PEMBINA PIPELINE CORPORATION

Transcription

1 PEMBINA PIPELINE CORPORATION DOING THE IMPORTANT THINGS RIGHT December 2015 Corporate Update Presentation TSX: PPL; NYSE: PBA

2 Forward-looking statements & information This presentation is for information purposes only and is not intended to, and should not be construed to constitute, an offer to sell or the solicitation of an offer to buy, securities of Pembina Pipeline Corporation ("Pembina"). This presentation and its contents should not be construed, under any circumstances, as investment, tax or legal advice. Any person accepting delivery of this presentation acknowledges the need to conduct their own thorough investigation into Pembina and its activities before considering any investment in its securities. This presentation contains certain forward-looking statements and information that are based on Pembina's expectations, estimates, projections and assumptions in light of its experience and its perception of historical trends as well as current market conditions and perceived business opportunities. In some cases, forward-looking information can be identified by terminology such as "expects", "anticipates", "plans", "potential", "will", "continue", and similar expressions suggesting future events or future performance. In particular, this presentation contains forward-looking statements, including certain financial outlooks, pertaining to financial and business objectives, corporate strategy (capital expenditures, schedules, expected capacity, approval and contracting strategy and expectations with respect to current and potential projects), the timing of regulatory and environmental approvals, financial performance and future financing sources, the stability and sustainability of cash dividends, expansion and diversification opportunities, expectations regarding future commodity market supply, demand and pricing and supply and demand for hydrocarbon services. Undue reliance should not be placed on these forward-looking statements and information as they are based on assumptions made by Pembina as of the date hereof regarding, among other things, industry conditions, the availability and sources of capital, operating costs, the ability to reach required commercial agreements, and the ability to obtain required regulatory approvals. While Pembina believes the expectations and assumptions reflected in these forwardlooking statements are reasonable as of the date hereof, there can be no assurance that they will prove to be correct. Forward-looking statements are subject to known and unknown risks and uncertainties which may cause actual performance and financial results to differ materially from the results expressed or implied, including but not limited to: the impact of competitive entities and pricing; reliance on key alliances and agreements; the strength and operations of the oil and natural gas industry and related commodity prices; regulatory environment; fluctuations in operating results; the availability and cost of labour and other materials; the ability to finance projects on advantageous terms; and tax laws and tax treatment. Additional information on these factors as well as other factors that could impact Pembina's operational and financial results are contained in Pembina's Annual Information Form and Management's Discussion and Analysis, and described in our public filings available in Canada at and in the United States at Readers are cautioned that this list of risk factors should not be construed as exhaustive. The forward-looking statements contained in this document speak only as of the date of this document. Except as expressly required by applicable securities laws, Pembina and its subsidiaries assume no obligation to update forward-looking statements and information should circumstances or management's expectations, estimates, projections or assumptions change. The forward-looking statements contained in this document are expressly qualified by this cautionary statement. Readers are cautioned that management of Pembina approved the financial outlooks contained herein as of the date of this presentation. The purpose of the financial outlooks contained herein is to give the reader an indication of the value of Pembina's current and anticipated growth projects. Readers should be cautioned that the information contained in the financial outlooks contained herein may not be appropriate for other purposes. In this presentation, we refer to certain financial measures such as EBITDA, total enterprise value ("TEV") and operating margin that are not determined in accordance with International Financial Reporting Standards ("Canadian GAAP"). For more information about these non-gaap and additional GAAP measures, see the Appendix to this presentation. All financial information is expressed in Canadian dollars unless otherwise specified. 2

3 Pembina: a unique investment opportunity Pure play energy infrastructure company that allows investors to participate in the oil and natural gas liquids industry across Canada and North Dakota. We: are well-positioned for growth have a strong demand for our services have a solid and sustainable business platform with only moderate exposure to commodity prices TSX: PPL NYSE: PBA Common shares outstanding (1) 372 million TSX common share trading price (1) $31.49 TSX 52-week trading range (1) $ $44.32 Market capitalization (1) $11.7 billion Total enterprise value (1) $15.9 billion Common Share Dividend $1.83/share annualized ($0.1525/share monthly) Yield (1) 5.8% Corporate credit rating BBB (S&P and DBRS) Member of the TSX/S&P 60 One of the largest energy infrastructure companies in Canada with a sector leading secured growth platform See "Forward-looking statements & information. (1) As at December 1, 2015, Market capitalization includes common shares. TEV includes convertible debentures, preferred shares and senior debt. See "Non-GAAP and additional GAAP measures." 3

4 Our assets and businesses at a glance Conventional Pipelines 9,000+ km network transports hydrocarbon products and extends across much of Alberta and parts of British Columbia, Saskatchewan and North Dakota Midstream 73 mbpd Redwater fractionator; 20 truck terminals; 13.7 MMbbl storage; product marketing; 2.4 bcf/d extraction; Nexus Terminal hubs Gas Services 468 MMcf/d shallow cut gas processing capacity; 799 MMcf/d deep cut gas processing capacity; 400+ km of gathering pipelines Gas Processing Plant Redwater Fractionator Midstream Storage Facility Truck Terminal Pembina Conventional Pipelines Pembina Oil Sands Pipelines Third Party Pipelines Oil Sands & Heavy Oil 1,650 km of pipelines with 880 mbpd of contracted capacity Continental presence with focus on Western Canadian Sedimentary Basin and Bakken 4

5 Integrated, customer-focused value chain Gas/HVP Value Chain: Gas Services Conventional Pipelines Midstream Gathering and processing Mainline Extraction Transportation on Conventional Pipelines Fractionation Storage, logistics, distribution Production Gathering, Processing, Field Extraction HVP Feeder Pipelines Terminalling & Marketing Fractionation Logistics & Distribution Propane export Consumption Oil/Condensate/LVP Value Chain: Truck and full-service terminals Pipeline transportation Storage, logistics, distribution Production Mining/In-situ Midstream Field Terminalling &Treatment Upgrading Conventional & Oil Sands Pipelines LVP Feeder Pipelines Midstream Terminalling & Marketing Diluent Logistics & Distribution Refining Spec Products Logistics & Distribution Consumption Business Unit integration creates an exceptional customer service 5

6 Our business operates in prolific geology ALBERTA SASKATCHEWAN MONTNEY (Resource Life ~170 years) TAYLOR FORT MCMURRAY OIL SANDS (Resource life 200+ years) SEAL & PELICAN LAKE DEEP BASIN (Resource Life ~23 years) SWAN HILLS Fort Saskatchewan DUVERNAY (Resource Life ~500 years) EDMONTON CARDIUM (Resource Life ~40 years) Conventional Pipelines Oil Sands & Heavy Oil Pipelines Gas Processing Plants Redwater Fractionator KAMLOOPS CALGARY EMPRESS MONTANA Strong franchise areas create competitive advantages TIOGA, NORTH DAKOTA NORTH DAKOTA WILLISTON BASIN (Resource Life 68 years) Map for illustrative purposes only. Does not include US drilling activity. See "Forward-looking statements & information. 6

7 We are pursuing a fee-for-service growth portfolio Projects (all fee-for-service) In Service Capital (C$MM) Phase II NGL/Crude Expansions $660 SEEP $100 Saturn II Facility $150 Other projects (incl. Resthaven gathering pipeline) $ Assets In Service Subtotal $ 1,150 Phase III Pipeline Expansions (1) Mid 2017 $2,440 NEBC Expansion (1) Late 2017 $220 Vantage Expansion Q $85 Laterals Various $320 Conventional Pipelines Subtotal $3,065 Musreau III Facility Early 2016 $100 Resthaven Expansion (2) Mid 2016 $105 Duvernay I (1) H $125 Gas Services Subtotal $330 Cavern Development Various $105 Canadian Diluent Hub(1) Mid 2017 $350 Terminal and Hub Services Various $85 RFS II Fractionator Q $415 RFS III Fractionator Q $400 Sturgeon Refinery Terminalling Project (1) Mid 2017 $180 Other (1) Various $260 Midstream Subtotal $1,795 Horizon Expansion (1) Mid 2016 $125 Cheecham Expansion Mid 2016 $15 Oil Sands & Heavy Oil Subtotal $140 Committed Capital $5,330 Proposed Marine Terminal (USD) (3)(4) $500 Uncommitted Opportunities $1,000 Total Unrisked Capital Opportunities $6,980 Committed Capital / Current TEV 40% 35% 30% 25% 20% 15% 10% 5% - 34% Relative Growth Project Portfolio Pembina has the largest committed growth capital program compared to any of its Canadian peers on a relative basis through the end of % 18% 17% 17% 15% 3% Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Source: Company filings, Street Research (peers include: ALA, ENB, IPL, KEY, TRP, VSN). (1) Subject to regulatory and environmental approval. (2) If Resthaven partners participate in expansion, Pembina s capital will decrease to $75 million. Over $5 billion in committed projects underway (3) Subject to project sanctioning, reaching commercial agreements and regulatory and environmental approvals. (4) Converted to CAD based on $1.30 exchange rate: $500 US = $650 CAD. See "Forward-looking statements & information" and "Non-GAAP & additional GAAP measures." 7

8 Project timelines & in-service dates Committed Capital Expected In-Service Date* Expected Project Timelines* $4.5 $4.0 $3.5 $1.2 billion of capital expected to be put into service in 2016 $4.0 BB SEEP Saturn II Phase II Expansion RFS II Musreau III $3.0 Resthaven Expansion Terminal & Hub Services $BB $2.5 $2.0 Horizon Expansion Vantage Expansion Cheecham Expansion Phase III Expansion $1.5 $1.0 $1.1 BB $1.2 BB Laterals RFS III Cavern Development Canadian Diluent Hub $0.5 Sturgeon Refinery 660 ### NEBC Expansion Gas Services Midstream Conventional Pipelines Oil Sands & Heavy Oil Duvernay I Other Overall project portfolio is tracking on time and on budget to meet 2018 objective *Expected in-service dates are shown in the most conservative outcome. Actual capital in-service dates may be different than what is shown here depending on regulatory approval and construction See "Forward-looking statements & information. 8

9 We are committed to a low risk business platform $100-$150 million $600-$950 million of incremental annual run-rate EBITDA of potential incremental annual run-rate EBITDA in-service throughout 2015 (1) once Pembina s committed projects are all in-service (4) 14% 22% ~12% - 19% ~1% - 3% 19% 67% 78% ~80% - 85% (2) 2018 (3) Fee-for-Service / Cost-of-Service Product Margin Frac Spread In excess of 80% of EBITDA is expected to be generated from fee-for-service contracts in 2018 (1) Based on approximately $1.1 billion of capital projects (once fully commissioned) that were (2) 2015 is based on year-to-date actual results as of September 30, placed into service during 2015 compared to Upper end of range depending on utilization (3) Illustrative contribution by contract type, the actual results may vary depending on asset above take-or-pay levels. utilization and pricing. (4) Based on approximately $5.2 billion of committed capital projects with in-service dates between 2016 and end of Upper end of range depending on utilization above take-or-pay levels. See "Forward-looking statements & information" and "Non-GAAP & additional GAAP measures." 9

10 Evolution of Pembina s acquisitions EV/NOI multiple at acquisition date Current EV/NOI multiple 12.0x 11.6x 11.6x 11.5x 12.0x 10.0x 10.0x 10.0x 10.0x 8.6x 9.8x 8.4x 8.0x 8.0x 6.8x 7.1x 6.0x 6.0x 4.0x 4.0x 2.0x 2.0x 0.0x Cutbank Edmonton North Complex (2009) Terminal (2011) (1) (2) Provident Energy (2012) Vantage Pipeline (2014) Weighted Average 0.0x Cutbank Complex (3) (4) (1) Edmonton North Termin al Provident Energy (2) (3) Vantage Pipeline (4) Weighted Average Then And now. History of driving incremental shareholder value from acquisitions (1) Includes the expansion of Musreau Facility (Musreau II and Musreau III). (2) Includes expansion to the terminalling and storage facilities. (3) Includes the fractionator expansions at Redwater (RFS II & RFS IIII). (4) Includes the Vantage Pipeline system expansion & 100% interest in SEEP. See "Forward-looking statements & information" and "Non-GAAP & additional GAAP measures." 10

11 $2.50 $2.00 Dividend growth supported by growing cash flow 9.1% CAGR in ACFPS (1) % CAGR in Dividend per Share $1.50 $1.00 $0.50 $ Dividends per share Adjusted cash flow from operating activities per share Strong history of growing Pembina s dividend and adjusted cash flow per share (1) See "Forward-looking statements and information" and "Non-GAAP & additional GAAP measures." Incremental EBITDA based on approximately $6 billion of committed capital projects with in-service dates between end of 2014 and end of Upper end of range depending on utilization above take-or-pay levels. 11

12 BUSINESS OVERVIEW

13 Contract overview by business Conventional Pipelines Pembina is flexible to offer commercial framework to support customers needs Standard terms for pipeline transportation agreements include: Longer-term take-or-pay volume commitment (10+ years) Fixed capital toll subject annual inflation adjustment Operating fee to cover power and other variable operating costs Oil Sands & Heavy Oil Pembina s standard terms for oil sands and heavy oil agreements include: Longer term contracts (10+ years) Fixed return or cost-of-service Contracts provide flow through of eligible operating expenses No volume risk Gas Services Pembina is flexible to offer commercial framework to support customers needs Standard terms for gas processing agreements include: Longer-term take-or-pay volume commitment (5+ years) Payment of fixed capital fee on volume processed Payment of pro-rata share of facility operating costs Producer retains 100% of the value of the liquids produced at plant Other potential commercial considerations include: Anchor tenant benefits Alternative contract structures ROFR on available capacity Midstream Standard terms for NGL fractionation agreements include: Longer-term take-or-pay volume commitment (10 years) Payment of fixed capital fee on volumes & pro-rata share of facility operating costs Pembina markets finished products across its network significant value uplift for producers given Pembina s extensive marketing infrastructure and expertise Crude oil product margin Enter into buy/sell agreements for product while in transport on conventional pipelines; truck terminal and full service terminal fees; storage fees Low risk contracting strategy 13

14 Conventional Pipelines overview ALBERTA Pipeline operational excellence: 97% reliable (Q1 Q3 2015) Proximal to prolific geology TAYLOR FORT ST JOHN GRANDE PRAIRIE DUNVEGAN VALLEYVIEW SWAN HILLS FORT MCMURRAY Q throughput: 600 mbpd (~6% increase from Q3 2014) 2014 throughput: 575 mbpd (~17% increase from 2013) Connected to refineries, export pipelines, fractionation and petrochemical facilities Diverse producers and product type with over 300 receipt points WHITECOURT DRAYTON VALLEY FORT SASKATCHEWAN EDMONTON EMPRESS, ALBERTA KAMLOOPS CAROLINE EMPRESS VANTAGE PIPELINE SEEP TIOGA, NORTH DAKOTA NEBC/Western System Peace System Drayton Valley System Liquids Gathering System (LGS) Northern System Swan Hills System Bonnie Glen System (50% Operated) Brazeau NGL System Leader in conventional hydrocarbon products gathering business 14

15 Our throughput continues to grow 700 Solid industry performance and strategically located assets have led to strength in Pembina's throughput profile February 2015: reached a weekly all-time high peak throughput of over 650,000 bpd 575 mbpd 612 mbpd mbpd 492 mbpd mbpd 374 mbpd 417mbpd Mbpd Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Crude & Condensate NGL Year-to-date 2015 throughput highest in Pembina's history 15

16 Phase III Expansion, Phase II Expansion and Lateral Program Phase III Expansion Phase II HVP& LVP Expansions ALBERTA Phase III Expansion (under construction) Completed Phase III Expansion segment Previously announced Phase II Expansion Pembina crude oil and condensate pipelines Pembina NGL pipelines Project consisted mainly of pump stations, storage enhancements and pipeline reconfiguration work Phase II LVP in service in April 2015, HVP inservice September 2015 WAPITI LA GLACE Other Pembina pipelines Pipeline Laterals Phase II HVP Pump Station (new/upgrade) Phase II LVP Pump Station (new/upgrade) Phase III Expansions Capital investment of $2.44 billion Initial capacity of 420 mbpd between Fox Creek and Edmonton with ability to increase to over 680 mbpd 880 km total of new pipeline (previously 540 km) with four distinct lines that can separately transport C2+, C3+, condensate and crude oil FOX CREEK BRITISH COLUMBIA KAKWA SIMONETTE NAMAO FORT SASKATCHEWAN EDMONTON Pipeline Lateral Program Focus on Montney, Duvernay, Cardium, Deep Basin Cost-of-service or firm-service with take-or-pay provisions Undertaking significant construction across systems; Low-risk pipeline lateral program captures new geology to Phase III 16

17 1,600 Conventional Pipeline expansions could bring Alberta capacity to ~1.5 million bpd ~1,500 mbpd 1,400 1,200 1, Mbpd Pre Expansion (2010) Phase I (In-Service) Phase II (In-Service) Phase III (mid 2017) Phase III (ultimate capacity) Phase III (combined system capacity) Crude Oil & Condensate NGL Project under development Uncommitted projects Visibility to almost tripling capacity on conventional pipelines See "Forward-looking statements & information." Phase III Expansions are subject to regulatory and environmental approval. 17

18 Oil Sands & Heavy Oil overview Syncrude Pipeline Horizon Pipeline Cheecham Lateral Nipisi Pipeline Mitsue Pipeline Peace Pipeline Operational excellence 99+% reliable (Q1 Q3 2015) Diverse connectivity to various industry hubs for crude oil and condensate Contracts are long-life with high credit worthy counterparties Expansions underway on both Horizon and Cheecham PIPELINE SYSTEM SYNCRUDE HORIZON CHEECHAM NIPISI & MITSUE Total Capacity (bpd) 389, ,000 (1) 136, ,000 Contract Type Cost-of-Service Fixed Return Fixed Return Fee-for-Service Initial Term 25+ years 25+ years 25+ years 10+ years Map for illustrative purposes only, using third-party info. Shippers Syncrude Partnership: Canadian Oil Sands 37% Imperial Oil 25% Suncor 12% Sinopec 9% Nexen 7% Murphy 5% Mocal 5% CNRL Conoco Total CNOOC CNRL Cenovus Pembina Midstream (1) Denotes ultimate capacity with the addition of pump stations, announced June 2, See Forward-looking statements & information. Large-scale asset base supporting some of Canada s largest oil sands projects 18

19 New Horizon Pipeline System expansion Expanding the existing Horizon Pipeline System to 250 mbpd as requested by the anchor tenant CNRL (1) Expansion includes upgrading of mainline pump stations and other facility modifications for an expected capital cost of $125 million Expected to be in-service mid-2016, subject to regulatory and environmental approval Horizon, a 513 km pipeline, was originally commissioned in 2008 under a 25-year fixed return contract to connect CNRL s Horizon Oil Sands facility to refineries, export pipelines and other delivery locations (1) Canadian Natural Resources Limited (CNRL). See Forward-looking statements & information. Supports long-term growth of fixed-return, low-risk cash flow streams 19

20 Gas Services overview CUTBANK COMPLEX (MUSREAU I & II) RESTHAVEN SATURN I & II DUVERNAY I ALBERTA FORT MCMURRAY EDMONTON Operational excellence 100% reliable (Q1 Q3 2015) Positioned in active and emerging NGL rich plays Provide gas gathering, compression and shallow/deep cut processing services Nine facilities in service Q average processing volume: 690 MMcf/d (62% increase from Q3 2014) Recently placed into service: Saturn II and SEEP Constructing new projects: Musreau III, Resthaven Expansion and Duvernay I KAMLOOPS CALGARY Gas Processing Plant Redwater Fractionator Pembina Pipelines Leader in conventional third-party gas processing Maps for illustrative purposes only (does not show SEEP). 20

21 Growing volumes in Gas Services Q4: Saturn I (200 MMcf/d) 2014 Q4: Musreau II (100 MMcf/d) 2014 Q4: Resthaven (134 MMcf/d (1) ) 2015 Q3: SEEP (60 MMcf/d) 2015 Q3: Saturn II (200 MMcf/d) 500 MMcf/d Q Q Q Gas processing volume Gas Services is one of Pembina's fastest growing businesses (1) Current Resthaven Facility gross capacity is 200 MMcf/d,134 MMcf/d net to Pembina. (2) Volumes at Musreau exclude deep cut processing as those volumes are counted when they are processed through the shallow cut portion of the plant. (2) 21

22 Duvernay I gas plant development Development of a new 100 MMcf/d shallow cut gas plant, with expected NGL extraction capacity of ~5,500 (1) bpd Facility will be located near Pembina s Fox Creek Terminal Underpinned by a large, diversified, investment grade customer Expected capital cost of ~$125 million, including incremental pipeline lateral capital Integrated & repeatable project development approach: 1. Substantial take-or-pay agreement supporting gas plant 2. NGL transportation as part of Peace Phase III expansion 3. NGL fractionation at Pembina s Redwater complex 4. Leverages similar design of Musreau II and III gas plants Expected to be in service in the second half of 2017 (2) Duvernay I will be the first large-scale gas processing plant designed specifically for the Duvernay (1) Subject to gas compositions. (2) Subject to regulatory and environmental approval. See Forward-looking statements & information. Establishes a new growth platform and supports the development of the Duvernay 22

23 Field processing capacity expanding to meet customer demand 1,800 1,600 1,400 increase in capacity since ~300% Gas Service s inception ,567 MMcf/d , MMcf/d 1, Mbpd (NGL & C5) Cutbank Musreau Deep Cut Shallow cut Expansion Resthaven Saturn Musreau II SEEP Saturn II Resthaven Expansion (mid 2016) (1) Musreau III (mid 2016) Duvernay I (H2 2017) Total In-Service Under Construction NGL and C 5 output (bpd) Working to become Canada s largest third party gas processing company (1) If partners participate in Resthaven expansion, Pembina s net capacity will be reduced to 69 MMcf/d. See "Forward-looking statements & information." 23

24 NGL Midstream overview Redwater West: 73 mbpd NGL fractionator and 7.3 mmbbls of finished product cavern storage Industry-leading rail-based terminal (largest NGL rail yard in Canada) with unit train capability 320 MMcf/d (net to Pembina) Younger extraction and fractionation facility in northeast B.C. Empress East: 2.4 bcf/d capacity in the straddle plants at Empress, Alberta 20 mbpd of fractionation capacity and 1.1 mmbbls of cavern storage in Sarnia, Ontario Ownership of 5.3 mmbbls of hydrocarbon storage at Corunna, Ontario 14 MMbbl (net) commercial cavern storage Gas Processing Plant Redwater Fractionator Midstream Storage Facility Truck Terminal Rail Terminal Pembina Pipelines Third Party Pipelines Corunna Pembina has a leading position in Canadian NGL markets Maps for illustrative purposes only. 24

25 Significantly growing our NGL fractionation capacity ~257 mbpd RFS II New $415 million 73 mbpd C2+ fractionator Committed take-or-pay revenue streams for 10-year term from in-service date, for 97% of the operating capacity Expected on-stream date in Q mbpd Ethane produced at RFS II will be sold under a longterm arrangement with a major NGL consumer Sarnia & RFS I 8 RFS Debottleneck 9 RFS C3+ Debottleneck (Q1 2016) RFS II (Q1 2016) RFS II C3+ Debottleneck (TBD) RFS III (Q3 2017) RFS III Deethanizer (TBD) In-service assets Projects under development Uncommitted projects Total RFS III New $400 million 55 mbpd C3+ fractionator Underpinned by long-term take-or-pay contracts with multiple producers Leverage design and engineering work completed for RFS I and RFS II Expected to be in-service in the Q Aim to triple Pembina s fractionation capacity at Redwater with RFS III See "Forward-looking statements & information." 25

26 Terminalling services for Sturgeon Refinery Provide terminalling services for Sturgeon Refinery (North West Redwater Partnership) under a 30-year fixed return agreement and a 10-year NGL mix purchase and sale agreement related to RFS III Expected capital cost of $180 million to construct terminalling facilities, including: truck and rail loading, storage and handling and processing equipment for a variety of products Facilities are expected to be in-service mid-2017, subject to regulatory and environmental approval Creating value for our customers by leveraging our existing integrated suite of assets See "Forward-looking statements & information." 26

27 NGL salt cavern storage potential ~28 MMbbls Substantial storage cavern development potential Cavern development: At Redwater 12 caverns in-service 2 in development Significant demand in west and east In Service RFS Under Development RFS Growth Potential Corunna Growth Potential See "Forward-looking statements & information." Pembina continues to steadily wash caverns 27

28 Crude Oil Midstream overview TAYLOR PRINCE GEORGE Gas Processing Plant Redwater Fractionator Midstream Storage Facility Truck Terminal Rail Terminal Midstream Operations Other Pembina Pipelines Third Party Pipelines ALBERTA ALBERTA EDMONTON PEMBINA NEXUS TERMINAL CALGARY FORT MCMURRAY FORT SASKATCHEWAN Develop and provide terminal, hub & storage services to support the energy industry 310 mbbl of above ground crude oil and condensate storage capacity, with 550 mbbl under construction; expansion potential to 1,500 2,000 mbbl Access to approximately 1.2 mmbpd through connected pipelines Revenue generated from multiple service offerings and commodity types Opportunities exist in various market conditions One of Canada s largest crude oil marketing businesses Maps for illustrative purposes only (does not show SEEP). 28

29 STRONG FINANCIAL PLATFORM

30 Financial objectives overview Finance growth ~50/50 debt/equity Maintain BBB rating with conservative balance sheet metrics Manage through the investment cycle Ensure ample liquidity to fund capital program Ensure financing flexibility to respond to market conditions Pembina continues to have excellent access to capital See "Forward-looking statements & information." 30

31 Access to capital at attractive rates Medium term notes (2013-YTD) Preferred shares (2013-YTD) Common shares (2013-YTD) $700 $600 $600 $600 $600 $700 $600 $700 $600 $500 $500 $500 $460 $MM $400 $300 $200 $200 $MM $400 $300 $200 $250 $150 $250 $250 $225 $MM $400 $300 $200 $345 $286 $321 $266 $274 $100 $100 $100 - Apr-2013 Apr-2014 Feb-2015 Jun-2015 $600 MM $500 MM 12-year notes at 4.24% $100 MM 30-year (1) notes at 4.75% $600 MM $450 MM 10-year notes at 3.54% $150 MM 30-year (1) notes at 4.75% $600 MM 30-year notes at 4.81% $200 MM 30-year notes at 4.75% - Jul-2013 Oct-2013 Jan-2014 Sep-2014 Apr-2015 Size ($MM) Rate (%) Rate reset spread (%) Mar DRIP 2014 DRIP Oct Q1- (Common Shares) (Vantage Acquisition) Q3 DRIP Nov-2015 (Common Shares) $345 MM common shares (2013) DRIP participation rate 57% in 2014 $286 MM raised in 2013 $321 MM raised in 2014 $274 MM raised YTD 2015 (Q1 Q3) $266 MM Vantage acquisition $460 MM common shares (2015) Pembina has access to multiple sources of capital (1) Series 5 and Series 6 are a re-open of Series 3 and expire 28 years from issuance date. 31

32 Clean balance sheet 8.0x 7.0x 6.0x Debt / EBITDA (2015E) 5.0x 4.0x 3.0x 2.0x 1.0x - BBB+ BBB A- BBB BBB+ A- A Ba2 BBB NR Pembina continues to employ less leverage than its peers Source: RBC Capital Markets (December 4 th, 2015). See "Non-GAAP & additional GAAP measures." 32

33 SUMMARY

34 Our businesses in 2018 Now Conventional Pipelines 9,000+ km network Fox Creek to Namao capacity at 365 mbpd In Largest conventional crude oil and NGL feeder system in Canada 12% increase in km (adding 1,120+ km with Phase III and laterals) ~90% increase in Fox Creek to Namao capacity (to 680 mbpd+) Midstream 73 mbpd fractionator 7 MMbbl storage capacity at Redwater Largest fractionation facility in Canada and handler of condensate 188% increase in fractionation capacity (to 210 mbpd) 14% increase in storage capacity at Redwater (to 8.3 MMbbl+) One of the largest straddle plant owners Gas Services 468 MMcf/d shallow cut processing capacity 799 MMcf/d deep cut processing capacity One of the largest third-party gas processors in Canada 43% increase in shallow cut gas processing capacity (to 668 MMcf/d) Total natural gas processing capacity of ~1.6 bcf/d Oil Sands & Heavy Oil 1,650 km of pipeline with 880 mbpd capacity under contract Long-life contracts continue to provide stable cash flows Investment-grade counterparties Investing to support one of Canada s largest oil sands projects Leader in energy infrastructure and services See "Forward-looking statements & information." 34

35 Key take-away: we are doing the important things right Assets Growth Stable Well-financed Responsible Value Strategically located infrastructure serving longlife hydrocarbon reserves Sector leading growth portfolio: ~$5.3 billion of committed opportunities Growing our highly contracted and stable cash flow; expect 80-85% of operating margin to be fee-forservice in 2018 Strong balance sheet, investmentgrade credit rating and proven access to funding Working for the interests of all Pembina's stakeholders History of generating shareholder value and growing dividends and cash flow; 9.1% CAGR in ACFPS ( ) Doing the important things right to facilitate our objective of doubling EBITDA in 2018 See "Forward-looking statements & information" and "Non-GAAP & additional GAAP measures." 35

36 We continue driving shareholder value 487% total shareholder return* * Jan 1, 2005 Dec 31, 2014, inclusive of dividends reinvested 5.8 % * CAGR in dividends per share* $3.4 billion * To December 2014, Pembina began paying dividends in 1997 in dividends paid since inception* 17 % average compound annual return* * Jan 1, 2005 Dec 31, 2014, inclusive of dividends reinvested Proven long-term track record of shareholder value creation 36

37 Contact Us: Pembina Pipeline Corporation Suite 4000, 585 8th Avenue S.W. Calgary, AB T2P 1G1 Toll Free: Phone: (403)

38 Non-GAAP and additional GAAP measures This presentation uses certain terms that are not defined by GAAP but are used by management of Pembina to evaluate Pembina's performance. Non- GAAP and additional GAAP financial measures do not have a standardized meaning prescribed by GAAP and are therefore unlikely to be comparable to similar measures presented by other companies. Pembina uses the non-gaap terms "total enterprise value" (market value of Pembina's common shares plus preferred shares and convertible debentures plus senior debt less cash and cash equivalents), EBITDA (results from operating activities plus share of profit from equity accounted investees (before tax, depreciation and amortization) plus depreciation and amortization (included in operations and general and administrative expense) and unrealized gains or losses on commodity-related derivative financial instruments) and Adjusted Cash Flow from Operating Activities (cash flow from operating activities plus the change in non-cash working capital, adjusting for current tax and share-based payment expenses, and deducting preferred share dividends declared), and the additional GAAP term "operating margin" (gross profit before depreciation and amortization included in operations and unrealized gain/loss on commodity-related derivative financial instruments). Financial ratios are used to demonstrate financial leverage (extent to which debt is used in a company s capital structure) which include Total Debt (Total Senior Debt outstanding plus face value of Convertible Debentures as per the financial statements of the corresponding reporting year), Total Debt to Total Capitalization (Total Debt divided by Total Equity less non-controlling interest). Management believes these non-gaap measures provide an indication of the results generated by Pembina's business activities and the value those businesses generate. Investors should be cautioned that these non- GAAP measures should not be construed as an alternative to net earnings, cash flow from operating activities or other measures of financial performance determined in accordance with GAAP as an indicator of Pembina's performance. For additional information with respect to financial measures which have not been identified by GAAP, including reconciliations to the closest comparable GAAP measure, see Pembina's Management's Discussion and Analysis for the fiscal year ended December 31, 2014, available on SEDAR at or in Pembina's annual report on Form 40-F for the fiscal year ended December 31, 2014 available on EDGAR at 38