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CORPORATE PROFILE
A p r i l 2 0 1 9
Disclaimer
In the interests of providing Keyera Corp. (“Keyera” or the “Company”) shareholders and potential investors with information regarding Keyera,
including Management’s assessment of future plans and operations relating to the Company, this document contains certain statements and
information that are forward-looking statements or information within the meaning of applicable securities legislation, and which are collectively
referred to herein as “forward-looking statements". Forward-looking statements in this document include, but are not limited to statements and
tables with respect to: capital projects and expenditures; strategic initiatives; anticipated producer activity and industry trends; and anticipated
performance. Readers are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans,
intentions or expectations upon which they are based will occur. By their nature, forward looking statements involve numerous assumptions, as
well as known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts,
projections and other forward-looking statements will not occur and which may cause Keyera’s actual performance and financial results in
future periods to differ materially from any estimates or projections of future performance or results expressed or implied by the forward-looking
statements. These assumptions, risks and uncertainties include, among other things: Keyera’s ability to successfully implement strategic
initiatives and whether such initiatives yield the expected benefits; future operating results; fluctuations in the supply and demand for natural
gas, NGLs, crude oil and iso-octane; assumptions regarding commodity prices; activities of producers, competitors and others; the weather;
assumptions around construction schedules and costs, including the availability and cost of materials and service providers; fluctuations in
currency and interest rates; credit risks; marketing margins; potential disruption or unexpected technical difficulties in developing new facilities
or projects; unexpected cost increases or technical difficulties in constructing or modifying processing facilities; Keyera’s ability to generate
sufficient cash flow from operations to meet its current and future obligations; its ability to access external sources of debt and equity capital;
changes in laws or regulations or the interpretations of such laws or regulations; political and economic conditions; and other risks and
uncertainties described from time to time in the reports and filings made with securities regulatory authorities by Keyera. Readers are
cautioned that the foregoing list of important factors is not exhaustive. The forward-looking statements contained in this document are made as
of the date of this document or the dates specifically referenced herein. For additional information please refer to Keyera’s public filings
available on SEDAR at www.sedar.com. All forward-looking statements contained in this document are expressly qualified by this cautionary
statement.
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14
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Keyera at a Glance1
Market capitalization: ~$6.7 billion2
Enterprise value: ~$8.7 billion2
2018 Adjusted EBITDA: $807 million
2018 Payout Ratio: 56%
Dividend: $1.80/share p.a. ($0.15/share per month)
Dividend yield: ~5.7%2
Corporate credit ratings: BBB/Stable3
Net Debt/EBITDA: 2.6x
2019 Growth Capital Program: $800-$900 million
One of Canada’s largest midstream companies
3
1. All information as at December 31, 2018, unless otherwise stated. 2. As at March 31, 2019. 3. DBRS and S&P
12 %
cagr
d i s t r i b u t a b l e c a s h
f l o w p e r s h a r e 1 , 3
8 %
cagr
d i v i d e n d p e r s h a r e 2 , 3
56 %
2 0 1 8 p a yo u t r a t i o 3 , 4
Our Track Record
Focused On Growing Value: 18% Annual Total Shareholder Return5 Since IPO 4
1 Compound annual growth rate from 5/30/2003 to 12/31/2018. 2 Compound annual growth rate from 7/15/2003 to 12/31/2018. 3 Not a standard measure under GAAP. Based on dividends declared. 4 From 1/1/2018 to 12/31/2018, inclusive. 5 Includes reinvestment of dividends.
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Core Strengths
Responsible stewards of capital
Focused, consistent strategy
One of the most integrated midstream companies
Experienced and reliable operator
5
An Integrated Value Chain
6
1. Percentage of total realized margin for the year ended December 31st 2018 (2017 - 81%) . Realized margin is defined as operating margin excluding unrealized gains and losses from commodity-related
risk management contracts. Realized margin is not a standard measure under GAAP.
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1. Realized margin is defined as operating margin excluding unrealized gains and losses from commodity-related risk management contracts. Realized margin is not a standard measure under GAAP.
Includes intersegment transactions. This graph excludes other income from production associated with Keyera’s oil and gas reserves.
Diversified and Growing Margins
Fee-for-Service Business Underpins Balanced Growth 7
~33%
~36%
~31%
AEF
Turnaround AEF
Outage
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$-
$200
$400
$600
$800
$1,000
$1,200
$1,400
12/31/13 12/31/14 12/31/15 12/31/16 12/31/17 12/31/18 12/31/19e
Millions ANNUAL CAPITAL EXPENDITURES
Growth Capital Upper End of Growth Capital Range Acquisitions Maintenance Capital
1 Acquisition capital in 2017 reflects the $55 million purchase price for undeveloped land in the Industrial Heartland of Alberta completed in 1Q17, among other actual YTD costs. 2 Keyera’s 50% acquisition of the South Grand Rapids pipeline is included in 2018 Acquisitions. .
Investment Opportunities Continue
$800 – $900 Million of Growth Capital Investment in 2019 8
1 2
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Approved Projects Capital Cost (Net, in $ Millions)1
2019 2020 2021
Wapiti Area Gathering & Processing Complex (Phase I) 575
Wapiti Gas Plant (Phase II) & North Wapiti Pipeline System 325
Wapiti Water Disposal System 100
Simonette Inlet & Acid Gas Injection Enhancements 100
Simonette Plant Expansion 85
Pipestone Plant (Phase I) 2 600
Wildhorse Terminal US185
Storage Cavern Development Program at Keyera Fort Saskatchewan 110
TOTAL ~$2.1 Billion
Growth Projects Currently Under Development
9 $2.1B Program expected to achieve 10-15% return on capital3
1. Keyera’s share of estimated capital cost. See Keyera’s 2018 Year End MD&A for capital investment risks and assumptions. 2. Pipestone plant expected to start up in 2021. 3.Return on
Capital is defined as operating margin divided by the estimated capital cost of the projects noted on this slide. Keyera expects to achieve this return, in 2022 once all projects achieve their
annual run rate. See “non-GAAP Financial Measure” and “Forward-Looking Statements” in Keyera’s 2018 Year End MD&A for further details.
Western Canada Sedimentary Basin
335 Billion boe u l t imate po ten t ia l recoverab le
reserves o f c rude o i l and b i tumen 1
1 Alberta Energy Regulator’s “ST98-2017: Alberta’s Energy Reserves and Supply/Demand Outlook”, February 28, 2017
Globally Unique Multi-Zone Geology Underlies Alberta
Shale Carbonate Sandstone/Siltstone
/Mannville
/Ellerslie
/Fahler Spirit R
iver
Keyera facilities
u l t imate po ten t ia l recoverab le reserves
o f na tu ra l gas 1
223 Tcf
10
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Gathering and Processing Business Unit
Well maintained, long-life facilities
– ~3.0 bcf/d licensed gross capacity1
– 18 active gas plants; 16 operated by Keyera
Extensive gathering systems
– Network of gathering pipelines tied into existing gas plants
– >4,000 kilometres of pipelines operated by Keyera
– Large capture areas create franchise regions
Fee-for-service revenues with negligible direct commodity exposure
Network of Facilities Supported by Fee-for-Service Contracts
1. Licensed capacity is not equivalent to actual operating capacity. Actual operational capacity can be lower as it depends on
operating conditions and capabilities of functional units at each plant.
11
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HISTORICAL THROUGHPUT & THE PERCENTAGE CHANGE IN AECO & WTI TO December 31 , 2018
Relatively Stable Throughput
12
Keyera’s Presence in Liquids-Rich Area of NW Alberta
With our plans at Pipestone, Wapiti and Simonette gas plants, Keyera will have 950 mmcf/d of
gross processing capacity and 90,000 bbls/d of condensate handling facilities focused on
liquids-rich Montney and Duvernay developments..
Supporting Producer Growth Plans in Liquids-Rich Developments 13
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Simonette Gas Plant Investments
Plant Expansion Project:
− Expanding processing capacity by 150 mmcf/d, resulting in total capacity of 450 mmcf/d
− Project expected to be completed 4Q191 at an estimated cost of $85 million1
Inlet & Acid Gas Injection Enhancements:
− Improves inlet capabilities and adds acid gas injection facilities
− Backed by gas handling agreements with Athabasca Oil Corporation and Murphy Oil Company Ltd., including take-or-pay commitments and facility dedications
− Project expected to be operational in 3Q191 at an estimated cost of $100 million1
Liquids Handling Expansion Project:
− Increases condensate handling capacity to ~27,000 bbls/d and improves liquids recoveries for customers
− Project completed in May 2018 for an estimated cost of $100 million1
Supporting Growing Montney and Duvernay Production
1 Project costs and timing are subject to construction and commissioning schedules.
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Wapiti Area Gathering & Processing Complex
New gas plant supporting liquids-rich Montney development
New infrastructure includes:
Phase 1: 150 mmcf/d of sour gas processing capacity; 25,000 bbls/d of condensate handling capacity; acid gas injection; raw gas gathering and field compression system. Target in-service date of mid-20191.
Phase 2: incremental 150 mmcf/d of sour gas processing capacity, additional compressor station and raw gas gathering pipelines. Target in-service date of mid-20201.
Phase 1 backed by an area dedication and take-or-pay commitments under a long-term gas handling agreement with Paramount
Estimated cost of Phase 1 ~$575 million1; Phase 2 and the NWPS expected to cost ~$325 million1
Future potential to connect the plant to Keyera’s Wapiti pipeline and Simonette gas plant
Supporting Producer Growth Plans in Liquids-Rich NW Alberta
1 Project cost and timing subject to timely receipt of remaining regulatory approvals and construction schedule variables.
Producers active in the
Wapiti area: • CNRL
• Cenovus
• Encana
• NuVista
• Paramount
• Seven Generations
• Shell
• Sinopec-Daylight
15
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North Wapiti Pipeline System (NWPS)
1 The Wapiti gas plant is currently under construction.
NWPS extends Keyera’s Wapiti gas plant1 capture area to north of the Wapiti River
New infrastructure includes: 12-inch sour gas gathering pipeline 8-inch condensate and water (emulsion) pipeline compressor station
Agreements with Pipestone Oil Corp. include: Long-term take-or-pay obligation for raw gas handling and
processing as well as pipeline transportation Long-term NGL fractionation and marketing services
Target in-service date in 2H19
NWPS provided the foundation for Phase 2 of the Wapiti gas plant adding 150 mmcf/d of processing capacity
Keyera Wapiti
Gas Plant
NWPS
Compressor
Station
Grande
Prairie
Wapiti River
Smoky River
North Wapiti
Gathering Pipeline
Producers in the
Pipestone area:
• Blackbird
• CNRL
• Encana
• Hammerhead
• Inception
• Iron Bridge
• NuVista
• Paramount
• Pipestone Oil Corp.
• Seven Generations
• Shell
• Sinopec
• Velvet Montney Well
16 Supporting Producer Growth Plans in Liquids-Rich NW Alberta
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Pipestone Liquids Hub and Plant
Increasing Keyera’s Presence in the Liquids-Rich Montney
1 Project timing and cost subject to timely receipt of regulatory approvals, completing engineering and cost estimates, and construction schedule variables.
Another new plant supporting liquids-rich Montney development
Backed by long-term fee-for-service arrangement with an area dedication and modest revenue guarantee from Encana
Keyera will own the facilities with an option to operate the Project after five years of plant start up
New facilities include: Liquids Hub: 14,000 bbls/d of condensate processing
capacity; completed in 3Q18 for $91 million Plant: 200 mmcf/d of sour gas processing capacity and
24,000 bbls/d of condensate processing capacity; expected to start up in 20211; estimated cost of $600 million1
Future potential to expand Pipestone Plant up to an additional 200 mmcf/d
17
Pipestone Liquids
Hub and Plant
Source: Peters & Co.
Liquids Business Unit
Unmatched Infrastructure for NGL and Oil Sands Customers 18
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Keyera Fort Saskatchewan
Gilby Gas Plant
3,650 bbls/d gross (2,930 bbls/d net) of C3+ fractionation capacity
Nevis Gas Plant
3,740 bbls/d of C3+ fractionation capacity
Rimbey Gas Plant
28,000 bbls/d gross (27,640 bbls/d net) of C3+ fractionation capacity
20,000 bbls/d gross (19,740 bbls/d net) of de-ethanization capacity
65,200 bbls/d gross (50,000 bbls/d net) of C3+ fractionation capacity
30,000 bbls/d gross (23,010 bbls/d net) of de-ethanization capacity
Dow Fort Saskatchewan
30,000 bbls/d gross (5,420 bbls/d net) of C3+ fractionation capacity
69,200 bbls/d gross (6,920 bbls/d net) of de-ethanization capacity
Fractionation at Multiple Locations
Adding Value by Processing NGLs from the Gas Stream 19
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Expanding Underground Storage at KFS
Underground storage capacity expansion project:
– Gross storage capacity of ~14 million barrels
– 16th and 17th caverns currently being washed; expected in-service 1H201 and1H211
– 18th cavern in engineering phase
– Expected net cost of $110 million2 to complete three cavern program
Providing Customers with Flexibility
1 Timing subject to receipt of remaining regulatory approvals and completion of final work to bring into service. 2 Costs subject to construction and schedule variables.
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Keylink NGL Gathering Pipeline System
– Connects eight Keyera gas plants to the
Rimbey gas plant for on site fractionation
– Provides a safe, reliable and economically
improved transportation alternative
– Enhanced service offering as Rimbey is pipeline
connected to Keyera’s Edmonton Terminal and
Ft. Saskatchewan fractionation and storage
complex
– Completed on time for $125 million, $25 million
lower than the original forecast
– Capacity of ~22,000 bbls/d1
New NGL gathering solution enhancing Keyera’s integrated service offering:
An Integrated & Economic NGL Transportation Solution
1 Capacity is estimated based on certain assumptions
21
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Oil Sands Production Continues to Grow
22 Bitumen Production Growth Driving Condensate Demand
Company
Select Projects Sanctioned
and/or Under Construction Capacity (MB/d) Timing
MEG Christina eMSAGP / Brownfield 20 2018-2020
Cenovus Christina Lake Phase G 50 2019-2020
Canadian Natural Kirby North Phase 1 40 2019
Imperial / Exxon Kearl Reliability 20 2020
CNOOC / Nexen Long Lake Southwest Expansion 26 2021
Imperial Aspen Phase 1 75 2022-2023
Total Capacity Additions of Certainty 231
WCSB
Condensate
Market:
Supply
vs
Demand
Oil Sands
Production:
Mining
vs
In Situ
Company Projects with a High Likelihood
Capacity
(MB/d) Timing
Canadian Natural Horizon Debottlenecks (SCO) 40 2020-2023
Suncor Fort Hills Debottleneck 30 2020-2023
Cenovus Foster Creek Phase H 30 2021-2022
Imperial Cold Lake Expansion Project 55 2022-2023
Suncor / CNOOC Meadow Creek East Phase 1 40 2022-2023
Cenovus Narrows Phase A 65 2022-2023
Canadian Natural Kirby Phase 2 (North or South) 40 2022-2023
Cenovus Christina Lake Phase H 50 2022-2023
Canadian Natural Horizon PFT Expansion (Bitumen) 45 2024
Total Capacity Additions of High Likelihood 395 Sourc
e:
Pete
rs &
Co.
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Extensive, Flexible Condensate Infrastructure
Most connected condensate hub in Western Canada
Major oil sands delivery options:
Supply through multiple receipt points:
– Local fractionators and refineries
– Kinder Morgan Cochin pipeline
– Enbridge Southern Lights pipeline and CRW pool
– Western Canada feeder pipelines
– Canadian Diluent Hub
– Rail imports at the Alberta Diluent Terminal
Storage at Keyera Fort Saskatchewan
Long-term take-or-pay and fee-for-service agreements:
Industry-Leading Diluent Handling Services 23
– Polaris
– Norlite
– Access
– FSPL
– Grand Rapids
– South Cheecham
– Imperial Oil (Kearl)
– Husky/BP (Sunrise)
– Suncor/Teck/Total (Fort Hills)
– North West Upgrading
– Cenovus (Christina Lake)
– CNRL (Kirby, Primrose)
– JACOS/Nexen (Hangingstone)
– Devon (Jackfish)
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Norlite Pipeline
Diluent pipeline from Ft. Saskatchewan to Athabasca oil sands completed in June 2017
Enbridge is the operator of the pipeline; Keyera is a 30% owner
Long-term take-or-pay agreements with owners of Fort Hills project (Suncor, Total and Teck) and other third parties
Norlite shippers can contract for services through Keyera’s other condensate infrastructure in Edmonton/Fort Saskatchewan, including storage and rail
Initial capacity of approximately 218,000 bbls/d with potential to expand to 465,000 bbls/d1
Provides Additional Long-Term Stable Cash Flows
1 Pipeline capacities are estimated based on certain assumptions.
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South Grand Rapids Pipeline
50/50 joint venture between Keyera and Grand Rapids Pipeline LP (TransCanada PipeLines and PetroChina Canada) and operated by Keyera
45-kilometre 20-inch diluent pipeline from Edmonton to Fort Saskatchewan
Provides Keyera with ≥225,000 bbls/d of net capacity1 for diluent transportation, a portion of which will be used to meet commitments under existing customer agreements
Remaining capacity available for Keyera to pursue new diluent transportation business
Net capital cost to Keyera $125 million
Completed in 3Q18
Further Enhancing and Expanding our Condensate Network
1 Pipeline capacities are estimated based on certain assumptions.
25
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Base Line Terminal - Crude Oil Storage for WCSB
50/50 joint venture operated by Kinder Morgan
12 crude oil storage tanks with 4.8 million bbls of capacity located at Keyera’s Alberta EnviroFuels site
Completed in 4Q18
Connected to Kinder Morgan’s Edmonton terminal
Backstopped by 8 customers with take-or-pay contracts up to 10 years in length
Expected net capital cost to Keyera of $315 million1
Potential to add additional tanks for total storage capacity of up to 6.6 million bbls, subject to customer demand
Expanding and Diversifying Keyera’s Service Offering
1 Subject to finalization of outstanding costs, invoices and final clean up.
26
Close
proximity
to pipelines
and railroads
Keyera holds
salt rights
beneath
most of these
lands
166 undeveloped acres 1290 undeveloped acres 132 undeveloped acres
Keyera Josephburg Terminal (KJT) Keyera Fort Saskatchewan (KFS)
350 undeveloped acres
Keyera’s Hull Terminal in Texas
Undeveloped Land for Future Growth
Strategic Optionality in the Industrial Heartland of Alberta 27
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Wildhorse Crude Oil Terminal at Cushing, OK
Crude oil storage and blending terminal1 in a key U.S. liquids hub
Backed by fee-for-service take-or-pay storage contracts ranging from 2 – 6 years in length
Provides significant commercial opportunities by blending lower value products into higher value product streams
12 storage tanks with 4.5 million bbls of working storage capacity will be constructed
Terminal will be initially pipeline connected to two existing storage terminals in Cushing, OK
Expected to be in service in mid-2020 with a net capital cost to Keyera of US$185 million2
Complemented by acquisition of Oklahoma Liquids Terminal, a nearby logistics and diluent blending facility
Expanding Keyera’s Presence in the US at a major liquids hub
1 90/10 joint venture with an affiliate of Lama Energy Group 2 Cost and timing subject to construction and schedule variables.
28
Cushing, OK
Unparalleled
connectivity with
90 mmbls of storage
Wildhorse
Terminal
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Hull Terminal and Pipeline System
Rail, truck and pipeline terminal handles
NGL mix, propane, butane and iso-butane
South pipeline system completed in 2Q18
Provides connections to Beaumont and
Mont Belvieu, North America’s largest NGL
hub
Provides commercial opportunities for
Keyera’s marketing business along with
3rd party fee-for-service opportunities
Agreement with major US midstream
company securing storage and other
midstream services in Mont Belvieu
Enhancing Keyera’s Access to Mont Belvieu
South pipeline system completed in 2Q18
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Marketing Services
Diversified Portfolio of Logistics Services 30
C3
Propane
• Supply exceeds demand in North America
• Majority sold into U.S. markets
• Demand and pricing vary seasonally
• Keyera uses its storage and logistics to
access markets
C2
Ethane
• Sold under long-term agreements to
petrochemical producers in Alberta
• Limited spot market in western Canada
• Produced at three Keyera facilities
C4
Butane
• Sourced and consumed in Alberta
• Feedstock for iso-octane production at
Alberta EnviroFuels
• Seasonal imports from the U.S.
iC8
Iso-octane
• Majority of sales in the U.S.
• High quality gasoline additive
• Produced from butane at Keyera’s
Alberta EnviroFuels facility
C5+ Condensate
• Keyera’s C5+ hub creates industry liquidity
• Consumed in Alberta as diluent for bitumen
• Significant imports required today to meet
demand
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Alberta EnviroFuels (AEF)
Iso-octane (iC8) is a high octane, low vapour
pressure gasoline additive
Butane is the NGL feedstock
Only merchant iC8 facility in North America
Licensed capacity of 13,600 bbls/d
Supply networks and distribution infrastructure
used to source feedstock while rail logistics
broaden sales markets
Financial forward markets enable hedging of
feedstock costs and large portion of iC8 sales
iC8 demand driven by premium gasoline demand
Seasonality is complementary to propane and
butane
31 iC8 is a Premium Value-Added Product Produced in Alberta
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Iso-Octane Business and its Margin Components
32 Iso-Octane is a High-Value, Low-Volume Business
NOTE: Components are not indicative of their relative size in the margin equation.
Cost
Components
Revenue
Components
Risk Management Hedges
Foreign Exchange
(iC8 sold in USD)
Iso-Octane (iC8)
Premium over RBOB
RBOB Premium over WTI
WTI
Strong demand for iso-octane
- 13,600 bbls/d of facility capacity
- Annual peak occurs during summer driving season
Access to butane feedstock
- Sourced locally and from the US
- Utilize cavern storage assets and pipeline network to
manage volumes and costs
Operational expertise to maximize
utilization
Access to continental markets
- Leverage Keyera’s rail terminals, storage facilities
and logistical expertise to identify best opportunities
- Sell into regions with the strongest demand across
North America, including the US Gulf Coast and
Midwest to maximize iso-octane premiums
Risk Management Hedges
Periodic Plant Maintenance
Plant Operating Expenses,
Storage & Transportation Costs
~1.4 bbl of C4 per bbl of iC8
Butane (C4) cost is a Fraction
of WTI (priced in USD)
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1. Calculated as of December 31, 2018 in accordance with Keyera’s debt covenants. For further information regarding covenant calculations, please see
Keyera’s 2018 Year End Report MD&A or copies of the note purchase agreements, all of which are filed on SEDAR.
2. All US dollar denominated debt is translated into Canadian dollars at its swap rate. 2019 maturities as of February 1, 2019.
3. Midstream Peer Group includes ENB, GEI, IPL, PPL, and TRP.
LONG-TERM DEBT MATURIT IES 2 (exc ludes d rawings under revo l ve r )
2.6x
Net Debt1 to EBITDA vs Midstream Peer Group3 Average >4.5x
Conservative Capital Structure
33 Well Positioned to Fund Keyera’s $2.1 Billion Capital Program
Issuer Credit Ratings:
• DBRS Limited: BBB with a Stable trend
• S&P Global: BBB/Stable
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1. Realized margin is a “Non-GAAP Measure” and excludes the effect of non-cash gains and losses from commodity-related risk management contracts. 2. Keyera uses certain “Non-GAAP Measures” such as Adjusted EBITDA, Distributable Cash Flow, Distributable Cash Flow per Share and Payout Ratio.
(Millions of Canadian dollars, except where noted; arithmetic inconsistencies due to rounding)
Current Financial Results
Continued Strong Performance 34
4Q18 4Q17 Change 2018 2017 Change
Operating Margin
Gathering & Processing 74 73 1% 272 275 -1%
Liquids Infrastructure 84 82 2% 324 285 14%
Marketing 157 54 190% 366 128 185%
Other 3 2 21% 14 15 -6%
Total Operating Margin 317 211 50% 976 703 39%
Realized Margin1 266 219 21% 906 703 29%
Adjusted EBITDA2 248 197 26% 807 617 31%
Net Earnings 165 88 87% 394 290 36%
Distributable Cash Flow2 200 174 15% 638 510 25%
Per Share 0.96 0.90 7% 3.08 2.70 14%
Payout Ratio2 47% 47% 0% 56% 61% -8%
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1 Total return includes the reinvestment of dividends paid by Keyera and the TSX between May 30, 2003 and March 31, 2019. 2 Distributable cash flow is not a standard measure under GAAP. See Keyera’s 2018 Year End Report for a definition of distributable cash flow and for a reconciliation of distributable cash flow to its related
GAAP measure. 3 Payout ratio is not a standard measure under GAAP. Payout ratio is defined as dividends declared to shareholders divided by distributable cash flow.
Investment Summary
Providing Growth and Income for Shareholders 35
2 3
1
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Investment Highlights
20 year track record of profitable operations & project execution
Long life integrated assets in the right liquids rich areas
Diversified risk profile driven by oil, gas and NGL fundamentals
Commitment to a strong balance sheet & dividend growth
36
www.keyera.com
Contact Information
Lavonne Zdunich, CPA, CA
Director, Investor Relations & Communications
Calvin Locke, P.Eng
Manager, Investor Relations
888-699-4853
ir@keyera.com
Keyera Corp. Sun Life Plaza West Tower
200, 144 4 Avenue SW
Calgary, Alberta
T2P 3N4
37
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