EXECUTING ON 25 PERCENT PRODUCTION GROWTH FROM A LEANER, LOWER COST PLATFORM

Transcription

1 EXECUTING ON 25 PERCENT PRODUCTION GROWTH FROM A LEANER, LOWER COST PLATFORM February 1,

2 CORPORATE OVERVIEW KEY STATS PRODUCTION SPLIT (DECEMBER 2017) Capitalization Market Capitalization Debt Enterprise Value $574 million $610 million $1,184 million 69% Operations and Financial December 2017 Production 20,700 boe/d Liquids Weighting 77% P Reserves (Lindbergh) 318 million boe 8% 15% 4% 4% P NPV10 (Lindbergh) $2,721 million Thermal Oil Light Oil NGLs Natural Gas Quirk Creek 2

3 TWO KEY 100 PERCENT OWNED GROWTH ASSETS Asset portfolio is focused on our Lindbergh SAGD and our Groundbirch Montney dry gas properties These assets account for approximately 90 percent of production and 95 percent of reserves Focus on oil development provides significant torque to recovering oil prices Material future upside in production, reserves and cash flow 3

4 MEANINGFUL DEBT REDUCTION IN 2017 ASSET SALES HAVE ALLOWED FOR SIGNIFICANT REDUCTION IN DEBT FROM YEAR END 2016 $1.3 billion Total debt repaid in 2017 DEBT COMPOSITION CREDIT FACILITY ($ MILLION) $610 million $501 million Term Notes $109 million Credit Facility Undrawn $221 Drawn $109 $330 $330 million credit facility Matures on March 31, 2019 Borrowing cost of 6.3 percent 4

5 BALANCE SHEET MANAGEMENT FIRST MATURITY (~CDN $56 MILLION) NOT DUE UNTIL OCTOBER 2019 LONG-TERM DEBT MATURITIES (CDN $ MILLION EQUIVALENT) $501 million of remaining term debt Remaining term notes have a weighted average interest rate of approximately 6.5% $200 $118 $128 $ Interest rate will increase by 1% starting on January 1,

6 RESTRUCTURED AND FOCUSED COMPANY ASSET SALES HAVE IMPROVED EFFICIENCIES Disposition efforts and results have led to a more efficient business model, through the sale of high cost assets and the reduction of maintenance capital and liabilities associated with these high cost legacy assets In 2017 we have: Reduced our total gross well count by 81 percent dropping from approximately 9,600 to approximately 1,800 wellbores Reduced our total gross facility count by 81 percent dropping from approximately 763 to approximately 148 facilities Reduced our gross operated pipeline kilometers by 84 percent from approximately 7,000 kilometers to approximately 1,140 kilometers In the process of reducing our full-time equivalent employee count by 75 percent from approximately 560 in 2016 to approximately 125 by end of

7 2018 CAPITAL PROGRAM DEVELOPMENT FOCUSED ON LINDBERGH TO DELIVER GROWTH 2018 capital program focused on continuing to grow Lindbergh production in bite size pieces Development program follows on similar 2017 program Characteristics of these capital programs: Optimization of existing facilities and infrastructure Small highly efficient capital bolt on projects Discreet high IRR projects that enhance production performance as well as understanding of the project 2017 and 2018 capital projects are expected to grow Lindbergh production from the current 15,000 bbl/d to approximately 18,000 bbl/d by the end of

8 ASSET PORTFOLIO 8

9 2018 CORPORATE GUIDANCE 25 PERCENT PRODUCTION GROWTH IN Average daily production (boe/d) Total capital expenditures ($ million) Corporate Guidance 22,500 to 23,500 $65 Royalties (%) 6.0% Operating costs ($/boe) $10.50 to $11.50 Cash G&A ($/boe) $3.10 to $3.35 CAPITAL ALLOCATION BY AREA $65 million Lindbergh Groundbirch Other 70 percent of 2018 capital spending is focused on Lindbergh 9

10 2018 CAPITAL BUDGET 25 PERCENT PRODUCTION GROWTH AND LOWER COST STRUCTURES 25 percent year over year production growth in 2018 with exit guidance of 24,000 boe/d 6. 3 % Reduced cost structures compared to 2017 guidance: Operating expenses lower by 17 percent from mid-point of 2017 guidance of $13.00 to $13.50/boe to a range of $10.50 to $11.50/boe G&A expenses lower by 14 percent from mid-point of 2017 guidance of $3.50 to $4.00/boe to a range of $3.10 to 3.35/boe Expect to see lower G&A costs in H2/18 to $2.46/boe, representing a decline of 34 percent from mid-point of 2017 guidance 10

11 LINDBERGH THERMAL OIL TOP TIER SAGD OPERATION Exceptional Operated SAGD Project Strong Economics Large Resource with Low Risk Growth Potential LEGEND Lindbergh Liquids pipelines Lindbergh is one of the most economic, ultra long-life SAGD projects with sizable, organic low risk growth 11

12 LINDBERGH THERMAL OIL SUBSTANTIAL UPSIDE EXPOSURE Demonstrated excellence as SAGD developer and operator Well situated in the advantaged Cold Lake oil sands region Strong base production with large growth potential Performance exceeding expectations with new 2017 well pairs just coming on production Nameplate capacity of 12,500 bbl/d with a design ISOR of 3.6x 2018 production expected to reach ~ 18,000 bbl/d Cold Lake advantages include superior bitumen quality and proximity to markets Significant economic and strategic benefits from flexible transportation agreement ~318 MMbbl of 2P reserves Regulatory approvals in place to increase production to 40,000 bbl/d Productive capacity of 40,000 to 50,000 bbl/d with full development 12

13 LINDBERGH IS A TOP QUARTILE SAGD PROJECT DEMONSTRATED SUPERIOR SOR AND WELL PRODUCTIVITY 1400 Firebag Christina Lake (CVE) 1200 Average well productivity (bbl/d) Jackfish Surmont Foster Creek Lindbergh 600 Leismer Christina Lake (MEG) Hangingstone (ATH) 400 MacKay River Tucker Orion Cold Lake Project Athabasca Project Peer Group Average More Desirable 200 Long Lake Great Divide Cold Lake (IMO CSS) Steam-Oil Ratio (SOR) 13

14 PEANUT BUTTER VS. HOCKEY PUCKS LINDBERGH: THE PERFECT COMBINATION OF RESERVOIR FLUID AND ROCK Peanut butter vs. hockey pucks Athabasca Lower API, more steam required Cold Lake/Lindbergh Higher API, less steam required 14

15 LINDBERGH THERMAL PROJECT PRODUCTION CONTINUES TO EXCEED NAMEPLATE CAPACITY 18, Scheduled plant turnaround , ,000 10, , , Steam-Oil Ratio (SOR) Bitumen Production (bbl/d) 16,000 4, , Jun-14 Dec-14 Jun-15 Dec-15 Production (bbl/d) Jun-16 SOR Dec-16 Jun-17 Nameplate Capacity (12,500 bbl/d) Production performance exceeds 12,500 bbl/d nameplate capacity of facility 2018 capital program volumes do not require incremental capital to be spent on the central processing facility Current production rates of approximately 15,000 bbl/d at a steam oil ratio of approximately 3.0, expected to increase to 18,000 bbl/d by end of

16 LINDBERGH THERMAL PROJECT GENERATING STRONG OPERATING NETBACKS $45.00 $ per bbl of bitumen at the lease $40.00 $35.00 $30.00 $25.00 $ $15.00 $22.69 $10.00 $21.72 $24.89 $24.77 $19.67 $16.93 $11.48 $5.00 $0.00 $3.05 Q Q Q Operating Netbacks Q Royalties Q Q Operating Expenses Q Q4 2017E Transportation 1. Q1, 2016 WTI crude oil price of $33/bbl, Lindbergh operation was able to generate positive cash flow netback WCS price and apportionment protection of US $16.82/bbl through 2018 provides ability to participate in WTI crude oil price increases 16

17 2017 PAD 01 PROGRAM Company Land (100%) 2017 infill capital program included: Operating Well Pads New Well Pairs Infill Well Pairs Two producing infill wells drilled and on production at a combined rate of 1,000 bbl per day New well pair on D01 currently producing 850 bbl per day All wells now on production and expected to continue to contribute to Lindbergh volume growth in 2018 Strong half-cycle economics with projected IRRs of 90% to 125% Based on WTI Crude oil US $60.00/bbl and WCS differential of US $16.82/bbl EUR (MMbbls) Capex ($MM) Capital efficiency ($/bbl/d) IRR (%) D01-infill $3.5 $6, % D01-infill $3.8 $8, % D01-03 well pair 1.3 $6.6 $9,600 90% Well 17

18 2017 PAD D04 CAPITAL PROGRAM A total of nine well pairs drilled Company Land (100%) Operating Well Pads New Well Pairs One well pair drilled to test old cyclic steam (CSS) area in section 13 Six of these well pairs are currently on production Three remaining well pairs expected to come on production in Q2, 2018 Pad D04 All wells expected to contribute to Lindbergh volume growth in 2018 Based on WTI Crude oil US $60.00/bbl and WCS differential of US $16.82/bbl Well D04 well pairs EUR (MMbbls) Capex ($MM) Capital efficiency ($/bbl/d) IRR (%) 1.3 $7.4 $11,500 84% 18

19 2018 CAPITAL GROWTH PROGRAM Approximately $45 million allocated in 2018 towards continued production growth at Lindbergh Company Land (100%) Operating Well Pads Infill Well Pairs Eight infill wells to be drilled on Pad D05 Wells expected to be drilled in second quarter of 2018 with production volumes coming on in fourth quarter of 2018 resulting in exit production of approximately 18,000 bbl/d Re-commissioning of pilot facility expected to provide incremental steam generation capacity Pad D05 Based on WTI Crude oil US $60.00/bbl and WCS differential of US $16.82/bbl Pad D01 Well D05 infill wells EUR (MMbbls) Capex ($MM) Capital efficiency ($/bbl/d) IRR (%) $12,500 76% 19

20 WHY DOES SEYMOUR SCHULICH OWN OVER 24% OF PENGROWTH The Lindbergh SAGD thermal oil project is one of the lowest cost and best in class in Canada. At the some point, sentiment will swing back to Canadian opportunities and this will be recognized and reflected in the Pengrowth share price - Seymour Schulich O.C. 20

21 SIGNIFICANT UPSIDE POTENTIAL LINDBERGH OFFERS CASH FLOW TORQUE TO INCREASING OIL PRICES AND VOLUMES WTI CRUDE OIL PRICES (US$/BBL) BBL PER DAY Lindbergh Field Operating Cash Flow (Cdn$ Million) $60 $70 $80 $90 20,000 $202 $273 $343 $413 30,000 $304 $409 $514 $620 40,000 $405 $545 $686 $826 50,000 $506 $682 $857 $1,033 Assumptions: FX WTI Differential to WCS Royalty rate Diluent expense as % of revenue Transportation Operating Costs (Cdn$/US$) (US$/bbl) (%) (%) ($/bbl) ($/bbl) $0.80 $ % 17.00% $2.90 $

22 GROUNDBIRCH MONTNEY DEVELOPMENT STRATEGIC DEVELOPMENT PLAN TO SUPPORT LINDBERGH GROWTH Pengrowth is a net consumer of natural gas for fuel needs at Lindbergh in the first quarter 2018 Groundbirch production is expected to grow from 10 MMcf/d to 30 MMcf/d effective April 1, 2018 and delivered onto the NOVA system With the new volumes from Groundbirch, Lindbergh will utilize approximately 87 percent of Pengrowth s WCSB natural gas production Pace of development at Groundbirch expected to be dependent on Lindbergh energy requirements Groundbirch Lindbergh 22

23 SUMMARY Leaner, stronger company with significant upside exposure to a recovering crude oil price Focused portfolio expected to deliver 25 percent production growth in 2018 and significantly lower cost structures versus 2017 High quality asset portfolio focused on operated thermal oil and Montney gas resource plays Long-term development plan centered on operational excellence, reduced cost structures, reduced long-term liabilities and reduced infrastructure costs 23

24 APPENDIX 24

25 APPROXIMATELY $1.0 BILLION OF PROCEEDS FROM DISPOSITIONS IN 2017 In 2017, $984 million in asset sales were completed Sold 31,500 boe per day (approximately 61 percent of 2017 original guidance) Only sold approximately 29 percent of 2P reserves 2017 Property Dispositions Gross Proceeds ($ million) Lindbergh GORR $250 January 6, 2017 Bernadet Lands $92 April 11, 2017 Swan Hills (Judy Creek) $185 July 6, 2017 Olds/Garrington $300 August 11, 2017 $- October 23, 2017 Swan Hills $150 November 3, 2017 Quirk Creek $6.5 Q4, 2017 Total Gross Proceeds $984 W4M Alberta Assets Closing Date 25

26 LINDBERGH RESERVOIR CHARACTERISTICS The Lloydminster zone is well defined across Lindbergh asset: No thick shale baffles or barriers or Inclined Heterolithic Stratification (IHS) Excellent porosity and vertical permeability throughout Well defined cap rock proven to contain steam No top gas or other thief zones Average Reservoir Characteristics Depth (m) 540 Thickness (m) 17 Porosity (%) 36% Permeability (D) 3.5 Bitumen Saturation (%) 65% Water Saturation (%) 35% Temperature (0C) 20 Pressure (kpa) 3,000 Oil Gravity (0API) (cp) <100,000 Viscosity 26

27 COLD LAKE/LINDBERGH REGIONAL ADVANTAGES COLD LAKE REGION = SUPERIOR ECONOMICS Projects in the Cold Lake region such as Lindbergh benefit from a number of significant regional economic advantage based on their bitumen quality and closer proximity to end markets LOWER BLENDING REQUIREMENTS = HIGHER REALIZED PRICE HIGHER BITUMEN QUALITY = LOWER QUALITY DISCOUNTS The higher API and lower level of contaminants (i.e. TAN, metals, sulfur, etc.) of the bitumen in the region results in materially lower quality dilbit differentials to benchmark WCS vs. heavier Athabasca bitumen» Cold Lake bitumen producers quality discounts have historically ranged from US $1.00 to $2.00/bbl vs. their Athabasca counterparts at US$ 2.50 to $5.00+/bbl» Lindbergh s production is sold as Lloyd light blend ("LLB") and its quality discount is even lower (+/-US$0.25/bbl over the last 4 quarters) Cold Lake s higher bitumen quality also results in lower diluent requirements (and costs) compared to Athabasca peers» Producers in the Athabasca region are faced with diluent blending requirements ranging between 28% - 33% to achieve Enbridge s pipeline spec depending on the project and season» Lindbergh s blend ratio ranges between 26% - 30% LOWER TRANSPORTATION COSTS = HIGHER NETBACKS Cold lake projects benefit from lower transportation costs given their closer proximity to Hardisty» Lindbergh additionally benefits from an attractive transportation agreement with Husky» Lindbergh s transportation cost is currently ~$3.00/bbl of dilbit compared to Fort McMurray SAGD projects which are expected to pay ~$5.00 to $6.00/bbl 27

28 LINDBERGH GROWTH PROFILE Current Operations (Phase 1 incl. throughput initiative & Pilot) Full Field Lindbergh (Current Operations + Phase 2 expansion) Fully Developed (Full field Lindbergh + Muriel Lake expansion) 28

29 PENGROWTH GROUNDBIRCH MONTNEY OVERVIEW MULTI-ZONE PLAY WITH LONG-TERM GROWTH POTENTIAL PGF Within the Montney fairway, Pengrowth has 19 sections (100 percent working interest) Pengrowth s Groundbrich lands have 360 net (unrisked) drilling locations Pengrowth operates a 30 million cubic feet per day facility 29

30 GROUNDBIRCH 2018 MONTNEY DEVELOPMENT Current development plan MMcf/d MMcf/d Current $18 MM Four well development program with the addition of sales compression and pipeline tie-in to Nova-Saturn meter station. First wells drilled in 2017 with completions commencing in January Multi-phase development potential Multi-phase development could increase productive capacity up to 60 MMcf/d Timeframe : Timeframe : - April 2018 Deliverables : Deliverables : 28 MMcf/d facility with production at approximately 9 MMcf/d Drill four new wells, facility upgrades and new infrastructure for additional takeaway capacity Build transportation capacity April 1, 2018 moving delivery point from Spectra System to Nova System Nova firm service expected to provide 30 MMcf/d of service capacity starting April 1, of

31 RISK MANAGEMENT Hedge positions as at January 16, 2018 Price Volume (US$/bbl) (bbl/d) Ceiling $ ,000 Floor $ ,000 Swaps $ ,000 WTI Financial Crude Oil Fixed Hedges Price Volume (US$/bbl) (bbl/d) 2018 $ , $ ,500 WCS Price Differential Fixed Hedges 31

32 SLIDE FOOTNOTES Slide 2 Market capitalization as a January 26, 2018 based on TSX closing price of $1.04 Debt as at December 31, Reserves are as estimated by GLJ Petroleum Consultants Ltd. as at December 31, 2016 December production includes Quirk Creek production volumes of approximately 1,700 boe/d. Quirk Creek was sold in late December Slide 3 Percentages are based on December 31, 2016 reserves as estimated by GLJ Petroleum Consultants Ltd Debt as at December 31, US dollar debt converted to Canadian dollar equivalent using a USD/Cdn foreign exchange rate of $1.25 and British Pound debt converted to Canadian dollar equivalent using a /Cdn foreign exchange rate of $1.70 Royalties are before impacts of commodity risk management activities Per boe estimates based on high and low ends of production guidance Slide 12 Reserves are GLJ Petroleum Consultants Ltd. estimated reserves as December 31, 2016 Slide 13 Source RBC Capital Markets as at March 31, 2017 Slide 15 Commercial production data includes former pilot well production Slide 17,18,19 Economics based on internal estimates using internal play type curves. Pricing based on WTI US $60/bbl, AECO gas price of Cdn $1.50/Gj, USD/Cdn foreign exchange rate of $1.25, WTI/WCS price differential of US $16.82/bbl Slide 21 Lindbergh operating cash flow estimates based in internal management estimates using labeled assumptions Slide 27 Tan = Total acidity number Dilbit is defined as the bitumen sales volumes plus the required diluent to meet pipeline specifications Slide 4,5 Slide 9 Quality discounts are based on Imperial Oilˈs Cold Lake Blend Diluent blending requirement represent the proportion of diluent per barrel of dilbit 32

33 ADVISORIES Caution Regarding Forward Looking Information: This presentation contains forward-looking statements within the meaning of securities laws, including the "safe harbour" provisions of Canadian securities legislation and the United States Private Securities Litigation Reform Act of Forward-looking information is often, but not always, identified by the use of words such as "anticipate", "believe", "expect", "plan", "intend", "forecast", "target", "project", "guidance", "may", "will", "should", "could", "estimate", "predict" or similar words suggesting future outcomes or language suggesting an outlook. In particular, forward-looking statements in this presentation include, but are not limited to: executing on 25% production growth predicted in 2018; the Corporation being leaner and lower cost than it historically has been; growth potential of the Lindbergh SAGD and Groundbirch Montney dry gas properties; focus on oil development providing significant torque to a recovery in oil prices; Company having material future upside in production, reserves and cash flow; borrowing cost under credit facility of 6.3%; term debt maturities and average interest costs associated therewith; focus of 2018 capital program on Lindbergh growth; plans to optimize existing facilities and infrastructure at Lindbergh; plans for small, highly efficient bolt on capital projects; 2017 and 2018 capital expenditures expected to grow Lindbergh production from 15,000 bbl/d to 18,000 bbl/d by the end of 2018; 2018 corporate guidance; anticipated 2018 exit production of 24,000 BOE/d; expected reduced cost structures in 2018 compared to 2017 guidance; WCS price and apportionment protection through 2018 and ability to participate in WTI crude oil price increases; expected contribution to Lindbergh volume growth in 2018 of 2017 wells on Pad 1 and Pad 4; expected strong half-cycle economics and projected IRRs from Lindbergh drilling; $45 million of 2018 capital allocated toward continued production growth at Lindbergh; eight infill wells to be drilled on Pad D05 at Lindbergh in 2018; timing of 2018 Lindbergh drilling and timing of volumes coming on production; plans to recommission Lindbergh pilot; expectation that sentimental swing back to Canadian opportunities which will be recognized and reflected in Pengrowth s share price; significant upside potential under various pricing and other assumptions; expectation of Pengrowth being a net consumer of natural gas in the first quarter of 2018; expected growth in Groundbirch production in the second quarter; expected move from the Spectra system to the Nova system in April 2018; expectation that Lindbergh will utilize approximately 87% of Pengrowth s WCSB natural gas production as fuel gas; pace of development at Groundbirch to be dependent upon Lindbergh energy requirements; upside exposure to recovering oil price; long-term development plans centered on operational excellence, reduced cost structures, reduced long-term liabilities and reduced infrastructure costs; expectation of Cold Lake advantages leading to lower quality discounts, higher realized prices and higher netbacks; Lindbergh growth profile; and Groundbirch 2018 Montney development plans. By their very nature, the forward-looking statements included in this presentation involve inherent risks and uncertainties, both general and specific, and risks that predictions, forecasts, projections and other forward-looking statements will not be achieved. We caution readers not to place undue reliance on these statements as a number of important factors could cause the actual results to differ materially from the beliefs, plans, objectives, expectations and anticipations, estimates and intentions expressed in such forward-looking statements. These factors include, but are not limited to: the volatility of oil and gas prices; production and development costs and capital expenditures; the imprecision of reserve estimates and estimates of recoverable quantities of oil, natural gas and liquids; Pengrowth's ability to replace and expand oil and gas reserves; environmental claims and liabilities; incorrect assessments of value when making acquisitions; increases in debt service charges; ability to remain in compliance of debt covenants and the availability of credit; the loss of key personnel; the marketability of production; defaults by third party operators; unforeseen title defects; fluctuations in foreign currency and exchange rates; inadequate insurance coverage; changes in environmental or other legislation applicable to our operations, and our ability to comply with current and future environmental and other laws and regulations; actions by governmental or regulatory authorities including changes in royalty structures and programs and income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry laws; our ability to access external sources of debt and equity capital on acceptable terms, which will be negatively impacted and our bank line made unavailable should we violate a debt covenant, and the implementation of greenhouse gas emissions legislation. Readers are cautioned that the foregoing list of factors that may affect future results is not exhaustive. When relying on our forward-looking statements to make decisions with respect to Pengrowth, investors and others should carefully consider the foregoing factors and other uncertainties and potential events. Furthermore, the forward-looking statements contained in this presentation are made as of the date of this presentation and we do not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as required by applicable law. The forwardlooking statements contained in this presentation are expressly qualified by this cautionary statement. Additional Information Supplemental Non-IFRS Measures Readers should refer to Pengrowth s most recent Annual Information Form under the heading Business Risks in the most recent year-end Management s Discussion and Analysis and most recent consolidated financial statements, management information circular, quarterly reports, material change reports and news releases for additional information with respect to the Company, its operations and risks faced. Copies of our Canadian public filings are available on SEDAR at Our U.S. public filings, including our most recent annual report form 40-F as supplemented by our filings on form 6-K, are available at In addition to providing measures prepared in accordance with International Financial Reporting Standards (IFRS), Pengrowth presents supplemental non-ifrs measures, operating netbacks and funds flow from operations. These measures do not have any standardized meaning prescribed by IFRS and therefore are unlikely to be comparable to similar measures presented by other companies. These supplemental non-ifrs measures are provided to assist readers in determining Pengrowth s ability to generate cash from operations. Pengrowth believes these measures are useful in assessing operating performance and liquidity of Pengrowth s ongoing business on an overall basis. These measures should be considered in addition to, and not as a substitute for, net income, funds flow from operating activities and other measures of financial performance and liquidity reported in accordance with IFRS. 33

34 ADVISORIES Caution Regarding Engineering Terms: When used herein, the term "boe" means barrels of oil equivalent on the basis of one boe being equal to one barrel of oil or NGLs or 6,000 cubic feet of natural gas (6 Mcf: 1 bbl). Barrels of oil equivalent may be misleading, particularly if used in isolation. A conversion ratio of six Mcf of natural gas to one boe is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In addition, 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 six to one basis may be misleading as an Indication of value. The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. In addition, Pengrowth uses the following frequently-recurring industry terms in this presentation: bbls refers to barrels, Mbbls refers to a thousand barrels, MMbbls refers to a million barrels, Mboe refers to a thousand barrels of oil equivalent, MMboe refers to a million barrels of oil equivalent, Mcf refers to thousand cubic feet, Bcf refers to billion cubic feet. Caution Regarding Reserves: All amounts are stated in Canadian dollars unless otherwise specified. All reserves, resources, reserve life index, and production information herein is based upon Pengrowth s company interest working interest share of reserves or production plus Pengrowth s royalty interest, being Pengrowth s interest in production and payment that is based on the gross production at the wellhead, before royalties and using GLJ s January 1, 2017 forecast prices and costs. Some Lindbergh specific reserves and resources information is based on a GLJ December 31, 2016 reserves and resources update and use GLJ s January 1, 2017 forecast prices and costs. Numbers presented may not add due to rounding. The estimates of reserves and future net revenues for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to effects of aggregation. When used herein, the term "boe" means barrels of oil equivalent on the basis of one boe being equal to one barrel of oil or NGLs or 6,000 cubic feet of natural gas (6 mcf: 1 bbl). Barrels of oil equivalent may be misleading, particularly if used in isolation. A conversion ratio of six mcf of natural gas to one boe is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Caution Regarding Well Test and Initial Production ( IP ) and Steam/Oil Ratios Results This presentation makes references to well test results, IP rates and steam/oil ratios for certain properties. These results are not necessarily representative of long-term well performance or ultimate recoveries and are subject to various performance factors including geological formation, duration of test, pressure and production declines. Some wells will experience significant and immediate decreases in production rates. Note to US Readers Current SEC reporting requirements permit oil and gas companies, in their filings with the SEC, to disclose probable and possible reserves, in addition to the required disclosure of proved reserves. Under current SEC requirements, net quantities of reserves are required to be disclosed, which requires disclosure on an after royalties basis and does not include reserves relating to the interests of others. Because we are permitted to prepare our reserves information in accordance with Canadian disclosure requirements, we have included contingent resources, disclosed reserves before the deduction of royalties and interests of others and determined and disclosed our reserves and the estimated future net cash therefrom using forecast prices and costs. See "Presentation of our Reserve Information" in our most recent Annual Information Form or Form 40-F for more information. We report our production and reserve quantities in accordance with Canadian practices and specifically in accordance with NI These practices are different from the practices used to report production and to estimate reserves in reports and other materials filed with the SEC by companies in the United States. We incorporate additional information with respect to production and reserves which is either not generally included or prohibited under rules of the SEC and practices in the United States. We follow the Canadian practice of reporting gross production and reserve volumes; however, we also follow the United States practice of separately reporting these volumes on a net basis (after the deduction of royalties and similar payments). We also follow the Canadian practice of using forecast prices and costs when we estimate our reserves. The SEC permits, but does not require, the disclosure of reserves based on forecast prices and costs. We include herein estimates of proved, proved plus probable and possible reserves, as well as contingent resources. The SEC permits, but does not require the inclusion of estimates of probable and possible reserves in filings made with it by United States oil and gas companies. The SEC does not permit the inclusion of estimates of contingent resources in reports filed with it by United States companies. 34

35 2100, 222 3rd Avenue SW Calgary, AB, Canada T2P 0B4 Tel Toll-Free Fax INVESTOR RELATIONS Toll-Free Website 35