CORPORATE PROFILE - Keyera · CORPORATE PROFILE April 2019 . Disclaimer In the interests of...

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.

Image input resolution: minimum 1920 x 1080 pixels @ 96 ppi

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.


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


$-

$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


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


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


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


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.

14


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


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


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


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


20,000 bbls/d gross (19,740 bbls/d net) of de-ethanization capacity



Dow Fort Saskatchewan



Fractionation at Multiple Locations

Adding Value by Processing NGLs from the Gas Stream 19


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.

20


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


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.


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)


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.

24


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


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


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


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

29


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


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


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)


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


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%


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


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

[email protected]

Keyera Corp. Sun Life Plaza West Tower

200, 144 4 Avenue SW

Calgary, Alberta

T2P 3N4

37

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