Driving New Growth TSX:PGF. TD Securities Calgary Energy Conference July 10-11, 2018

Transcription

1 Driving New Growth TD Securities Calgary Energy Conference July 10-11, 2018

2 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 double-digit production growth predicted in 2018; growth potential of the Lindbergh SAGD and Groundbirch Montney dry gas properties; the Company s operational, development and capital expenditure plans; anticipated production and production growth; the Company s plans to increase surface processing capacity; deployment of low cost technologies and the anticipated benefits therefrom; the Company s cost reduction strategies and the anticipated benefits therefrom; the implementation of NCG at Lindbergh and the anticipated benefits therefrom; commodity prices; and planned drilling activities; focus on oil development providing significant torque to a recovery in oil prices; Company having material future upside in production, reserves and cash flow; focus of 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 14,000 bbl/d to 18,000 bbl/d by the end of 2018; 2018 corporate guidance; anticipated 2018 exit production of 24,000 boe/d; 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 from infill wells; 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; 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; 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; 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. 2

3 Advisories 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, enterprise value, cash G&A expenses, royalty expenses, adjusted operating expenses, operating netbacks and field operating income. 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. 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 conf idence 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, 2018 forecast prices and costs. Some Lindbergh specific reserves and resources information is based on a GLJ December 31, 2017 reserves and resources update and use GLJ s January 1, 2018 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. 3

4 Deep Value? WE LL LET YOU DO THE MATH $2,170 million 2017 Proved & Probable NPV10 $1,231 million 2017 Proved NPV10 $1,173 million Current Enterprise Value Reserves estimated by GLJ Petroleum Consultants as at December 31, Assumes WTI of $59 - $60 / bbl up to Enterprise value defined as market capitalization (July 4, 2018) plus debt (March 31, 2018). Pengrowth management believes Enterprise Value makes for easier comparisons of the relative size of Pengrowth 4

5 Growth Potential TWO WORLD CLASS LONG-LIFE ASSETS A PLATFORM FOR LONG-TERM GROWTH Groundbirch Gas High performance Montney asset Hedge and Optionality 746 Billion cf Proved & Probable Reserves (Company Interest) 50 Year Reserve Life Fort McMurray Edmonton Calgary Lindbergh SAGD Well defined thermal oil asset Driving Growth 317 Million bbl Proved & Probable Reserves (Company Interest) 26 Year Reserve Life Reserves estimated by GLJ Petroleum Consultants as at December 31, Reserve life: Groundbirch at 30 MMcf/d = 68 years; Lindbergh at 17,500 bbl/d = 50 years. Bcf Billions of cubic feet MMbbl Millions of barrels 2P Proved and Probable MMcf/d Millions of cubic feet per day bbl/d barrels per day 5

6 Growth Capacity CURRENT AND POTENTIAL PRODUCTION Groundbirch Gas Lindbergh Oil Current Production: Fort McMurray Current Production: 20 MMcf/d (Cut back from 28 MMcf/d) Productive Capacity: Edmonton 17,500 bbl/d Regulatory Approval For: 30 MMcf/d (Subject to stronger gas prices) Calgary 40,000 bbl/d (Subject to further expansion) MMcf/d Millions of cubic feet per day bbl/d barrels per day 6

7 Growth in Bites GROW OIL PRODUCTION AT LINDBERGH BY 40% TO MORE THAN 20,000 BBL/D BY Q Focus 2019 Capital on Lindbergh $45 - $125 Million WTI: $55/bbl WTI: $65/bbl Will invest within cash flow Tied to oil price environment Co-Generation Expansion Explore third party alternatives to construct and own additional cogeneration capacity to provide steam and power for further expansion in late 2020 Deploy Proven Technologies Co-injection of Non-Condensable Gas (NCG) and solvents to enhance production and lower steam-oil ratios (SOR) Free cash flow generation expected starting in 2019 Minimal capital deficits Both capital investment scenarios allow us to reach our 2020 targets due to the two year lag between investment and production. A $45 million capex would result in declining production in Free cash flow is defined as cash flow from operations less development capital. 7

8 Balance Sheet $1.1 BILLION IN DEBT PAID DOWN IN CONTINUED FOCUS ON COSTS AND DEBT $662 Million Total Debt $330 Million Credit Facility $515 Million Term note maturities Credit Facility $147 Un-Drawn $ $662M $330M $205 Term Notes $515 Drawn $ $58 $121 $ As at March 31,2018. Does not include letters of credit in the amount of $73 million. Remaining term notes have a weighted average interest rate of approximately 6.5% Interest rate will increase by 1% starting on January 1, All figures in Canadian dollars 8

9 Guidance CAPITAL PROGRAMS TO GROW LINDBERGH PRODUCTION IN BITE SIZE PIECES Lindbergh Production (average bbl/d) 16,500 17,500 to 18,000 19,500 to 20,000 Corporate Production (average boe/d) 22,500 to 23,500 22,000 to 22,500 23,000 to 24,000 Capital Expenditures ($ millions) $65 $45 to $125 Royalties 6.0% Cash G&A expenses ($/bbl) $ $3.35 Adjusted operating expenses ($/bbl) $ $11.50 Lindbergh production expected to exceed 18,000 bbl/d by the end of 2018 Corporate production volumes in 2019 and 2020 exclude Sable Offshore Energy Project volumes, curtailed Groundbirch production and any additional divestments Assumptions: AECO Cdn $ 2.00/Mcf, WCS Differential of CDN $23.25/bbl and Cdn/USD of $0.77 per BBL estimates based on high and low ends of production guidance 9

10 Lindbergh SAGD Long-life World Class Oil Asset Driving Growth US refineries prefer our thermal oil Peanut butter versus hockey pucks No similar brand competition from the US oilpatch Mexican and Venezuelan heavies declining fast 317 Million bbl Proved & Probable Reserves (Company Interest) 26 Year Reserve Life

11 Bitumen Production (bbl/d) Steam-Oil Ratio (SOR) Lindbergh SAGD STABLE PRODUCTION PROFILE 18,000 Scheduled plant turnaround 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2,000 0 Jun-14 Dec-14 Jun-15 Dec-15 Jun-16 Dec-16 Jun-17 Dec-17 Nameplate Capacity (12,500 bbl/d) Production (bbl/d) SOR CSOR COMMERCIAL PRODUCTION DATA INCLUDES FORMER PILOT WELL PRODUCTION 11

12 OPERATING NETBACK ($ PER BBL) Lindbergh SAGD GENERATING STRONG OPERATING NETBACKS $45.00 $40.00 $35.00 $30.00 $25.00 $20.00 $15.00 $10.00 $5.00 $ $22.69 $24.77 $24.89 $26.16 $21.72 $19.67 $16.93 $11.48 $3.05 Q Q Q Q Q Q Q Q Q Operating Netbacks Royalties Operating Expenses 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 Operating netback is defined as petroleum and natural gas sales less blending expense, royalties, production and operating expense and transportation expense divided by barrels of oil equivalent sales volume for the applicable period. Management of Pengrowth believes that operating netback assists in characterizing the company s ability to generate cash margin on a unit of production basis. Netback excludes corporate level WTI financial hedge impacts. 12

13 Lindbergh SAGD 2018 CAPITAL GROWTH PROGRAM $45 million (approximately) allocated in 2018 towards continued production growth at Lindbergh Wells drilled in second quarter of 2018 with production coming on in third quarter of 2018 resulting in exit production of approximately 18,000 bbl/d Re-commissioned pilot facility to provide incremental steam generation capacity Continued debottlenecking Based on WTI Crude oil US $65.00/bbl and WCS differential of US $16.82/bbl Well EUR (MMbbls) Capex ($MM) Capital efficiency ($/bbl/d) IRR (%) Each D05 infill well $12,500 96% Economics based on internal estimates using internal play type curves. Pricing based on WTI US $65/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. Internal rate of return or IRR is a rate of return measure used to compare the profitability of an investment and represents the discount rate at which the net present value of costs equals the net present value of the benefits. The higher a project s IRR, the more desirable the project. 13

14 Lindbergh Growth LINDBERGH DEVELOPMENT PLANS Pad D to 2020 development program focus: CPF Pad D03 Infill drilling and gas co-injection Pad D02 Pad D04 Infill drilling at pads D05, D02, D03 and D04 NCG injection to free up steam for new well pairs off existing pads (D01, D02 and D03) 2020 to 2022 development program focus: Pad D05 Pad D01 Solvent assisted SAGD to develop new well pads New SA-SAGD pads at D08 and D09 New D12 well pad Pad D09 Pad D12 14

15 Enhancing SAGD NON-CONDENSABLE GAS CO-INJECTION (NCG) NCG application approval received June 1, 2018 Gas co-injected into reservoir to maintain pressure Reduces injector well steam requirements 15% to 20% Freed-up steam is then available for new SAGD well pairs Add new SAGD well pairs without adding additional steam generation capacity Improved efficiency Reduction in water use and emissions INNOVATION THAT IS ALREADY PROVEN IN OTHER SAGD PROJECTS 15

16 BBL PER DAY Lindbergh Upside CASH FLOW TORQUE TO PRICE AND VOLUME WTI CRUDE OIL PRICES (US$/BBL) Lindbergh Operating Income (Cdn$ 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 $1,033 Assumptions: FX (Cdn$/US$) $0.80 WTI Differential to WCS (US$/bbl) $17.00 Royalty expense (%) 6.05% Diluent expense as % of revenue (%) 17.00% Transportation ($/bbl) $2.90 Operating expense ($/bbl) $10.50 Operating income is at the field level and only incorporates royalties, transportation, and field operating expenses. It does not reflect corporate expenses such as interest, general and administrative, etc. 16

17 Groundbirch Gas High Performance Montney Asset Hedge and Optionality 746 Billion cf Proved & Probable Reserves (Company Interest) 50 Year Reserve Life

18 Groundbirch EMERGING AS A PREMIUM MONTNEY ASSET 9 MMcf/ d 20 MMcf/ d Current development plan Field initially produced at a combined rate of 28 MMcf/d. Due to current weakness in natural gas prices, Pengrowth has elected to reduce production to approximately 20 MMcf/d. Timeframe : Start of 2018 Timeframe : Current Multi-phase development potential Multi-phase development could increase productive capacity up to 60 MMcf/d subject to a stronger gas price environment. Deliverables : 28 MMcf/d facility with production at approximately 9 MMcf/d Deliverables : Drilled four new wells, facility upgrades and new infrastructure for additional takeaway capacity Built alternative transportation capacity Moved delivery point from Spectra System to Nova System to provide 30 MMcf/d of service capacity starting April 1, Expect to utilize approximately 85 percent of natural gas production volumes from Groundbirch at Lindbergh operations. 18

19 Summary WHY INVEST IN NEW PENGROWTH? Thermal Oil company with high quality assets focused on combining growth in production and free cash flow Production growth at Lindbergh is easily attainable as a result of the low decline nature of the asset base Bite size growth projects are achievable at today s prices Location and oil quality results in access to market at fixed differentials Targeting improved capital structure SEYMOUR SCHULICH HAS INVESTED IN PENGROWTH 19

20 Summary Investor Relations: Toll-Free: MARKET INFORMATION AS AT CLOSE OF JULY 4, 2018 Capitalization Trading Symbols TSX: PGF Share Price $ Week Low-High $ $1.53 Shares Outstanding 556 million 90D Average Trading Volume 991,632 Market Capitalization Debt (as at March 31, 2018) Enterprise Value Value Metrics $512 million $661 million $1,173 million 2017 Proved & Probable NPV10 $2,170 million 2017 Proved NPV10 $1,231 million Reserves estimated by GLJ Petroleum Consultants as at December 31, For more information see Pengrowth s most recent Annual Information Form Enterprise value defined as market capitalization plus debt and Pengrowth management believes it makes for easier comparisons of the relative size of Pengrowth 20

21 Appendix

22 Guidance COMMODITY RISK MANAGEMENT CONTRACTS WTI Financial Crude Oil Hedges for 2018 Price (US$/bbl) Volume (bbl/d) Ceiling $ ,000 Floor $ ,000 Swaps $ ,000 Currently there are no WTI hedges in 2019 or beyond Fixed WCS Price Differential Physical Contracts Price (US$/bbl) Volume (bbl/d) 2018 $ , $ ,500 WCS price differential physical contracts also provide pipeline apportionment protection HEDGE POSITIONS AS OF JUNE 25,

23 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 ( 0 C) 20 Pressure (kpa) 3,000 Oil Gravity ( 0 API) Viscosity (cp) <100,000 23

24 Groundbirch Montney WELL ECONOMICS VERSUS GAS PRICES Opportunity for future growth as natural gas pricing improves Single Well Economics (Current Strip Price) At $2.00/Mcf AECO ROR = 35% NPV10 = $3 MM Payout = 3 years Reserves (Bcf) 7.5 DCET Capital ($M) 6,000 NPV10 ($M) 1,711 ROR (%) 19.2 Payout (yrs) 5 Recycle Ratio 1.74 Cost of Prod ($/boe/d) 7,800 F&D ($boe) 5.04 Numbers presented are based on internal management estimates using labeled assumptions and provide a measure of the economic returns of the development capital deployed. 24

25 Groundbirch Montney OFFSET ACTIVITY AND COMPARISON Pengrowth well Pengrowth s well was one of the top producing natural gas wells in April. Significant industry activity offsetting Pengrowth s Groundbirch lands Numbers presented are based on internal management estimates using labeled assumptions and provide a measure of the economic returns of the development capital deployed. 25