LLP (“Deloitte”) and McDaniel & Associates Consultants Ltd. (“McDaniel”), to evaluate and prepare reports on 100% of our light crude oil and medium crude oil (combined), conventional natural gas, shale gas and NGLs reserves. Deloitte evaluated all of our properties other than our Gordondale assets, representing approximately 75% of the assigned total proved plus probable reserves, and McDaniel evaluated the reserves attributable to our Gordondale assets, representing approximately 25% of the assigned total proved plus probable reserves. The reserves data set forth below at December 31, 2017 is based upon the evaluation by Deloitte with an effective date of December 31, 2017 as contained in the report of Deloitte dated February 9, 2018 (the “2017 Deloitte Reserves Report”) and the evaluation by McDaniel with an effective date of December 31, 2017 as contained in the report of McDaniel dated February 14, 2018 (the “2017 McDaniel Reserves Report”), which are contained in the consolidated report of Deloitte with an effective date of December 31, 2017 (the “2017 Consolidated Reserves Report”). Deloitte prepared the 2017 Consolidated Reserves Report by consolidating the properties evaluated by Deloitte in the 2017 Deloitte Reserves Report with the properties evaluated by McDaniel in the 2017 McDaniel Reserves Report, in each case using Deloitte’s forecast price and cost assumptions effective December 31, 2017 (the “2017 Deloitte Price Forecast”). Hedging gains and losses have been incorporated into the 2017 Consolidated Reserves Report. Deloitte also prepared an evaluation with an effective date of December 31, 2016 as contained in the report of Deloitte dated February 8, 2017 (the “2016 Deloitte Reserves Report”) and McDaniel prepared an evaluation 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”). All of the above-noted reserves reports were prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) in effect at the relevant time. For additional information regarding the presentation of our 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 our Annual Information Form for the year ended December 31, 2017. Numbers presented in the tables below may not total due to rounding. 30 2017 Annual Report2017 YEAR-END RESERVES RESERVES SUMMARY The following table summarizes the estimates of Birchcliff’s gross reserves at December 31, 2017 and December 31, 2016, 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 Total Probable Total Proved Plus Probable Corporate Reserves Corporate Dec 31, 2017 (Mboe) Dec 31, 2016 (Mboe) Change from Dec 31, 2016 197,955.1 664,480.5 308,034.8 972,515.3 165,507.0 548,523.8 331,940.0 880,463.8 20% 21% (7%) 10% 1,200 1,000 800 600 400 200 0 1,200 1,000 800 600 400 200 0 ) e o b M M ( s e v r e s e R ) e o b M M ( s e v r e s e R PDP TP 2P PDP TP 2P 31 2010 2011 2012 2013 2014 2015 2016 2017 Montney 2010 2011 2012 2013 2014 2015 2016 2017 2017 Annual Report2017 YEAR-END RESERVES 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, 2017, estimated using the 2017 Deloitte Price Forecast: Summary of Reserves at December 31, 2017 (Forecast Prices and Costs)(1) 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) Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Total Probable Total Proved Plus Probable 8,403.9 6,797.3 13,950.1 13,040.2 982,574.8 898,576.8 23,463.6 18,180.4 197,955.1 176,913.8 0.0 0.5 4,309.1 3,994.8 20,400.5 18,818.3 254.3 183.6 4,372.5 3,986.3 8,211.8 6,912.3 3,493.2 3,201.6 2,467,406.9 2,187,549.4 42,124.4 34,708.8 462,152.9 406,746.3 16,615.8 13,710.0 21,752.4 20,236.6 3,470,382.2 3,104,944.5 65,842.3 53,072.9 664,480.5 587,646.4 14,394.0 11,500.2 14,103.2 12,884.0 1,449,379.3 1,241,483.1 49,727.2 39,579.9 308,034.8 260,141.3 31,009.7 25,210.2 35,855.6 33,120.6 4,919,761.5 4,346,427.6 115,569.4 92,652.8 972,515.3 847,787.7 (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. 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, 2017, estimated using the 2017 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, 2017 (Forecast Prices and Costs) Reserves Category Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Total Probable Total Proved Plus Probable Before Income Taxes Discounted At (%/year) 0 (MM$) 5 (MM$) 10 (MM$) 15 (MM$) 20 (MM$) Unit Value Discounted at 10%/yr ($/boe) 3,542.7 2,469.5 71.0 7,484.0 11,097.7 6,662.2 17,759.9 46.0 3,603.1 6,118.5 2,779.3 8,897.8 1,871.9 32.6 1,827.9 3,732.4 1,375.7 5,108.1 1,504.4 1,259.9 10.58 24.7 917.9 2,447.0 764.1 3,211.1 19.6 412.2 1,691.7 458.7 2,150.5 8.19 4.49 6.35 5.29 6.03 32 2017 Annual Report PRICING ASSUMPTIONS The following table sets forth the forecast price and cost assumptions used in the 2017 Consolidated Reserves Report: 2017 Deloitte Price Forecast Crude Oil Natural Gas NGLs WT I at Cushing Oklahoma (US$/bbl) Edmonton City Gate (CDN$/bbl) Alberta AECO Average Price (CDN$/Mcf) Ontario Dawn Reference Point (CDN$/Mcf) Edmonton Ethane (CDN$/bbl) Edmonton Propane (CDN$/bbl) Edmonton Butane (CDN$/bbl) Edmonton Pentanes + Condensate (CDN$/bbl) Currency Exchange Rate (CDN$/US$) Price and Cost Inflation Rates (%) 55.00 58.65 62.40 69.00 75.75 77.30 78.85 80.40 82.00 83.65 85.35 87.05 88.80 90.55 92.35 94.20 96.10 98.00 100.00 102.00 2%/yr 65.40 68.25 70.65 76.15 84.05 85.75 87.45 89.20 91.00 92.80 94.65 96.55 98.50 100.45 102.45 104.50 106.60 108.75 110.90 113.10 2%/yr 2.00 2.30 2.75 2.95 3.20 3.40 3.75 4.10 4.20 4.35 4.45 4.55 4.65 4.70 4.80 4.90 5.00 5.10 5.20 5.30 3.85 4.00 4.15 4.40 4.60 4.90 5.25 5.55 5.75 5.90 6.05 6.15 6.30 6.40 6.55 6.65 6.80 6.95 7.05 7.20 5.60 6.45 7.70 8.35 8.95 9.60 10.60 11.45 11.85 12.20 12.45 12.70 12.95 13.20 13.45 13.75 14.00 14.30 14.55 14.85 39.25 37.55 35.30 34.30 33.60 34.30 34.95 35.65 36.40 37.10 37.85 38.60 39.40 40.15 40.95 41.80 42.60 43.50 44.35 45.25 42.50 44.35 45.95 49.50 54.60 55.70 56.80 57.95 59.10 60.30 61.50 62.75 64.00 65.25 66.55 67.90 69.25 70.65 72.05 73.50 68.65 71.65 74.20 79.95 88.25 90.05 91.85 93.70 95.55 97.45 99.40 101.40 103.45 105.50 107.60 109.75 111.95 114.20 116.45 118.80 0.780 0.800 0.825 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%/yr 2%/yr 2%/yr 2%/yr 2%/yr 2%/yr 0.850/yr 2.0/yr Year 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2037+ 33 2017 Annual Report RECONCILIATION OF CHANGES IN RESERVES The following table sets forth a reconciliation of Birchcliff’s gross reserves at December 31, 2017 set forth in the 2017 Consolidated Reserves Report, using the 2017 Deloitte Price Forecast, to Birchcliff’s gross reserves at December 31, 2016 set forth in the 2016 Consolidated Reserves Report, using the 2016 Deloitte Price Forecast: Reconciliation of Gross Reserves from December 31, 2016 to December 31, 2017 (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, 2016 31,792.0 59,393.8 2,741,455.4 49,923.6 548,523.8 Discoveries Extensions & Improved Recovery Technical Revisions Acquisitions Dispositions Economic Factors Production(1) Closing balance December 31, 2017 GROSS TOTAL PROBABLE 0.0 4,145.7 (120.0) 0.2 (17,275.8) (244.5) (1,681.8) 16,615.8 0.0 99.7 4,095.0 10.1 (37,618.3) (1,364.6) (2,863.3) 0.0 700,773.6 151,766.1 5,865.6 (173.9) (14,195.4) (115,109.2) 21,752.4 3,470,382.2 0.0 15,204.3 4,250.2 42.4 (408.7) (107.7) (3,061.8) 65,842.3 0.0 136,162.2 30,107.0 1,021.9 (23,983.2) (2,945.5) (24,405.7) 664,480.5 Opening balance December 31, 2016 26,655.7 62,289.1 1,532,149.2 39,544.6 331,940.0 Discoveries Extensions & Improved Recovery Technical Revisions Acquisitions Dispositions Economic Factors Production(1) 0.0 2,590.6 1,077.7 0.0 0.0 54.8 13.2 1.7 (15,817.3) (48,025.0) 0.0 (228,436.8) 167,035.2 5,674.5 (125.8) (112.8) 0.0 (230.6) (26,917.0) 0.0 0.0 0.0 1,059.4 9,607.0 56.6 (493.4) (47.0) 0.0 0.0 (34,413.7) 38,526.1 1,002.6 (24,335.8) (4,684.4) 0.0 Closing balance December 31, 2017 14,394.0 14,103.2 1,449,379.3 49,727.2 308,034.8 GROSS TOTAL PROVED PLUS PROBABLE Opening balance December 31, 2016 58,447.7 121,682.9 4,273,604.6 89,468.2 880,463.8 Discoveries Extensions & Improved Recovery Technical Revisions Acquisitions Dispositions Economic factors Production(1) Closing balance December 31, 2017 0.0 6,736.3 957.7 0.2 0.0 154.5 4,108.2 11.8 (33,093.1) (85,643.3) (357.3) (1,681.8) 31,009.7 (1,595.2) (2,863.3) 35,855.6 0.0 472,336.8 318,801.3 11,540.1 (299.7) (41,112.4) (115,109.2) 4,919,761.5 0.0 16,263.7 13,857.1 99.0 (902.1) (154.7) (3,061.8) 115,569.4 0.0 101,748.6 68,633.1 2,024.5 (48,319.0) (7,629.9) (24,405.7) 972,515.3 (1) Represents the independent qualified reserves evaluators’ estimates of actual production for the year ended December 31, 2017 before year-end results were available. 34 2017 Annual Report With respect to our total corporate reserves, proved reserves increased by 21%, probable reserves decreased by 7% and proved plus probable reserves increased by 10%. The increases in our proved and proved plus probable reserves is primarily attributable to: (i) the success of our 2017 drilling program which resulted in more potential net future drilling locations to which reserves were assigned; and (ii) positive technical revisions as a result of improved well performance. Positive technical revisions accounted for 42% of the proved plus probable reserves additions and 18% of the total proved reserves additions, after excluding the effects of acquisitions and dispositions and adding back in 2017 actual production of 24,806.3 Mboe. These increases were partially offset by the various dispositions we completed during 2017 (including the Worsley Disposition) as well as economic factors as a result of a lower commodity price forecast. The decrease in our probable reserves is primarily attributable to the re-classification of probable reserves as proved reserves in several of our potential net future drilling locations, as well as the dispositions we completed during 2017. The following sets forth additional information on the reconciliation of our reserves by product type: • NGLs: Proved reserves increased by 32%, probable reserves increased by 26% and proved plus probable reserves increased by 29%. The increases are primarily attributable to: (i) the success of our 2017 drilling program which resulted in more potential net future drilling locations to which reserves were assigned; and (ii) positive technical revisions as a result of higher NGLs yields at a proposed deep-cut facility at the Pouce Coupe Gas Plant as compared to a third-party facility. These increases were partially offset by the various dispositions we completed during 2017 (including the Worsley Disposition), as well as economic factors as a result of a lower commodity price forecast. • Shale Gas: Proved reserves increased by 27%, probable reserves decreased by 5% and proved plus probable reserves increased by 15%. The increases are primarily attributable to: (i) the success of our 2017 drilling program which resulted in more potential net future drilling locations to which reserves were assigned; and (ii) positive technical revisions as a result of improved well performance. The decrease in our probable reserves is primarily attributable to the re-categorization of probable reserves as proved reserves in several of our potential net future drilling locations. • Conventional Natural Gas: Proved reserves decreased by 63%, probable reserves decreased by 77% and proved plus probable reserves decreased by 71%. The decreases are primarily attributable to the Worsley Disposition. • Light and Medium Crude Oil: Proved reserves decreased by 48%, probable reserves decreased by 46% and proved plus probable reserves decreased by 47%. The decreases are primarily attributable to the Worsley Disposition. Since we acquired our Gordondale assets on July 28, 2016, we have drilled, completed and brought on production a total of 22 (22.0 net) wells in Gordondale, consisting of 12 (12.0 net) Montney D2 horizontal oil wells, 5 (5.0 net) Montney D1 horizontal oil wells and 5 (5.0 net) Montney D1 liquids-rich horizontal natural gas wells. All of these wells were brought on production in 2017 and added significant reserves at December 31, 2017 on a proved developed producing basis. On a proved and a proved plus probable basis, we added 16 new proved and 43 new proved plus probable potential net future drilling locations in the largely unbooked Montney D2 interval. The Gordondale Montney D2 drilling and delineation continues to prove the large oil accumulation in the Gordondale area. 35 2017 Annual Report FUTURE DEVELOPMENT COSTS FDC reflects the independent reserves evaluators’ best estimate of what it will cost to bring the proved and proved plus probable reserves on production. Changes in forecast FDC occur annually as a result of development activities, acquisition and disposition activities and capital cost estimates. The following table sets forth the independent reserves evaluators’ estimated FDC to bring the proved and proved plus probable reserves on production: Future Development Costs (Forecast Prices and Costs) 2018 2019 2020 2021 2022 Thereafter Total undiscounted Proved (MM$) 247.1 485.6 325.3 502.0 628.9 1,045.1 3,234.0 Proved Plus Probable (MM$) 307.7 528.7 416.2 556.0 701.9 1,992.5 4,503.0 FDC for total proved reserves increased to $3.23 billion at December 31, 2017 from $2.50 billion at December 31, 2016. FDC for total proved plus probable reserves increased to $4.50 billion at December 31, 2017 from $4.15 billion at December 31, 2016. The increases in FDC for both proved and proved plus probable reserves are largely due to: (i) the increase in Montney/Doig potential net future drilling locations added in each category of reserves as a result of our successful 2017 drilling program; (ii) proved potential net future drilling locations added in Pouce Coupe due to increased geological confidence and continued delineation on the Montney/Doig Resource Play; and (iii) the expansion of natural gas processing capacity and related infrastructure capital. The increases in FDC were partially offset by the reserves associated with the assets that were disposed of pursuant to the Worsley Disposition and the associated capital required to develop such reserves ($159 million on a proved basis and $357 million on a proved plus probable basis). The FDC for both proved and proved plus probable reserves are primarily the capital costs required to drill, complete, equip and tie-in the net undeveloped locations. The estimates of FDC on a proved basis also include approximately $660 million for the expansion of the Pouce Coupe Gas Plant from the existing 260 MMcf/d to 810 MMcf/d of total throughput. Of this 550 MMcf/d of additional capacity, 150 MMcf/d is related to a proposed deep-cut facility that will process the Gordondale gas as a replacement for a third-party facility. The estimates of FDC on a proved plus probable basis include approximately $678 million for the same capacity expansions as the proved case above with additional gathering pipeline requirements. The FDC for the expansions of the Pouce Coupe Gas Plant also include the costs of the related gathering pipelines, sales pipeline expansion and compression. 36 2017 Annual Report The following table sets forth the average cost to drill, complete, equip and tie-in a multi-stage fractured horizontal well as estimated by Deloitte and McDaniel: Average Well Cost, as Estimated by Deloitte or McDaniel Pouce Coupe(1) Gordondale(2) December 31, 2017 (MM$) December 31, 2016 (MM$) 4.6 5.2 4.5 5.7 (1) Estimated by Deloitte. Up slightly compared to 2016 due to increased frac intensity in completions. (2) Estimated by McDaniel. Down slightly based on actual costs incurred in 2017 and go forward DCCET costs. RESERVES REPLACEMENT The following table sets forth our 2017 reserves replacement ratios: Reserves Category Proved Developed Producing Proved Proved Plus Probable 2017 Reserves Replacement, Excluding the Effects of Acquisitions and Dispositions(1) 2017 Reserves Replacement, Including the Effects of Acquisitions and Dispositions(1) 266% 660% 658% 231% 567% 471% (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 our 2017 reserves life index: Reserves Category Proved Developed Producing Total Proved Total Proved Plus Probable 2017 Reserves Life Index(1) 7.0 years 23.6 years 34.6 years (1) Based on a forecast production rate of 77,000 boe/d for 2018, which represents the mid-point of Birchcliff’s annual average production guidance range for 2018. Please see “Advisories – Oil and Gas Metrics” for a description of the methodology used to calculate reserves life index. 37 2017 Annual Report RESERVES ON THE MONTNEY/DOIG RESOURCE PLAY The following table summarizes the estimates of reserves attributable to our horizontal wells on the Montney/Doig Resource Play as contained in the 2017 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) 2017 2016 2017 2016 2017 2016 2017 2016 2017 2016 2017 2016 976.5 764.1 8,323.4 6,036.5 23,066.0 18,572.5 194,145.1 151,964.1 339 281 333.8 275.7 3,464.1 2,734.5 16,318.7 14,400.5 65,348.2 48,808.2 659,029.0 518,965.8 862 736 846.0 721.7 4,911.2 4,274.8 30,428.7 25,307.2 114,869.1 87,687.7 963,836.1 825,454.6 1,103 1,000 1,072.0 974.4 Reserves Category Proved Developed Producing Total Proved Total Proved Plus Probable (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, 2017, the estimated FDC for our reserves on our Montney/Doig Resource Play is $0.0 million on a proved developed producing basis (as compared to $0.9 million at December 31, 2016), $3,223.3 million on a proved basis (as compared to $2,277.5 million at December 31, 2016) and $4,480.8 million on a proved plus probable basis (as compared to $3,680.9 million at December 31, 2016). Corporate Montney/Doig Reserves 1,200 1,000 800 600 400 200 0 ) e o b M M ( s e v r e s e R 2010 2011 2012 2013 2014 2015 2016 2017 Montney 38 1,200 ) e o b M M ( s e v r e s e R 1,000 800 600 400 200 0 2010 2011 2012 2013 2014 2015 2016 2017 PDP TP 2P PDP TP 2P 2017 Annual Report 2017 FINDING AND DEVELOPMENT COSTS During 2017, our F&D costs were $415.0 million and our FD&A costs were $274.3 million. The following table sets forth our estimates of our F&D costs per boe and FD&A costs per boe for 2017, 2016 and 2015, excluding and including FDC: Excluding FDC ($/boe)(1) F&D – Proved Developed Producing F&D – Proved F&D – Proved Plus Probable FD&A – Proved Developed Producing FD&A – Proved FD&A – Proved Plus Probable Including FDC ($/boe)(1) F&D – Proved F&D – Proved Plus Probable FD&A – Proved FD&A – Proved Plus Probable 2017 $6.29 $2.53 $2.54 $4.79 $1.95 $2.35 2017(2) $8.14 $7.27 $7.16 $5.37 2016 $6.42 $1.57 $1.25 $9.32 $3.53 $2.33 2016(3) $4.89 $4.43 $6.73 $5.58 2015 $8.11 $3.09 $2.06 $7.79 $2.96 $2.02 2015(4) $2.41 $1.55 $2.28 $1.32 Three Year Average $6.78 $2.38 $1.99 $7.51 $2.91 $2.27 Three Year Average $5.81 $4.68 $6.02 $4.62 (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 2017 increase in FDC from 2016 of $732.9 million on a proved basis and $352.9 million on a proved plus probable basis. (3) 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. (4) 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. 2017 RECYCLE RATIOS The following table sets forth our recycle ratios for operating and adjusted funds flow netbacks for 2017 and 2016, 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 Recycle Ratio(1) Adjusted Funds Flow Netback Recycle Ratio(1) 2017 2016 2017 2016 2.2 2.9 5.5 7.2 5.5 6.0 1.7 2.0 1.9 2.6 1.7 1.2 7.0 3.1 8.8 4.7 2.3 1.6 2.5 2.0 2.0 2.7 5.1 6.6 5.0 5.5 1.6 1.8 1.8 2.4 1.3 0.9 5.2 2.3 6.6 3.5 1.7 1.2 1.8 1.5 (1) Please see “Advisories – Oil and Gas Metrics” for a description of the methodology used to calculate F&D costs, FD&A costs and recycle ratios. During 2017, the average benchmark price for WTI crude oil was US$50.95/bbl and the average benchmark price for natural gas sold at AECO was CDN$2.16/MMBtu. The operating netback was $13.97/boe in 2017, as compared to $11.01/boe in 2016. Adjusted funds flow netback was $12.81/boe in 2017, as compared to $8.18/boe in 2016. 39 2017 Annual Report R E S P O N S I B I L I T Y Looking Out for Our Team and the Community HEALTH, SAFETY AND ENVIRONMENT At Birchcliff, we are committed to constantly evolving and improving our health, safety and environmental management program and conducting our activities in a manner that safeguards our employees, contractors, representatives, the environment and the public at large. We have an active program to monitor and comply with health, safety and environmental laws, rules and regulations applicable to our operations. Birchcliff’s corporate policies require operational activities to be conducted in a manner which meets or exceeds regulatory requirements and industry standards to safeguard the environment and protect employees, contractors and the public at large. Employees receive pertinent health, safety and environmental training for their roles. We conduct operational audits and assessments to identify risks and takes steps to reduce or prevent incidents. 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 one arise. We conduct rigorous emergency response exercises and training for our staff that exceeds minimum regulatory requirements. Birchcliff participates in Alberta’s Certificate of Recognition (COR) Safety Program and has received and maintained a COR certification since 2011. A COR certification demonstrates that the employer’s health and safety management system has been evaluated by a certified auditor and meets provincial standards, as established by Occupational Health and Safety (Alberta). 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 Alberta Energy Regulator (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. Our Chief Inspector and our Asset Integrity Group make use of databases and associated work tracking systems to ensure that all integrity tasks (inspections, pigging, etc.) are scheduled and completed according to 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 which reduces our environmental footprint. 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. 40 2017 Annual Report COMMUNITY SUPPORT Fostering a strong relationship with the community and its stakeholders is as integral to the success of Birchcliff’s projects as obtaining the required regulatory approvals. We believe cooperative, sincere and responsive consultation efforts with stakeholders in the areas in which we operate creates a solid foundation for our business. Birchcliff has an experienced team working with local stakeholders to learn their values and priorities and to resolve any issues or concerns that arise in the course of our field operations. Birchcliff recognizes the role that communities play in our success and looks for opportunities to “give back”. We are a staunch supporter of the community and the business and educational initiatives of the Indigenous Communities who live in the areas where we operate. Every year, we participate in a number of community support endeavours in the areas surrounding our field operations and in Calgary. In 2017, Birchcliff contributed to a number of local community initiatives that help elevate and enhance the quality of life at the local level, including minor hockey and other amateur sports, local schools, agricultural societies and fire departments. To date, Birchcliff and its partners have donated approximately $1,059,000 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, Birchcliff raises funds for the United Way of Calgary 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. INDIGENOUS RELATIONS Birchcliff’s activity is focused in the Peace River Area of Alberta which is within the traditional area occupied by the Treaty 8 First Nations members and by the Metis people. Birchcliff recognizes and respects these indigenous groups, their rights and their culture. Much of our activity takes place upon the unoccupied crown lands which are administered by the Province of Alberta. We are committed to open, honest and straightforward communication with the indigenous groups who have been formally recognized as having rights within the areas in which we operate. Currently those groups include Horse Lake First Nation, Duncan’s First Nation and East Prairie Metis Settlement. We provide support to these communities and their ventures to enhance their human, economic and cultural development. Our support is aligned with several key philosophies and based upon the principle that all individuals should be treated fairly and with respect. The success of our children and future generations is the key. For this reason we are strong supporters of all education initiatives from early childhood programs, programs that support adolescents, post-secondary courses, upgrading and equivalency programs and trade and technical training programs. We believe that everyone should be aware of, and proud of, their culture and heritage. We support many cultural events including round dances, formal events such as Treaty 8 Days and cultural camps which bring youth and elders together for traditional learning and sharing opportunities. Communities are most successful when their members drive the programs. We look to community members to set goals and take the initiative to plan, prepare budgets, submit the request for support and organize their events. We have long standing agreements with the key communities in our areas of operations. We are proud of the relationships that we have with these communities and the reputation we have worked hard to build and maintain. We believe that our actions must always speak louder than our words. 41 2017 Annual Report “ F I N A N C I A L S 2017 FINANCIALS M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S GENERAL This Management’s Discussion and Analysis (“MD&A”) for Birchcliff Energy Ltd. (“Birchcliff” or the “Corporation”) is dated March 14, 2018. This MD&A with respect to the three and twelve months ended December 31, 2017 (the “Reporting Periods”) as compared to the three and twelve months ended December 31, 2016 (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 the related notes for the year ended December 31, 2017. Birchcliff’s audited financial statements and the related notes for the year ended December 31, 2017 have been prepared in accordance with IFRS. All dollar amounts are expressed in Canadian currency, unless otherwise stated. This MD&A uses “adjusted funds flow”, “adjusted funds flow per common share”, “operating netback”, “estimated operating netback”, “operating margin”, “total cash costs”, “adjusted working capital deficit” and “total debt”, which do not have standardized meanings prescribed by GAAP and therefore may not be comparable to similar measures presented by other companies where similar terminology is used. For further information, see “Non-GAAP Measures” in this MD&A. This MD&A contains forward-looking 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 within its one core area, the Peace River Arch of Alberta. Birchcliff’s common shares and cumulative redeemable preferred shares, Series A and Series C are listed for trading on the Toronto Stock Exchange (the “TSX”) under the symbols “BIR”, “BIR.PR.A” and “BIR.PR.C”, respectively. Additional information relating to the Corporation, including its Annual Information Form for the financial year ended December 31, 2017, is available on the SEDAR website at www.sedar.com and on the Corporation’s website at www.birchcliffenergy.com. 2017 FINANCIAL AND OPERATIONAL HIGHLIGHTS During 2017, Birchcliff reduced its exposure to pricing at AECO and diversified the natural gas markets it sells to. Birchcliff entered into agreements for the firm service transportation of an aggregate of 175,000 GJ/d (approximately 152 MMcf/d) of natural gas on TCPL’s Canadian Mainline for a 10-year term, whereby natural gas is transported to the Dawn trading hub located in Southern Ontario. The first tranche of this service (120,000 GJ/d) became available to Birchcliff on November 1, 2017, with additional tranches becoming available on November 1, 2018 (35,000 GJ/d) and November 1, 2019 (20,000 GJ/d). Birchcliff also has sales agreements with a third party marketer to sell and deliver into the Alliance pipeline system: (i) approximately 40 MMcf/d of natural gas under contracts which commenced November 1, 2017 and expire March 31, 2018, 10 MMcf/d of which is sold at Alliance’s Trading Pool daily index price and 30 MMcf/d of which is sold at a Chicago index price; and (ii) approximately 5 MMcf/d of natural gas under contracts which commenced April 1, 2017 and expire October 31, 2020, which is sold at Alliance’s Trading Pool daily index price. The 80 MMcf/d Phase V expansion of Birchcliff’s 100% owned and operated natural gas processing plant in Pouce Coupe (the “Pouce Coupe Gas Plant”) was successfully brought on-stream in the third quarter of 2017, increasing the total processing capacity of the plant to 260 MMcf/d from 180 MMcf/d. During 2017, Birchcliff completed asset sales for total proceeds of approximately $148 million (before adjustments), including the disposition of its Worsley Charlie Lake Light Oil Pool (the “Worsley Assets”) for total proceeds of approximately $100 million (before adjustments) ($90 million in cash; $10 million in securities) which closed on August 31, 2017 (the “Worsley Disposition”). 43 2017 Annual Report Other highlights of 2017 include the following: • Birchcliff achieved record annual average production of 67,963 boe/d, a 38% increase from 49,236 boe/d in 2016. • Birchcliff had adjusted funds flow of $317.7 million, or $1.20 per basic common share, a 115% increase and a 62% increase, respectively, from $147.4 million and $0.74 per basic common share in 2016. • Birchcliff recorded a net loss to common shareholders of $51.0 million ($0.19 per basic common share), as compared to the net loss to common shareholders of $28.3 million ($0.14 per basic common share) in 2016. The net loss included an after-tax loss of $132.3 million resulting from the Worsley Disposition. • Birchcliff had operating costs of $4.45/boe, a 6% increase from $4.18/boe in 2016. • Birchcliff had general and administrative expense of $1.07/boe, a 10% decrease from $1.19/boe in 2016. • Birchcliff had interest expense of $1.14/boe, a 32% decrease from $1.68/boe in 2016. • Birchcliff had net capital expenditures of $276.1 million and total capital expenditures of $416.8 million in 2017. • Birchcliff’s total debt at December 31, 2017 was $598.2 million, as compared to $600.0 million at December 31, 2016. • Birchcliff began paying a quarterly dividend to its common shareholders during 2017 in the amount of $0.10 per share per year ($0.025 per share per quarter). Highlights of the fourth quarter of 2017 include the following: • Birchcliff had record quarterly average production of 80,103 boe/d, a 32% increase from 60,750 boe/d in the fourth quarter of 2016. • Birchcliff had quarterly adjusted funds flow of $97.0 million, or $0.36 per basic common share, a 35% increase and a 33% increase, respectively, from $71.8 million and $0.27 per basic common share in the fourth quarter of 2016. • Birchcliff recorded net income to common shareholders of $24.8 million ($0.09 per basic common share), as compared to net income to common shareholders of $11.1 million ($0.04 per basic common share) in the fourth quarter of 2016. • Birchcliff had operating costs of $3.86/boe, a 15% decrease from $4.54/boe in the fourth quarter of 2016. • Birchcliff had general and administrative expense of $1.28/boe, an 8% increase from $1.19/boe in the fourth quarter of 2016. • Birchcliff had interest expense of $0.97/boe, a 31% decrease from $1.40/boe in the fourth quarter of 2016. • Birchcliff had net capital expenditures of $18.7 million. See “Cash Flow from Operating Activities and Adjusted Funds Flow”, “Net Income (Loss) to Common Shareholders”, “Pouce Coupe Gas Plant Netbacks”, “Discussion of Operations”, “Capital Expenditures” and “Capital Resources and Liquidity” in this MD&A for further information regarding the financial and operational results for the Reporting Periods. 2018 OUTLOOK The Board of Directors of the Corporation has approved a capital expenditure budget for 2018 of $255 million. Approximately $149.9 million has been allocated for drilling and development, $66.9 million for facilities and infrastructure and $17.1 million for sustaining and optimization. Based on the assumptions set forth in the table on the next page, the Corporation expects that its 2018 capital expenditures will be less than its adjusted funds flow during 2018. Birchcliff’s 2018 capital expenditure program (the “2018 Capital Program”) reflects the Corporation’s long-term plan to continue the exploration and development of its low-cost natural gas, crude oil and liquids-rich assets on the Montney/Doig Resource Play. The program will focus on the drilling of crude oil wells in Gordondale and a combination of liquids-rich and low-cost natural gas wells in Pouce Coupe to take advantage of the recently improved prices for oil and NGLs. The objectives of the 2018 Capital Program are to maintain a prudent pace of development and focus on rates of return, while also maintaining balance sheet strength and the payment of a sustainable quarterly dividend to Birchcliff’s shareholders. The 2018 Capital Program contemplates the drilling, completing, equipping and bringing on production of a total of 27 (27.0 net) wells during 2018 and targets an annual average production rate for 2018 in the range of 76,000 to 78,000 boe/d. In addition, the 2018 Capital Program contemplates the completion of the 80 MMcf/d Phase VI expansion of the Pouce Coupe Gas Plant, which is expected to come on-stream in October 2018. In addition, Phases V and VI of the plant are being re-configured to allow for shallow-cut capability to remove propane plus (C3+) liquids from the natural gas stream. 44 Birchcliff Energy Ltd. During 2018, Birchcliff expects that approximately 34% of its 2018 forecast annual average natural gas production will be sold at prices that are not based on AECO, with 30% being sold at the Dawn index price and 4% being marketed via the Alliance pipeline system. Birchcliff’s market diversification initiatives have helped to reduce its exposure to volatility in commodity prices, including AECO prices which have been extremely volatile in recent months. The Corporation continues to actively look for further profitable market diversification opportunities. The following table sets forth the Corporation’s guidance and commodity price assumptions for 2018, as well as its 2017 results for comparative purposes: 2018 Guidance and Assumptions(1) 2017 Annual Actuals Production Annual average production (boe/d) % Natural gas % Oil and NGLs Average Expenses ($/boe) Royalty Operating Transportation and marketing Capital Expenditures (MM$) Estimated total capital Estimated drilling and development capital Estimated facilities and infrastructure capital Natural Gas Market Exposure(4) AECO production as a % of total natural gas production Dawn production as a % of total natural gas production Commodity Prices Average WTI oil price (US$/bbl) Average AECO price ($/MMBtu)(6) Average Dawn price ($/MMBtu)(6) Average wellhead natural gas price ($/Mcf)(7) 76,000 – 78,000 80% 20% 1.20 – 1.40 3.75 – 4.00 3.80 – 4.10(2) 255.0 149.9 66.9 66% 30% 61.00 1.58 3.48 2.32 67,963 79% 21% 1.16 4.45 2.87(3) 416.8 269.1 132.4 58%(5) 29%(5) 50.95 2.16 3.82(5) 2.72(8) (1) For further information regarding Birchcliff’s 2018 guidance, including the assumptions surrounding such guidance, please see “Advisories – Forward-Looking Information” in this MD&A. (2) Includes transportation tolls for 120,000 GJ/d of natural gas sold at the Dawn price from January 1, 2018 to October 31, 2018 and 155,000 GJ/d from November 1, 2018 to December 31, 2018. (3) Includes transportation tolls for 120,000 GJ/d of natural gas sold at the Dawn price from November 1, 2017 to December 31, 2017. (4) Approximately 13% of total natural gas production was sold via the Alliance pipeline system in 2017. Approximately 4% of total natural gas production is expected to be sold via the Alliance pipeline system in 2018. (5) For the months of November and December 2017 only as the Corporation’s TCPL-Dawn arrangement did not commence until November 1, 2017. (6) $1.00 per MMBtu equals $1.00 per Mcf based on a standard heat value of 37.4 MJ/m3 or a heat uplift of 1.055 when converting from $/GJ. (7) Birchcliff receives premium pricing for its natural gas production due to its high heat content from its properties. The conversion from standard heat value in MMBtu to realized wellhead price in Mcf is based on an expected corporate average realized natural gas heat content value of 40.80 MJ/ m3 or a heat uplift of 1.091. The total conversion is $1.00/GJ = $1.15/Mcf at the wellhead. (8) Includes the effects of any commodity fixed price physical delivery contracts in the period. The average wellhead natural gas price for 2018 of $2.32/Mcf is based upon an annual average AECO price of $1.58/MMBtu during 2018 ($2.11/MMBtu during the months of January, February, March, November and December and $1.20/MMBtu during the remaining months of 2018) and an annual Dawn price of $3.48/MMBtu during 2018 ($4.22/MMBtu during the months of January and February and $3.33/MMBtu during the remaining months of 2018). See “Advisories – Forward-Looking Information”. 45 2017 Annual Report SELECTED ANNUAL INFORMATION Average daily production (boe) Petroleum and natural gas revenue ($000s)(1) Average sales price (CDN$)(1) Light oil – (per bbl) Natural gas – (per Mcf) NGLs – (per bbl) Total – (per boe) Cash flow from operating activities ($000s) Adjusted funds flow ($000s)(2) Per common share – basic ($) Per common share – diluted ($) Net loss ($000s) Net loss to common shareholders ($000s) Per common share – basic ($) Per common share – diluted ($) Capital expenditures, net ($000s) Operating costs ($ per boe) Total assets ($000s) Capital securities ($000s) Revolving term credit facilities ($000s) Adjusted working capital deficit ($000s) Total debt ($000s) Common shares outstanding (000s): End of period – basic End of period – diluted Weighted average common shares for period – basic(3) Weighted average common shares for period – diluted (3) Common shares – dividend distribution ($000s) Per common share ($) Series A preferred shares outstanding – end of period (000s) Series A – dividend distribution ($000s) Per Series A preferred share ($) Series C preferred shares outstanding – end of period (000s) Series C – dividend distribution ($000s) Per Series C preferred share ($) 2017 67,963 556,942 61.42 2.72 33.39 22.44 287,660 317,680 1.20 1.19 (46,980) (51,027) (0.19) (0.19) 276,125 4.45 2,627,108 49,225 587,126 11,067 598,193 265,797 282,895 265,182 265,182 26,522 0.10 2,000 4,047 2.02 2,000 3,500 1.75 2016 49,236 337,586 51.40 2.41 31.23 18.73 140,514 147,443 0.74 0.73 (24,335) (28,335) (0.14) (0.14) 762,030 4.18 2,710,457 48,916 572,517 27,495 600,012 264,042 279,881 199,581 199,581 - - 2,000 4,000 2.00 2,000 3,500 1.75 2015 38,950 317,304 53.68 2.90 50.76 22.31 148,797 160,756 1.06 1.04 (12,160) (16,160) (0.11) (0.11) 247,207 4.54 2,025,373 48,606 622,074 21,538 643,612 152,308 167,817 152,286 152,286 - - 2,000 4,000 2.00 2,000 3,500 1.75 (1) Excludes the effects of hedges using financial instruments but includes the effects of fixed price physical delivery contracts. (2) Birchcliff previously referred to adjusted funds flow as “funds flow from operations”. See “Non-GAAP Measures”. (3) As the Corporation reported net losses for 2017, 2016 and 2015, the basic and diluted weighted average shares outstanding are the same for the respective periods. 46 Birchcliff Energy Ltd. In 2017, annual average production was 67,963 boe/d, up 38% from 2016 and up 74% from 2015. The increase in annual average production from 2015 is primarily due to the production volumes acquired pursuant to the Gordondale asset acquisition that was completed in July 2016 (the “Gordondale Acquisition”) and the incremental production from new horizontal oil and natural gas wells brought on production in Pouce Coupe and Gordondale in connection with Birchcliff’s successful 2016 and 2017 capital programs. Birchcliff generated higher adjusted funds flow in 2017 as compared to the prior two years. The increase in adjusted funds flow from the prior two years was largely due to an increase in annual average production volumes and a higher average realized sales price. Adjusted funds flow in 2017 was also positively impacted by a $25.8 million realized cash gain on financial instruments, partially offset by increases in royalty, operating and transportation and marketing expenses primarily resulting from higher production in 2017. Birchcliff recorded a net loss to common shareholders of $51.0 million ($0.19 per basic common share) in 2017, as compared to the net loss to common shareholders of $28.3 million ($0.14 per basic common share) in 2016 and $16.2 million ($0.11 per basic common share) in 2015. The increase in the net loss to common shareholders from the prior two years is mainly attributable to an after-tax book loss of $132.3 million resulting from the Worsley Disposition and higher stock-based compensation and depletion costs, partially offset by higher adjusted funds flow in 2017. Net capital expenditures in 2017 were significantly lower as compared to 2016 but comparable to net capital expenditures in 2015. Net capital expenditures in 2016 included the Gordondale Acquisition for cash consideration of $613.5 million, after closing adjustments and other related costs. Excluding the Gordondale Acquisition, capital expenditures in the last three years were largely directed towards the Montney/Doig Resource Play which included: (i) the drilling and completion of new horizontal oil and natural gas wells brought on production in Pouce Coupe and Gordondale; and (ii) the Phase V expansion of the Pouce Coupe Gas Plant (including related wells and infrastructure) which increased the natural gas processing capacity from 180 MMcf/d to a licensed processing capacity of 260 MMcf/d. Net capital expenditures in 2017 also included the disposition of the Worsley Assets for total consideration of approximately $100 million before closing adjustments. CASH FLOW FROM OPERATING ACTIVITIES AND ADJUSTED FUNDS FLOW The following table sets forth the Corporation’s cash flow from operating activities and adjusted funds flow for the Reporting Periods and the Comparable Prior Periods: ($000s) Cash flow from operating activities Adjusted funds flow(1) Per common share – basic ($) Per common share – diluted ($) Three months ended December 31, Twelve months ended December 31, 2017 88,995 97,008 0.36 0.36 2016 2017 90,574 287,660 71,806 317,680 0.27 0.27 1.20 1.19 2016 140,514 147,443 0.74 0.73 (1) Birchcliff previously referred to adjusted funds flow as “funds flow from operations”. See “Non-GAAP Measures”. Cash flow from operating activities for the three month Reporting Period was comparable to the three month Comparable Prior Period. Cash flow from operating activities for the twelve month Reporting Period increased 105% from the twelve month Comparable Prior Period primarily due to a higher average realized sales price and higher corporate production. Adjusted funds flow in the three and twelve month Reporting Periods increased by 35% and 115%, respectively, from the Comparable Prior Periods. The increase in adjusted funds flow from the three month Comparable Prior Period was largely due to higher corporate production, a realized cash gain on financial instruments and lower royalty expense, partially offset by a lower average realized sales price, higher general and administrative expense and increased operating and transportation and marketing expenses primarily resulting from higher production in three month Reporting Period. Adjusted funds flow increased from the twelve month Comparable Prior Period primarily due to a higher average realized sales price, higher corporate production, a realized cash gain on financial instruments and lower interest costs, partially offset by higher royalties, operating and transportation and marketing expenses primarily resulting from higher production in the twelve month Reporting Period. 47 2017 Annual Report The following table sets forth a breakdown of total cash costs on a per unit basis and the percentage change period-over-period for the Reporting Periods and the Comparable Prior Periods: ($/boe) Royalty expense Operating expense Transportation and marketing expense General & administrative expense, net Interest expense Total cash costs Three months ended December 31, 2016 % Change 1.82 4.54 2.42 1.19 1.40 11.37 (31%) (15%) 45% 8% (31%) (4%) 2017 1.26 3.86 3.52 1.28 0.97 10.89 2017 1.16 4.45 2.87 1.07 1.14 Twelve months ended December 31, 2016 % Change 1.16 4.18 2.38 1.19 1.68 0% 6% 21% (10%) (32%) 1% 10.69 10.59 On a per unit basis, total cash costs for the three month Reporting Period decreased by 4% and for the twelve month Reporting Period increased by less than 1% as compared to the Comparable Prior Periods. 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 on the previous page. NET INCOME (LOSS) TO COMMON SHAREHOLDERS The following table sets forth the Corporation’s net income (loss) and net income (loss) to common shareholders for the Reporting Periods and the Comparable Prior Periods: ($000s) Net income (loss) Net income (loss) to common shareholders(1) Per common share – basic ($) Per common share – diluted ($) Three months ended December 31, Twelve months ended December 31, 2017 25,820 24,773 0.09 0.09 2016 2017 12,085 (46,980) 11,085 (51,027) 0.04 0.04 (0.19) (0.19) 2016 (24,335) (28,335) (0.14) (0.14) (1) Net income (loss) to common shareholders is calculated by adjusting net income (loss) for the dividends paid on the Series A Preferred Shares during the period. Per common share amounts are calculated by dividing net income (loss) to common shareholders by the weighted average number of basic or diluted common shares outstanding for the period. During the three month Reporting Period, Birchcliff reported net income to common shareholders of $24.8 million as compared to $11.1 million in the three month Comparable Prior Period. The increase in net income to common shareholders from the three month Comparable Prior Period is primarily due to an increase in adjusted funds flow and an after-tax gain of $10.0 million on the sale of Birchcliff’s Progress Charlie Lake assets which closed on October 2, 2017 (the “Progress Disposition”), partially offset by higher depletion expense resulting from higher production in the three month Reporting Period. During the twelve month Reporting Period, Birchcliff reported a net loss to common shareholders of $51.0 million, as compared to the net loss to common shareholders of $28.3 million in the twelve month Comparable Prior Period. The increase in net loss to common shareholders from the twelve month Comparable Prior Period was mainly attributable to an after-tax book loss of $132.3 million resulting from the Worsley Disposition and higher depletion and stock-based compensation costs, partially offset by an unrealized mark-to-market gain on financial instruments and higher adjusted funds flow in the twelve month Reporting Period. 48 Birchcliff Energy Ltd. POUCE COUPE GAS PLANT NETBACKS During the twelve month Reporting Period, Birchcliff processed approximately 60% of its total corporate natural gas production and 49% of its total corporate production through its Pouce Coupe Gas Plant as compared to 68% and 59%, respectively, during the twelve month Comparable Prior Period. These decreases are primarily due to the increased weighting of production from the Corporation’s Gordondale assets as a percentage of corporate production. The average plant and field operating cost for production processed through the Pouce Coupe Gas Plant was $0.34/Mcfe ($2.07/boe) and the estimated operating netback at the Pouce Coupe Gas Plant was $2.19/Mcfe ($13.12/boe), resulting in an operating margin of 72% in the twelve month Reporting Period. The following table sets forth Birchcliff’s average daily production and estimated operating netback for wells producing to the Pouce Coupe Gas Plant for the twelve month Reporting Period and the twelve month Comparable Prior Period: Average daily production, net to Birchcliff: Natural gas (Mcf) Oil & NGLs (bbls) Total boe AECO – C daily ($/MMBtu)(1) Netback and cost: Petroleum and natural gas revenue(2) Royalty expense Operating expense(3) Transportation and marketing expense(4) Estimated operating netback Operating margin Twelve months ended December 31, 2017 Twelve months ended December 31, 2016 193,417 1,316 33,552 $/boe 18.24 $2.16 $/Mcfe 2.54 (0.44) (0.06) (2.07) (0.25) (2.61) (0.33) $13.12 72% $1.90 75% 168,444 960 29,034 $/boe 15.21 (0.38) (1.49) (1.96) $11.38 75% $2.16 $/Mcfe 3.04 (0.07) (0.34) (0.44) $2.19 72% (1) $1.00/MMBtu = $1.00/Mcf based on a standard heat value Mcf. See “Advisories”. (2) Excludes the effects of hedges using financial instruments but includes the effects of fixed price physical delivery contracts and higher average realized sales pricing for a portion of natural gas sold at Dawn commencing November 1, 2017. The average benchmark price for natural gas sold from November 1, 2017 to December 31, 2017 at Dawn was $3.82/MMBtu compared to $2.17/MMBtu at AECO. (3) Represents plant and field operating costs. (4) Includes transportation tolls for a portion of natural gas sold at Dawn from November 1, 2017 to December 31, 2017. DISCUSSION OF OPERATIONS The following table sets forth Birchcliff’s P&NG revenues, production and percentage of production and sales price by product category for the Reporting Periods and the Comparable Prior Periods: Three months ended December 31, 2017 Three months ended December 31, 2016 Light oil (bbls) Natural gas (Mcf) NGLs (bbls) Total Revenue(1) ($000s) Average Daily Production 33,332 93,647 39,114 5,283 385,280 10,607 (%) 7 80 13 Total P&NG sales (boe) 166,093 80,103 100 Royalty revenue P&NG revenues 56 166,149 Average ($/unit) Total Revenue(1) ($000s) Average Daily Production (%) 8 79 13 26,018 88,135 21,254 4,656 289,587 7,830 135,407 60,750 100 50 68.58 2.64 40.08 22.54 0.01 22.55 135,457 (1) Excludes the effects of hedges using financial instruments but includes the effects of fixed price physical delivery contracts. Average ($/unit) 60.75 3.31 29.50 24.23 0.01 24.24 49 2017 Annual Report Twelve months ended December 31, 2017 Twelve months ended December 31, 2016 Light oil (bbls) Natural gas (Mcf) NGLs (bbls) Total P&NG sales (boe) Royalty revenue P&NG revenues 134,597 318,790 103,244 556,631 311 556,942 Total Revenue(1) ($000s) Average Daily Production Average ($/unit) Total Revenue(1) ($000s) Average Daily Production 6,004 320,927 8,471 (%) 9 79 12 61.42 2.72 33.39 22.44 0.01 70,144 218,432 48,901 337,477 109 22.45 337,586 3,729 247,373 4,279 (%) 8 83 9 Average ($/unit) 51.40 2.41 31.23 18.73 - 18.73 67,963 100 49,236 100 (1) Excludes the effects of hedges using financial instruments but includes the effects of fixed price physical delivery contracts. The increase in P&NG revenues from the Comparable Prior Periods was largely attributable to an increase in production from the Corporation’s 2017 capital program which resulted in incremental production from new horizontal oil wells being brought on production in Gordondale, as well as from new horizontal natural gas wells being brought on production in Pouce Coupe in connection with the start-up of Phase V of the Pouce Coupe Gas Plant. P&NG revenues were also impacted by the average realized sales price in the Reporting Periods, which was down by 7% from the three month Comparable Prior Period and up by 20% from the twelve month Comparable Prior Period. Petroleum and Natural Gas Revenues Production Production averaged 80,103 boe/d in the three month Reporting Period and 67,963 boe/d in the twelve month Reporting Period, a 32% and 38% increase, respectively, from the Comparable Prior Periods. The average production of 80,103 boe/d in the three month Reporting Period is slightly above the high end of Birchcliff’s previous guidance range of 79,000 to 80,000 boe/d. The average production of 67,963 boe/d in the twelve month Reporting Period is on the high end of the Corporation’s previous guidance range of 67,000 to 68,000 boe/d. Birchcliff’s oil, natural gas and NGLs production for the three month Reporting Period increased by 13%, 33% and 35%, respectively, from the three month Comparable Prior Period. During the twelve month Reporting Period, production from oil, natural gas and NGLs increased by 61%, 30% and 98%, respectively, from the twelve month Comparable Prior Period. The increase in production from the Comparable Prior Periods was primarily attributable to: (i) the Gordondale Acquisition which resulted in significant production additions subsequent to closing on July 28, 2016; (ii) incremental production from new horizontal oil wells being brought on production in Gordondale; and (iii) incremental production from new horizontal natural gas wells being brought on production in Pouce Coupe in connection with the start-up of Phase V of the Pouce Coupe Gas Plant. Production in the twelve month Reporting Period was also negatively impacted by the Worsley Disposition which was completed on August 31, 2017. During the twelve month Reporting Period, production from the Worsley Assets averaged 1,714 boe/d as compared to 2,923 boe/d in the twelve month Comparable Prior Period. During the three month Reporting Period, production from the Montney/Doig Resource Play was comprised of 49,138 boe/d in Pouce Coupe and 30,639 boe/d in Gordondale. During the twelve month Reporting Period, production from the Montney/Doig Resource Play was comprised of 39,092 boe/d in Pouce Coupe and 26,608 boe/d in Gordondale. Production consisted of approximately 80% natural gas, 7% light oil and 13% NGLs in the three month Reporting Period which was in line with Birchcliff’s previous guidance, as compared to 79% natural gas, 8% light oil and 13% NGLs in the three month Comparable Prior Period. Production consisted of approximately 79% natural gas, 9% light oil and 12% NGLs in the twelve month Reporting Period which was in line with Birchcliff’s previous guidance, as compared to 83% natural gas, 8% light oil and 9% NGLs in the twelve month Comparable Prior Period. The change in the corporate production mix from the twelve month Comparable Prior Period was a result of the more heavily-weighted oil and NGLs production attributed to the Corporation’s Gordondale assets. 50 Birchcliff Energy Ltd. Commodity Prices Birchcliff sold the majority of its light crude oil on a spot basis and its natural gas production for prices primarily based on the AECO natural gas spot price during the Reporting Periods. Commencing November 1, 2017, Birchcliff began selling its natural gas production at the Dawn index price. The average realized sales 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 crude oil. 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 the 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 a lack of pipeline infrastructure connecting to key consuming oil markets. Canadian natural gas prices are mainly influenced by North American supply and demand fundamentals which can be impacted by a number of factors, including, but not limited to, weather-related conditions, 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. AECO natural gas spot prices were challenged during the three month Reporting Period, with spot natural gas prices under pressure periodically due to temporary restrictions in pipeline and compressor station capacity on the Alberta NGTL system. Approximately half of Birchcliff’s total corporate production was hedged during the three month Reporting Period, which reduced the pricing impact as a result of these restrictions. During the Reporting Periods, the Corporation entered into agreements with TCPL for the firm service transportation of an aggregate of 175,000 GJ/d (approximately 152 MMcf/d) of natural gas on TCPL’s Canadian Mainline for a 10-year term, whereby natural gas is transported to the Dawn trading hub located in Southern Ontario. The first tranche of this service (120,000 GJ/d) became available to Birchcliff on November 1, 2017, with additional tranches becoming available later in 2018 and in 2019. In addition, Birchcliff entered into arrangements during the Reporting Periods with third party marketers to sell and deliver natural gas into the Alliance pipeline system. At December 31, 2017, approximately 58% of Birchcliff’s natural gas production was being sold at AECO, 29% sold at the Dawn price and 13% was being sold into the Alliance pipeline system. After taking into account Birchcliff’s oil and NGLs production, approximately 47% of the Corporation’s total corporate production at December 31, 2017 was exposed to AECO pricing, with the remaining 53% of corporate production not exposed to AECO pricing. The following table sets forth the average benchmark prices and Birchcliff’s average corporate realized sales price for the Reporting Periods and the Comparable Prior Periods: Average benchmark index prices: Light oil – WTI Cushing (US$/bbl) Light oil – Edmonton Par ($/bbl) Natural gas – AECO-C daily ($/MMBtu)(1) Natural gas – Union-Dawn Day Ahead ($/MMBtu)(1)(2) Exchange rate – (US$/CDN$) Birchcliff’s average realized sales price:(3) Light oil ($/bbl) Natural gas ($/Mcf) NGLs ($/bbl) Average corporate realized sales price ($/boe) Three months ended December 31, Twelve months ended December 31, 2017 2016 2017 2016 55.40 68.62 1.69 3.82 1.27 68.58 2.64 40.08 22.54 49.29 61.66 3.09 - 1.33 60.75 3.31 29.50 24.23 50.95 62.52 2.16 - 1.29 61.42 2.72 33.39 22.44 43.32 53.90 2.16 - 1.33 51.40 2.41 31.23 18.73 (1) $1.00/MMBtu = $1.00/Mcf based on a standard heat value Mcf. See “Advisories”. (2) For the months of November and December 2017 only as Birchcliff’s TCPL-Dawn arrangement did not commence until November 1, 2017. (3) Excludes the effects of hedges using financial instruments but includes the effects of fixed price physical delivery contracts. 51 2017 Annual Report The average corporate realized sales price was $22.54/boe for the three month Reporting Period and $22.44/boe for the twelve month Reporting Period, a 7% decrease and 20% increase, respectively, from the Comparable Prior Periods. During the three month Reporting Period: (i) Birchcliff’s average realized natural gas sales price decreased 20% from the Comparable Prior Period; (ii) Birchcliff’s average realized oil sales price increased 13% from the Comparable Prior Period; and (iii) Birchcliff’s average realized NGLs sales price increased 36% from the Comparable Prior Period. During the twelve month Reporting Period: (i) Birchcliff’s average realized natural gas sales price increased 13% from the Comparable Prior Period; (ii) Birchcliff’s average realized oil sales price increased 19% from the Comparable Prior Period; and (iii) Birchcliff’s average realized NGLs sales price increased 7% from the Comparable Prior Period. During the three month Reporting Period, the average realized oil, natural gas and NGLs sales price was $29.46/boe for the Corporation’s Gordondale assets as compared to $18.27/boe for the Corporation’s Pouce Coupe assets. During the twelve month Reporting Period, the average realized oil, natural gas and NGLs sales price was $26.92/boe for the Gordondale assets as compared to $18.41/boe for the Pouce Coupe assets. The Corporation’s assets in Gordondale receive a higher average sales price compared to the Corporation’s assets in Pouce Coupe, largely as a result of higher volume weighting of NGLs produced in the Gordondale area which receive a higher value on a per unit basis than Birchcliff’s natural gas sales. The higher weighting of NGLs in the total corporate production mix improves Birchcliff’s overall average realized sales price. With respect to the Corporation’s Gordondale assets, NGLs (ethane, propane, butane) are substantially recovered from the raw natural gas stream at AltaGas’ owned and operated natural gas processing facility located in Gordondale (the “AltaGas Facility”) which reduces the heat content value and realized sales price of natural gas from the area. During the three and twelve month Reporting Periods, the average realized natural gas sales price for the Gordondale assets was $2.62/Mcf and $2.67/Mcf, respectively, as compared to $2.65/Mcf and $2.74/Mcf, respectively, for the Pouce Coupe assets. During the three month Reporting Period, the NGLs production mix in Gordondale consisted of approximately 36% ethane, 30% propane, 17% butane and 17% condensate (“C5+”). During the twelve month Reporting Period, the NGLs production mix in Gordondale consisted of approximately 33% ethane, 32% propane, 19% butane and 16% C5+. In comparison, approximately 95% of Birchcliff’s NGLs production mix in Pouce Coupe was comprised of C5+ during the Reporting Periods. The NGLs sales price averaged $32.48/boe for the Gordondale assets as compared to $70.47/boe for the Pouce Coupe assets during the three month Reporting Period. For the twelve month Reporting Period, the NGLs sales price averaged $26.01/boe for the Gordondale assets as compared to $63.09/boe for the Pouce Coupe assets. Commodity Price Risk Management The Corporation maintains an ongoing commodity price risk management program in order to reduce volatility in its financial results. As a part of this program, the Corporation utilizes various financial derivative and physical delivery sales contracts. The Board of Directors of the Corporation has authorized the Corporation to hedge such portion of its forecast production as is permitted by the Corporation’s credit facilities, which generally 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 current strategy for 2018 is to hedge up to 50% of its estimated 2018 forecast average production using a combination of financial derivatives and physical sales contracts, depending on its outlook for commodity prices and the availability of hedges on terms acceptable to Birchcliff. Financial Derivative Contracts As at December 31, 2017, the Corporation had the following financial derivatives in place: Type of contract Notional quantity Term(1) Contract price Fair value ($000s) Product Crude oil Financial swap 1,500 bbls/d Crude oil Financial swap 3,000 bbls/d Fair value assets(2) January 1, 2018 – December 31, 2018 January 1, 2018 – December 31, 2018 WTI CDN $71.85/bbl 1,300 WTI CDN $71.88/bbl 2,746 4,046 (1) Transactions with common terms and the same counterparty have been aggregated and presented at the weighted average price. (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 “mark-to-market” fair value basis at December 31, 2017, with the changes in fair value being recognized as a non-cash unrealized gain or loss in profit or loss. These contracts are not entered into for trading or speculative purposes. 52 Birchcliff Energy Ltd. The following table sets forth a summary of the realized and unrealized gains (losses) on financial derivative contracts for the Reporting Periods and the Comparable Prior Periods: Three months ended December 31, Twelve months ended December 31, 2017 2016 2017 2016 ($000s) 10,787 (13,712) ($/boe) ($000s) 1.46 (134) (1.86) (9,603) ($/boe) (0.02) (1.72) ($000s) 25,785 5,387 ($/boe) ($000s) 1.03 0.22 802 (9,433) ($/boe) 0.04 (0.52) Realized gain (loss) Unrealized gain (loss) There were no financial derivative contracts entered into by the Corporation subsequent to December 31, 2017. Physical Delivery Sales Contracts As at December 31, 2017, the Corporation had no physical delivery sales contracts in place. There were no physical delivery sales contracts entered into by the Corporation subsequent to December 31, 2017. Royalties The following table sets forth Birchcliff’s royalty expense for the Reporting Periods and the Comparable Prior Periods: 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, 2017 9,271 1.26 6% 2016 10,177 1.82 8% 2017 28,727 1.16 5% 2016 20,911 1.16 6% (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 royalties decreased from the three month Comparable Prior Period primarily due to a 20% decrease in natural gas prices and the effect these lower prices have on the sliding scale royalty calculation, partially offset by higher corporate production and increased oil and NGLs prices. Birchcliff’s aggregate royalties increased from the twelve month Comparable Prior Period primarily due to higher average realized sales prices and higher corporate production. During the three and twelve month Reporting Periods, the effective royalty rate for the Gordondale assets averaged 9% and 8%, respectively, and for the Pouce Coupe assets the effective royalty rate averaged 3% and 2%, respectively. The higher effective royalty rate for the Gordondale assets were due to higher oil and NGLs weighting which generally have higher sliding scale royalty rates. Operating Costs The following table sets forth for the Reporting Periods and the Comparable Prior Periods a breakdown of Birchcliff’s operating costs: Three months ended December 31, Twelve months ended December 31, 2017 2016 2017 2016 ($000s) 28,901 (523) 28,378 82 28,460 ($/boe) ($000s) ($/boe) ($000s) ($/boe) ($000s) 3.92 (0.07) 3.85 0.01 3.86 25,786 (429) 25,357 28 4.61 112,287 (0.08) (1,917) 4.53 0.01 110,370 116 4.53 (0.08) 4.45 - 76,706 (1,700) 75,006 245 25,385 4.54 110,486 4.45 75,251 ($/boe) 4.26 (0.09) 4.17 0.01 4.18 Field operating costs Recoveries Field operating costs, net Expensed workovers and other Operating costs 53 2017 Annual Report The per unit operating costs for the three month Reporting Period were $3.86/boe, a 15% decrease from $4.54/boe in the three month Comparable Prior Period and in line with Birchcliff’s previous guidance of less than $4.00/boe for the quarter. The decrease in operating costs per boe from the three month Comparable Prior Period was largely due to incremental production additions brought on-stream to Phase V of the Pouce Coupe Gas Plant, the sale of the higher cost Worsley Assets and various cost reductions and infrastructure optimization initiatives implemented by Birchcliff throughout 2017. The per unit operating costs for the twelve month Reporting Period were $4.45/boe, a 6% increase from $4.18/boe in the twelve month Comparable Prior Period. The increase in operating costs per boe from the twelve month Comparable Prior Period was largely due to higher operating, processing and service costs associated with the Gordondale assets which were acquired partway through 2016 and operational for the twelve month Reporting Period, partially offset by incremental production additions brought on-stream to Phase V of the Pouce Coupe Gas Plant, the sale of the higher cost Worsley Assets and various cost reductions and infrastructure optimization initiatives implemented by Birchcliff throughout 2017. The Gordondale assets have a higher cost structure primarily resulting from increased oil and NGLs production weighting and additional fees incurred to process natural gas from the Gordondale area at the AltaGas Facility. During the three and twelve month Reporting Periods, operating costs: (i) for the Gordondale assets averaged approximately $6.15/boe and $6.32/boe, respectively; and (ii) for the Pouce Coupe assets averaged approximately $2.37/boe and $2.66/boe, respectively. Transportation and Marketing Expense The following table sets forth Birchcliff’s transportation and marketing expense for the Reporting Periods and the Comparable Prior Periods: Three months ended December 31, Twelve months ended December 31, 2017 2016 2017 2016 ($000s) ($/boe) ($000s) ($/boe) ($000s) ($/boe) ($000s) Transportation and marketing expenses 25,883 3.52 13,489 2.42 71,224 2.87 42,989 ($/boe) 2.38 The increase in the aggregate and per unit transportation and marketing expense from the Comparable Prior Periods was largely due to firm service pipeline transportation tolls for natural gas transported to Dawn between November 1, 2017 and December 31, 2017, and an increase in pipeline and trucking transportation costs associated with higher weighting of oil and NGLs production from the Gordondale assets, partially offset by a reduction in trucking costs associated with the Worsley Assets which were disposed of on August 31, 2017. During the three and twelve month Reporting Periods, transportation and marketing expense for the Gordondale assets averaged approximately $3.27/boe and $2.93/boe, respectively. For the Pouce Coupe assets, transportation and marketing expense averaged approximately $3.69/boe and $2.68/boe during the three and twelve month Reporting Periods, respectively. 54 Birchcliff Energy Ltd. Operating Netbacks The following table sets forth Birchcliff’s net production and operating netback for the Corporation’s assets in Pouce Coupe and Gordondale on the Montney/Doig Resource Play and on a corporate basis for the Reporting Periods and the Comparable Prior Periods: Pouce Coupe Montney/Doig Resource Play Average daily production, net: Natural gas (Mcf) Oil & NGLs (bbls) Total boe % of corporate production(1) Netback and cost ($/boe): Petroleum and natural gas revenue(2) Royalty expense Operating expense, net of recoveries Transportation and marketing expense Operating netback Gordondale Montney/Doig Resource Play(3) 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, 2017 2016 2017 2016 282,084 199,866 224,561 200,364 2,125 49,138 61% 18.27 (0.50) (2.37) (3.69) 11.71 101,385 13,742 30,639 38% 29.46 (2.50) (6.15) (3.27) 17.54 1,361 1,666 34,672 39,092 57% 58% 21.59 (0.74) (2.26) (2.14) 16.45 18.41 (0.40) (2.66) (2.68) 12.67 81,814 90,599 9,482 23,118 38% 26.07 (3.25) (6.72) (2.44) 13.66 11,508 26,608 39% 26.92 (2.07) (6.32) (2.93) 15.60 385,280 289,587 320,927 15,890 80,103 22.55 (1.26) (3.86) (3.52) 13.91 12,484 60,750 14,475 67,963 24.24 (1.82) (4.54) (2.42) 15.46 22.45 (1.16) (4.45) (2.87) 13.97 1,407 34,801 71% 15.49 (0.43) (2.39) (2.05) 10.62 37,076 4,331 10,510 21% 24.11 (3.21) (7.31) (2.49) 11.10 247,373 8,007 49,236 18.73 (1.16) (4.18) (2.38) 11.01 (1) Production from Birchcliff’s other oil and natural gas properties including the Worsley Assets was not individually significant during the Reporting Periods and Comparable Prior Periods. (2) Excludes the effects of hedges using financial instruments but includes the effects of fixed price physical delivery contracts. (3) The Gordondale assets were acquired pursuant to the Gordondale Acquisition which was completed on July 28, 2016. As such, the production and operating netback for the Gordondale assets during the twelve month Comparable Prior Period reflect the results from July 29, 2016 to December 31, 2016. 55 2017 Annual Report Montney/Doig Resource Play Birchcliff’s production from the Montney/Doig Resource Play, which is comprised of the Corporation’s Pouce Coupe assets and Gordondale assets, was 79,777 boe/d in the three month Reporting Period and 65,700 boe/d in the twelve month Reporting Period, a 38% and 45% increase, respectively, from the Comparable Prior Periods. The increase in production is primarily attributable to the success of Birchcliff’s 2017 capital drilling program which resulted in incremental production from new Montney horizontal oil wells brought on production in Gordondale and incremental volumes from new Pouce Coupe Montney/Doig horizontal natural gas wells brought on production to Phase V of the Pouce Coupe Gas Plant which came on-stream in the third quarter of 2017. Birchcliff’s recoveries of liquids (oil and NGLs) from its Montney/Doig Resource Play were 41.4 bbls/MMcf in the three month Reporting Period and 41.8 bbls/MMcf in the twelve month Reporting Period as compared to 38.5 bbls/MMcf and 24.2 bbls/MMcf in the three and twelve month Comparable Prior Periods, respectively. The liquids recoveries averaged approximately 135.5 bbls/MMcf and 127.0 bbls/MMcf in Gordondale during the three and twelve month Reporting Periods, respectively, as compared to 7.5 bbls/MMcf and 7.4 bbls/MMcf in Pouce Coupe during the three and twelve month Reporting Periods, respectively. Any liquids not recovered from the raw natural gas stream increases the heat content value of Birchcliff’s natural gas sales and the realized sales price. Birchcliff’s operating netback for the Montney/Doig Resource Play was $13.94/boe in the three month Reporting Period and $13.85/boe in the twelve month Reporting Period, a decrease of 9% and an increase of 29%, respectively, from the Comparable Prior Periods. The decrease in operating netback from the three month Comparable Prior Period was primarily driven by a lower average realized sales price received for Birchcliff’s oil and natural gas production and an increase in transportation expense largely due to firm service pipeline tolls for natural gas transported to Dawn between November 1, 2017 and December 31, 2017. The increase in the operating netback from the twelve month Comparable Prior Period was primarily driven by a higher average realized sales price received for Birchcliff’s oil and natural gas production, partially offset by higher per unit operating and transportation and marketing costs mainly attributed to the Corporation’s 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 the AltaGas Facility. Net production and operating netback for the Worsley Assets and Birchcliff’s other oil and natural gas properties were not significant as they accounted for approximately 3% of Birchcliff’s average corporate production during the Reporting Periods. Birchcliff completed the Worsley Disposition on August 31, 2017. 56 Birchcliff Energy Ltd. Administrative Expenses The components of Birchcliff’s net administrative expenses for the Reporting Periods and the Comparable Prior Periods are set forth in the table below: Three months ended December 31, Twelve months ended December 31, 2017 2016 2017 2016 ($000s) (%) ($000s) (%) ($000s) (%) ($000s) Cash: Salaries and benefits(1) Other(2) General and administrative, gross 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 13,451 2,832 16,283 (52) (6,781) 9,450 $1.28 2,370 (1,376) 994 $0.13 10,444 $1.41 83 17 100 (1) (41) 58 100 (58) 42 10,056 2,856 12,912 (35) 78 22 100 (1) 31,437 13,498 44,935 (202) 70 30 100 (1) 25,576 12,449 38,025 (154) (6,234) (48) (18,229) (40) (16,382) 6,643 $1.19 1,583 (903) 680 $0.12 7,323 $1.31 51 26,504 59 21,489 $1.07 $1.19 100 (57) 43 9,945 (5,886) 4,059 $0.16 30,563 $1.23 100 (59) 41 6,053 (3,575) 2,478 $0.14 23,967 $1.33 (%) 67 33 100 (1) (42) 57 100 (59) 41 (1) Includes salaries, benefits and bonuses paid to officers and employees of the Corporation and retainer fees, meeting fees and benefits paid to directors of the Corporation. (2) Includes costs such as rent, legal fees, tax, insurance, corporate travel, minor computer hardware and software and other general business expenses incurred by the Corporation. (3) Includes a portion of gross general and administrative costs and stock-based compensation directly attributable to the exploration and development activities of the Corporation which have been capitalized. The increase in the aggregate net administrative costs in the Reporting Periods as compared to the Comparable Prior Periods was primarily driven by the additional staff needed to manage the increase in production, reserves and land base associated with the Corporation’s assets in Gordondale and Pouce Coupe and higher general business expenditures. Net administrative expenses for the twelve month Reporting Period were also affected by the accelerated vesting of unvested stock options held by staff managing the Worsley Assets which resulted in additional stock-based compensation expense recorded in the third quarter of 2017. 57 2017 Annual Report The following table sets forth the Corporation’s outstanding stock options for the Reporting Periods and the Comparable Prior Periods: Outstanding, beginning of period Granted Exercised Forfeited Expired Outstanding, end of period (1) Determined on a weighted average basis. Outstanding, beginning of period Granted Exercised Forfeited Expired Outstanding, end of period (1) Determined on a weighted average basis. Three months ended December 31, 2017 Three months ended December 31, 2016 Number 14,378,009 137,000 (8,000) (148,734) (200,168) 14,158,107 Exercise price($)(1) 6.90 4.96 (3.35) (6.73) (7.75) Number 13,821,239 55,000 (971,964) - (4,500) 6.88 12,899,775 Exercise price($)(1) 6.43 8.48 (6.23) - (10.18) 6.45 Twelve months ended December 31, 2017 Twelve months ended December 31, 2016 Number 12,899,775 4,867,400 (1,754,796) (1,606,437) (247,835) 14,158,107 Exercise price($)(1) 6.45 7.67 (5.33) (7.49) (7.55) Number 12,569,238 3,356,000 (1,209,363) (120,400) (1,695,700) 6.88 12,899,775 Exercise price($)(1) 7.80 3.90 (6.28) (6.78) (11.46) 6.45 At December 31, 2017, 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. 58 Birchcliff Energy Ltd. 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 the actual production in the relevant period. The Corporation determines its D&D expenses on a field area basis. The following table sets forth Birchcliff’s D&D expenses for the Reporting Periods and the Comparable Prior Periods: Three months ended December 31, Twelve months ended December 31, 2017 2016 2017 2016 Depletion and depreciation expenses ($000s) 57,920 ($/boe) ($000s) ($/boe) ($000s) ($/boe) ($000s) 7.86 43,184 7.73 185,666 7.48 149,369 ($/boe) 8.29 D&D expenses for the Reporting Periods were higher on an aggregate basis as compared to the Comparable Prior Periods mainly due to an increase in corporate production. Included in the depletion calculation for 2017 were 972.5 MMboe of proved plus probable reserves and $4.50 billion of future development costs required to recover those reserves as estimated by the Corporation’s independent qualified reserves evaluators effective December 31, 2017. Asset Impairment Assessment The Corporation reviews its petroleum and natural gas assets for impairment in accordance with International Accounting Standards (“IAS”) 36 under IFRS. Birchcliff’s assets are grouped into cash generating units (“CGU”) for the purpose of determining impairment. A CGU represents the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets. In determining the Corporation’s CGUs, the Corporation takes into consideration all available information, including, but not limited to: geographical proximity; geological similarities (i.e. reservoir characteristics and production profiles); degree of shared infrastructure; independent versus interdependent cash flows; operating structure; the regulatory environment; management decision-making; and overall business strategy. The Corporation’s CGUs are reviewed at each reporting date for both internal and external indicators of potential impairment. Potential CGU impairment indicators include, but are not limited to: changes to Birchcliff’s business plan; deterioration in commodity prices; negative changes in the technological, economic, legal, capital or operating environment; adverse changes to the physical condition of a CGU; current expectations that a material CGU (or a significant component thereof) is more likely than not to be sold or otherwise disposed of before the end of its previously estimated useful life; non-compliance with the agreements governing the Corporation’s bank credit facilities; deterioration in the financial and operational performance of a CGU; net assets exceeding market capitalization; and significant downward revisions of estimated proved plus probable reserves of a CGU. If impairment indicators exist, an impairment test is performed by comparing a CGU’s carrying value to its recoverable amount. In light of the current low natural gas commodity price environment, Birchcliff performed an impairment test for its petroleum and natural gas assets on a CGU basis to assess for recoverability at December 31, 2017. Management has determined that the recoverable amount of Birchcliff’s CGUs exceed the carrying amount at December 31, 2017 and therefore no impairment exists. At December 31, 2016, Birchcliff performed an impairment assessment of its petroleum and natural gas assets on a CGU basis and determined there were no impairment triggers identified. As a result, an impairment test was not required at December 31, 2016. Management has determined that the calculation of the recoverable amount is most sensitive to key assumptions regarding discount rates, commodity prices and estimated quantities of proved plus probable reserves and future production profile of those reserves. Each of these underlying key assumptions are reviewed by management and corroborated independently to assess for reasonableness. The petroleum and natural gas future prices are based on period-end commodity price forecast assumptions determined by the Corporation’s independent reserves evaluator. 59 2017 Annual Report Finance Expenses The components of the Corporation’s finance expenses for the Reporting Periods and the Comparable Prior Periods are set forth in the table below: Three months ended December 31, Twelve months ended December 31, 2017 2016 2017 2016 ($000s) ($/boe) ($000s) ($/boe) ($000s) ($/boe) ($000s) ($/boe) Cash: Interest on credit facilities 7,131 0.97 7,822 1.40 28,374 1.14 30,305 1.68 Non-cash: Accretion on decommissioning obligations Amortization of deferred financing fees Finance expenses 595 400 8,126 0.08 0.05 1.10 813 330 8,965 0.15 0.06 1.61 3,055 1,510 32,939 0.12 0.06 1.32 2,547 1,088 33,940 0.14 0.06 1.88 The decrease in the aggregate interest expense from the Comparable Prior Periods was largely due to a lower average outstanding total credit facilities balance in the Reporting Periods and, for the three month Reporting Period, lower average effective interest rates. 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 extendible revolving credit facilities (the “Credit Facilities”). EBITDA is defined as earnings before interest and non-cash items, including (if any) income taxes, stock-based compensation, gains and losses on sale of assets, unrealized gains and losses on financial instruments and depletion, depreciation and amortization. The following table sets forth the Corporation’s effective interest rates under its credit facilities for the Reporting Periods and the Comparable Prior Periods: Effective interest rates: Revolving working capital facility Revolving syndicated term credit facility Three months ended December 31, Twelve months ended December 31, 2017 2016 2017 2016 5.0% 4.9% 5.2% 5.2% 5.0% 4.8% 5.2% 4.7% Birchcliff’s average outstanding total credit facilities balance was approximately $586 million and $588 million in the three and twelve month Reporting Periods, respectively, as compared to $599 million and $632 million in the Comparable Prior Periods, calculated as the simple average of the month-end amounts. Gain (Loss) on Sale of Assets The following table sets forth Birchcliff’s gain (loss) on its sale of assets for the Reporting Periods and the Comparable Prior Periods: Three months ended December 31, Twelve months ended December 31, 2017 2016 2017 2016 Gain (loss) on sale of assets ($000s) 13,705 ($/boe) ($000s) ($/boe) ($000s) ($/boe) ($000s) 1.86 945 0.17 (186,143) (7.50) (9,489) ($/boe) (0.53) On October 2, 2017, Birchcliff completed the Progress Disposition for cash consideration of $31.7 million before closing adjustments. As a result of the disposition, Birchcliff recorded a gain on the sale of assets of approximately $13.7 million ($10.0 million, net of tax) in the three month Reporting Period. On August 31, 2017, Birchcliff completed the Worsley Disposition for consideration of $100 million, before closing adjustments. As a result of the disposition, Birchcliff recorded a loss on the sale of assets of approximately $181.3 million ($132.3 million, net of tax) in the twelve month Reporting Period. 60 Birchcliff Energy Ltd. In May 2017, Birchcliff completed the disposition of certain miscellaneous petroleum and natural gas properties and related assets and interests in the Progress area. The cash consideration was $6.0 million, before closing adjustments. As a result of the disposition, Birchcliff recorded a loss on the sale of assets of approximately $19.8 million ($14.4 million, net of tax) in the twelve month Reporting Period. In April 2017, Birchcliff completed the dispositions of certain miscellaneous petroleum and natural gas properties and related assets and interests in each of the Valhalla, Gordondale and Rycroft areas. The cash consideration was approximately $4.3 million, before closing adjustments. As a result of the dispositions, Birchcliff recorded a loss on the sale of assets of approximately $1.2 million ($0.9 million, net of tax) in the twelve month Reporting Period. In March 2017, Birchcliff completed the dispositions of certain miscellaneous petroleum and natural gas properties and related assets and interests in each of the Elmworth and Rycroft areas. The cash consideration was $0.3 million, before closing adjustments. As a result of the dispositions, Birchcliff recorded a gain on the sale of assets of approximately $0.7 million ($0.5 million, net of tax) in the twelve month Reporting Period. In February 2017, Birchcliff completed the disposition of certain assets in the Gold Creek area of Alberta for cash consideration of approximately $5.0 million. As a result of the disposition, Birchcliff recorded a gain on the sale of assets of approximately $1.8 million ($1.3 million, net of tax) in the twelve month Reporting Period. Income Taxes The components of the Corporation’s income tax expense (recovery) for the Reporting Periods and the Comparable Prior Periods are set forth in the table below: ($000s) Deferred income tax expense (recovery) Dividend income tax expense on preferred shares Income tax expense (recovery) Income tax expense (recovery) per boe Three months ended December 31, Twelve months ended December 31, 2017 9,631 767 10,398 $1.42 2016 4,433 750 5,183 $0.92 2017 (16,906) 3,020 (13,886) ($0.54) 2016 (9,126) 3,000 (6,126) ($0.34) Birchcliff recorded a deferred income tax expense of $9.6 million for the three month Reporting Period as compared to a deferred income tax expense of $4.4 million in the three month Comparable Prior Period. 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. Birchcliff had a deferred income tax recovery in the twelve month Reporting Period of $16.9 million as compared to a deferred income tax recovery of $9.1 million in the twelve month Comparable Prior Period. The increase in deferred income tax recovery from the twelve month Comparable Prior Period was a result of a larger net loss before tax position recorded in the twelve month Reporting Period. The Corporation’s estimated income tax pools were $2.1 billion at December 31, 2017. 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) (1) Excludes Veracel tax pools of $39.3 million which were reassessed by the Canada Revenue Agency. Tax pools as at December 31, 2017 471,352 352,028 277,215 350,115 610,920 19,010 2,080,640 61 2017 Annual Report 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 tax pools in dispute totalled $39.3 million. Birchcliff appealed the Reassessment to the Tax Court of Canada (the “Trial Court”) and the trial of that appeal occurred in November 2013. On October 1, 2015, the Trial Court issued its decision (the “Trial Decision”) and dismissed Birchcliff’s appeal on the basis of the general anti-avoidance rule contained in the Income Tax Act (Canada). The Trial Decision was rendered by a judge based on the written record and not by the judge who conducted the trial. As a result of the Trial Decision, Birchcliff recorded a non-cash deferred income tax expense in the amount of $10.2 million in the fourth quarter of 2015. Birchcliff appealed the Trial Decision to the Federal Court of Appeal (the “FCA”), which appeal was heard in January 2017. On April 28, 2017, the FCA issued its decision and allowed the appeal and set aside the Trial Decision, based on the lack of jurisdiction by the judge who rendered the Trial Decision. In setting aside the Trial Decision, the FCA referred the matter back to the judge of the Trial Court who initially conducted the trial in 2013 to render a judgement. The judge of the Trial Court rendered a decision in November 2017 and dismissed the Corporation’s appeal. The Corporation has appealed that decision to the FCA. CAPITAL EXPENDITURES The following table sets forth a summary of the Corporation’s capital expenditures for the Reporting Periods and the Comparable Prior Periods: ($000s) Land Seismic Workovers Drilling and completions Well equipment and facilities Finding and development capital Acquisitions Dispositions(1) Finding, development and acquisition capital Administrative assets Capital expenditures, net Three months ended December 31, Twelve months ended December 31, 2017 286 515 3,328 35,457 9,734 49,320 58 2016 1,057 253 1,770 40,039 17,597 60,716 1,958 2017 1,700 1,435 10,279 269,142 132,429 414,985 2016 4,529 1,203 3,809 89,111 66,839 165,491 999 614,273 (31,159) (1,473) (141,690) (20,720) 18,219 450 61,201 274,294 759,044 1,281 1,831 2,986 18,669 62,482 276,125 762,030 (1) For further information regarding dispositions in the Reporting Periods, please see “Gain (Loss) on Sale of Assets” in this MD&A. In the three month Reporting Period, Birchcliff had total capital expenditures of $49.8 million (finding and development capital plus administrative assets) and net capital expenditures of $18.7 million (net of acquisitions and dispositions). During the three month Reporting Period, Birchcliff incurred finding and development capital of $49.3 million which included approximately $22.9 million (46%) on the drilling and completion of Montney/Doig horizontal wells in Pouce Coupe and $7.9 million (16%) on the drilling and completion of Montney horizontal wells in Gordondale. Net capital expenditures in the three month Reporting Period included the Progress Disposition for cash consideration of $31.7 million, before closing adjustments. In the three month Reporting Period, Birchcliff drilled 2 (2.0 net) wells, both of which were Montney/Doig horizontal natural gas wells in the Pouce Coupe area. In the twelve month Reporting Period, Birchcliff had total capital expenditures of $416.8 million (finding and development capital plus administrative assets) and net capital expenditures of $276.1 million (net of acquisitions and dispositions), which is 3% above and 5% above, respectively, the Corporation’s previous guidance of $404 million total capital expenditures and $262 million net capital expenditures. Birchcliff’s total finding and development capital in the twelve month Reporting Period was $415.0 million which included approximately $157.4 million (38%) on the drilling and completion of Montney/Doig horizontal wells in Pouce Coupe, $100.3 million (24%) on the drilling and completion of Montney horizontal wells in Gordondale, $29.7 million (7%) on the Phase V expansion of the Pouce Coupe Gas Plant (which came on-stream in the third quarter of 2017) primarily on field construction and $26.7 million (6%) on the Phase VI expansion of the Pouce Coupe Gas Plant (expected to come on-stream in October 2018) primarily on engineering, procurement and fabrication. Dispositions in the twelve month Reporting Period included the Worsley Disposition and the Progress Disposition for total consideration of approximately $131.7 million before closing adjustments. Total consideration for all dispositions completed in 2017 was approximately $148 million before closing 62 Birchcliff Energy Ltd. adjustments. In the twelve month Reporting Period, Birchcliff drilled a total of 54 (54.0 net) wells consisting of 37 (37.0 net) Montney/Doig horizontal natural gas wells drilled in the Pouce Coupe area, 16 (16.0 net) Montney horizontal oil and natural gas wells drilled in the Gordondale area and 1 (1.0 net) Montney/Doig vertical science and technology well drilled in the Pouce Coupe area. The remaining capital during the Reporting Periods was primarily attributed to land, seismic, infrastructure expansion projects and minor acquisitions and dispositions in the Montney/Doig Resource Play and on other oil and gas exploration and development projects in the Peace River Arch. CAPITAL RESOURCES AND LIQUIDITY Liquidity and Capital Resources The Corporation generally relies on its adjusted funds flow and available credit under its existing credit facilities to fund its capital requirements, including its dividend payments. In addition, the Corporation may from time to time seek additional capital in the form of debt and/or equity or dispose of non-core properties to fund its on-going capital expenditure programs and protect its balance sheet. The following table sets forth a summary of the Corporation’s capital resources for the Reporting Periods and the Comparable Prior Periods: ($000s) Adjusted funds flow Changes in non-cash working capital from operations Decommissioning expenditures Exercise of stock options Issue of common shares Share issue costs Financing fees paid on credit facilities Dividends paid on common shares Dividends paid on preferred shares Net change in revolving term credit facilities Deposit on acquisition Changes in non-cash working capital from investing Capital resources Three months ended December 31, Twelve months ended December 31, 2017 97,008 (7,920) (93) 27 - - - (6,644) (1,922) 2016 2017 71,806 317,680 19,248 (29,226) (480) 6,060 51 (8) (794) 9,350 - - - - (2,375) (26,522) 2016 147,443 (5,586) (1,343) 7,597 690,801 (27,589) (795) - (1,875) (7,547) (7,500) 1,479 (62,269) 15,783 (49,540) - - - (63,225) 29,949 9,780 (1,206) 9,738 18,710 62,482 286,129 762,020 Birchcliff’s adjusted funds flow depends on a number of factors, including, but not limited to, commodity prices, production and sales volumes, royalties, operating expenses and foreign exchange rates. The Corporation has been closely monitoring commodity prices and its capital spending and in response to continued low and volatile commodity prices, has taken proactive measures with a view to ensuring liquidity and financial flexibility in the current environment. Birchcliff’s market diversification initiatives during 2017 have helped to reduce its exposure to volatility in commodity prices, including AECO prices which have been extremely volatile in recent months. During 2017, Birchcliff entered into agreements with TCPL for the firm service transportation of an aggregate of 175,000 GJ/d (approximately 152 MMcf/d) of natural gas on TCPL’s Canadian Mainline for a 10-year term, whereby natural gas is transported from the Empress receipt point in Alberta to the Dawn trading hub located in Southern Ontario. During 2018, the Corporation expects that approximately 34% of its 2018 forecast annual average natural gas production will be sold at prices that are not based on AECO, with 30% being sold at the Dawn daily index price and 4% being marketed via the Alliance pipeline system. After taking into account Birchcliff’s forecasted oil and NGLs production in 2018, approximately 48% of the Corporation’s total forecasted corporate production is exposed to AECO pricing, with the remaining 52% of corporate production not exposed to AECO pricing in 2018. Birchcliff continues to actively look for further profitable market diversification opportunities. Birchcliff also has financial swaps for 4,500 bbls/d of crude oil at an average price of CDN$71.87/bbl for 2018. See “2018 Outlook”, “Commodity Price Risk Management” and “Advisories” in this MD&A for further details. 63 2017 Annual Report In May 2017, Birchcliff’s syndicate of lenders completed its semi-annual review of the Corporation’s borrowing base limit under the Corporation’s Credit Facilities. In connection with such review, the Corporation and the lenders agreed to an extension of the maturity dates from May 11, 2018 to May 11, 2020 and to the borrowing base remaining unchanged at $950 million. In November 2017, Birchcliff’s syndicate of lenders completed its semi-annual review of Birchcliff’s borrowing base and agreed to the borrowing base remaining unchanged at $950 million. The 2018 Capital Program is set at $255 million with approximately $149.9 million allocated for drilling and development and $66.9 million for facilities and infrastructure. Birchcliff expects that its 2018 capital expenditures will be less than its adjusted funds flow during 2018 based on the assumptions set forth in the table under the heading “2018 Outlook”. Management believes that its adjusted funds flow during 2018 will be sufficient to fund the Corporation’s 2018 Capital Program. Should commodity prices deteriorate materially, Birchcliff may adjust its on-going capital program, draw down on its Credit Facilities, seek additional equity financing and/or consider the potential sale of additional non-core assets to fund planned growth. The 2018 Capital Program has been designed with financial and operational flexibility with the potential to accelerate or decelerate capital expenditures throughout the year, depending on commodity prices and industry conditions. See “Advisories”. Working Capital The Corporation’s adjusted working capital deficit decreased to $11.1 million at December 31, 2017 from a $27.5 million deficit at December 31, 2016. The deficit at the end of the Reporting Period is largely comprised of costs incurred from the drilling and completion of new wells. At December 31, 2017, the major component of Birchcliff’s current assets was revenue to be received from its marketers in respect of December 2017 production (83%), which was subsequently received in January 2018. In contrast, current liabilities largely consisted of trade payables (56%) and accrued capital and operating costs (24%). Birchcliff routinely assesses the financial strength of its marketers. At this time, Birchcliff expects that such counterparties will be able to meet their financial obligations. Adjusted working capital includes items expected for normal operations, including trade receivables and payables, accruals, deposits and prepaid expenses, and excludes the fair value of financial instruments. The Corporation’s adjusted working capital varies from quarter to quarter primarily due to the timing of such items, as well as due to the size and timing of the Corporation’s capital expenditures, volatility in commodity prices and changes in revenue, among other things. Birchcliff manages any adjusted working capital deficit using adjusted funds flow and advances under its Credit Facilities. Any adjusted working capital deficit position will not reduce the amount available under the Credit Facilities. Bank Debt Management of debt levels continues to be a priority for Birchcliff given its long-term growth plans and the current volatility in the commodity price environment. As of December 31, 2017, 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 each of the Syndicated Credit Facility and the Working Capital Facility is May 11, 2020. 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 $598.2 million at December 31, 2017 as compared to $600.0 million at December 31, 2016. The decrease in total debt to $598.2 million at December 31, 2017 as compared to $600.0 million at December 31, 2016 is due to increased adjusted funds flow and the proceeds realized from the various dispositions completed during the twelve month Reporting Period, partially offset by finding and development capital spent in the twelve month Reporting Period. 64 Birchcliff Energy Ltd. The following table sets forth the Corporation’s unused Credit Facilities as at December 31, 2017 and 2016: As at, ($000s) Maximum borrowing base limit: Revolving term credit facilities Principal amount utilized: Drawn revolving term credit facilities(1) Outstanding letters of credit(2) Unused credit % unused credit December 31, 2017 December 31, 2016 950,000 950,000 (594,823) (580,770) (12,184) (12,310) (607,007) (593,080) 342,993 36% 356,920 38% (1) The drawn amounts are not reduced for unamortized costs and fees applicable to the Credit Facilities. (2) Letters of credit are issued to various service providers. The letters of credit reduce the amount available under the Working Capital Facility from $50 million to approximately $37 million. There were no amounts drawn on the letters of credit during the Reporting Periods and Comparable Prior Periods. 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, 2017: ($000s) Accounts payable and accrued liabilities Drawn revolving term credit facilities Operating leases(1) Capital commitments(2) Firm transportation, processing and fractionation(3) Estimated contractual obligations(4) 2018 83,039 - 3,222 14,208 152,839 253,308 2019 2020-2022 Thereafter - - 4,491 - 125,800 130,291 - 594,823 13,790 - 457,554 1,066,167 - - 24,661 - 370,455 395,116 (1) 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 $46.2 million, which includes costs allocated to base rent, parking and building operating expenses. The office lease commitment amounts disclosed in the above table have not been reduced for any rents receivable by the Corporation. (2) Includes drilling commitments and facility spending commitments relating to the Phase VI expansion of the Pouce Coupe Gas Plant. (3) Includes the impacts from firm service transportation agreements on TCPL’s Canadian Mainline to the Dawn trading hub. The Corporation has negotiated firm service for a 10-year period which commenced in November 2017. See “2018 Outlook” in this MD&A. (4) Contractual obligations and commitments that are not material to Birchcliff are excluded from the above table. The Corporation’s decommissioning obligations are excluded from the table as these obligations arose from a regulatory requirement rather than from a contractual arrangement. Birchcliff estimates the total undiscounted cash flow to settle its decommissioning obligations on its wells and facilities at December 31, 2017 to be approximately $270 million and are estimated to be incurred as follows: 2018 - $1.6 million, 2019 - $1.0 million and $267.4 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 September 30, 2020, have not been included in this table as they are not contractual obligations of the Corporation at the end of the Reporting Period. Upon receipt of a notice of redemption, the Corporation has an obligation to redeem the Series C Preferred Shares, at its option, for cash or common shares. 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 Period and Comparable Prior Period. 65 2017 Annual Report OUTSTANDING SHARE INFORMATION At March 13, 2018, Birchcliff had common shares, Series A Preferred Shares and Series C Preferred Shares that were outstanding. Birchcliff’s common shares are listed on the TSX under the symbol “BIR” and are included in the S&P/TSX Composite Index. Birchcliff’s Series A Preferred Shares and Series C Preferred Shares are individually listed on the TSX under the symbols “BIR.PR.A” and “BIR.PR.C”, respectively. The following table sets forth the common shares issued by the Corporation: Balance at December 31, 2015 Exercise of options Issuance of common shares Balance at December 31, 2016 Exercise of options Balance at December 31, 2017 Exercise of options Balance at March 13, 2018 Common shares 152,307,539 1,209,363 110,525,000 264,041,902 1,754,796 265,796,698 - 265,796,698 At March 13, 2018, the Corporation had the following securities outstanding: 265,796,698 common shares; 2,000,000 Series A Preferred Shares; 2,000,000 Series C Preferred Shares; 16,997,406 stock options to purchase an equivalent number of common shares; and 2,939,732 performance warrants to purchase an equivalent number of common shares. Dividends The following table sets forth the dividend distributions by the Corporation for each class of shares for the Reporting Periods and the Comparable Prior Periods: Common shares: Dividend distribution (000s) Per common share ($) Preferred shares - Series A: Series A dividend distribution (000s)(1) Per Series A preferred share ($)(1) Preferred shares - Series C: Series C dividend distribution (000s) Per Series C preferred share ($) Three months ended December 31, Twelve months ended December 31, 2017 2016 2017 2016 6,644 0.0250 1,047 0.5234 875 0.4375 - - 1,000 0.5000 875 0.4375 26,522 0.1000 4,047 2.0234 3,500 1.7500 - - 4,000 2.0000 3,500 1.7500 (1) On September 30, 2017, the annual fixed dividend rate for the Series A Preferred Shares was reset to 8.374%. Subject to the terms and conditions of the Series A Preferred Shares and Birchcliff’s right to redeem such shares, the dividend rate will reset on September 30, 2022 and every five years thereafter at a rate equal to the sum of the then five-year Government of Canada bond yield plus 6.83%. All dividends have been designated as “eligible dividends” for the purposes of the Income Tax Act (Canada). 66 Birchcliff Energy Ltd. Normal Course Issuer Bid On November 15, 2017, Birchcliff announced that the TSX had accepted the Corporation’s notice of intention to make a normal course issuer bid (the “NCIB”). Pursuant to the NCIB, Birchcliff may purchase up to 20,121,747 of its outstanding common shares. The total number of common shares that Birchcliff is permitted to purchase is subject to a daily purchase limit of 280,426 common shares; provided, however, that the Corporation may make one block purchase per calendar week which exceeds the daily purchase restriction. The NCIB commenced on November 20, 2017 and will terminate on November 19, 2018, or such earlier time as the NCIB is completed or is terminated at the option of Birchcliff. Purchases under the NCIB will be effected through the facilities of the TSX and/or Canadian alternative trading systems at the prevailing market price at the time of such transaction. All common shares purchased under the NCIB will be cancelled. As at the date of this MD&A, Birchcliff has not purchased any common shares pursuant to the NCIB. A security holder of the Corporation may obtain, for no charge, a copy of the notice in respect of the NCIB filed with the TSX by contacting the Corporation at 403-261-6401. SUMMARY OF QUARTERLY RESULTS The following table sets forth a summary of the Corporation’s quarterly results for the eight most recently completed quarters: Quarter ending, Dec. 31, 2017 Sep. 30, 2017 Jun. 30, 2017 Mar. 31, 2017 Dec. 31, 2016 Sep. 30, 2016 Jun. 30, 2016 Mar. 31, 2016 Average daily production (boe) 80,103 65,276 64,636 61,662 60,750 54,538 39,513 41,958 Realized natural gas sales price ($/Mcf)(1) Realized oil sales price ($/bbl)(1) 2.64 68.58 2.11 3.13 55.62 60.38 3.06 62.59 3.31 60.75 2.53 52.12 1.48 51.20 1.99 36.93 Total revenues ($000s)(1) Operating costs ($/boe) 166,149 111,488 146,597 132,708 135,457 97,365 47,261 57,503 3.86 4.27 4.67 5.22 4.54 4.65 Capital expenditures, net ($000s) 18,669 12,136 120,782 124,538 62,482 599,715 Cash flow from operating activities ($000s) 88,995 70,584 57,467 70,614 90,574 Adjusted funds flow ($000s) 97,008 64,430 88,612 67,630 71,806 Per common share – basic ($) Per common share – diluted ($) 0.36 0.36 0.24 0.24 0.33 0.33 0.26 0.25 0.27 0.27 22,144 41,675 0.18 0.18 3.45 4,722 7,049 3.71 63,860 20,747 13,267 20,695 0.09 0.09 0.14 0.13 Net income (loss) ($000s) 25,820 (120,743) 18,015 29,928 12,085 (1,064) (23,321) (12,035) Net income (loss) to common shareholders ($000s)(2) 24,773 (121,743) 17,015 28,928 11,085 (2,064) (24,321) (13,035) Per common share – basic ($) Per common share – diluted ($) Total assets ($ million) 0.09 0.09 2,627 (0.46) (0.46) 2,615 0.06 0.06 2,871 0.11 0.11 2,797 0.04 0.04 2,710 (0.01) (0.01) 2,704 (0.16) (0.16) 2,059 (0.09) (0.09) 2,053 Long-term bank debt ($000s) 587,126 585,323 628,401 578,954 572,517 634,534 709,510 647,359 Total debt ($000s) 598,193 666,808 700,484 664,352 600,012 612,080 715,651 690,138 Dividends on common shares ($000s)(3) Dividends on pref. shares – Series A ($000s) Dividends on pref. shares – Series C ($000s) Pref. shares outstanding – Series A (000s) Pref. shares outstanding – Series C (000s) Common shares outstanding (000s) 6,644 1,047 875 2,000 2,000 6,635 1,000 875 2,000 2,000 6,635 1,000 875 2,000 2,000 6,604 1,000 875 2,000 2,000 - 1,000 875 2,000 2,000 - 1,000 875 2,000 2,000 - 1,000 875 2,000 2,000 - 1,000 875 2,000 2,000 Basic Diluted 265,797 265,789 265,417 264,442 264,042 263,065 152,308 152,308 282,895 283,106 284,461 284,160 279,881 279,826 169,089 169,239 Wtd. average common shares outstanding (000s) Basic Diluted 265,792 265,490 265,326 264,099 263,396 229,287 152,308 152,308 267,619 267,988 268,203 268,077 268,974 234,295 154,279 153,418 (1) Excludes the effects of financial hedges using financial instruments but includes the effects of fixed price physical delivery contracts. (2) Reduced for the Series A Preferred Share dividends paid in the period. (3) Birchcliff paid its first common share dividend in the first quarter of 2017. 67 2017 Annual Report Average daily production volumes in the last six quarters has increased largely due to incremental production volumes from both the assets acquired in Gordondale and new horizontal wells brought on-stream in Pouce Coupe and Gordondale, partially offset by natural production declines from those wells. Quarterly variances in revenues, adjusted funds flow and net income are primarily due to fluctuations in commodity prices and production volumes. Oil and gas revenues and adjusted funds flow in the last six quarters were largely impacted by incremental production from the assets acquired in Gordondale in the third quarter of 2016 and, except for the third quarter of 2017, higher trending average realized sales prices. Birchcliff had net income in the three month Reporting Period primarily in response to increases in adjusted funds flow. Birchcliff recorded a net loss in the third quarter of 2017 primarily as a result of the after-tax book loss of $132.3 million from the Worsley Disposition. Net income or loss in the last eight quarters was also impacted by certain non-cash adjustments including depletion expense, unrealized gains and losses on financial instruments and gains and losses on the sale of 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. In the third quarter of 2016, Birchcliff completed the Gordondale Acquisition which significantly increased net capital expenditures in that quarter in comparison to the other quarters. Birchcliff paid a common share dividend of $6.6 million or $0.025 per common share in each of the quarters ending March 31, 2017, June 30, 2017, September 30, 2017, and December 31, 2017. In connection with the Gordondale Acquisition, Birchcliff issued a total of 110,520,000 common shares in the third quarter of 2016 which increased both the number of common shares and the weighted average common shares outstanding at the end of the period compared to the previous quarters. Quarterly variances in long-term debt and total debt are primarily due to fluctuations in adjusted funds flow, the amount and timing of capital expenditures (including acquisitions and dispositions) and the timing of proceeds received from equity financings in a period. The fluctuations in long-term debt and total debt in the last five quarters have been primarily impacted by the net proceeds from the equity financings in the third quarter of 2016 (after the payment of the balance of the purchase price for the assets in Gordondale) and the proceeds from the Worsley Disposition and the Progress Disposition which were used to initially reduce indebtedness under the Credit Facilities. POTENTIAL TRANSACTIONS Within its focus area, the Corporation is continually reviewing potential asset acquisitions and dispositions and corporate mergers and acquisitions for the purpose of determining whether any such potential transaction is of interest to the Corporation, as well as the terms on which such a potential transaction would be available. As a result, the Corporation may from time to time be involved in discussions or negotiations with other parties or their agents in respect of potential asset acquisitions and dispositions and corporate merger and acquisition opportunities. 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, 2017 and have concluded that the Corporation’s DC&P were effective at December 31, 2017. 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. 68 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, 2017 and have concluded that the Corporation’s ICFR was effective at December 31, 2017. There were no changes in the Corporation’s ICFR that occurred during the period beginning on October 1, 2017 and ended on December 31, 2017 that have materially affected, or are reasonably likely to materially affect, the Corporation’s ICFR. While the Certifying Officers believe that the Corporation’s ICFR provides a reasonable level of assurance and is effective, they do not expect that the ICFR will prevent all errors and fraud. A control system, no matter how well conceived, maintained and operated, can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met. CRITICAL ACCOUNTING ESTIMATES The preparation of the financial statements requires management to make judgments, estimates and assumptions that affect the application of IFRS accounting policies, reported amounts of assets and liabilities and income and expenses. Accordingly, actual results may differ from these estimates. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected. Critical Judgments in Applying Accounting Policies: The following are the critical judgments that management has made in the process of applying the Corporation’s accounting policies and that have the most significant effect on the amounts recognized in these financial statements: Identification of Cash-Generating Units Birchcliff’s assets are required to be aggregated into CGUs for the purpose of calculating impairment based on their ability to generate largely independent cash inflows. CGUs have been determined based on similar geological structure, shared infrastructure, geographical proximity, operating structure, commodity type and similar exposures to market risks. By their nature, these assumptions are subject to management’s judgment and may impact the carrying value of the Corporation’s assets in future periods. Identification of Impairment Indicators IFRS requires Birchcliff to assess, at each reporting date, whether there are any indicators that its petroleum and natural gas assets may be impaired. Birchcliff is required to consider information from both external sources (such as negative downturn in commodity prices, significant adverse changes in the technological, market, economic or legal environment in which the entity operates) and internal sources (such as downward revisions in reserves, significant adverse effects on the financial and operational performance of a CGU, evidence of obsolescence or physical damage to the asset). By their nature, these assumptions are subject to management’s judgment. Tax Uncertainties IFRS requires Birchcliff, at each reporting date, to make certain judgments on uncertain tax positions by relevant tax authorities. Judgments include determining whether the Corporation will “more likely than not” be successful in defending its tax positions by considering information from relevant tax interpretations and tax laws in Canada. As such, this recognition threshold is subject to management’s judgment and may impact the carrying value of the Corporation’s deferred tax assets and liabilities at the end of the reporting period. 69 2017 Annual Report Key Sources of Estimation Uncertainty: The following are the key assumptions concerning the sources of estimation uncertainty at the end of the reporting period, that have a significant risk of causing adjustments to the carrying amounts of assets and liabilities within the next financial year: Reserves Reported recoverable quantities of proved and probable reserves requires estimation regarding production profile, commodity prices, exchange rates, remediation costs, timing and amount of future development costs, and production, transportation and marketing costs for future cash flows. It also requires interpretation of geological and geophysical models in order to make an assessment of the size, shape, depth and quality of reservoirs, and their anticipated recoveries. The economical, geological and technical factors used to estimate reserves may change from period to period. Changes in reported reserves can impact the carrying values of the Corporation’s petroleum and natural gas properties and equipment, the calculation of depletion and depreciation, the provision for decommissioning obligations, and the recognition of deferred tax assets due to changes in expected future cash flows. The recoverable quantities of reserves and estimated cash flows from Birchcliff’s petroleum and natural gas interests are independently evaluated by reserve engineers at least annually. The Corporation’s petroleum and natural gas reserves represent the estimated quantities of petroleum, natural gas and NGLs which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be economically recoverable in future years from known reservoirs and which are considered commercially producible. Such reserves may be considered commercially producible if management has the intention of developing and producing them and such intention is based upon: (i) a reasonable assessment of the future economics of such production; (ii) a reasonable expectation that there is a market for all or substantially all the expected petroleum and natural gas production; and (iii) evidence that the necessary production, transmission and transportation facilities are available or can be made available. Reserves may only be considered proved and probable if producibility is supported by either production or conclusive formation tests. Birchcliff’s oil and gas reserves are determined in accordance with the standards contained in National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) and the Canadian Oil and Gas Evaluation Handbook (the “COGE 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. 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 70 Birchcliff Energy Ltd. 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. FUTURE ACCOUNTING PRONOUNCEMENTS In May 2014, the IASB issued IFRS 15: Revenue From Contracts With Customers (“IFRS 15”) 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 will be adopting IFRS 15 on January 1, 2018. The Corporation has substantially completed its assessment and evaluation of the underlying terms of its revenue contracts with customers and has determined that the adoption of the standard will not have a material impact on the Corporation’s net income. In July 2014, the IASB issued the final version of IFRS 9: Financial Instruments (“IFRS 9”) 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. Birchcliff has determined that the adoption of IFRS 9 will result in changes to the Corporation’s investments in securities which, upon adoption of IFRS 9, will be measured at fair value through profit or loss. In January 2016, the IASB issued IFRS 16: Leases (“IFRS 16”). The standard will be effective for annual periods beginning on or after January 1, 2019. Early adoption is permitted, provided IFRS 15 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. 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 and financial condition 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 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, to export oil and liquefied natural gas and NGLs from North America; the availability, proximity and capacity of gathering, transportation, processing and/or refining facilities in regional or localized areas that may affect the realized price for oil and natural gas; 71 2017 Annual Report • 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, increased growth of shale oil production in the United States and other concerns of over-supply, OPEC actions, sanctions imposed on certain oil producing nations by other countries 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 cash flows from operations and may have a material adverse effect on the Corporation’s business, financial condition, results of operations, prospects, its ability to pay dividends and ultimately on the market prices of the Corporation’s securities. Lower commodity prices may also affect the volume and value of the Corporation’s reserves, rendering certain reserves uneconomic. The Corporation’s reserves at December 31, 2017 are estimated using forecast prices and costs. 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. Any decrease in the value of the Corporation’s reserves may reduce the borrowing base under the Credit Facilities, which, depending on the level of the Corporation’s indebtedness, could result in the Corporation having to repay a portion of its indebtedness. See “Risk Factors – Financial Risks and Risks Relating to Economic Conditions – Credit Facilities”. In addition, lower commodity prices restrict the Corporation’s cash flow resulting in less funds from operations being available to fund the Corporation’s capital expenditure programs. The Corporation’s capital expenditure plans are impacted by the Corporation’s cash flow. Consequently, the Corporation may not be able to replace its production with additional reserves and both the Corporation’s production and reserves could be reduced on a year-over-year basis. In addition to possibly resulting in a decrease in the value of the Corporation’s economically recoverable reserves, lower commodity prices may also result in a decrease in the value of the Corporation’s infrastructure and facilities, all of which could also have the effect of requiring a write down of the carrying value of its oil and gas assets on its balance sheet and the recognition of an impairment charge on its income statement. Weakness in the Oil and Natural Gas Industry Recent market events and conditions, including global excess oil and natural gas supply, actions taken by OPEC, slowing growth in 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 natural gas companies and a decrease in the confidence in the oil and natural gas industry. These difficulties have been exacerbated in Canada by political and other actions resulting in uncertainty surrounding regulatory, tax, royalty changes and environmental regulation. In addition, the inability to get the necessary approvals to build pipelines, liquefied natural gas plants and other facilities to provide better access to markets for the oil and natural gas industry in Western Canada has led to additional downward price pressure on oil and gas produced in Western Canada and uncertainty and reduced confidence in the oil and natural gas industry in Western Canada. Given the current market conditions and the lack of confidence in the Canadian oil and natural gas industry, the Corporation may have difficulty raising additional funds or if it is able to do so, it may be on unfavourable and highly dilutive terms. 72 Birchcliff Energy Ltd. Substantial Capital and Additional Funding Requirements The Corporation anticipates that it will make substantial capital expenditures for the acquisition, exploration development and production of oil and natural gas reserves and resources in the future. As future capital expenditures are expected to be financed out of cash generated from operations, borrowings and possible future equity sales, the Corporation’s ability to do so is dependent on, among other factors: • • the overall state of the capital markets; the Corporation’s credit rating (if applicable); • commodity prices; • • • • interest rates; royalty rates; tax burden due to current and future tax laws; and investor appetite for investments in the energy industry and the Corporation’s securities in particular. The Corporation’s cash flow from its properties may not be sufficient to fund its ongoing activities at all times and from time to time the Corporation may require additional financing. The inability of the Corporation to access sufficient capital for its operations and activities could have a material adverse effect on the Corporation’s financial condition, results of operations and prospects. Due to the conditions in the oil and natural gas industry and/or global economic and political volatility, the Corporation may from time to time have restricted access to capital and increased borrowing costs. The 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 financing on a timely basis could cause the Corporation to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce or terminate its operations. There can be no assurance that debt or equity financing or cash generated by operations will be available or sufficient to meet the Corporation’s requirements or, if debt or equity financing is available, that it will be on terms acceptable to the Corporation. To the extent that external sources of capital become limited, unavailable or available on onerous terms, the Corporation’s ability to make capital investments and maintain existing assets may be impaired, and its assets, liabilities, business, financial condition and results of operations may be affected materially and adversely as a result. In addition, the future development of the Corporation’s petroleum properties may require additional financing and there are no assurances that such financing will be available or, if available, will be available upon acceptable terms. The Corporation may be required to seek additional equity financing on terms that are highly dilutive to existing shareholders. Moreover, future activities may require the Corporation to alter its capitalization significantly. 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. Credit Facilities The amount authorized under the Credit Facilities is dependent on the borrowing base determined by the Corporation’s lenders. The Credit Facilities are subject to a semi-annual review of the borrowing base limit by Birchcliff’s syndicate of lenders, which limit is directly impacted by the value of Birchcliff’s oil and natural gas reserves. The Corporation’s lenders use the Corporation’s reserves, commodity prices and other factors to determine the Corporation’s borrowing base. Commodity prices continue to be depressed and have fallen dramatically since 2014. Continued depressed commodity prices or further declines in commodity prices could result in a reduction in the Corporation’s borrowing base, thereby reducing the funds available to the Corporation under the Credit Facilities. As the borrowing base is determined based on the lender’s interpretation of the Corporation’s reserves and future commodity prices, there can be no assurance as to the amount of the borrowing base determined at each review. In addition, 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, 73 2017 Annual Report 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, 2020. 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 a default under the Credit Facilities, which could result in the Corporation being required to repay amounts owing thereunder. The acceleration of the Corporation’s indebtedness under one agreement may permit acceleration of indebtedness under other agreements that contain cross-default or cross-acceleration provisions. In addition, the Credit Facilities impose certain restrictions on the Corporation, including, but not limited to, restrictions on the payment of dividends, incurring of additional indebtedness, dispositions of properties and the entering into of amalgamations, mergers, plans of arrangements, reorganizations or consolidations with any person. The Credit Facilities do not currently contain any financial maintenance covenants; however, there is no assurance that the lenders may not impose any such covenants on the Corporation in the future. Any such covenants may either affect the availability or price of additional funding. If the Corporation’s lenders require repayment of all or portion of the amounts outstanding under the Credit Facilities for any reason, including for a default of a covenant, there is no certainty that the Corporation would be in a position to make such repayment. Even if the Corporation is able to obtain new financing in order to make any required repayment under the Credit Facilities, it may not be on commercially reasonable terms or terms that are acceptable to the Corporation. If the Corporation is unable to repay amounts owing under the Credit Facilities, the lenders under the Credit Facilities could proceed to foreclose or otherwise realize upon the collateral granted to them to secure the indebtedness. Dividends The declaration and payment of dividends is subject to the discretion of the 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) (the “ABCA”) for the declaration and payment of dividends and other factors that the Board of Directors may deem relevant. Depending on these and various other factors, many of which are beyond the control of Birchcliff, the dividend policy of the Corporation may vary from time to time and, as a result, future cash dividends could be reduced or suspended entirely. Pursuant to the ABCA, the Corporation may not declare or pay a dividend if there are reasonable grounds for believing that: (i) the Corporation is, or would after the payment be, unable to pay its liabilities as they become due; or (ii) the realizable value of its assets would thereby be less than the aggregate of its liabilities and stated capital of its outstanding shares. Additionally, pursuant to the agreement governing the Credit Facilities, the Corporation is not permitted to make any distribution (which includes dividends) at any time when an event of default exists or would reasonably be expected to exist upon making such distribution, unless such event of default arose subsequent to the ordinary course declaration of the applicable distribution. Dividends may be reduced or suspended during periods of lower cash flows from operations. The timing and amount of Birchcliff’s capital expenditures, and the ability of the Corporation to repay or refinance existing debt as it becomes due, directly affects the amount of cash dividends that may be declared by the Board of Directors. Future acquisitions, expansions of Birchcliff’s assets, and other capital expenditures and the repayment or refinancing of existing debt as it becomes due may be financed from sources such as cash flows from operations, the issuance of additional shares or other securities of Birchcliff, and borrowings. Dividends may be reduced, or even eliminated, at times when significant capital or other expenditures are made. There can be no assurance that sufficient capital will be available on terms acceptable to Birchcliff, or at all, to make additional investments, fund future expansions or make other required capital expenditures. To the extent that external sources of capital, including the issuance of additional shares or other securities or the availability of additional credit facilities, become limited or unavailable on favourable terms or 74 Birchcliff Energy Ltd. at all due to credit market conditions or otherwise, the ability of the Corporation to make the necessary capital investments to maintain or expand its operations, to repay outstanding debt and to invest in assets, as the case may be, may be impaired. To the extent Birchcliff is required to use cash flows from operations to finance capital expenditures or acquisitions or to repay existing debt as it becomes due, the cash available for dividends may be reduced and the level of dividends declared may be reduced. The market value of the Corporation’s securities may deteriorate if dividends are reduced or suspended. Furthermore, the future treatment of dividends for tax purposes will be subject to the nature and composition of dividends paid by Birchcliff and potential legislative and regulatory changes. Hedging 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 or prices fall significantly lower than projected; • • there is a widening of price-basis differentials between delivery points for production and the delivery point assumed in the hedge arrangement; the counterparties to the hedging arrangements or other price risk management contracts fail to perform under those arrangements; and/or • a sudden unexpected 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 or other currencies in order to offset the risk of revenue losses if the Canadian dollar increases in value compared to the other currencies. However, if the Canadian dollar declines in value compared to such fixed currencies, the Corporation will not benefit from the fluctuating exchange rate. 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. 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 the counterparties with whom the Corporation may contract. Please see “Risk Factors – Financial Risks and Risks Relating to Economic Conditions – Hedging”. 75 2017 Annual Report An increase in interest rates could result in a significant increase in the amount the Corporation pays to service debt, resulting in a reduced amount available to fund its exploration and development activities and the cash available for dividends and could negatively impact the market prices of the Corporation’s securities. Business and Operational Risks Exploration, Development and Production Risks Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome. The long-term commercial success of the Corporation depends on its ability to find, acquire, develop and commercially produce oil and natural gas reserves. Without the continual addition of new reserves, any existing reserves the Corporation may have at 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. 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, completing (including hydraulic fracturing), operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. Drilling hazards, environmental damage and various field operating conditions could greatly increase the cost of operations and adversely affect the production from successful wells. Field operating conditions include, but are not limited to, delays in obtaining governmental approvals or consents, the shutting-in 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. 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. Please see “Risk Factors – 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 overruns 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; 76 Birchcliff Energy Ltd. • • • • • • 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 the Corporation’s ability to dispose of water used or removed from strata in accordance with applicable environmental regulations; 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, Pipeline Systems and Rail The Corporation delivers its products through gathering and processing facilities, pipeline systems and, in certain circumstances, by rail. The amount of oil and natural gas that the Corporation can produce and sell is subject to the accessibility, availability, proximity and capacity of these gathering and processing facilities, pipeline systems and railway lines. The lack of availability of capacity in any of the gathering and processing facilities, pipeline systems and railway lines could result in the Corporation’s inability to realize the full economic potential of its production or in a reduction of the price offered for the Corporation’s production. 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 continues to affect the ability to export oil and natural gas. Unexpected shut-downs or curtailment of capacity of pipelines for maintenance or integrity work or because of actions taken by regulators could also affect the Corporation’s production, operations and financial results. As a result, producers are increasingly turning to rail as an alternative means of transportation. In recent years, the volume of crude oil shipped by rail in North America has increased dramatically. Any significant change in market factors or other conditions affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities could harm the Corporation’s business and, in turn, the Corporation’s financial condition, results of operations and cash flows. Announcements and actions taken by the governments of British Columbia and Alberta relating to approvals of infrastructure projects may continue to intensify, leading to increased challenges to interprovincial and international infrastructure projects moving forward. In addition, while the federal government has recently introduced draft legislation to overhaul the existing environmental assessment process and replace the NEB with a new regulatory agency, the impact of the new proposed regulatory scheme on proponents and the timing of receipt of approvals of major projects remains unclear. Following major accidents in Lac-Megantic, Quebec and North Dakota, the Transportation Safety Board of Canada and the U.S. National Transportation Board recommended additional regulations for railway tank cars carrying crude oil. In June 2015, as a result of these recommendations, the Government of Canada passed the Safe and Accountable Rail Act which increased insurance obligations on the shipment of crude oil by rail and imposed a per tonne levy of $1.65 on crude oil shipped by rail to compensate victims and for environmental cleanup in the event of a railway accident. In addition to this legislation, new regulations have implemented the TC-117 standard for all rail tank cars carrying flammable liquids which formalized the commitment to retrofit, and phase out DOT-111 tank cars carrying crude oil. The increased regulation of rail transportation may reduce the ability of railway lines to alleviate pipeline capacity issues and adds additional costs to the transportation of crude oil by rail. On July 13, 2016, the Minister of Transport (Canada) issued Protective Direction No. 38, which directed that the shipping of crude oil on DOT-111 tank cars end by November 1, 2016. Tank cars entering Canada from the United States will be monitored to ensure they are compliant with Protective Direction No. 38. 77 2017 Annual Report The Corporation’s production passes through Birchcliff owned or third-party infrastructure prior to it being ready for sale. There is a risk that should this infrastructure fail and cause a significant portion of the Corporation’s production to be shut-in and unable to be sold, this could have a material adverse effect on the Corporation’s available cash flow. With respect to facilities owned by third parties and over which the Corporation has no control, these facilities may discontinue or decrease operations either as a result of normal servicing requirements or as a result of unexpected events. A discontinuation or decrease of operations could have a material adverse effect on the Corporation’s ability to process its production and deliver the same for sale. Midstream and pipeline companies may take actions to maximize their return on investment which may in turn adversely affect producers and shippers, especially when combined with a regulatory framework that may not always align with the interests of particular shippers. Further, the Corporation has certain long-term take-or-pay transportation commitments to deliver products through third-party owned infrastructure which creates a financial liability and there can be no assurance that future volume commitments will be met which may adversely affect the Corporation’s financial condition and cash flows from operations. Uncertainty of Reserves and Resource 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, production 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, the classification of such reserves based on risk of recovery and estimates of future net revenue associated with reserves prepared by different engineers, or by the same engineer at different times, may vary 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. The estimation of proved reserves that may be developed and produced in the future is often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Recovery factors and drainage areas 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. Such variations could be material. In accordance with applicable securities laws in Canada, the Corporation’s independent qualified reserves evaluators have used forecast prices and costs in estimating the reserves and future net revenue as summarized herein. Actual future net revenue will be affected by other factors such as actual production levels, supply and demand for oil and natural gas, curtailments or increases in consumption by oil and natural gas purchasers, changes in governmental regulations or taxation and the impact of inflation on costs. Actual production and cash flows derived from the Corporation’s reserves will vary from the estimates contained in the Corporation’s independent reserves evaluations and such variations could be material. The independent reserves evaluations are based in part on the assumed success of the Corporation’s forecast operations. The reserves and estimated future net revenue to be derived therefrom and contained in the Corporation’s independent reserves evaluations may be reduced to the extent that such activities do not achieve the level of success assumed in the evaluations. 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. 78 Birchcliff Energy Ltd. 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 for many years, there has been increased focus on the environmental aspects of hydraulic fracturing practices in recent years. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition (including litigation) to oil and natural gas production activities using hydraulic fracturing techniques. Any new laws, regulations or permitting requirements regarding hydraulic fracturing could lead to operational delays, increased operating costs, third-party or governmental claims and could increase the Corporation’s costs of compliance and doing business, as well as delay the development of oil and natural gas resources from certain formations which are not commercial without the use of hydraulic fracturing. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that the Corporation is ultimately able to produce from its reserves and, therefore, could adversely affect the Corporation’s business, financial condition, results of operations and prospects. Potential Future Drilling Locations The Corporation’s identified potential future drilling locations represent a significant part of the Corporation’s future growth. 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 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 that the Corporation 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. Operational Dependence Other companies operate some of the assets in which the Corporation has an interest. The Corporation has limited ability to exercise influence over the operation of those assets or their associated costs, which could adversely affect the Corporation’s business, financial condition, results of operations and prospects. The Corporation’s return on assets operated by others depends upon a number of factors that may be outside of the Corporation’s control, including, but not limited to, the timing and amount of capital expenditures, the operator’s expertise and financial resources, the approval of other participants, the selection of technology and risk management practices. In addition, due to the current low and volatile commodity price environment, many companies, including companies that may operate some of the assets in which the Corporation has an interest, may be in financial difficulty, which could impact their ability to fund and pursue capital expenditures, carry out their operations in a safe and effective manner and satisfy regulatory requirements with respect to abandonment and reclamation obligations. If companies that operate some of the assets in which the Corporation has an interest fail to satisfy regulatory requirements with respect to abandonment and reclamation obligations, the Corporation may be required to satisfy such obligations and to seek recourse from such companies. To the extent that any of such companies go bankrupt, become insolvent or make a proposal or institute any proceedings relating to bankruptcy or insolvency, it could result in such assets being shut-in, the Corporation potentially becoming subject to additional liabilities relating to such assets and the Corporation having difficulty collecting revenue due to it from such operators. Any of these factors could have a material adverse effect on the Corporation’s financial and operational results. 79 2017 Annual Report 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 renewable energy generation devices could reduce the demand for oil, natural gas and liquid hydrocarbons. Recently, certain jurisdictions have implemented policies or incentives to decrease the use of fossil fuels and encourage the use of renewable fuel alternatives, which may lessen the demand for petroleum products and put downward pressure on commodity prices. In addition, advancements in energy efficient products have a similar effect on the demand for oil and natural gas products. The Corporation cannot predict the impact of the changing demand for oil and natural gas products and any major changes may have a material adverse effect on the Corporation’s business, financial condition, results of operations and cash flows by decreasing the Corporation’s profitability, increasing its costs, limiting its access to capital or decreasing the value of its assets. Seasonality and Extreme Weather Conditions The level of activity in the Canadian oil and natural gas industry is influenced by seasonal weather patterns. Wet weather and spring thaw may make the ground unstable. Consequently, municipalities and provincial transportation departments may enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels. Road bans and other restrictions generally result in a reduction of drilling and exploratory activities and may also result in the shut-in of some of the Corporation’s production if not otherwise tied-in. In addition, certain oil and gas producing properties are located in areas that are inaccessible other than during the winter months because the ground surrounding the sites in these areas consists of swampy terrain. In addition, extreme cold weather and heavy snowfall and heavy rainfall may restrict the Corporation’s ability to access its properties and cause operational difficulties, including damage to machinery or dangerous working conditions. Seasonal factors and unexpected weather patterns may lead to declines in exploration and production activity and also to volatility in commodity prices as the demand for natural gas 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. 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. 80 Birchcliff Energy Ltd. 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 Corporation’s exposure to one or more existing risk factors, which may in turn result in the Corporation’s future operational and financial condition being adversely affected. Environmental, Regulatory and Political Risks Political Uncertainty In the last several years, the United States and certain European countries have experienced significant political events that have cast uncertainty on global financial and economic markets. During the 2016 presidential campaign, a number of election promises were made and the American administration has begun taking steps to implement certain of these promises. The administration has announced the withdrawal of the United States from the Trans-Pacific Partnership and Congress has passed sweeping tax reforms, which, among other things, significantly reduces U.S. corporate tax rates. This may affect the competitiveness of other jurisdictions, including Canada. The North American Free Trade Agreement is currently under renegotiation and the result is uncertain at this time. The administration has also taken action with respect to the reduction of regulation which may also affect the relative competitiveness of other jurisdictions. It is unclear exactly what other actions the administration in the United States will implement, and if implemented, how these actions may impact Canada and in particular the oil and natural gas industry. Any actions taken by the American 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 natural gas companies, including the Corporation. In addition to the political disruption in the United States, the citizens of the United Kingdom voted to withdraw from the European Union and the Government of the United Kingdom has 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 as a result, negatively impact the Corporation’s business, operations, financial condition and the market value of the Corporation’s securities. A change in federal, provincial or municipal governments in Canada may have an impact on the directions taken by such governments on matters that may impact the oil and natural gas industry, including the balance between economic development and environmental policy such as the potential impact of the recent change of government in British Columbia and announcements and actions by the Government of British Columbia that may impact the completion of the Trans-Mountain Pipeline project and other infrastructure projects. Geopolitical Risks Political events throughout the world that cause disruptions in the supply of oil and natural gas 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 revenue. In addition, the Corporation’s oil and natural gas properties, wells and facilities could be the subject of a terrorist attack. If any of the Corporation’s properties, wells or facilities are the subject of terrorist attack, it may have a material adverse effect on the Corporation’s business, financial condition, results of operations and prospects. 81 2017 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 the demand for crude oil and natural gas and increase the Corporation’s costs or make certain projects uneconomic, which may have a material adverse effect on the Corporation’s business, financial condition, results of operations and prospects. Recently, the Government of Canada and certain provincial governments have taken steps to initiate protocols and regulations to limit the release of methane from oil and natural gas operations. Such draft regulations and protocols may require additional expenditures or otherwise negatively impact the Corporation’s operations and may affect the Corporation’s revenues. In order to conduct oil and natural gas operations, the Corporation requires regulatory permits, licences, registrations, approvals and authorizations from various governmental authorities. There can be no assurance that the Corporation will be able to obtain all of the permits, licences, registrations, approvals and authorizations that may be required to conduct operations that it may wish to undertake. In addition, the Corporation may have to comply with the requirements of certain federal legislation such as the Competition Act (Canada) and the Investment Canada Act (Canada), which may adversely affect its business and financial condition and the market value of its securities or assets, particularly when undertaking, or attempting to undertake, an acquisition or disposition. Environmental All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial and local laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on the spill, release or emission of various substances produced in association with oil and natural gas industry operations. In addition, such legislation sets out the requirements with respect to oilfield waste handling and storage, habitat protection and the satisfactory operation, maintenance, abandonment and reclamation of well and facility sites. Compliance with environmental legislation can require significant expenditures and a breach of applicable environmental legislation may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require the Corporation to incur costs to remedy such discharge. Although the Corporation believes that it is in material compliance with current applicable environmental legislation, no assurance can be given that environmental 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. Please also see “Risk Factors – Environmental, Regulatory and Political Risks – Climate Change Regulation”. 82 Birchcliff Energy Ltd. Climate Change Regulation The Corporation’s exploration and production facilities and other operations and activities emit GHG which requires the Corporation to comply with applicable GHG emissions legislation. Climate change policy is evolving at regional, national and international levels and political and economic events may significantly affect the scope and timing of climate change measures that are ultimately put in place. As a signatory to the United Nations Framework Convention on Climate Change and the Paris Agreement, the Government of Canada pledged to cut its GHG emissions by 30% from 2005 levels by 2030. One of the pertinent policies announced to date by the Government of Canada to reduce GHG emission is the planned implementation of a nation- wide price on carbon emissions. Provincially, the Government of Alberta has already implemented a carbon levy on almost all sources of GHG emissions, now at a rate of $30 per tonne. The direct or indirect costs of compliance with GHG-related legislation may have a material adverse effect on the Corporation’s business, financial condition, results of operations and prospects. Adverse impacts to the Corporation’s business as a result of GHG legislation may include, but are not limited to, increased compliance costs, permitting delays, increased operating costs and capital expenditures and reduced demand for the oil, natural gas and NGLs that the Corporation produces. In addition, the Pouce Coupe Gas Plant is subject to the Carbon Competitiveness Incentive Regulation (Alberta) and some of the Corporation’s other significant facilities may ultimately become subject to future regional, provincial and/or federal climate change regulations to manage GHG emissions. In addition, concerns about climate change have resulted in a number of environmental activists and members of the public opposing the continued exploitation and development of fossil fuels. Given the evolving nature of the debate related to climate change and the control of GHG and resulting requirements, it is expected that current and future climate change regulations will have the effect of increasing the Corporation’s operating expenses and in the long-term reducing the demand for oil and gas production resulting in a decrease in the Corporation’s profitability and a reduction in the value of its assets or asset write-offs. Carbon Pricing Risk The majority of countries across the globe have agreed to reduce their carbon emissions in accordance with the Paris Agreement. In Canada, the federal and certain provincial governments have implemented legislation aimed at incentivizing the use of alternatives fuels and in turn reducing carbon emissions. The taxes placed on carbon emissions may have the effect of decreasing the demand for oil and natural gas products and at the same time, increasing the Corporation’s operating expenses, each of which may have a material adverse effect on the Corporation’s profitability and financial condition. Further, the imposition of carbon taxes puts the Corporation at a disadvantage with its counterparts who operate in jurisdictions where there are less costly carbon regulations. Liability Management Programs Alberta has developed the Licensee Liability Rating Program (the “Alberta LLR Program”) which is designed to prevent taxpayers from incurring costs associated with the suspension, abandonment, remediation and reclamation of wells, facilities and pipelines in the event that a licensee or permit holder is unable to satisfy its regulatory obligations. This program involves an assessment of the ratio of a licensee’s deemed assets to deemed liabilities. If a licensee’s deemed liabilities exceed its deemed assets, a security deposit is generally required. Changes to the required ratio of the Corporation’s deemed assets to deemed liabilities or other changes to the requirements of the Alberta LLR Program may result in the requirement for security to be posted in the future and may result in significant increases to the Corporation’s compliance obligations. In addition, the Alberta 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 Alberta LLR Program (both before and after the transfer of the assets) for the applicable regulatory agency to allow for the transfer of such assets. The decision of the Court of Queen’s Bench of Alberta in Redwater Energy Corporation (Re) (“Redwater”) found an operational conflict between the Bankruptcy and Insolvency Act (Canada) and the Alberta Energy Regulator’s (“AER”) abandonment and reclamation powers when the licensee is insolvent, which was affirmed by a majority of the Alberta Court of Appeal and has been appealed by the AER to the Supreme Court of Canada for final determination. In response to the decision, the AER issued interim rules to administer the Alberta LLR Program until the Government of Alberta can develop new regulatory measures to adequately address environmental liabilities. There remains a great deal of uncertainty as to what new regulatory measures will be developed by the provinces or in concert with the federal government, as the final ruling will become binding in all Canadian jurisdictions. 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. 83 2017 Annual Report Royalty Regimes The Corporation’s cash flows are directly affected by changes to royalty regimes. There can be no assurance that the Government of Alberta will not adopt a new royalty regime or modify the existing royalty regime, which may have an impact on the economics of the Corporation’s projects. An increase in the royalty rates in Alberta would reduce the Corporation’s earnings and could make future capital investments, or the Corporation’s operations, less economic or uneconomic. On January 29, 2016, the Government of Alberta adopted a new royalty regime which took effect on January 1, 2017. Disposal of Fluids Used in Operations The safe disposal of the hydraulic fracturing fluids (including the additives) and water recovered from oil and natural gas wells is subject to ongoing regulatory review by the federal and provincial governments, including its effect on fresh water supplies and the ability of such water to be recycled, amongst other things. While it is difficult to predict the impact of any regulations that may be enacted in response to such review, the implementation of stricter regulations may increase the Corporation’s costs of compliance. Other Risks Volatility in the Market Prices of the Corporation’s 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. Factors unrelated to the Corporation’s performance could include macroeconomic developments nationally, within North America or globally, domestic and global commodity prices or current perceptions of the oil and natural gas market. In certain jurisdictions, institutions, including government-sponsored entities, have determined to decrease their ownership in oil and gas entities which may impact the liquidity of certain securities and may put downward pressure on the trading price of those securities. Similarly, the market prices of the Corporation’s securities could be subject to significant fluctuations in response to variations in the Corporation’s operating results, financial condition, liquidity and other internal factors. In addition, market price fluctuations in the Corporation’s securities may also be due to the Corporation’s results failing to meet the expectations of securities analysts or investors in any quarter, downward revision in securities analysts’ estimates and material public announcements by the Corporation, along with a variety of additional factors, including, without limitation, those set forth under the heading “Advisories”. Accordingly, the prices at which the Corporation’s securities will trade cannot be accurately predicted. Reliance on Key Personnel The Corporation’s success depends, in large measure, on certain key personnel. The loss of the services of such key personnel could have a material adverse effect on the Corporation. The Corporation does not have “key person” insurance in effect for the Corporation. The contributions of the existing management team to the immediate and near-term operations of the Corporation are likely to be of central importance. In addition, the competition for qualified personnel in the oil and natural gas industry is intense and there can be no assurance that the Corporation will be able to continue to attract and retain all of the personnel necessary for the development and operation of its business. 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 considers acquisitions and dispositions of assets in the ordinary course of business. Typically, once an acquisition opportunity is identified, a review of available information relating to the assets is conducted. There is a risk that even a detailed review of records and assets may not necessarily reveal every existing or potential problem, nor will it permit the Corporation to become sufficiently familiar with the assets to fully assess their deficiencies and potential. There is no guarantee that defects in the chain of title will not arise to defeat the Corporation’s title to certain assets or that environmental defects, liabilities or deficiencies do not exist or are greater than anticipated. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the Corporation may assume certain environmental and other risk liabilities in connection with acquired assets. In addition, acquisitions of oil and 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. 84 Birchcliff Energy Ltd. 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 away from other strategic opportunities and operational matters. Management continually assesses the value and contribution of the various assets within its portfolio. In this regard, certain assets may be periodically disposed of so the Corporation can focus its efforts and resources more efficiently. Depending on the state of the market for such assets, there is a risk that certain assets of the Corporation could realize less on disposition than what the market may expect for such disposition or realize less than their carrying value on the Corporation’s financial statements. 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. Reputational Risk Associated with the Corporation’s Operations Any environmental damage, loss of life, injury or damage to property caused by the Corporation’s operations could damage its reputation in the areas in which it operates. Negative sentiment towards the Corporation could result in a lack of willingness of municipal authorities being willing to grant the necessary licenses or permits for the Corporation to operate its business. In addition, negative sentiment towards the Corporation could result in the residents of the areas where the Corporation is doing business opposing further operations in the area by the Corporation. If the Corporation develops a reputation of having an unsafe work site, this may impact its ability to attract and retain the necessary skilled employees and consultants to operate its business. Further, the Corporation’s reputation could be affected by actions and activities of other corporations operating in the oil and natural gas industry, over which it has no control. In addition, environmental damage, loss of life, injury or damage to property caused by the Corporation’s operations could result in negative investor sentiment towards it, which may result in limiting the Corporation’s access to capital, increasing the cost of capital, and decreasing the price and liquidity of the Corporation’s securities. Changing Investor Sentiment A number of factors, including the concerns of the effects of the use of fossil fuels on climate change, concerns of the impact of oil and gas operations on the environment, concerns of environmental damage relating to spills of petroleum products during transportation and concerns of indigenous rights, have affected certain investors’ sentiments towards investing in the oil and natural gas industry. As a result of these concerns, some institutional, retail and public investors have announced that they no longer are willing to fund or invest in oil and gas properties or companies or are reducing the amount thereof over time. In addition, certain institutional investors are requesting that issuers develop and implement more robust social, environmental and governance policies and practices. Developing and implementing such policies and practices can involve significant costs and require a significant time commitment from the Corporation’s Board of Directors, management and employees. Failing to implement the policies and practices as requested by institutional investors may result in such investors reducing their investment in the Corporation or not investing in the Corporation at all. Any reduction in the investor base interested or willing to invest in the oil and natural gas industry and more specifically, in the Corporation, may result in limiting Birchcliff’s access to capital, increasing the cost of capital and decreasing the price and liquidity of the Corporation’s securities. Information Technology Systems and Cyber-Security The Corporation is dependent upon the availability, capacity, reliability and security of its information technology infrastructure and its ability to expand and continually update this infrastructure, to conduct daily operations. The Corporation depends on various information technology systems to estimate reserves, process and record financial data, manage its land base, analyze seismic information, administer its contracts with its operators and lessees and communicate with employees and third-party partners. In the event the Corporation is unable to regularly deploy software and hardware, effectively upgrade systems and network infrastructure and take other steps to maintain or improve the efficiency and efficacy of its information technology systems, the operation of such systems could be interrupted or result in the loss, corruption, or release of data. Further, the Corporation is subject to a variety of information technology and system risks as a part of its normal course operations, including potential breakdown, invasion, virus, cyber-attack, cyber-fraud, security breach, and destruction or interruption of the Corporation’s information technology systems by third parties or insiders. Unauthorized access to these systems by employees or third parties 85 2017 Annual Report could lead to corruption or exposure of confidential, fiduciary or proprietary information, interruption to communications or operations or disruption to its business activities or its competitive position. In addition, cyber-phishing attempts, in which a malicious party attempts to obtain sensitive information such as usernames, passwords, and credit card details (and money) by disguising as a trustworthy entity in an electronic communication, have become more widespread and sophisticated in recent years. If the Corporation becomes a victim to a cyber-phishing attack it could result in a loss or theft of the Corporation’s financial resources or critical data and information or could result in a loss of control of the Corporation’s technological infrastructure or financial resources. The Corporation applies technical and process controls in line with industry-accepted standards to protect its information assets and systems; however, these controls may not adequately prevent cyber-security breaches. Disruption of critical information technology services, or breaches of information security, could have a negative effect on the Corporation’s performance and earnings, as well as on its reputation. The significance of any such event is difficult to quantify, but may in certain circumstances be material and could have a material adverse effect on the Corporation’s business, financial condition, results of operations and prospects. In addition to the oversight provided by the Corporation’s Information Technology Committee, there is further reporting on the Corporation’s information technology and cyber-security risks to the Board of Directors. To date, the Corporation has not been subject to a cyber-security attack or other breach that has had a material impact on its business or operations or resulted in material losses to the Corporation; however, there is no assurance that the measures the Corporation takes to protect its business systems and operational control systems will be effective in protecting against a breach in the future and that the Corporation will not incur such losses in the future. Insurance Although the Corporation maintains insurance in accordance with industry standards to address certain risks, such insurance has limitations on liability and may not be sufficient to cover the full extent of such liabilities. In addition, certain risks are not, in all circumstances, insurable or, in certain circumstances, the Corporation may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. The payment of any uninsured liabilities would reduce the funds available to the Corporation. The occurrence of a significant event that the Corporation is not fully insured against, or the insolvency of the insurer of such event, could have a material adverse effect on the Corporation’s business, financial condition, results of operations and prospects. Litigation In the normal course of the Corporation’s operations, it may become involved in, be named as a party to, or be the subject of, various legal proceedings, including regulatory proceedings, tax proceedings and legal actions, relating to personal injury, property damage, property taxes, land rights, access rights, royalty 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 away from the Corporation’s business operations, which may adversely affect the Corporation. Due to the rapid development of oil and gas technology, the Corporation may become involved in, be named as a party to, or be the subject of, various legal proceedings in which it is alleged that the Corporation has infringed the intellectual property rights of others or conversely the Corporation may commence lawsuits against others who the Corporation believes are infringing upon its intellectual property rights. The Corporation’s involvement in intellectual property litigation could result in significant expense, adversely affecting the development of its assets or intellectual property or diverting the efforts of its technical and management personnel, whether or not such litigation is resolved in the Corporation’s favour. In the event of an adverse outcome as a defendant in any such litigation, the Corporation may, among other things, be required to: (i) pay substantial damages; (ii) cease the development, use, sale or importation of processes that infringe upon other patented intellectual property; (iii) expend significant resources to develop or acquire non-infringing intellectual property; (iv) discontinue processes incorporating infringing technology; or (v) obtain licences to the infringing intellectual property. However, the Corporation may not be successful in such development or acquisition or such licences may not be available on reasonable terms. Any such development, acquisition or licence could require the expenditure of substantial time and other resources and could have a material adverse effect on the Corporation’s business and financial results. 86 Birchcliff Energy Ltd. Aboriginal Claims Aboriginal peoples have claimed aboriginal title and rights in portions of Western Canada. The Corporation is not aware that any claims have been made in respect of its properties or assets; however, the legal basis of an aboriginal land claim and aboriginal rights is a matter of considerable legal complexity and the impact of the assertion of such a claim, or the possible effect of a settlement of such claim, upon the Corporation cannot be predicted with any degree of certainty at this time. In addition, no assurance can be given that any recognition of aboriginal rights or claims whether by way of a negotiated settlement or by judicial pronouncement (or through the grant of an injunction prohibiting exploration or development activities pending resolution of any such claim) would not delay or even prevent the Corporation’s exploration and development activities. If a claim arose and was successful, such claim may have a material adverse effect on the Corporation’s business, financial condition, results of operations and prospects. In addition, the process of addressing such claims, regardless of the outcome, may be expensive and time consuming and could result in delays which could have a material adverse effect on the Corporation’s business, financial condition, results of operations and prospects. Internal Controls Effective internal controls are necessary for the Corporation to provide reliable financial reports and to help prevent fraud. Although the Corporation undertakes a number of procedures in order to help ensure the reliability of its financial reports, including those imposed on it under Canadian securities laws, the Corporation cannot be certain that such measures will ensure that the Corporation will maintain adequate control over financial processes and reporting. Failure to implement required new or improved controls, or difficulties encountered in their implementation, could harm the Corporation’s results of operations or cause it to fail to meet its reporting obligations. If the Corporation or its independent 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. 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 a 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. Income Taxes The Corporation files all required income tax returns and believes that it is in full compliance with the provisions of the Income Tax Act (Canada) and all other applicable provincial tax legislation. However, such returns are subject to reassessment by the applicable taxation authority. In the event of a successful reassessment of the Corporation, such reassessment may have an impact on current and future taxes payable. Income tax laws relating to the oil and natural gas industry, such as the treatment of resource taxation or dividends, may in the future be changed or interpreted in a manner that adversely affects the Corporation. Furthermore, tax authorities having jurisdiction over the Corporation may disagree with how the Corporation calculates its income for tax purposes or could change administrative practices to the Corporation’s detriment. 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. 87 2017 Annual Report Negative Impact of Additional Sales or Issuances of Securities The Corporation may issue an unlimited number of common shares without any vote or action by the shareholders, subject to the rules of any stock exchange on which the Corporation’s securities may be listed. The Corporation may make future acquisitions or enter into financings or other transactions involving the issuance of securities of the Corporation which may be dilutive. If the Corporation issues additional securities, the percentage ownership of existing shareholders will be reduced and diluted and the price of the Corporation’s securities could decrease. Additional Taxation Applicable to Non-residents Tax legislation in Canada may impose withholding or other taxes on the cash dividends, stock dividends or other property transferred by the Corporation to non-resident shareholders. These taxes may be reduced pursuant to tax treaties between Canada and the non-resident shareholder’s jurisdiction of residence. Evidence of eligibility for a reduced withholding rate must be filed by the non-resident shareholder in prescribed form with their broker (or in the case of registered shareholders, with the transfer agent). In addition, the country in which the non-resident shareholder is resident may impose additional taxes on such dividends. Any of these taxes may change from time to time. Foreign Exchange Risk for Non-resident Shareholders The Corporation’s cash dividends are declared in Canadian dollars and may be converted in certain instances to foreign denominated currencies at the spot exchange rate at the time of payment. As a consequence, non-resident shareholders and shareholders who calculate their return in currencies other than the Canadian dollar are subject to foreign exchange risk. To the extent that the Canadian dollar strengthens with respect to their currency, the amount of any dividend will be reduced when converted to their home currency. Conflicts of Interest Certain directors or officers of the Corporation may also be directors or officers of other oil and natural gas companies and as such may, in certain circumstances, have a conflict of interest. Conflicts of interest, if any, will be subject to and governed by procedures prescribed by the ABCA which require a director or officer of a Corporation who is a party to, or is a director or an officer of, or has a material interest in any person who is a party to, a material contract or proposed material contract with the Corporation to disclose his or her interest and, in the case of directors, to refrain from voting on any matter in respect of such contract unless otherwise permitted under the ABCA. Forward-Looking Information May Prove Inaccurate Shareholders and prospective investors are cautioned not to place undue reliance on the Corporation’s forward-looking 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. For additional information, see “Advisories – Forward-Looking Information”. 88 Birchcliff Energy Ltd. ABBREVIATIONS The abbreviations set forth below have the following meanings: AECO bbl bbls bbls/d boe boe/d GAAP GJ GJ/d IFRS m3 Mcf Mcfe MJ MM$ MMBtu MMcf MMcf/d NGLs NGTL P&NG WTI TCPL 000s $000s benchmark price for natural gas determined at the AECO ‘C’ hub in southeast Alberta barrel barrels barrels per day barrel of oil equivalent barrels of oil equivalent per day generally accepted accounting principles gigajoule gigajoules per day International Financial Reporting Standards cubic meters thousand cubic feet thousand cubic feet of gas equivalent megajoule millions of dollars million British thermal units million cubic feet million cubic feet per day natural gas liquids NOVA Gas Transmission Ltd. petroleum and natural gas West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma, for crude oil of standard grade TransCanada Pipelines thousands thousands of dollars 89 2017 Annual Report NON-GAAP MEASURES This MD&A uses “adjusted funds flow”, “adjusted funds flow per common share”, “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. “Adjusted funds flow” denotes cash flow from operating activities before the effects of decommissioning expenditures and changes in non-cash working capital. “Adjusted funds flow per common share” denotes adjusted funds flow divided by the basic or diluted weighted average number of common shares outstanding for the period. The Corporation eliminates changes in non-cash working capital and settlements of decommissioning expenditures from cash flow from operations as the amounts can be discretionary and may vary from period to period depending on its capital programs and the maturity of its operating areas. The settlement of decommissioning expenditures are managed with the Corporation’s capital budgeting process which considers available adjusted funds flow. Management believes that adjusted funds flow and adjusted funds flow per common share assist management and investors in assessing Birchcliff’s profitability, as well as its ability to generate the cash necessary to fund future growth through capital investments, pay dividends and repay debt. Birchcliff previously referred to adjusted funds flow as “funds flow from operations”. The following table provides a reconciliation of cash flow from operating activities, as determined in accordance with IFRS, to adjusted funds flow: ($000s) Cash flow from operating activities Adjustments: Decommissioning expenditures Change in non-cash working capital Adjusted funds flow Three months ended December 31, Twelve months ended December 31, 2017 88,995 2016 2017 2016 90,574 287,660 140,514 93 7,920 480 794 (19,248) 29,226 1,343 5,586 97,008 71,806 317,680 147,443 “Operating netback” denotes petroleum and natural gas revenue less royalties, less operating expense and less transportation and marketing expense. “Estimated operating netback” of the Pouce Coupe Gas Plant (and the components thereof) is based upon certain cost allocations and accruals directly attributable to the Pouce Coupe Gas Plant and related wells and infrastructure. All netbacks are calculated on a per unit basis, unless otherwise indicated. Management believes that 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: Three months ended December 31, Twelve months ended December 31, 2017 2016 2017 2016 ($000s) ($/boe)(1) ($000s) ($/boe)(1) ($000s) ($/boe)(1) ($000s) ($/boe)(1) Petroleum and natural gas revenue 166,149 22.55 135,457 24.24 556,942 22.45 337,586 Royalty expense Operating expense (9,271) (1.26) (10,177) (1.82) (28,727) (1.16) (20,911) (28,460) (3.86) (25,385) (4.54) (110,486) (4.45) (75,251) Transportation and marketing expense (25,883) (3.52) (13,489) (2.42) (71,224) (2.87) (42,989) Operating netback 102,535 13.91 86,406 15.46 346,505 13.97 198,435 18.73 (1.16) (4.18) (2.38) 11.01 (1) All per boe figures are calculated by dividing each aggregate financial amount by the production (boe) in the respective period. 90 Birchcliff Energy Ltd. “Operating margin” for the Pouce Coupe 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 Pouce Coupe Gas Plant and Birchcliff’s ability to generate operating cash flows (equal to petroleum and natural gas revenue less royalties, less operating expense and less transportation and marketing expense). “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 unit basis. Management believes that total cash costs assists management and investors in assessing Birchcliff’s efficiency and overall cash cost structure. “Adjusted working capital deficit” is calculated as current assets minus current liabilities excluding the effects of any financial instruments. Management believes that adjusted working capital deficit assists management and investors in assessing Birchcliff’s liquidity. The following table reconciles working capital deficit (current assets minus current liabilities), as determined in accordance with IFRS, to adjusted working capital deficit: As at, ($000s) Working capital deficit Fair value of financial instruments Adjusted working capital deficit December 31, 2017 December 31, 2016 15,113 (4,046) 11,067 36,928 (9,433) 27,495 “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 ADVISORIES Operating Costs December 31, 2017 December 31, 2016 587,126 11,067 598,193 572,517 27,495 600,012 References in this MD&A to “operating costs” exclude transportation and marketing costs. Boe and Mcfe Conversions Boe amounts have been calculated by using the conversion ratio of 6 Mcf of natural gas to 1 bbl of oil and Mcfe amounts have been calculated by using the conversion ratio of 1 bbl of oil to 6 Mcf of natural gas. Boe and Mcfe amounts may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 bbl and an Mcfe conversion ratio of 1 bbl: 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. MMBtu Pricing Conversions $1.00 per MMBtu equals $1.00 per Mcf based on a standard heat value Mcf. Oil and Gas Metrics This MD&A contains metrics commonly used in the oil and natural gas industry, including “operating netback”. These oil and gas metrics do not have any standardized meanings or standard methods of calculation and therefore may not be comparable to similar measures presented by other companies where similar terminology is used 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. For information on how operating netback is calculated, please see “Non-GAAP Measures”. 91 2017 Annual Report Capital Expenditures Unless otherwise stated, references in this MD&A to: (i) “net capital expenditures” and “capital expenditures, net” denote F&D costs (which includes land, seismic, workovers, drilling and completions and well equipment and facilities) plus administrative assets, plus acquisition costs, less any dispositions; and (ii) “total capital expenditures” denotes F&D costs plus administrative assets. 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, 2017. Such evaluations were prepared in accordance with the standards contained in the COGE Handbook and NI 51-101. Further information regarding the Corporation’s reserves can be found in the Corporation’s Annual Information Form for the financial year ended December 31, 2017. Certain terms used herein are defined in NI 51-101 or the COGE Handbook and, unless the context otherwise requires, shall have the same meanings in this MD&A as in NI 51-101 or the COGE Handbook, as the case may be. Forward-Looking 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”, “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 financial performance, operations, focus, objectives, strategies, opportunities, priorities and goals; Birchcliff’s guidance regarding its 2018 Capital Program and its proposed exploration and development activities and the timing thereof (including estimates of capital expenditures in 2018, planned capital expenditures and capital allocation, the focus of, the objectives of and the anticipated results from the 2018 Capital Program, the number and types of wells to be drilled and brought on production, Birchcliff’s expectation that its 2018 capital expenditures will be less than its adjusted funds flow during 2018, the financial and operational flexibility of the 2018 Capital Program and the potential to accelerate or decelerate capital expenditures); Birchcliff’s other guidance for 2018 (including its estimates of its annual average production and commodity mix, its estimates of royalty, operating and transportation and marketing expenses, its estimates of AECO and Dawn production levels and forecasts of commodity prices); the proposed Phase VI expansion of the Pouce Coupe Gas Plant (including the anticipated processing capacity of the Pouce Coupe Gas Plant after such expansion and the anticipated timing thereof); statements regarding the re-configuring of Phases V and VI of the Pouce Coupe Gas Plant to provide for shallow-cut capability; the performance characteristics of Birchcliff’s oil and natural gas properties and expected results from its assets; Birchcliff’s marketing and transportation arrangements (including its expectation that approximately 34% of its 2018 forecast annual average natural gas production will be sold at prices that are not based on AECO, with 30% expected to be sold at the Dawn index price and 4% expected to be marketed via the Alliance pipeline system during 2018, that additional tranches of service on TCPL’s Canadian Mainline will become available later in 2018 and 2019 and that approximately 48% of the Corporation’s total forecasted corporate production is exposed to AECO pricing, with the remaining 52% of corporate production not exposed to AECO pricing in 2018); Birchcliff’s hedging strategy, activities and the use of risk-management techniques (including that its current hedging strategy for 2018 is to hedge up to 50% of its estimated 2018 forecast average production using a combination of financial derivatives and physical delivery sales contracts); 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 the Corporation’s financial flexibility, the sources of funding for the Corporation’s activities and capital requirements, that the Corporation generally relies on its adjusted funds flow and available credit under its existing credit facilities to fund its capital requirements, statements that the Corporation may from time to time seek additional capital in the form of debt and/or equity or dispose of non-core properties to fund its on-going capital expenditure programs and protect its balance sheet, management’s belief that its adjusted funds flow during 2018 will be sufficient to fund the Corporation’s 2018 Capital Program, statements that Birchcliff may adjust its on-going capital program, draw down on its Credit Facilities, seek 92 Birchcliff Energy Ltd. additional equity financing and/or consider the potential sale of additional non-core assets to fund planned growth should commodity prices deteriorate materially and the Corporation’s expectation that counterparties will be able to meet their financial obligations); statements that management of debt levels continues to be a priority for Birchcliff; estimates of Birchcliff’s material contractual obligations and commitments; statements regarding Birchcliff’s decommissioning obligations; the payment of dividends (including statements regarding the timing thereof and the sustainability of dividends); statements relating to the NCIB (including potential purchases under the NCIB and the cancellation of common shares purchased under the NCIB); and the treatment under and impact of existing and proposed governmental regulatory regimes (including the impact of climate change and GHG legislation on the Corporation). 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 its 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 adjusted funds flow; 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 or other approvals in a timely manner; the ability of Birchcliff to secure adequate transportation for its products; Birchcliff’s ability to market oil and gas; the availability of hedges on terms acceptable to Birchcliff; and abandonment costs and decommissioning obligations. 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 2018 Capital Program (including estimates of 2018 capital expenditures, statements that the Corporation’s 2018 capital expenditures will be less than its adjusted funds flow during 2018 and statements that its adjusted funds flow during 2018 will be sufficient to fund the 2018 Capital Program), such estimates and statements are based on the assumptions set forth in the table under the heading “2018 Outlook”. o With respect to estimates of capital expenditures, such estimates assume that the 2018 Capital Program will be carried out as currently contemplated. o With respect to statements that the Corporation’s 2018 capital expenditures will be less than its adjusted funds flow during 2018 and that its adjusted funds flow during 2018 will be sufficient to fund the 2018 Capital Program, such statements assume that: the 2018 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. o The amount and allocation of capital expenditures for exploration and development activities by area and the number and types of wells to be drilled is dependent upon results achieved and is subject to review and modification by management on an ongoing basis throughout the year. Actual spending may vary due to a variety of factors, including commodity prices, industry conditions, results of operations and costs of labour, services and materials. In addition, any acquisitions and dispositions completed during the 2018 could have an impact on Birchcliff’s capital expenditures, production and adjusted funds flow for 2018, which impact could be material. o Birchcliff will monitor industry conditions and commodity prices and, where deemed prudent, will adjust the 2018 Capital Program to respond to changes in commodity prices and other material changes in the assumptions underlying the 2018 Capital Program. 93 2017 Annual Report • With respect to Birchcliff’s production guidance, the key assumptions are that: Birchcliff’s capital expenditure program will be carried out as currently contemplated; no unexpected outages occur in the infrastructure that Birchcliff relies on to produce its wells and that any transportation service curtailments or unplanned outages that occur will be short in duration or otherwise insignificant; the construction of new infrastructure meets timing and operational expectations; existing wells continue to meet production expectations; and future wells scheduled to come on production meet timing, production and capital expenditure expectations. In addition, Birchcliff’s production guidance may be affected by acquisition and disposition activity and acquisitions and dispositions could occur that may impact expected production. • With respect to 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 industry conditions will warrant proceeding with the drilling of such wells. • With respect to statements regarding the proposed Phase VI expansion of the Pouce Coupe Gas Plant, including the anticipated processing capacity of the Pouce Coupe Gas Plant after such expansion and the anticipated timing of such expansion, 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 industry conditions will warrant proceeding with the construction of such facilities and the drilling of associated wells. • With respect to estimates of reserves, the key assumption is the validity of the data used by the Corporation’s independent qualified reserves evaluators in their independent 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; 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; an inability to access sufficient capital from internal and external sources; fluctuations in the costs of borrowing; 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; 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; 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; horizontal drilling and completions techniques and the failure of drilling results to meet expectations for reserves or production; uncertainties related to Birchcliff’s future potential drilling locations; 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; potential delays or changes in plans with respect to exploration or development projects or capital expenditures, including delays in the completion of Birchcliff’s gas plants and other facilities; 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; risks associated with the declaration and payment of dividends, including the discretion of Birchcliff’s Board of Directors to declare dividends; the failure to obtain any required approvals in a timely manner or at all; 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; negative public perception of the oil and natural gas industry, including transportation, hydraulic fracturing and fossil fuels; management of Birchcliff’s growth; the availability of insurance and the risk that certain losses may not be insured; and cyber-security issues. 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, under the heading “Risk Factors” in Birchcliff’s most recent Annual Information Form and in other reports filed with Canadian securities regulatory authorities from time to time. 94 Birchcliff Energy Ltd. 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. 95 2017 Annual Report M A N A G E M E N T ’ S R E P O R T To the Shareholders of Birchcliff Energy Ltd. The annual financial statements of Birchcliff Energy Ltd. for the year ended December 31, 2017 were prepared by management within the acceptable limits of materiality and are in accordance with International Financial Reporting Standards. Management is responsible for ensuring that the financial and operating information presented in the annual report is consistent with that shown in the financial statements. The financial statements have been prepared by management in accordance with the accounting policies as described in the notes to the financial statements. Timely release of financial information sometimes necessitates the use of estimates when transactions affecting the current accounting period cannot be finalized until future periods. When necessary, such estimates are based on informed judgments made by management. Management has designed and maintains an appropriate system of internal controls to provide reasonable assurance that all assets are safeguarded and financial records properly maintained to facilitate the preparation of financial statements for reporting purposes. KPMG LLP, an independent firm of Chartered Professional Accountants appointed by shareholders, have conducted an examination of the corporate and accounting records in order to express their opinion on the financial statements. The Audit Committee, consisting of non-management directors, has met with representatives of KPMG LLP and management in order to determine if management has fulfilled its responsibilities in the preparation of the financial statements. The Board of Directors has approved the financial statements on the recommendation of the Audit Committee. Respectfully, (signed) “Bruno P. Geremia” Bruno P. Geremia, (signed) “A. Jeffery Tonken” A. Jeffery Tonken, Vice-President and Chief Financial Officer President and Chief Executive Officer Calgary, Canada March 14, 2018 96 Birchcliff Energy Ltd. I N D E P E N D E N T A U D I T O R S ’ R E P O R T 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, 2017 and December 31, 2016, 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, 2017 and December 31, 2016, 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 14, 2018 97 2017 Annual Report B I R C H C L I F F E N E R G Y L T D . S T A T E M E N T S O F F I N A N C I A L P O S I T I O N (Expressed in thousands of Canadian dollars) As at December 31, ASSETS Current assets: Cash Accounts receivable (Note 17) Prepaid expenses and deposits Non-current assets: Exploration and evaluation (Note 5) Petroleum and natural gas properties and equipment (Note 6) Investment in securities (Note 7) Total assets LIABILITIES Current liabilities: Accounts payable and accrued liabilities Financial instruments (Note 17) Non-current liabilities: Revolving term credit facilities (Note 8) Decommissioning obligations (Note 9) Deferred income taxes (Note 10) Capital securities (Note 11) Total liabilities SHAREHOLDERS’ EQUITY Share capital (Note 11) Common shares Preferred shares (perpetual) Contributed surplus Retained earnings Total shareholders’ equity and liabilities Commitments (Note 18) 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 98 2017 2016 48 69,302 2,622 71,972 81 2,545,050 10,005 2,555,136 2,627,108 83,039 4,046 87,085 587,126 124,825 82,694 49,225 843,870 930,955 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 1,477,750 1,464,567 41,434 69,959 107,010 1,696,153 2,627,108 41,434 63,847 184,559 1,754,407 2,710,457 Birchcliff Energy Ltd. B I R C H C L I F F E N E R G Y L T D . S T A T E M E N T S O F N E T L O S S A N D C O M P R E H E N S I V E L O S S (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 Other income (Note 7) Realized gain on financial instruments (Note 17) Unrealized gain (loss) on financial instruments (Note 17) EXPENSES Operating (Note 12) Transportation and marketing Administrative, net (Note 13) Depletion and depreciation (Note 6) Finance (Note 14) Dividends on capital securities (Note 11) Loss on sale of assets (Note 6) Net loss before taxes Income tax recovery (Note 10) NET LOSS AND COMPREHENSIVE LOSS Net loss per common share (Note 11) Basic Diluted The accompanying notes are an integral part of these financial statements. 2017 2016 556,942 (28,727) 528,215 268 25,785 5,387 559,655 110,486 71,224 30,563 185,666 32,939 3,500 186,143 620,521 (60,866) 13,886 (46,980) ($0.19) ($0.19) 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) 99 2017 Annual Report B I R C H C L I F F E N E R G Y L T D . S T A T E M E N T S O F C H A N G E S I N S H A R E H O L D E R S ’ E Q U I T Y (Expressed in thousands of Canadian dollars) As at December 31, 2015 Issue of common shares (Note 11) Share issue costs, net of tax (Note 11) Dividends on perpetual preferred shares Exercise of stock options Stock-based compensation Net loss and comprehensive loss Share Capital Common Shares Preferred Shares Contributed Surplus Retained Earnings Total 783,481 690,801 (20,143) - 10,428 - - 41,434 60,625 212,894 1,098,434 - - - - - - - - - (2,831) 6,053 - - (4,000) - - 690,801 (20,143) (4,000) 7,597 6,053 - (24,335) (24,335) As at December 31, 2016 1,464,567 41,434 63,847 184,559 1,754,407 Dividends on common shares (Note 11) Dividends on perpetual preferred shares (Note 11) Exercise of stock options (Note 11) Stock-based compensation (Note 13) Net loss and comprehensive loss - - 13,183 - - - - - - - - - (26,522) (4,047) (3,833) 9,945 - - (26,522) (4,047) 9,350 9,945 - (46,980) (46,980) As at December 31, 2017 1,477,750 41,434 69,959 107,010 1,696,153 The accompanying notes are an integral part of these financial statements. 100 Birchcliff Energy Ltd. B I R C H C L I F F E N E R G Y L T D . S T A T E M E N T S O F C A S H F L O W S (Expressed in thousands of Canadian dollars) Years ended December 31, Cash provided by (used in): OPERATING Net loss and comprehensive loss Adjustments for items not affecting operating cash: Unrealized (gain) loss on financial instruments Depletion and depreciation Stock-based compensation Finance Loss on sale of assets Income tax recovery Interest paid Dividends on capital securities Decommissioning expenditures Changes in non-cash working capital (Note 19) FINANCING Exercise of stock options Issue of common shares Share issue costs Financing fees paid on credit facilities Dividends on common shares Dividends on perpetual preferred shares Dividends on capital securities Net change in revolving term credit facilities INVESTING Petroleum and natural gas properties Acquisition of petroleum and natural gas properties and equipment Sale of petroleum and natural gas properties and equipment (Note 6) Exploration and evaluation assets Changes in non-cash working capital (Note 19) Net change in cash Cash, beginning of year CASH, END OF YEAR The accompanying notes are an integral part of these financial statements. 2017 2016 (46,980) (24,335) (5,387) 185,666 4,059 32,939 186,143 (13,886) (28,374) 3,500 (794) (29,226) 287,660 9,350 - - (2,375) (26,522) (4,047) (3,500) 15,783 (11,311) (416,786) (999) 131,685 (28) 9,780 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) (614,273) 20,720 (46) 8,532 (276,348) (753,498) 1 47 48 (10) 57 47 101 2017 Annual Report B I R C H C L I F F E N E R G Y L T D . N O T E S T O T H E F I N A N C I A L S T A T E M E N T S F O R T H E Y E A R S E N D E D D E C E M B E R 3 1 , 2 0 1 7 A N D 2 0 1 6 (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 14, 2018. 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, 2017 and December 31, 2016. 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. 102 Birchcliff Energy Ltd. (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 103 2017 Annual Report energy equivalent conversion ratio of six thousand cubic feet of natural gas to one barrel of oil. These estimates are reviewed by the Corporation’s independent reserves evaluator at least annually. Capitalized plant turnaround costs are depreciated on a straight-line basis over the estimated time until the next turnaround is completed. Corporate assets, which include office furniture and equipment, software, computer equipment and leasehold improvements, are depreciated on a straight-line basis over the estimated useful lives of the assets, which are estimated to be four years. When significant parts of property and equipment, including petroleum and natural gas interests, have different useful lives, they are accounted for as separate items (major components). Depreciation methods, useful lives and residual values for petroleum and natural gas properties and equipment are reviewed at each reporting date. (f) Provisions Provisions are recognized when the Corporation has a present obligation (legal or constructive), as a result of a past event, if it is probable that the Corporation will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. The amount recognized as a provision is the best estimate of the consideration required to settle the present obligation at the end of the reporting period, taking into account the risks and uncertainties surrounding the obligation. When a provision is measured using the cash flows estimated to settle the present obligation, its carrying amount is the present value of those cash flows (where the effect of the time value of money is significant). When some or all of the economic benefits required to settle a provision are expected to be recovered from a third party, a receivable is recognized as an asset if it is virtually certain that reimbursement will be received and the amount of the receivable can be measured reliably. Provisions are not recognized for future operating losses. (g) Decommissioning Obligations The Corporation’s activities give rise to dismantling, restoration and site disturbance remediation activities. Costs related to abandonment activities are estimated by management in consultation with the Corporation’s independent reserves evaluators based on risk-adjusted current costs which take into consideration current technology in accordance with existing legislation and industry practices. Decommissioning obligations are measured at the present value of the best estimate of expenditures required to settle the present obligations at the reporting date. When the best estimate of the liability is initially measured, the estimated cost, discounted using a pre-tax risk-free discount rate, is capitalized by increasing the carrying amount of the related petroleum and natural gas properties and equipment. The increase in the provision due to the passage of time, which is referred to as accretion, is recognized as a finance expense. Actual costs incurred upon settlement of the liability are charged against the obligation to the extent that the obligation was previously established. The carrying amount capitalized in petroleum and natural gas properties and equipment is depleted in accordance with the Corporation’s depletion and depreciation policy. The Corporation reviews the obligation at each reporting date and revisions to the estimated timing of cash flows, discount rates and estimated costs result in an increase or decrease to the obligations and the related petroleum and natural gas properties and equipment. Any difference between the actual costs incurred upon settlement of the obligation and the recorded liability is recognized as a gain or loss in profit or loss. (h) Share-Based Payments Equity-settled share-based awards granted by the Corporation include stock options and performance warrants granted to officers, directors and employees. The fair value determined at the grant date of an award is expensed on a graded basis over the vesting period of each respective tranche of an award with a corresponding increase to contributed surplus. In calculating the expense of share-based awards, the Corporation revises its estimate of the number of equity instruments expected to vest by applying an estimated forfeiture rate for each vesting tranche and subsequently revising this estimate throughout the vesting period, as necessary, with a final adjustment to reflect the actual number of awards that vest. Upon the exercise of 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. 104 Birchcliff Energy Ltd. The fair value of equity-settled share-based awards is measured using the Black-Scholes option-pricing model taking into account the terms and conditions upon which the awards were granted. Measurement inputs as at the grant date include: share price, exercise price, expected volatility (based on weighted average historical traded daily volatility), weighted average expected life of the instruments (based on historical experience and general option holder behaviour), expected dividends and the risk-free interest rate (based on government bonds) applicable to the term of the award. A portion of share-based compensation expense directly attributable to the exploration and development of the Corporation’s assets are capitalized. (i) Finance Income and Expenses Finance expenses include interest expense on borrowings, accretion of the discount on decommissioning 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, deposits, investment in securities, accounts payable and accrued liabilities, outstanding credit facilities and capital securities. Non-derivative financial instruments are recognized initially at fair value plus any directly attributable transaction costs. Subsequent to initial recognition, non-derivative financial instruments are measured based on their classification. The Corporation has made the following classifications: • Cash, accounts receivable, and deposits are classified as loans and receivables and are measured at amortized cost using the effective interest method. Typically, the fair value of these balances approximates their carrying value due to their short term to maturity. • Investment in securities have been categorized as available for sale which requires the securities to be fair valued at the end of each reporting period with any gains or losses recognized in other comprehensive income. In the event of disposal or impairment the cumulative fair value changes recognized in other comprehensive income are reclassified to profit or loss. Distributions declared are recorded to profit or loss and presented as an operating activity on the statement of cash flow. • Accounts payable and accrued liabilities and outstanding credit facilities are classified as other financial liabilities and are measured at amortized cost using the effective interest method. Due to the short-term nature of accounts payable and accrued liabilities, their carrying values approximate their fair values. The Corporation’s outstanding credit facilities bear interest at a floating rate and accordingly the fair market value approximates the carrying value before the carrying value is reduced for any remaining unamortized costs. The interest costs and financing fees associated with the Corporation’s credit facilities have been deferred and netted against the amounts drawn, and are being amortized to profit or loss using the effective interest method over the applicable term. • The proceeds from the issuance of Series C Preferred Shares, which are presented as “capital securities” on the statement of financial position, are classified as “other financial liabilities” under IFRS. The incremental costs directly attributable to the issuance of Series C Preferred Shares are initially recognized as a reduction to capital securities and subsequently amortized to profit and loss, using the effective interest rate method, as a finance expense. Dividend distributions on capital securities are recorded as an expense directly to profit and loss and presented as a financing activity on the statements of cash flows. 105 2017 Annual Report (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. 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. 106 Birchcliff Energy Ltd. Where circumstances change such that an impairment no longer exists or is less than the amount previously recognized, the carrying amount of the CGU is increased to the revised estimate of its recoverable amount as long as the revised estimate does not exceed the carrying amount that would have been determined, net of depletion and depreciation, had no impairment loss been recognized for the CGU in prior periods. A reversal of an impairment loss is recognized immediately through profit or loss. Exploration and evaluation assets are assessed for impairment if: (i) sufficient data exists to determine technical feasibility and commercial viability of an exploration area, or (ii) facts and circumstances suggest that the carrying amount exceeds the recoverable amount. For purposes of impairment testing, exploration and evaluation assets are allocated to CGUs. (m) Income Taxes Birchcliff is a corporation as defined under the Income Tax Act (Canada) and is subject to Canadian Federal and provincial taxes. Birchcliff is subject to provincial taxes in Alberta as the Corporation operates in this jurisdiction. The Corporation’s income tax expenses include current and/or deferred tax. Income tax expense is recognized through profit or loss except to the extent that it relates to items recognized directly in equity, in which case the related income taxes are also recognized in equity. Current tax is the expected tax payable on taxable income and Part VI.I dividend tax payable on taxable preferred shares for the period, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years. Deferred tax is recognized on temporary differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable income. Deferred tax liabilities are generally recognized for all taxable temporary differences. Deferred tax assets are generally recognized for all deductible temporary differences to the extent that it is probable that taxable income will be available against which those deductible temporary differences can be utilized. The carrying amount of deferred tax assets is reviewed at the end of each reporting period and reduced to the extent that it is no longer probable that sufficient taxable income will be available to allow all or part of the asset to be recovered. Deferred tax assets and liabilities are measured at the tax rates that are expected to apply in the period in which the liability is expected to be settled or the asset realized, based on tax rates (and tax laws) that have been enacted or substantively enacted by the end of the reporting period. The measurement of deferred tax liabilities and assets reflects the tax consequences that would follow from the manner in which Birchcliff expects, at the end of the reporting period, to recover or settle the carrying amount of its assets and liabilities. (n) Flow-Through Shares The Corporation may issue flow-through shares to finance a portion of its capital expenditure program. Pursuant to the terms of the flow-through share agreements, the tax deductions associated with the expenditures are renounced to the subscribers. The difference between the value ascribed to flow-through shares issued and the value that would have been received for common shares at the date of announcements of the flow-through shares is initially recognized as a liability on the statements of financial position. When the expenditures are incurred, the liability is drawn down, a deferred tax liability is recorded equal to the estimated amount of deferred income tax payable by the Corporation as a result of the renunciation and the difference is recognized as a deferred tax expense. (o) Per Common Share The Corporation calculates per common share amounts using net income available to Birchcliff’s shareholders, reduced for perpetual preferred share dividends and divided by the weighted average number of common shares outstanding. Basic per share information is computed using the weighted average number of basic common shares outstanding during the period. Diluted per share information is calculated using the treasury stock method, which assumes that any proceeds from the exercise of “in-the-money” stock options, performance warrants or warrants (the “Securities”), plus the unamortized stock-based compensation expense amounts, would be used to purchase common shares at the average market price during 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. 107 2017 Annual Report (p) Business Combinations The purchase method of accounting is used to account for acquisitions of businesses and assets that meet the definition of a business under IFRS. The cost of an acquisition is measured as the fair value of the assets given and liabilities incurred or assumed at the date of exchange. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. If the consideration given up is less than the fair value of the net assets received, the difference is recognized immediately in the income statement. If the consideration is greater than the fair value of the net assets received, the difference is recognized as goodwill on the statement of financial position. Acquisition costs incurred are expensed. (q) 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. 108 Birchcliff Energy Ltd. 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. 109 2017 Annual Report 4. CHANGES IN ACCOUNTING POLICIES Future Accounting Pronouncements 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 will be adopting IFRS 15 on January 1, 2018. The Corporation has substantially completed its assessment and evaluation of the underlying terms of its revenue contracts with customers and has determined that the adoption of the standard will not have a material impact on the Corporation’s net income. 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. Birchcliff has determined that the adoption of IFRS 9 will result in changes to the Corporation’s investments in securities which, upon adoption of IFRS 9, will be measured at fair value through profit or loss. 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. 5. EXPLORATION AND EVALUATION ASSETS The continuity for exploration and evaluation (“E&E”) assets are as follows: ($000s) As at December 31, 2015 Additions Lease expiries As at December 31, 2016 Additions As at December 31, 2017 E&E(1) 247 46 (240) 53 28 81 (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 2017 and 2016. 110 Birchcliff Energy Ltd. 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, 2015 Additions Acquisitions Dispositions(1) As at December 31, 2016 Additions Acquisitions Dispositions(2) As at December 31, 2017(3) Accumulated depletion and depreciation: As at December 31, 2015 Depletion and depreciation expense(4) Dispositions(1) As at December 31, 2016 Depletion and depreciation expense(4) Disposition(2) As at December 31, 2017 Net book value: As at December 31, 2016 As at December 31, 2017(5) P&NG Assets Corporate Assets 2,588,350 190,546 634,345 (37,005) 3,376,236 455,894 999 (542,027) 3,291,102 (592,590) (147,837) 5,206 (735,221) (183,831) 168,292 (750,760) 10,969 2,981 - - 13,950 1,774 - - 15,724 (7,649) (1,532) - (9,181) (1,835) - (11,016) Total 2,599,319 193,527 634,345 (37,005) 3,390,186 457,668 999 (542,027) 3,306,826 (600,239) (149,369) 5,206 (744,402) (185,666) 168,292 (761,776) 2,641,015 2,540,342 4,769 4,708 2,645,784 2,545,050 (1) 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. (2) Consists largely of two asset dispositions, the Worsley Charlie Lake Light Oil Pool Disposition (the “Worsley Disposition”) and the Progress Area Disposition (the “Progress Disposition”). The Worsley Disposition had a net book value of $321.1 million for total consideration of $100 million, before closing adjustments and other costs, consisting of: (i) cash consideration of $90 million and (ii) securities of affiliates of the purchaser with a total value of $10 million (Note 7). The Worsley Disposition closed on August 31, 2017. The Progress Disposition had a net book value of $18.7 million for cash consideration of $31.7 million before closing adjustments and other costs. The Progress Disposition closed on October 2, 2017. (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 $4.5 billion at the end of 2017 (2016 - $4.1 billion) and are included in the depletion expense calculation. (5) In light of low commodity prices, the Corporation performed an asset impairment test to ensure that the carrying value of its P&NG properties and equipment was recoverable at the end of the reporting period. Birchcliff’s P&NG properties and equipment were not impaired at December 31, 2017. 111 2017 Annual Report 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 11, “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 from 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 7. INVESTMENT IN SECURITIES As Stated 337,586 (24,335) Gordondale Acquisition Pro Forma December 31, 2016 95,740 (4,072) 433,326 (28,407) In connection with the closing of the Worsley Disposition (Note 6), the Corporation received on August 31, 2017 (the “Issuance Date”) securities consisting of 4,500,000 common A units (the “Common A LP Units”) in a limited partnership (the “Limited Partnership”) affiliated with the purchaser and 10,000,000 preferred units (the “Preferred Trust Units”) in a trust (the “Trust”) affiliated with the purchaser (collectively, the “Securities”) at a combined value of $10 million. The Securities acquired are not publicly listed and do not constitute significant investments of the Corporation. The Securities have limited voting rights and, in the case of the Common A LP Units, no redemption rights and limited participation rights in the event of the liquidation, dissolution or wind-up of the Limited Partnership. Holders of the Securities are entitled to, if and when declared, non-cumulative, quarterly dividend distributions for each three month period ending March 31, June 30, September 30 and December 31. The Preferred Trust Units are redeemable on demand by Birchcliff. 112 Birchcliff Energy Ltd. For each Preferred Trust Unit redeemed by Birchcliff within the first five years of the Issuance Date, the redemption price will be equal to the lesser of (i) 90% of the fair market value of each redeemed Preferred Trust Unit at the date the redemption and (ii) $0.90 per redeemed Preferred Trust Unit. For each Preferred Trust Unit redeemed on a date that is later than five years from the Issuance Date, being after August 31, 2022 (the “Fifth Anniversary Date”), the redemption price will be equal to the lesser of (i) the fair market value of each redeemed Preferred Trust Unit at the date the redemption and (ii) $1.00 per redeemed Preferred Trust Unit. Payment of the redemption price by the Trust is limited to a maximum cash amount of $10,000 per month (or a greater amount, if the trustees of the Trust so decide) and any portion of the redemption price in excess of such cash amount (the “Balance”) will be repaid through the Trust’s issuance of a redemption note or an in specie distribution of the Trust’s property. If the Preferred Trust Units are redeemed by Birchcliff before the Fifth Anniversary Date, the Balance is paid by the Trust through the issuance of redemption notes due and payable prior to the sixth anniversary of the Issuance Date, being August 31, 2023. If the Preferred Trust Units are redeemed by Birchcliff after the Fifth Anniversary Date, the Balance is paid by the Trust through the issuance of redemption notes due and payable within less than a year of the date the redemption notes are issued. The Securities had a fair value of $10 million as of December 31, 2017. During the year ended December 31, 2017, Birchcliff recorded $268,000 in dividend distributions in respect of the Securities that are included in other income. 8. 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 2017 2016 578,000 569,000 16,823 11,770 594,823 580,770 (4,891) (2,806) 587,126 (6,621) (1,632) 572,517 At December 31, 2017, the Corporation’s credit facilities consisted of extendible revolving credit facilities in the aggregate principal amount of $950 million with maturity dates of May 11, 2020 (the “Credit Facilities”). 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 facility of $50 million (the “Working Capital Facility”). In May 2017, Birchcliff’s syndicate of lenders completed its semi-annual review of the Corporation’s borrowing base limit under its credit facilities. In connection with such review, the Corporation and the lenders agreed to an extension of the maturity dates from May 11, 2018 to May 11, 2020 and to the borrowing base remaining unchanged at $950 million. The Credit Facilities allow for prime rate loans, LIBOR loans, U.S. base rate loans, bankers’ acceptances and, in the case of the Working Capital Facility only, letters of credit. The interest rates applicable to the drawn loans are based on a pricing margin grid and will change as a result of the ratio of outstanding indebtedness to EBITDA as calculated in accordance with the agreement governing the Credit Facilities. EBITDA is defined as earnings before interest and non-cash items including (if any) income taxes, 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. 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 maintenance covenants. 113 2017 Annual Report 9. 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 $269.7 million (December 31, 2016 – $266.9 million) and is expected to be incurred between 2018 and 2069. A risk-free rate of 2.36% (December 31, 2016 – 2.36%) and an inflation rate of 2.0% (December 31, 2016 – 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 Obligations divested(1) Change in discount rate on acquisition Changes in estimated future cash flows(2) Accretion expense Actual expenditures Balance, ending 2017 2016 133,470 92,504 8,468 626 (45,902) - 25,902 3,055 (794) 2,772 20,072 (1,579) 22,599 (4,102) 2,547 (1,343) 124,825 133,470 (1) Primarily relates to the disposition of wells and facilities associated with the Worsley Disposition and Progress Disposition (Note 6). (2) Changes in estimated future cash flows largely due to the revision in abandonment and reclamation cost and date estimates for Birchcliff’s oil and natural gas wells and facilities. 10. INCOME TAXES Included in the income tax recovery for the year ended December 31, 2017 is a deferred income tax recovery totalling $16.9 million (2016 – $9.1 million) and a Part VI.I dividend tax totalling $3.0 million (2016 – $3.0 million) resulting from preferred share dividends paid during the period. For the purposes of determining the current and deferred income tax, the Corporation applied a combined Canadian federal and provincial income tax rate of 27% in 2017 (2016 – 27%). The components of income tax recovery are set forth below: Years ended December 31, ($000s) Net loss before taxes Computed expected income tax recovery Decrease (increase) in taxes resulting from: Non-deductible stock-based compensation Non-deductible dividends on capital securities Non-deductible expenses Other Balance, ending 2017 2016 (60,866) (30,461) 16,434 8,224 (1,275) (945) (161) (167) 13,886 (844) (945) (147) (162) 6,126 114 Birchcliff Energy Ltd. The components of net deferred income tax liabilities are set forth below: As at December 31, ($000s) Deferred income tax liabilities: P&NG properties and equipment and E&E assets Deferred financing fees Capital securities Deferred income tax assets: Decommissioning obligations Risk management contracts Share issue costs Non-capital losses Deferred income tax liabilities A continuity of the net deferred income tax liabilities is set forth below: 2017 2016 286,604 309,741 758 209 441 293 (33,703) (36,037) (1,092) (5,133) (2,547) (6,041) (164,949) (166,251) 82,694 99,599 ($000s) P&NG and E&E assets Deferred financing fees Capital securities Decommissioning obligations Risk management contracts Share issue costs Non-capital losses ($000s) P&NG and E&E assets Deferred financing fees Capital securities Decommissioning obligations Risk management contracts Share issue costs Non-capital losses Balance Jan. 1, 2017 Recognized in Profit or Loss Recognized in Equity 309,741 (23,137) Balance Dec. 31, 2017 286,604 758 209 (33,703) (1,092) (5,133) (164,949) 82,694 - - - - - - - - 317 (84) 2,334 1,455 908 1,302 (16,905) 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) - - - - - (7,446) - (7,446) 309,741 441 293 (36,037) (2,547) (6,041) (166,251) 99,599 441 293 (36,037) (2,547) (6,041) (166,251) 99,599 Balance Jan. 1, 2016 256,004 436 376 (24,976) - (520) (115,149) 116,171 As at December 31, 2017, the Corporation had approximately $2.1 billion (2016 - $2.1 billion) in tax pools available for deduction against future taxable income. Included in this tax basis are estimated non-capital loss carry forwards of approximately $609 million that expire between 2026 and 2037. 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. 115 2017 Annual Report 11. 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 Issue of common shares Exercise of stock options Outstanding at end of period(1) Series A Preferred Shares (perpetual)(2): Outstanding at beginning of period Outstanding at end of period 2017 2016 264,042 - 1,755 152,308 110,525 1,209 265,797 264,042 2,000 2,000 2,000 2,000 (1) On November 15, 2017, Birchcliff announced that the TSX had accepted the Corporation’s notice of intention to make a normal course issuer bid (the “NCIB”). Pursuant to the NCIB, Birchcliff may purchase up to 20,121,747 of its outstanding common shares. The total number of Common Shares that Birchcliff is permitted to purchase is subject to a daily purchase limit of 280,426 common shares; provided, however, that the Corporation may make one block purchase per calendar week which exceeds the daily purchase restriction. The NCIB commenced on November 20, 2017 and will terminate on November 19, 2018, or such earlier time as the NCIB is completed or is terminated at the option of Birchcliff. Purchases under the NCIB will be effected through the facilities of the TSX and/or Canadian alternative trading systems at the prevailing market price at the time of such transaction. All common shares purchased under the NCIB will be cancelled. Birchcliff did not purchase any common shares pursuant to the NCIB in 2017. (2) In August 2012, Birchcliff completed a bought deal equity financing for gross proceeds of $50 million. The Corporation issued 2,000,000 preferred units at a price of $25.00 per preferred unit for gross proceeds of $50 million. Each preferred unit was comprised of one cumulative redeemable five year rate reset Series A Preferred Share of Birchcliff, to yield initially 8% per annum; 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 paid cumulative dividends of $2.00 per Series A Preferred Share per annum for the initial five year period ending September 30, 2017. On September 30, 2017 the Series A Preferred Shares dividend was reset to $2.09 per Series A Preferred Share per annum, payable quarterly if, as and when declared by Birchcliff’s Board of Directors. Thereafter, the dividend rate will be reset every five years at a rate equal to the then current five year Government of Canada bond yield plus 6.83%. The Series A Preferred Shares were redeemable at $25.00 per preferred share at the option of the Corporation on September 30, 2017. The Corporation did not exercise the option to redeem any Series A Preferred Shares on September 30, 2017. The next opportunity for the Corporation to redeem the Series A Preferred Shares at $25.00 per preferred share is September 30, 2022 and on September 30 in every fifth year thereafter. Holders of the Series A Preferred Shares had the right, at their option, to convert their Series A Preferred Shares into cumulative redeemable floating rate Series B Preferred Shares, subject to certain conditions, on September 30, 2017. None of Birchcliff’s outstanding Series A Preferred Shares were converted into Series B Preferred Shares on September 30, 2017 as only 165,960 Series A Preferred Shares were tendered for conversion, which was less than the 250,000 shares required to give effect to conversions into Series B Preferred Shares. The next opportunity for holders of the Series A Preferred Shares to convert their Series A Preferred Shares into Series B Preferred Shares, subject to certain conditions, is September 30, 2022 and on September 30 in every fifth year thereafter. The holders of the Series B Preferred Shares will be entitled to receive quarterly floating rate cumulative preferential cash dividends, if declared by Birchcliff’s Board of Directors, at a rate equal to the sum of the then current 90 day Government of Canada Treasury Bill rate plus 6.83%. In the event of liquidation, dissolution or winding-up of Birchcliff, the holders of the Series A Preferred Shares and Series B Preferred Shares will be entitled to receive $25.00 per share as well as all accrued unpaid dividends before any amounts will be paid or any assets will be distributed to the holders of any other shares ranking junior to the Series A Preferred Shares and the Series B Preferred Shares. The holders of the Series A Preferred Shares and the Series B Preferred Shares will not be entitled to share in any further distribution of the assets of the Corporation. Capital Securities On June 14, 2013, Birchcliff completed a $50 million preferred share issue. The Corporation issued 2,000,000 cumulative redeemable Series C Preferred Shares, at a price of $25.00 per share. The Series C Preferred Shares bear a 7% dividend and their holders are entitled to receive, as and when declared by the Board of Directors of Birchcliff, fixed cumulative preferential cash dividends at an annual rate of $1.75 per share, payable quarterly. The Series C Preferred Shares are not redeemable by the Corporation prior to June 30, 2018. On and after June 30, 2018, the Corporation may, at its option, redeem for cash, all or any number of the outstanding Series C Preferred Shares at $25.75 per share if redeemed before June 30, 2019, at $25.50 per share if redeemed on or after June 30, 2019 but before June 30, 2020 and at $25.00 per share if redeemed on or after June 30, 2020, in each case together with all accrued and unpaid dividends to but excluding the date fixed for redemption. 116 Birchcliff Energy Ltd. 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. 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, 2017 (2016 – 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, 2017, the Board of Directors declared a quarterly cash dividend of $6.6 million or $0.025 per common share for the calendar quarter ending December 31, 2017. This dividend was payable to shareholders of record on December 15, 2017. On November 30, 2017, the Board of Directors declared a quarterly cash dividend of $1.0 million or $0.523375 per Series A Preferred Share and $0.875 million or $0.4375 per Series C Preferred Share for the calendar quarter ending December 31, 2017. These dividends were payable to shareholders of record on December 15, 2017. In 2017, cash dividends totalled $26.5 million or $0.10 per common share (2016 - $NIL), $4.05 million or $2.02 per Series A Preferred Share (2016 - $4.0 million or $2.00 per Series A) and $3.5 million or $1.75 per Series C Preferred Share (2016 - $3.5 million or $1.75 per Series C). All dividends have been designated as “eligible dividends” 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 Weighted average diluted common shares outstanding(1) Net loss per common share Basic Diluted 2017 2016 (46,980) (24,335) (4,047) (4,000) (51,027) (28,335) 265,182 265,182 199,581 199,581 ($0.19) ($0.19) ($0.14) ($0.14) (1) As the Corporation reported a loss for 2017 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, 2017 excludes 17,097,839 common shares issuable pursuant to outstanding stock options and performance warrants (December 31, 2016 – 15,839,507). 117 2017 Annual Report 12. 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 13. ADMINISTRATIVE EXPENSES The components of administrative expenses are set forth below: Years ended December 31, ($000s) Cash: Salaries and benefits(1) Other(2) General and administrative, gross Operating overhead recoveries Capitalized overhead(3) General and administrative, net Non-cash: Stock-based compensation Capitalized stock-based compensation(3) Stock-based compensation, net Administrative expenses, net 2017 112,287 (1,917) 110,370 116 2016 76,705 (1,700) 75,005 246 110,486 75,251 2017 2016 31,437 13,498 44,935 (202) 25,576 12,449 38,025 (154) (18,229) (16,382) 26,504 21,489 9,945 (5,886) 4,059 30,563 6,053 (3,575) 2,478 23,967 (1) Includes salaries, benefits and bonuses paid to officers and employees of the Corporation and retainer fees, meeting fees and benefits paid to directors of the Corporation. (2) Includes costs such as rent, legal, tax, insurance, minor computer hardware and software and other business expenses incurred by the Corporation. (3) Includes a portion of gross general and administrative expenses and 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 2017 8,623 2,256 10,879 2016 7,406 1,588 8,994 (1) Includes salaries, benefits and bonuses paid to officers of the Corporation and directors’ fees and benefits paid to the directors of the Corporation. (2) Represents the amortization of stock-based compensation expense in the year associated with options granted to the executive officers and directors participating in the Corporation’s Amended and Restated Stock Option Plan. 118 Birchcliff Energy Ltd. 14. 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 15. SHARE-BASED PAYMENTS Stock Options 2017 2016 28,374 30,305 3,055 1,510 2,547 1,088 32,939 33,940 At December 31, 2017, the Corporation’s Amended and Restated Stock Option Plan (the “Option Plan”) permitted the grant of options in respect of a maximum of 26,579,670 (December 31, 2016 – 26,404,190) common shares. At December 31, 2017, there remained available for issuance options in respect of 12,421,563 (December 31, 2016 – 13,504,415) common shares. For stock options exercised during 2017, the weighted average common share trading price on the Toronto Stock Exchange was $6.22 (December 31, 2016 – $7.70) per common share. A summary of the outstanding stock options is set forth below: Outstanding, December 31, 2015 Granted(1) Exercised Forfeited Expired Outstanding, December 31, 2016 Granted(1) Exercised Forfeited Expired Outstanding, December 31, 2017(1) (1) Each stock option granted entitles the holder to purchase one common share at the exercise price. Number 12,569,238 3,356,000 (1,209,363) (120,400) (1,695,700) 12,899,775 4,867,400 (1,754,796) (1,606,437) (247,835) 14,158,107 Weighted Average Exercise Price ($) 7.80 3.90 (6.28) (6.78) (11.46) 6.45 7.67 (5.33) (7.49) (7.55) 6.88 The weighted average fair value per option granted during 2017 was $2.96 (December 31, 2016 – $1.40). In determining the stock-based compensation expense for options issued during 2017, the Corporation applied a weighted average estimated forfeiture rate of 11% (December 31, 2016 – 12%). The weighted average assumptions used in calculating the Black-Scholes fair values are set forth below: Years ended December 31, Risk-free interest rate Expected life (years) Expected volatility Dividend yield 2017 1.0% 4.0 49.3% 0.1% 2016 0.6% 4.0 45.3% - 119 2017 Annual Report A summary of the stock options outstanding and exercisable under the Option Plan at December 31, 2017 is set forth below: Exercise Price ($) Awards Outstanding Awards Exercisable Weighted Average Remaining Contractual Life 3.17 2.38 1.96 2.53 Weighted Average Exercise Price ($) 3.54 7.62 10.00 6.88 Weighted Average Remaining Contractual Life 3.06 1.17 1.54 1.41 Weighted Average Exercise Price ($) 3.44 7.65 10.19 7.19 Quantity 856,041 6,033,250 147,333 7,036,624 Low 3.35 6.01 9.01 High 6.00 9.00 11.86 Quantity 2,699,002 11,281,105 178,000 14,158,107 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, 2017 (December 31, 2016 – 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. 16. 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 2017. The following table sets forth the Corporation’s total available credit: As at December 31, ($000s) Maximum borrowing base limit(1): Revolving term credit facilities Principal amount utilized: Drawn revolving term credit facilities Outstanding letters of credit(2) Unused credit 2017 2016 950,000 950,000 (594,823) (580,770) (12,184) (12,310) (607,007) (593,080) 342,993 356,920 (1) The Credit Facilities are subject to a semi-annual review of the borrowing base limit, which is directly impacted by the value of Birchcliff’s petroleum and natural gas reserves. (2) Letters of credit are issued to various service providers. The letters of credit 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 2017 and 2016. 120 Birchcliff Energy Ltd. The capital structure of the Corporation is as follows: As at December 31, ($000s) Shareholders’ equity(1) Capital securities 2017 2016 Change 1,696,153 1,754,407 49,225 48,916 Shareholders’ equity & capital securities 1,745,378 1,803,323 (3%) 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 74% 75% 11,067 27,495 594,823 580,770 605,890 608,265 (1%) 26% 25% 2,351,268 2,411,588 (3%) (1) Shareholders’ equity is defined as share capital plus contributed surplus plus retained earnings, less any deficit. (2) Of the 74%, approximately 69% relates to common capital stock and 5% relates to preferred capital stock. (3) Working capital is defined as current assets less current liabilities (excluding fair value of financial instruments). 17. 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 2017 59,821 3,544 5,937 2016 47,021 373 15,178 69,302 62,572 (1) At December 31, 2017, approximately 23% was due from one marketer (2016 – 15%, one marketer). During 2017, the Corporation received 20%, 16% and 10% of its revenue, respectively, from three core marketers (2016 – 20%, 12%, 12%, 10% and 10% of its revenue, respectively, from five core marketers). (2) At December 31, 2017 included a $3.2 million receivable for leasehold improvements. 121 2017 Annual Report 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 2017 66,901 1,637 666 26 72 2016 59,733 2,420 142 40 237 69,302 62,572 At December 31, 2017 approximately $0.07 million or 0.1% (2016 – $0.2 million or 0.4%) 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 and investment in securities 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 with a corresponding charge to profit or loss. For accounts receivable, should Birchcliff determine that the ultimate collection of an account 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, 2017 and December 31, 2016. 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 2017 (2016 - $950 million) which are reviewed semi-annually by its lenders (see Note 8). The principal amount drawn under the Corporation’s total credit facilities at December 31, 2017 was $607.0 million (2016 – $593.1 million) and $343.0 million in unused credit was available at the end of 2017 (2016 – $356.9 million) to fund future obligations. 122 Birchcliff Energy Ltd. The following table lists the Corporation’s financial liabilities at December 31, 2017 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 2018 83,039 - 4,046 87,085 2020 - 594,823 - 594,823 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 As at December 31, 2017, Birchcliff had the following financial derivative contracts in place in order to manage commodity price risk: Product Crude oil Type of contract Notional quantity Financial swap 1,500 bbls/d Crude oil Financial swap 3,000 bbls/d Fair value liabilities Term(1) Contract price Fair value ($000s) January 1, 2018 – December 31, 2018 January 1, 2018 – December 31, 2018 WTI CDN $71.85/bbl 1,300 WTI CDN $71.88/bbl 2,746 4,046 (1) Transactions with common terms and the same counterparty have been aggregated and presented at the weighted average price. The fair value liability of the Corporation’s financial derivative contracts at December 31, 2017 was $4.0 million (2016 – $9.4 million). As of December 31, 2017, 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 2017 would have increased by $1.2 million. The following table provides a summary of the realized and unrealized gains (losses) on financial derivative contracts: Years ended December 31, ($000s) Realized gain on derivatives Unrealized gain (loss) on derivatives 2017 25,785 5,387 2016 802 (9,433) There were no financial derivative contracts entered into subsequent to December 31, 2017. Physical Delivery Sales Contracts As at December 31, 2017, the Corporation had no physical delivery sales contracts in place. There were no physical delivery sales contracts entered into subsequent to December 31, 2017. 123 2017 Annual Report 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, 2017 and 2016. 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 2017 would have changed after-tax net income by approximately $4.3 million (2016 - $4.6 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, 2017 and 2016. Fair Value of Financial Instruments Birchcliff’s financial instruments include cash, accounts receivable, deposits, investment in securities, accounts payable and accrued liabilities, financial derivative contracts, outstanding credit facilities and capital securities. All of Birchcliff’s financial instruments are transacted in active markets. Financial instruments carried at fair value are assessed using the following hierarchy based on the amount of observable inputs used to value the instrument: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace. 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, 2017 are set forth below: ($000s) Loans and receivables: Cash Accounts receivable Deposits Investment in securities(1) Other liabilities: Accounts payable and accrued liabilities Fair value of financial derivatives(2) Capital Securities Drawn revolving term credit facilities (1) Investment in securities are fair valued based on level 1. (2) Financial derivative contracts are fair valued based on level 2. 124 Carrying Value Fair Value 48 69,302 1,983 10,005 83,039 4,046 49,225 48 69,302 1,983 10,005 83,039 4,046 49,920 594,823 594,823 Birchcliff Energy Ltd. 18. COMMITMENTS The Corporation enters into contracts and commitments in the normal course of operations. The following table lists Birchcliff’s commitments at December 31, 2017: ($000s) Operating leases(1) Capital commitments(2) Firm transportation, processing and fractionation(3) Commitments 2018 3,222 14,208 152,839 170,269 2019 4,491 - 125,800 130,291 2020 - 2022 Thereafter 13,790 - 457,554 471,344 24,661 - 370,455 395,116 (1) 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 $46.2 million, which includes costs allocated to base rent, parking and building operating expenses. The office lease commitment amounts disclosed in the above table have not been reduced for any rents receivable by the Corporation. (2) Includes drilling commitments and facility spending commitments relating to the VI expansion of the Pouce Coupe Gas Plant. (3) Includes the impacts from firm service transportation agreements on TCPL’s Canadian Mainline to the Southern Ontario Dawn trading hub. TCPL received approval from the National Energy Board for service on the Canadian Mainline on September 21, 2017. The Corporation has negotiated firm service for a 10-year period which commenced in November 2017. 19. 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 20. CONTINGENT LIABILITY 2017 2016 (6,730) (39,162) (621) (9,076) (3,019) (19,446) 577 44,531 (3,000) 2,946 (29,226) (5,586) 9,780 (19,446) 8,532 2,946 Birchcliff’s 2006 income tax filings were reassessed by the Canada Revenue Agency (the “CRA”) in 2011 (the “Reassessment”). The Reassessment was based on the CRA’s position that the tax pools available to Veracel Inc. (“Veracel”), prior to its amalgamation with Birchcliff, ceased to be available to Veracel after Birchcliff and Veracel amalgamated on May 31, 2005. The Veracel tax pools in dispute totalled $39.3 million. Birchcliff appealed the Reassessment to the Tax Court of Canada (the “Trial Court”) and the trial of that appeal occurred in November 2013. On October 1, 2015, the Trial Court issued its decision (the “Trial Decision”) and dismissed Birchcliff’s appeal on the basis of the general anti-avoidance rule contained in the Income Tax Act (Canada). The Trial Decision was rendered by a judge based on the written record and not by the judge who conducted the trial. As a result of the Trial Decision, Birchcliff recorded a non-cash deferred income tax expense in the amount of $10.2 million in the fourth quarter of 2015. Birchcliff appealed the Trial Decision to the Federal Court of Appeal (the “FCA”), which appeal was heard in January 2017. On April 28, 2017, the FCA issued its decision and allowed the appeal and set aside the Trial Decision, based on the lack of jurisdiction by the judge who rendered the Trial Decision. In setting aside the Trial Decision, the FCA referred the matter back to the judge of the Trial Court who initially conducted the trial in 2013 to render a judgement. The judge of the Trial Court rendered a decision in November 2017 and dismissed the Corporation’s appeal. The Corporation has appealed that decision to the FCA. 125 2017 Annual Report G L O S S A R Y DEFINITIONS Capitalized terms not otherwise defined in this Annual Report shall have the following meanings: “Birchcliff”, “its”, “our”, “us” or “we” means Birchcliff Energy Ltd. “CSA Staff Notice 51-324” means CSA Staff Notice 51-324 – Revised Glossary to NI 51-101 Standards of Disclosure for Oil and Gas Activities. “GAAP” means generally accepted accounting principles for publicly accountable enterprises in Canada which is currently in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board. “Montney/Doig Resource Play” means Birchcliff’s Montney and Doig formations resource play located northwest of Grande Prairie, Alberta. “TSX” means the Toronto Stock Exchange. “Western Canadian Sedimentary Basin” “working interest” “Worsley Disposition” 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. means the disposition of certain petroleum and natural gas properties, interests and related assets primarily located in the Worsley area on the Charlie Lake Light Oil Resource Play pursuant to a purchase and sale agreement dated August 1, 2017, which disposition closed on August 31, 2017. 126 Birchcliff Energy Ltd. ABBREVIATIONS AND CONVERSIONS Abbreviations AECO ° API bbl bbls bbls/d Bcf boe boe/d F&D FD&A FDC GJ GJ/d Mbbls Mboe Mcf MM MM$ MMBtu MMcf MMcf/d MPa NGLs TCPL WTI 000s $000s benchmark price for natural gas determined at the AECO ‘C’ hub in southeast Alberta the measure of the density or gravity of liquid petroleum products derived from a specific gravity barrel barrels barrels per day billion cubic feet barrel of oil equivalent barrel of oil equivalent per day finding and development finding, development and acquisition future development costs gigajoule gigajoules per day thousand barrels thousand barrels of oil equivalent thousand cubic feet millions millions of dollars million British thermal units million cubic feet million cubic feet per day megapascal natural gas liquids TransCanada PipeLines West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma, for crude oil of standard grade thousands thousands of dollars Conversions The following table sets forth certain conversions between Standard Imperial Units and the International System of Units (or metric units): From Mcf cubic metres bbls cubic metres feet metres miles kilometres acres hectares To cubic metres cubic feet cubic metres bbls metres feet kilometres miles hectares acres Multiply By 28.317 35.315 0.159 6.289 0.305 3.281 1.609 0.621 0.405 2.471 127 2017 Annual Report CONVENTIONS Certain terms used herein are defined in NI 51-101, CSA Staff Notice 51-324 or the COGE Handbook and, unless the context otherwise requires, shall have the same meanings in this Annual Report as in NI 51-101, CSA Staff Notice 51-324 or the COGE Handbook, as the case may be. Unless otherwise indicated, all information contained herein is given at or for the year ended December 31, 2017. Unless otherwise indicated, all dollar amounts are expressed in Canadian dollars and all references to “$”, “CDN$” or “dollars” are to Canadian dollars and all references to “US$” are to United States dollars. All financial information contained in this Annual Report has been presented in accordance with GAAP. Words importing the singular number only include the plural, and vice versa, and words importing any gender include all genders. N O N - G A A P M E A S U R E S This Annual Report uses “adjusted funds flow”, “adjusted funds flow per common share”, “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. For further details on these non-GAAP measures, please see “Non-GAAP Measures” in the MD&A. In addition, this Annual Report uses “adjusted funds flow netback” which denotes petroleum and natural gas revenue less royalties, less operating expense, less transportation and marketing expense, less net general and administrative expense, less interest expense and less any realized losses (plus realized gains) on financial instruments and plus any other cash income sources. Adjusted funds flow netback has been calculated on a per unit basis, unless otherwise indicated. Management believes that adjusted funds flow netback assists management and investors in assessing Birchcliff’s profitability and its operating results on a per unit basis to better analyze its performance against prior periods on a comparable basis. The following table provides a breakdown of adjusted funds flow netback: Twelve months ended 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 Other cash income sources Adjusted funds flow netback December 31, 2017 December 31, 2016 ($000s) $/boe(1) ($000s) $/boe(1) 556,942 (28,727) 22.45 337,586 (1.16) (20,911) (110,486) (4.45) (75,251) (71,224) 346,505 (26,504) (28,374) 25,785 268 317,680 (2.87) (42,989) 13.97 198,435 (1.07) (21,489) (1.14) (30,305) 1.03 0.02 802 - 12.81 147,443 18.73 (1.16) (4.18) (2.38) 11.01 (1.19) (1.68) 0.04 - 8.18 (1) All per boe figures are calculated by dividing each aggregate financial amount by the production (boe) in the respective period. 128 Birchcliff Energy Ltd. P R E S E N T A T I O N O F O I L A N D G A S R E S E R V E S Deloitte prepared the 2017 Consolidated Reserves Report, the 2016 Consolidated Reserves Report, the 2017 Deloitte Reserves Report and the 2016 Deloitte Reserves Report. McDaniel prepared the 2017 McDaniel Reserves Report and the 2016 McDaniel Reserves Report. In addition, Deloitte prepared reserves evaluations in respect of Birchcliff’s oil and natural gas properties effective December 31, 2015, 2014, 2013, 2012, 2011 and 2010. Such evaluations were prepared in accordance with the standards contained in NI 51-101 and the COGE Handbook that were in effect at the relevant time. Reserves estimates stated herein are extracted from the relevant evaluation. There are numerous uncertainties inherent in estimating quantities of oil, natural gas and NGLs reserves and the future cash flows attributed to such reserves, including many factors beyond the control of Birchcliff. The reserves and associated cash flow 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 cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve 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 revenues 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 the reserves and future net revenues of Birchcliff 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, 2017. RESERVES CATEGORIES Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates: • • “Proved reserves” are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. “Probable reserves” are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. INTEREST IN RESERVES, PRODUCTION, WELLS AND PROPERTIES “Gross” means: (a) in relation to Birchcliff’s interest in production or reserves, 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. 129 2017 Annual Report LEVELS OF CERTAINTY FOR REPORTED RESERVES The qualitative certainty levels referred to in the definitions on the previous page 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. 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). A D V I S O R I E S BOE CONVERSIONS Boe amounts have been calculated by using the conversion ratio of 6 Mcf of natural gas to 1 bbl of oil. Boe amounts may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. MMBTU PRICING CONVERSIONS $1.00 per MMBtu equals $1.00 per Mcf based on a standard heat value Mcf. OIL AND GAS METRICS This Annual Report contains metrics commonly used in the oil and natural gas industry, including netbacks, reserves life index, reserves per common share, 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, 2017 by 77,000 boe/d, which production rate represents the mid-point of Birchcliff’s annual average production guidance range for 2018. Reserves life index may be used as a measure of a company’s sustainability. • Reserves per common share is calculated by dividing proved developed producing reserves, proved reserves or proved plus probable reserves at the end of the period by basic common shares at the end of the period. 130 Birchcliff Energy Ltd. • 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 ratios have been presented both including and excluding the effects of acquisitions and dispositions. Reserves replacement may be used as a measure of a company’s sustainability and its ability to replace its proved developed producing reserves, proved reserves or proved plus probable reserves, as the case may be. • With respect to F&D and FD&A costs disclosed in this Annual Report: • F&D costs both including and excluding FDC have been presented herein. F&D costs for each reserves category in a particular period are calculated by taking the sum of: (i) exploration and development costs incurred in the period; and (ii) where FDC has been included, the change during the period in FDC for the reserves category; divided by the additions to the reserves category before production during the period. F&D costs exclude the effects of acquisitions and dispositions. FD&A costs are calculated in the same manner as F&D costs but include the effects of acquisitions and dispositions. • In calculating the amounts of F&D and FD&A costs for a year, the changes during the year in estimated reserves and estimated FDC are based upon the evaluations of Birchcliff’s reserves prepared by its independent qualified reserves evaluators, effective December 31 of such year. • 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. • 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 5,052.8 net existing horizontal wells and potential net future horizontal drilling locations identified herein, 846.0 are proved locations, 1,070.0 are proved plus probable locations and 3,982.8 are unbooked locations. Proved locations and probable locations are proposed drilling locations identified in the 2017 Consolidated Reserves Report that have proved and/or probable reserves, as applicable, attributed to them in the 2017 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 2017 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, the net price received for commodities produced, regulatory approvals and regulatory changes. As a result of these uncertainties, there can be no assurance that the potential future drilling locations that Birchcliff has identified will ever be drilled 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 de-risked 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. 131 2017 Annual Report INITIAL PRODUCTION (IP) RATES Any references in this Annual Report to initial production rates (e.g. IP60) 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. In addition, 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 undue reliance on such rates in calculating the aggregate production for Birchcliff. Such rates are based on field estimates and may be based on limited data available at this time. OPERATING COSTS References in this Annual Report to “operating costs” exclude transportation and marketing costs. CAPITAL EXPENDITURES Unless otherwise stated, references in this Annual Report to: (i) “net capital expenditures” and “capital expenditures, net” denote F&D costs (which includes land, seismic, workovers, drilling and completions and well equipment and facilities) plus administrative assets, plus acquisition costs, less any dispositions; and (ii) “total capital expenditures” denotes F&D costs plus administrative assets. Birchcliff’s guidance regarding its 2018 capital expenditures has been presented on a total basis. Birchcliff makes acquisitions and dispositions in the ordinary course of business. Any acquisitions and dispositions completed during 2018 could have an impact on Birchcliff’s capital expenditures, production and adjusted funds flow for 2018, which impact could be material. See also “Advisories – Forward-Looking Information” below. PAYMENT OF DIVIDENDS The declaration 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 and debt service requirements, contractual restrictions, hedging activities or programs, available investment opportunities, Birchcliff’s business plan, strategies and objectives, the satisfaction of the solvency and liquidity tests imposed by the Business Corporations Act (Alberta) for the declaration and payment of dividends and other factors that Birchcliff’s Board of Directors may deem relevant. The payment of cash dividends to common shareholders in the future is not assured or guaranteed and dividends may be reduced or suspended. Birchcliff’s dividend policy will be periodically reviewed by its Board of Directors and no assurance or guarantee can be given that Birchcliff will maintain the dividend policy in its current form. 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”, “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 financial performance, operations, focus, objectives, strategies, opportunities, priorities and goals (including the objectives identified under the heading “2018 Key Objectives” and statements that Birchcliff’s focus during 2018 will be on protecting its balance sheet, improving its already-low cost structure and paying a sustainable quarterly dividend to its shareholders, while it maintains a prudent pace of development and continues to position Birchcliff for future growth); statements regarding Birchcliff’s ability to grow when commodity prices warrant doing so, while also having the ability to maintain production in a low commodity price environment; statements regarding Birchcliff’s competitive advantage; Birchcliff’s guidance regarding its 2018 capital program and its proposed exploration and development activities and the timing thereof (including estimates of 132 Birchcliff Energy Ltd. capital expenditures in 2018, planned capital expenditures and capital allocation, the focus of, the objectives of and the anticipated results from the 2018 capital program, the number and types of wells to be drilled and brought on production, Birchcliff’s science and technology multi-well pad program, Birchcliff’s expectation that its capital expenditures during 2018 will be less than its cash flow during 2018, that Birchcliff is dedicated to strict capital discipline, the financial and operational flexibility of the 2018 capital program with the potential to accelerate or decelerate capital expenditures, Birchcliff’s expectation that, once the investment in the Phase VI expansion has been made, its facilities and infrastructure capital expenditures going forward will decrease significantly until a decision is made to build additional phases of the Pouce Coupe Gas Plant, and that the Pouce Coupe Gas Plant is a cornerstone of Birchcliff’s strategy to develop its Montney/Doig Resource Play); Birchcliff’s production guidance for 2018; the proposed Phase VI expansion of the Pouce Coupe Gas Plant (including the anticipated processing capacity of the Pouce Coupe Gas Plant after the expansion, the anticipated timing of the expansion, the anticipated cost of the expansion, that Phase VI will allow for future growth and help Birchcliff reduce its operating costs on a per boe basis and statements regarding the excess capacity at the Pouce Coupe Gas Plant and Birchcliff’s ability to fill this excess capacity); statements regarding the re-configuring of Phases V and VI to provide for shallow-cut capability (including the timing thereof, the amount of C3+ expected to be provided and the anticipated cost of this shallow-cut capability); Birchcliff’s future plans in the Elmworth area; estimates of reserves and the net present values of future net revenue associated with Birchcliff’s reserves; price forecasts; FDC; reserves life index; decline rates; estimates of future drilling locations and opportunities; the payment of dividends (including statements regarding the sustainability of dividends); the performance characteristics of Birchcliff’s oil and natural gas properties and expected results from its assets (including the expected performance of certain wells); and Birchcliff’s marketing and transportation arrangements (including its expectation that during 2018 approximately 34% of its 2018 forecast annual average natural gas production will be sold at prices that are not based on AECO, with 30% expected to be sold at the Dawn daily index price, and that additional tranches of service on TCPL’s Canadian Mainline will become available later in 2018 and 2019). 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 its 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 adjusted funds flow; 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 or other 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 Annual Report: • With respect to statements regarding the 2018 capital program (including estimates of 2018 capital expenditures and statements that 2018 capital expenditures will be less than its adjusted funds flow during 2018), such statements are based on the following commodity price assumptions during 2018: (i) an annual average WTI price of US$61.00/bbl of oil; (ii) an annual average AECO price of CDN$1.58/MMBtu of natural gas; (iii) an annual average Dawn price of CDN$3.48/ MMBtu; and (iv) an annual average wellhead natural gas price of $2.32/Mcf. • With respect to estimates of capital expenditures, such estimates assume that the 2018 capital program will be carried out as currently contemplated. See “Advisories – Capital Expenditures”. • With respect to statements that the 2018 capital program is expected to be fully funded out of 2018 funds flow from operations and that 2018 capital expenditures will be less than its adjusted funds flow during 2018, such statements assume that: the 2018 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. 133 2017 Annual Report • The amount and allocation of capital expenditures for exploration and development activities by area and the number and types of wells to be drilled is dependent upon results achieved and is subject to review and modification by management on an ongoing basis throughout the year. Actual spending may vary due to a variety of factors, including commodity prices, economic conditions, results of operations and costs of labour, services and materials. Birchcliff will monitor economic conditions and commodity prices and, where deemed prudent, will adjust the 2018 capital program to respond to changes in commodity prices and other material changes in the assumptions underlying the 2018 capital program. In addition, any acquisitions and dispositions completed during 2018 could have an impact on Birchcliff’s capital expenditures, production and adjusted funds flow for 2018, which impact could be material. • With respect to Birchcliff’s production guidance, the key assumptions are that: Birchcliff’s capital expenditure program will be carried out as currently contemplated; no unexpected outages occur in the infrastructure that Birchcliff relies on to produce its wells and that any transportation service curtailments or unplanned outages that occur will be short in duration or otherwise insignificant; the construction of new infrastructure meets timing and operational expectations; existing wells continue to meet production expectations; and future wells scheduled to come on production meet timing, production and capital expenditure expectations. In addition, Birchcliff’s production guidance may be affected by acquisition and disposition activity and acquisitions and dispositions could occur that may impact expected production. • With respect to 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 the proposed Phase VI expansion of the Pouce Coupe Gas Plant and any other proposed facilities, including the anticipated processing capacities of such facilities 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 facilities 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. 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; 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; an inability to access sufficient capital from internal and external sources; fluctuations in the costs of borrowing; 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; 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; 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; horizontal drilling and completions techniques and the failure of drilling results to meet expectations for reserves or production; uncertainties related to Birchcliff’s future potential drilling locations; 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; potential delays or changes in plans with respect to exploration or development projects or capital expenditures, including delays in the completion of Birchcliff’s gas plants and other facilities; 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 134 Birchcliff Energy Ltd. 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; risks associated with the declaration and payment of dividends, including the discretion of Birchcliff’s Board of Directors to declare dividends; the failure to obtain any required approvals in a timely manner or at all; 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; negative public perception of the oil and natural gas industry, including transportation, hydraulic fracturing and fossil fuels; management of Birchcliff’s growth; and the availability of insurance and the risk that certain losses may not be insured. 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. 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. 135 2017 Annual Report C O R P O R A T E I N F O R M A T I O N OFFICERS MANAGEMENT TEAM (cont’d) RESERVES EVALUATORS George Fukushima Manager of Engineering Andrew Fulford Surface Land Manager Paul Messer Manager of IT Tyler Murray Mineral Land Manager Bruce Palmer Manager of Geology Brian Ritchie Asset Manager – Gordondale Michelle Rodgerson Manager of Human Resources & Corporate Services Jeff Rogers Facilities Manager Randy Rousson Drilling & Completions Manager Vic Sandhawalia Manager of Finance Ryan Sloan Health, Safety & Environment Manager Duane Thompson Production Manager Hue Tran Business Development Manager Theo van der Werken Asset Manager – Pouce Coupe SOLICITORS Borden Ladner Gervais LLP Calgary, Alberta AUDITORS KPMG LLP, Chartered Professional Accountants Calgary, Alberta A. Jeffery Tonken President & Chief Executive Officer Myles R. Bosman Vice-President, Exploration & Chief Operating Officer Chris A. Carlsen Vice-President, Engineering Bruno P. Geremia Vice-President & Chief Financial Officer David M. Humphreys Vice-President, Operations DIRECTORS A. Jeffery Tonken (Chairman) President & Chief Executive Officer Calgary, Alberta Dennis A. Dawson Lead Independent Director Calgary, Alberta Debra A. Gerlach Independent Director Calgary, Alberta Rebecca J. Morley Independent Director Calgary, Alberta Larry A. Shaw Independent Director Calgary, Alberta James W. Surbey Non-Independent Director Calgary, Alberta MANAGEMENT TEAM Gates Aurigemma Manager, General Accounting Robyn Bourgeois General Counsel & Corporate Secretary Jesse Doenz Controller & Investor Relations Manager BirchcliffEnergy.com Deloitte LLP Calgary, Alberta McDaniel & Associates Consultants Ltd. Calgary, Alberta BANKERS The Bank of Nova Scotia HSBC Bank Canada National Bank of Canada Canadian Imperial Bank of Commerce Bank of Montreal The Toronto-Dominion Bank 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 2017 Annual Report 138 B I R C H C L I F F E N E R G Y L T D . 2 0 1 7 A n n u a l R e p o r t 2017 ANNUAL REPORT BIRCHCLIFF ENERGY LTD. Suite 1000, 600 3rd Avenue S.W. Calgary, Alberta T2P 0G5 Phone: 403-261-6401 BirchcliffEnergy.com 2 0 1 7 A N N U A L R E P O R T INFORMATION FINANCIAL AND OPERATIONAL HIGHLIGHTS FINANCIAL AND OPERATIONAL HIGHLIGHTS OPERATING OPERATING Average daily production Average daily production Light oil – (bbls) Light oil – (bbls) Natural gas – (Mcf) Natural gas – (Mcf) NGLs – (bbls) NGLs – (bbls) Total – boe Total – boe Average sales price ($ CDN)(1) Average sales price ($ CDN)(1) Light oil – (per bbl) Light oil – (per bbl) Natural gas – (per Mcf) Natural gas – (per Mcf) NGLs – (per bbl) NGLs – (per bbl) Total – boe Total – boe NETBACK AND COST ($/boe) NETBACK AND COST ($/boe) Petroleum and natural gas revenue(1) Petroleum and natural gas revenue(1) Royalty expense Royalty expense Operating expense Operating expense Transportation and marketing expense Transportation and marketing expense Operating netback Operating netback General & administrative expense, net General & administrative expense, net Interest expense Interest expense Other income Other income Realized gain (loss) on financial instruments Realized gain (loss) on financial instruments Adjusted funds flow netback Adjusted funds flow netback Stock-based compensation expense, net Stock-based compensation expense, net Depletion and depreciation expense Depletion and depreciation expense Accretion expense Accretion expense Amortization of deferred financing fees Amortization of deferred financing fees Gain (loss)on sale of assets Gain (loss)on sale of assets Unrealized gain (loss) on financial instruments Unrealized gain (loss) on financial instruments Dividends on Series C preferred shares Dividends on Series C preferred shares Income tax recovery (expense) Income tax recovery (expense) Net income (loss) Net income (loss) Dividends on Series A preferred shares Dividends on Series A preferred shares Net income (loss) to common shareholders Net income (loss) to common shareholders FINANCIAL FINANCIAL Petroleum and natural gas revenue ($000s)(1) Petroleum and natural gas revenue ($000s)(1) Adjusted funds flow ($000s) Adjusted funds flow ($000s) Per common share – basic ($) Per common share – basic ($) Per common share – diluted ($) Per common share – diluted ($) Net income (loss) ($000s) Net income (loss) ($000s) Net income (loss) to common shareholders ($000s) Net income (loss) to common shareholders ($000s) Per common share – basic ($) Per common share – basic ($) Per common share – diluted ($) Per common share – diluted ($) Common shares outstanding (000s) Common shares outstanding (000s) End of period – basic End of period – basic End of period – diluted End of period – diluted Weighted average common shares for period – basic Weighted average common shares for period – basic Weighted average common shares for period – diluted Weighted average common shares for period – diluted Dividends on common shares ($000s) Dividends on common shares ($000s) Dividends on Series A preferred shares ($000s) Dividends on Series A preferred shares ($000s) Dividends on Series C preferred shares ($000s) Dividends on Series C preferred shares ($000s) Capital expenditures, net ($000s) Capital expenditures, net ($000s) Revolving term credit facilites ($000s) Revolving term credit facilites ($000s) Adjusted working capital deficit ($000s) Adjusted working capital deficit ($000s) Total debt ($000s) Total debt ($000s) Three months ended Three months ended December 31, December 31, Twelve months ended Twelve months ended December 31, December 31, 2017 2017 2016 2016 2017 2017 2016 2016 5,283 5,283 385,280 385,280 10,607 10,607 80,103 80,103 4,656 4,656 289,587 289,587 7,830 7,830 60,750 60,750 6,004 6,004 320,927 320,927 8,471 8,471 67,963 67,963 3,729 3,729 247,373 247,373 4,279 4,279 49,236 49,236 68.58 68.58 2.64 2.64 40.08 40.08 22.54 22.54 22.55 22.55 (1.26) (1.26) (3.86) (3.86) (3.52) (3.52) 13.91 13.91 (1.28) (1.28) (0.97) (0.97) 1.46 1.46 0.04 0.04 13.16 13.16 (0.13) (0.13) (7.86) (7.86) (0.08) (0.08) (0.05) (0.05) 1.86 1.86 (1.86) (1.86) (0.12) (0.12) (1.42) (1.42) 3.50 3.50 (0.14) (0.14) 3.36 3.36 166,149 166,149 97,008 97,008 0.36 0.36 0.36 0.36 25,820 25,820 24,773 24,773 0.09 0.09 0.09 0.09 265,797 265,797 282,895 282,895 265,792 265,792 267,619 267,619 6,644 6,644 1,047 1,047 875 875 18,669 18,669 587,126 587,126 11,067 11,067 598,193 598,193 60.75 60.75 3.31 3.31 29.50 29.50 24.23 24.23 24.24 24.24 (1.82) (1.82) (4.54) (4.54) (2.42) (2.42) 15.46 15.46 (1.19) (1.19) (1.40) (1.40) (0.02) (0.02) - - 12.85 12.85 (0.12) (0.12) (7.73) (7.73) (0.15) (0.15) (0.06) (0.06) 0.17 0.17 (1.72) (1.72) (0.16) (0.16) (0.92) (0.92) 2.16 2.16 (0.18) (0.18) 1.98 1.98 135,457 135,457 71,806 71,806 0.27 0.27 0.27 0.27 12,085 12,085 11,085 11,085 0.04 0.04 0.04 0.04 264,042 264,042 279,881 279,881 263,396 263,396 268,974 268,974 - - 1,000 1,000 875 875 62,482 62,482 572,517 572,517 27,495 27,495 600,012 600,012 61.42 61.42 2.72 2.72 33.39 33.39 22.44 22.44 22.45 22.45 (1.16) (1.16) (4.45) (4.45) (2.87) (2.87) 13.97 13.97 (1.07) (1.07) (1.14) (1.14) 1.03 1.03 0.02 0.02 12.81 12.81 (0.16) (0.16) (7.48) (7.48) (0.12) (0.12) (0.06) (0.06) (7.50) (7.50) 0.22 0.22 (0.14) (0.14) 0.54 0.54 (1.89) (1.89) (0.17) (0.17) (2.06) (2.06) 556,942 556,942 317,680 317,680 1.20 1.20 1.19 1.19 (46,980) (46,980) (51,027) (51,027) (0.19) (0.19) (0.19) (0.19) 265,797 265,797 282,895 282,895 265,182 265,182 267,873 267,873 26,522 26,522 4,047 4,047 3,500 3,500 276,125 276,125 587,126 587,126 11,067 11,067 598,193 598,193 51.40 51.40 2.41 2.41 31.23 31.23 18.73 18.73 18.73 18.73 (1.16) (1.16) (4.18) (4.18) (2.38) (2.38) 11.01 11.01 (1.19) (1.19) (1.68) (1.68) 0.04 0.04 - - 8.18 8.18 (0.14) (0.14) (8.29) (8.29) (0.14) (0.14) (0.06) (0.06) (0.53) (0.53) (0.52) (0.52) (0.19) (0.19) 0.34 0.34 (1.35) (1.35) (0.22) (0.22) (1.57) (1.57) 337,586 337,586 147,443 147,443 0.74 0.74 0.73 0.73 (24,335) (24,335) (28,335) (28,335) (0.14) (0.14) (0.14) (0.14) 264,042 264,042 279,881 279,881 199,581 199,581 202,686 202,686 - - 4,000 4,000 3,500 3,500 762,030 762,030 572,517 572,517 27,495 27,495 600,012 600,012 THANK YOU TEAM BIRCHCLIFF THANK YOU TEAM BIRCHCLIFF Jeffrey Akeroyd, Bradley Alexander, Karen Allen, Camille Ashton, Gates Aurigemma, Valerie Babkov, Bryce Baloun, Angela Jeffrey Akeroyd, Bradley Alexander, Karen Allen, Camille Ashton, Gates Aurigemma, Valerie Babkov, Bryce Baloun, Angela Belbeck, Charmaine Belley, Tyrus Bender, Daniel Blattler, Calvin Bohdan, Angela Boire, Darryl Bolch, Deborah Borthwick, Myles Belbeck, Charmaine Belley, Tyrus Bender, Daniel Blattler, Calvin Bohdan, Angela Boire, Darryl Bolch, Deborah Borthwick, Myles Bosman, Jeff Boswell, Robyn Bourgeois, David Boyle, Wayne Brown, Madison Burns, Dave Campbell, Chris Carlsen, Alex Carlson, Bosman, Jeff Boswell, Robyn Bourgeois, David Boyle, Wayne Brown, Madison Burns, Dave Campbell, Chris Carlsen, Alex Carlson, Caitlin Carrigy, Ann Ceccanese, Bhuwan Chauhan, Matthew Chorney, Benjamin Christenson, Wendy Clay, Dallas Cline, Kalen Caitlin Carrigy, Ann Ceccanese, Bhuwan Chauhan, Matthew Chorney, Benjamin Christenson, Wendy Clay, Dallas Cline, Kalen Conrad, Mike Cordingley, Loren Damer, Dennis Dawson, Lara de Paula, Jesse Doenz, Joe Doenz, Kelly Dolen, Terrance Dyck, Conrad, Mike Cordingley, Loren Damer, Dennis Dawson, Lara de Paula, Jesse Doenz, Joe Doenz, Kelly Dolen, Terrance Dyck, Darryl Easter, Emily Ebbels, John (Cliff) Ennis, Tim Etcheverry, Lindsay Fast, Laura Ferguson, Kelsey Frechette, Grant Friesen, Darryl Easter, Emily Ebbels, John (Cliff) Ennis, Tim Etcheverry, Lindsay Fast, Laura Ferguson, Kelsey Frechette, Grant Friesen, Marshall Fritz, George Fukushima, Andy Fulford, Carrie Fyfe, Alexandra Gatza, Melina Geremia, Bruno Geremia, Debra Gerlach, Marshall Fritz, George Fukushima, Andy Fulford, Carrie Fyfe, Alexandra Gatza, Melina Geremia, Bruno Geremia, Debra Gerlach, Chad Goddard, David Graham, Lee Grant, Hannah Grigore, Ryan Gugyelka, Rylan Gulka, Tania Haberlack-Dolan, Mike Hale, Chad Goddard, David Graham, Lee Grant, Hannah Grigore, Ryan Gugyelka, Rylan Gulka, Tania Haberlack-Dolan, Mike Hale, Samuel Hampton, Trevor Harley, Richard Harris, Wanda Hiebert, Lorna Hildebrand, Warren Hingley, Jeremy Hingley, Paul Samuel Hampton, Trevor Harley, Richard Harris, Wanda Hiebert, Lorna Hildebrand, Warren Hingley, Jeremy Hingley, Paul Hirsekorn, Leah (Janet) Hogan, Jasen Holmstrom, Daryl Hudak, Dave Humphreys, Derek Jamieson, Anna Johnson, Julie Johnson, Hirsekorn, Leah (Janet) Hogan, Jasen Holmstrom, Daryl Hudak, Dave Humphreys, Derek Jamieson, Anna Johnson, Julie Johnson, Kathyrn (Katy) Josephs, Katrina Keable, Dustin Kelm, Gregory Kilgour, Phyllis Kinzner, Melissa Kinzner, Diane Knoblauch, Ashley Kathyrn (Katy) Josephs, Katrina Keable, Dustin Kelm, Gregory Kilgour, Phyllis Kinzner, Melissa Kinzner, Diane Knoblauch, Ashley Kozlowski Urch, Danny Kutrowski, Dani Laird, Anji Lawrence, Katherine Lazaruk, Heather Leahey, Calvin Leithead, Kristen Lewicki, Kozlowski Urch, Danny Kutrowski, Dani Laird, Anji Lawrence, Katherine Lazaruk, Heather Leahey, Calvin Leithead, Kristen Lewicki, Michael Lillejord, Ryan Linsley, Thomas Lundquist, Scott Lundquist, Joe Lyste, John MacGillivray, Dallas MacLean, Darcy MacLeod, Michael Lillejord, Ryan Linsley, Thomas Lundquist, Scott Lundquist, Joe Lyste, John MacGillivray, Dallas MacLean, Darcy MacLeod, Mary MacNeill, Curtis Mah, Maggie Malapad, Arun Mann, Kevin Matiasz, John Matijevich, Deb McFee, Angie McGonigal, Marc Mary MacNeill, Curtis Mah, Maggie Malapad, Arun Mann, Kevin Matiasz, John Matijevich, Deb McFee, Angie McGonigal, Marc McIntosh, Ryan McIntosh, Dani McPhee, Jennifer McPherson, Jerilyn McPherson (McLeod), Richard Melling, Paul Messer, Alfred McIntosh, Ryan McIntosh, Dani McPhee, Jennifer McPherson, Jerilyn McPherson (McLeod), Richard Melling, Paul Messer, Alfred Michetti, Derek Michetti, Emelyia Moghaddami, Rebecca Morley, Amy Morris, Stephen Morton, Steve Mueller, McKenzie Murdoch, Michetti, Derek Michetti, Emelyia Moghaddami, Rebecca Morley, Amy Morris, Stephen Morton, Steve Mueller, McKenzie Murdoch, Tyler Murray, Kody Naka, Sarah Nance, Michael Ng, Tam Nguyen, Matteo Niccoli, Christopher Olson, Laura O’Neill, Jason Orrock, Tyler Murray, Kody Naka, Sarah Nance, Michael Ng, Tam Nguyen, Matteo Niccoli, Christopher Olson, Laura O’Neill, Jason Orrock, Philomena Paisley, Bruce Palmer, Bill Partridge, Dean Paterson, Jesse Peterson, Paul Picco, Allan Pickel, Landon Poffenroth, Taylor Philomena Paisley, Bruce Palmer, Bill Partridge, Dean Paterson, Jesse Peterson, Paul Picco, Allan Pickel, Landon Poffenroth, Taylor Poole, Andrei Popescu, Austin Power, Glenn Power, Shoni Proctor, Brian Ritchie, Michelle Rodgerson, Blaine Rogers, Jeff Rogers, Poole, Andrei Popescu, Austin Power, Glenn Power, Shoni Proctor, Brian Ritchie, Michelle Rodgerson, Blaine Rogers, Jeff Rogers, Sherri Rosia, Randy Rousson, Jared Rousson, Todd Sajtovich, Lee Sallenbach, Victor Sandhawalia, Wade Schultz, Mohammad (Sadeq) Sherri Rosia, Randy Rousson, Jared Rousson, Todd Sajtovich, Lee Sallenbach, Victor Sandhawalia, Wade Schultz, Mohammad (Sadeq) Shahamat, Dan Sharp, Larry Shaw, Amy Short, Ryan Sloan, Kiran Somanchi, Hilary Steinbach, Darby Stolk, Lindsay Sturrock, Tracey Shahamat, Dan Sharp, Larry Shaw, Amy Short, Ryan Sloan, Kiran Somanchi, Hilary Steinbach, Darby Stolk, Lindsay Sturrock, Tracey Suchlandt, Tyson Suderman, Jim Surbey, Theresa Sutton (Hannouche), Ryan Swanson, Duane Thompson, Jeff Tonken, Gillian Topping, Suchlandt, Tyson Suderman, Jim Surbey, Theresa Sutton (Hannouche), Ryan Swanson, Duane Thompson, Jeff Tonken, Gillian Topping, Tammy Tran, Hue Tran, Theo van der Werken, Kara Vance, Kris Veach, Greg Vreim, Linda Wang, Michael Warrick, Shelby Watson, Matt Tammy Tran, Hue Tran, Theo van der Werken, Kara Vance, Kris Veach, Greg Vreim, Linda Wang, Michael Warrick, Shelby Watson, Matt Weiss, David Wetta, Philip Wu, John Yeo, Deirdre Yuzwa Weiss, David Wetta, Philip Wu, John Yeo, Deirdre Yuzwa (1) Excludes the effects of hedges using financial instruments but includes the effects of fixed price physical delivery contracts. (1) Excludes the effects of hedges using financial instruments but includes the effects of fixed price physical delivery contracts. 2017 Annual Report 137 2017 Annual Report 137 C O R P O R A T E I N F O R M A T I O N MANAGEMENT TEAM (cont’d) RESERVES EVALUATORS President & Chief Executive Officer Manager of Engineering OFFICERS A. Jeffery Tonken Myles R. Bosman Vice-President, Exploration & Chief Operating Officer Chris A. Carlsen Vice-President, Engineering Bruno P. Geremia Vice-President & Chief Financial Officer David M. Humphreys Vice-President, Operations DIRECTORS A. Jeffery Tonken (Chairman) President & Chief Executive Officer Calgary, Alberta Dennis A. Dawson Lead Independent Director Calgary, Alberta Debra A. Gerlach Independent Director Calgary, Alberta Rebecca J. Morley Independent Director Calgary, Alberta Larry A. Shaw Independent Director Calgary, Alberta James W. Surbey Non-Independent Director Calgary, Alberta MANAGEMENT TEAM Gates Aurigemma Manager, General Accounting Robyn Bourgeois General Counsel & Corporate Secretary Jesse Doenz Controller & Investor Relations Manager BirchcliffEnergy.com George Fukushima Andrew Fulford Surface Land Manager Paul Messer Manager of IT Tyler Murray Mineral Land Manager Bruce Palmer Manager of Geology Brian Ritchie Services Jeff Rogers Facilities Manager Randy Rousson Vic Sandhawalia Manager of Finance Ryan Sloan Health, Safety & Environment Manager Duane Thompson Production Manager Hue Tran Drilling & Completions Manager Business Development Manager Theo van der Werken Asset Manager – Pouce Coupe SOLICITORS Borden Ladner Gervais LLP Calgary, Alberta AUDITORS KPMG LLP, Calgary, Alberta Chartered Professional Accountants Deloitte LLP Calgary, Alberta Calgary, Alberta McDaniel & Associates Consultants Ltd. BANKERS The Bank of Nova Scotia HSBC Bank Canada National Bank of Canada Canadian Imperial Bank of Commerce 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 Fax: 403-261-6424 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 2017 Annual Report 138 Asset Manager – Gordondale Bank of Montreal Michelle Rodgerson Manager of Human Resources & Corporate The Toronto-Dominion Bank Alberta Treasury Branches 2017 ANNUAL REPORT B I R C H C L I F F E N E R G Y L T D . 2 0 1 7 A n n u a l R e p o r t BIRCHCLIFF ENERGY LTD. Suite 1000, 600 3rd Avenue S.W. Calgary, Alberta T2P 0G5 Phone: 403-261-6401 BirchcliffEnergy.com 2 0 1 7 A N N U A L R E P O R T INFORMATION